10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X]    Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2014

[  ]    Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission File No. 1-13726

Chesapeake Energy Corporation

(Exact name of registrant as specified in its charter)

Oklahoma	73-1395733
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
6100 North Western Avenue
Oklahoma City, Oklahoma	73118
(Address of principal executive offices)	(Zip Code)

(405) 848-8000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, par value $0.01	New York Stock Exchange
3.25% Senior Notes due 2016	New York Stock Exchange
6.25% Senior Notes due 2017	New York Stock Exchange
6.5% Senior Notes due 2017	New York Stock Exchange
7.25% Senior Notes due 2018	New York Stock Exchange
Floating Rate Senior Notes due 2019	New York Stock Exchange
6.625% Senior Notes due 2020	New York Stock Exchange
6.875% Senior Notes due 2020	New York Stock Exchange
6.125% Senior Notes due 2021	New York Stock Exchange
5.375% Senior Notes due 2021	New York Stock Exchange
4.875% Senior Notes due 2022	New York Stock Exchange
5.75% Senior Notes due 2023	New York Stock Exchange
2.75% Contingent Convertible Senior Notes due 2035	New York Stock Exchange
2.5% Contingent Convertible Senior Notes due 2037	New York Stock Exchange
2.25% Contingent Convertible Senior Notes due 2038	New York Stock Exchange
4.5% Cumulative Convertible Preferred Stock	New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES [X]     NO [ ]    

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. YES [ ]    NO [X] 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X]     NO [ ] 

 Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES [X]     NO [ ] 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   [X] 

 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer [X] Accelerated Filer [ ] Non-accelerated Filer [ ] Smaller Reporting Company [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES [ ]      NO [X]

The aggregate market value of our common stock held by non-affiliates on June 30, 2014 was approximately $20.5 billion. As of February 9, 2015, there were 665,038,368 shares of our $0.01 par value common stock outstanding.

________________________________________

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the 2015 Annual Meeting of Shareholders are incorporated by reference in Part III.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

2014 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

PART I		Page
Item 1.	Business	1
Item 1A.	Risk Factors	23
Item 1B.	Unresolved Staff Comments	32
Item 2.	Properties	32
Item 3.	Legal Proceedings	32
Item 4.	Mine Safety Disclosures	34
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6.	Selected Financial Data	37
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	39
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	64
Item 8.	Financial Statements and Supplementary Data	69
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	154
Item 9A.	Controls and Procedures	154
Item 9B.	Other Information	154
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	154
Item 11.	Executive Compensation	154
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	154
Item 13.	Certain Relationships and Related Transactions and Director Independence	154
Item 14.	Principal Accountant Fees and Services	154
PART IV
Item 15.	Exhibits and Financial Statement Schedules	155

PART I

Item 1. Business

Unless the context otherwise requires, references to “Chesapeake”, the “Company”, “us”, “we” and “our” in this report are to Chesapeake Energy Corporation together with its subsidiaries. Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, and our main telephone number at that location is (405) 848-8000. Definitions of oil and gas industry terms appearing in this report can be found under Glossary of Oil and Gas Terms beginning on page 20.

Our Business

Chesapeake is currently the second-largest producer of natural gas and the 11th largest producer of oil and natural gas liquids (NGL) in the United States. We own interests in approximately 45,100 oil and natural gas wells that produced an average of approximately 729 mboe per day in the 2014 fourth quarter, net to our interest. We have a large and geographically diverse resource base of onshore U.S. unconventional liquids and natural gas assets. We have leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas; the Utica Shale in Ohio and Pennsylvania; the Granite Wash, Cleveland, Tonkawa and Mississippian Lime plays in the Anadarko Basin in northwestern Oklahoma and the Texas Panhandle; and the Niobrara Shale and Upper Cretaceous sands in the Powder River Basin in Wyoming. Our natural gas resource plays are the Haynesville/Bossier Shales in northwestern Louisiana and East Texas; the Marcellus Shale in the northern Appalachian Basin in Pennsylvania; and the Barnett Shale in the Fort Worth Basin of north-central Texas. We also own oil and natural gas marketing and natural gas gathering and compression businesses.

The map below illustrates the locations of Chesapeake's oil and natural gas exploration and production operations.

The Company's estimated proved reserves as of December 31, 2014 were 2.469 bboe, a decrease of 209 mmboe, or 8%, from 2.678 bboe as of December 31, 2013. The 2014 proved reserve movement included 448 mmboe of extensions and discoveries, 27 mmboe of upward revisions resulting primarily from higher average natural gas prices and 78 mmboe of downward revisions resulting from changes to previous estimates as further discussed below in Oil,Natural Gas and NGL Reserves and in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report. In 2014, we produced 258 mmboe, acquired 14 mmboe and divested 362 mmboe of estimated proved reserves, primarily through the sale of our southern Marcellus and a portion of our eastern Utica Shale assets. Before price differential adjustments, oil prices used in estimating proved reserves decreased and natural gas prices used in estimating proved reserves increased as of December 31, 2014 compared to December 31, 2013 using the trailing 12-month average prices required by the Securities and Exchange Commission (SEC). Oil prices decreased by $1.84 per bbl, or 2%, to $94.98 per bbl from $96.82 per bbl. Natural gas prices increased $0.68

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per mcf, or 19%, to $4.35 per mcf from $3.67 per mcf. Proved developed reserves represented 75% of our proved reserves as of December 31, 2014 compared to 68% as of December 31, 2013.

Our daily production for 2014 averaged 706 mboe, an increase of 36 mboe, or 5%, over the 670 mboe of daily production for 2013, and consisted of approximately 115,800 bbls of oil (16% on an oil equivalent basis), approximately 90,500 bbls of NGL (13% on an oil equivalent basis), and approximately 3.0 bcf of natural gas (71% on an oil equivalent basis). Our average daily oil production increased 3%, or approximately 3 mbbls per day; our average daily natural gas production remained the same; and our average daily NGL production increased 58%, or approximately 33 mbbls per day over the average daily production for 2013.

Information About Us

We make available, free of charge on our website at www.chk.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. Documents and information on our website are not incorporated by reference herein.

Business Strategy

With substantial leasehold positions in most of the premier U.S. onshore resource plays, Chesapeake is focused on finding and producing hydrocarbons in a responsible and efficient manner that seeks to maximize shareholder returns. We are committed to increasing our profitability and decreasing our financial complexity through the execution of our business strategy, which consists of four fundamental tenets: financial discipline, profitable and efficient growth from captured resources, exploration and business development.

We are applying financial discipline to all aspects of our business, with the primary goals of balancing capital expenditures with cash flow from operations, increasing financial and operational flexibility through value-driven spending and lower business costs and achieving investment grade metrics. As a result of our focus on financial discipline, our combined production and general and administrative expenses decreased to $5.94 per boe in 2014 compared to $6.60 per boe in 2013.

The Company’s substantial inventory of hydrocarbon resources, including our acreage inventory, provides a strong foundation for future growth. We believe that focusing on profitable and efficient growth from our captured resources will allow us to deliver attractive financial returns through all phases of the commodity price cycle. We have seen and continue to see increased efficiencies through our leveraging of first-well investments made in prior periods, including drilling on pre-existing pads. We have a competitive capital allocation process designed to optimize our asset portfolio and identify the highest quality projects for future investment. To better understand our opportunities for continuous improvement, we benchmark our performance against that of our peers and evaluate the performance of completed projects. We also pay careful attention to safety, regulatory compliance and environmental stewardship measures while executing our strategy.

Although the Company’s substantial inventory of hydrocarbon resources provides a strong foundation, we believe exploration and business development are also key opportunities for future growth. We believe we will have opportunities to enhance or expand our portfolio through leveraging our innovative technology and expertise, exploring and exploiting new domestic resources, pursuing international growth opportunities and targeting strategic acquisitions. We believe these platforms will increase shareholder returns.

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During 2014, we executed on our business strategy by:

• selling noncore assets in the southern Marcellus and Utica Shale plays in December 2014, which provided approximately 7% of our total 2014 production, for net proceeds of approximately $5.0 billion;

• completing additional dispositions of other noncore assets for aggregate net proceeds of approximately $1.8 billion;

• acquiring approximately 203,000 net acres and 186 gross wells in the southern Powder River Basin of Wyoming;

• completing the spin-off of our oilfield services business intoSeventy Seven Energy Inc. (NYSE:SSE), a stand-alone publicly traded company;

• reducing financial complexity through a variety of transactions;

• entering into a new unsecured $4.0 billion credit facility with investment grade-like terms;

• ending the year with approximately $4.0 billion in cash and no borrowings under our revolving credit facility; and

• achieving record production of approximately 770,000 boe per day in mid-December 2014 with fewer than half the rigs used in 2012.

Operating Divisions

Chesapeake focuses its exploration, development, acquisition and production efforts in the two geographic operating divisions described below.

Southern Division. Includes the Eagle Ford Shale in South Texas, the Granite Wash, Cleveland, Tonkawa and Mississippian Lime plays in the Anadarko Basin in northwestern Oklahoma and the Texas Panhandle, the Haynesville/Bossier Shales in northwestern Louisiana and East Texas and the Barnett Shale in the Fort Worth Basin in north-central Texas.

Northern Division. Includes the Utica Shale in Ohio and Pennsylvania, the Marcellus Shale in the northern Appalachian Basin in Pennsylvania and the Niobrara Shale and Upper Cretaceous sands in the Powder River Basin in Wyoming.

Well Data

As of December 31, 2014, we held an interest in approximately 45,100 gross (18,500 net) productive wells, including 33,600 properties in which we held a working interest and 11,500 properties in which we held an overriding royalty interest. Of the wells in which we had a working interest, 28,000 gross (15,900 net) were classified as natural gas productive wells and 5,600 gross (2,600 net) were classified as oil productive wells. Chesapeake operated approximately 21,000 of its 33,600 productive wells in which we had a working interest. During 2014, we completed 1,048 gross (625 net) wells and participated in another 892 gross (57 net) wells completed by other operators. We operate approximately 90% of our current daily production volumes.

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Drilling Activity

The following table sets forth the wells we drilled or participated in during the periods indicated. In the table, "gross" refers to the total wells in which we had a working interest and "net" refers to gross wells multiplied by our working interest.

	2014				2013				2012
	Gross	%	Net	%	Gross	%	Net	%	Gross	%	Net	%
Development:
Productive	1,784	99	629	99	1,704	99	847	99	2,075	99	956	99
Dry	3	1	1	1	21	1	9	1	21	1	5	1
Total	1,787	100	630	100	1,725	100	856	100	2,096	100	961	100
Exploratory:
Productive	145	95	46	88	209	97	124	96	495	98	305	98
Dry	8	5	6	12	6	3	5	4	10	2	6	2
Total	153	100	52	100	215	100	129	100	505	100	311	100

The following table shows the wells we drilled or participated in by operating division:

	2014		2013		2012
	Gross Wells	Net Wells	Gross Wells	Net Wells	Gross Wells	Net Wells
Southern	1,448	473	1,352	698	1,933	982
Northern	492	209	588	287	668	290
Total	1,940	682	1,940	985	2,601	1,272

At December 31, 2014, we had 898 gross (464 net) wells in drilling or completing status.

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Production, Sales, Prices and Expenses

The following table sets forth information regarding our production volumes, oil, natural gas and NGL sales, average sales prices received, and other operating income and expenses for the periods indicated:

	December 31,
	2014			2013			2012
Net Production:
Oil (mmbbl)	42			41			31
Natural gas (bcf)	1,095			1,095			1,129
NGL (mmbbl)	33			21			18
Oil equivalent (mmboe)(a)	258			244			237
Oil, Natural Gas and NGL Sales ($ in millions):
Oil sales	$	3,682		$	3,911		$	2,829
Oil derivatives - realized gains (losses)(b)	(185		)	(108		)	39
Oil derivatives - unrealized gains (losses)(b)	859			280			857
Total oil sales	4,356			4,083			3,725
Natural gas sales	2,777			2,430			2,004
Natural gas derivatives - realized gains (losses)(b)	(191		)	9			328
Natural gas derivatives - unrealized gains (losses)(b)	535			(52		)	(331		)
Total natural gas sales	3,121			2,387			2,001
NGL sales	703			582			526
NGL derivatives - realized gains (losses)(b)	—			—			(9		)
NGL derivatives - unrealized gains (losses)(b)	—			—			35
Total NGL sales	703			582			552
Total oil, natural gas and NGL sales	$	8,180		$	7,052		$	6,278
Average Sales Price (excluding gains (losses) on derivatives):
Oil ($ per bbl)	$	87.13		$	95.17		$	90.49
Natural gas ($ per mcf)	$	2.54		$	2.22		$	1.77
NGL ($ per bbl)	$	21.27		$	27.87		$	29.89
Oil equivalent ($ per boe)	$	27.78		$	28.33		$	22.61
Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)	$	82.76		$	92.53		$	91.74
Natural gas ($ per mcf)	$	2.36		$	2.23		$	2.07
NGL ($ per bbl)	$	21.27		$	27.87		$	29.37
Oil equivalent ($ per boe)	$	26.32		$	27.92		$	24.12
Other Operating Income(c) ($ in millions):
Marketing, gathering and compression net margin	$	(11	)	$	98		$	119
Oilfield services net margin	$	115		$	159		$	142
Expenses ($ per boe):
Oil, natural gas and NGL production	$	4.69		$	4.74		$	5.50
Production taxes	$	0.90		$	0.94		$	0.79
General and administrative expenses(d)	$	1.25		$	1.86		$	2.26
Oil, natural gas and NGL depreciation, depletion and amortization	$	10.41		$	10.59		$	10.58
Depreciation and amortization of other assets	$	0.90		$	1.28		$	1.28
Interest expense(e)	$	0.63		$	0.65		$	0.35

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___________________________________________

(a) Oil equivalent is based on six mcf of natural gas to one barrel of oil or one barrel of NGL. This ratio reflects an energy content equivalency and not a price or revenue equivalency.

(b) Realized gains and losses include the following items: (i) settlements of undesignated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains and losses related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains and losses include the change in fair value of open derivatives scheduled to settle against future period production revenues offset by amounts reclassified as realized gains and losses during the period.

(c) Includes revenue and operating costs. See Results of Operations - Depreciation and Amortization of Other Assets in Item 7 of Part II of this report for details of the depreciation and amortization associated with our marketing, gathering and compression and former oilfield services operating segments.

(d) Includes stock-based compensation and excludes restructuring and other termination costs.

(e) Includes the effects of realized (gains) losses from interest rate derivatives, excludes the effects of unrealized (gains) losses from interest rate derivatives, and is shown net of amounts capitalized.

Oil, Natural Gas and NGL Reserves

The tables below set forth information as of December 31, 2014 with respect to our estimated proved reserves, the associated estimated future net revenue and present value (discounted at an annual rate of 10%) of estimated future net revenue before and after future income taxes (standardized measure). Neither the pre-tax present value of estimated future net revenue nor the after-tax standardized measure is intended to represent the current market value of the estimated oil, natural gas and NGL reserves we own. All of our estimated oil and natural gas reserves are located within the United States.

	December 31, 2014
	Oil	Natural Gas		NGL		Total
	(mmbbl)	(bcf)		(mmbbl)		(mmboe)
Proved developed	229	8,615		198		1,864
Proved undeveloped	192	2,077		68		605
Total proved(a)	421	10,692		266		2,469
		Proved Developed		Proved Undeveloped		Total Proved
		($ in millions)
Estimated future net revenue(b)		$	33,591	$	13,534	$	47,125
Present value of estimated future net revenue(b)		$	17,024	$	4,988	$	22,012
Standardized measure(b)(c)						$	17,133

Operating Division	Oil	Natural Gas	NGL	Oil Equivalent	Percent of Proved Reserves		Present Value
	(mmbbl)	(bcf)	(mmbbl)	(mmboe)			($ millions)
Southern	372	6,882	182	1,701	69	%	$	15,372
Northern	49	3,810	84	768	31	%	6,640
Total	421	10,692	266	2,469	100	%	$	22,012	(b)

___________________________________________

(a) Includes 2 mmbbl of oil, 46 bcf of natural gas and 5 mmbbl of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbl of oil, 22 bcf of natural gas and 2 mmbbl of NGL of which are attributable to the noncontrolling interest holders.

(b) Estimated future net revenue represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2014. For the purpose of determining "prices", we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended

6

December 31, 2014. The prices used in our reserve reports were $94.98 per bbl of oil and $4.35 per mcf of natural gas, before price differential adjustments. Including the effect of price differential adjustments, the prices used in our reserve reports were $89.09 per bbl of oil, $2.68 per mcf of natural gas and $24.10 per bbl of NGL. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2014. The amounts shown do not give effect to nonproperty-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue differs from the standardized measure only because the former does not include the effects of estimated future income tax expenses ($4.9 billion as of December 31, 2014).

Management uses future net revenue, which is calculated without deducting estimated future income tax expenses, and the present value thereof as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While future net revenue and the present value thereof are based on prices, costs and discount factors which are consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company.

(c) Additional information on the standardized measure is presented in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report.

As of December 31, 2014, our reserve estimates included 605 mmboe of reserves classified as proved undeveloped, compared to 869 mmboe as of December 31, 2013. Presented below is a summary of changes in our proved undeveloped reserves (PUDs) for 2014.

	Total
	(mmboe)
Proved undeveloped reserves, beginning of period	869
Extensions, discoveries and other additions	227
Revisions of previous estimates	(162	)
Developed	(225	)
Sale of reserves-in-place	(105	)
Purchase of reserves-in-place	1
Proved undeveloped reserves, end of period	605

As of December 31, 2014, there were no PUDs that had remained undeveloped for five years or more. In 2014, we invested approximately $1.289 billion, net of drilling and completion cost carries of $73 million, to convert 225 mmboe of PUDs to proved developed reserves. In 2015, we estimate that we will invest approximately $1.7 billion, net of drilling and completion cost carries of $11 million, for PUD conversion. The downward revisions of 162 mmboe of PUDs in 2014 were primarily related to the removal of PUDs in the Marcellus Shale, the Eagle Ford Shale and the Anadarko Basin.

The future net revenue attributable to our estimated proved undeveloped reserves of $13.5 billion as of December 31, 2014, and the $5 billion present value thereof, have been calculated assuming that we will expend approximately $6.3 billion to develop these reserves ($1.7 billion in 2015, $1.5 billion in 2016, $1.6 billion in 2017, $1.2 billion in 2018 and $292 million in 2019), although the amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs, commodity prices and the availability of capital. Chesapeake's developmental drilling schedules are subject to revision and reprioritization throughout the year resulting from unknowable factors such as unexpected developmental drilling results, title issues and infrastructure availability or constraints.

The SEC's rules for reporting reserves allow the booking of proved undeveloped reserves at locations other than direct offsets to producing wells. All proved reserves are required to meet reasonable certainty standards; thus, locations that are not direct offsets to producing wells must be underlain by the productive formation. Reasonable certainty also requires that the formation is continuous between the producing wells and the PUD locations and that the PUDs are economically viable.

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Our proved reserves as of December 31, 2014 included PUDs more than directly offsetting producing wells in three resource plays: the Haynesville Shale, the Marcellus Shale and the Eagle Ford Shale. In all other areas, we restricted PUD locations to immediate offsets to producing wells. Within the Haynesville, Marcellus and Eagle Ford Shale plays, we used both public and proprietary geologic data to establish continuity of the formation and its producing properties. This included seismic data and interpretations (2-D, 3-D and micro seismic); open hole log information (collected both vertically and horizontally) and petrophysical analysis of the log data; mud logs; gas sample analysis; drill cutting samples; measurements of total organic content; thermal maturity; sidewall cores; whole cores; and data measured in our internal core analysis facility. After the geologic areas were shown to be continuous, statistical analysis of existing producing wells was conducted to generate an area of reasonable certainty at distances from established production. Undrilled locations within these proved areas qualify as PUDs; however, due to other factors and SEC reserves guidance, numerous locations within these three statistically evaluated plays have not yet been booked as PUDs.

Our annual net decline rate on producing properties is projected to be 30% from 2015 to 2016, 20% from 2016 to 2017, 15% from 2017 to 2018, 13% from 2018 to 2019 and 11% from 2019 to 2020. Of our 1,864 mmboe of proved developed reserves as of December 31, 2014, approximately 156 mmboe, or 8%, were non-producing.

Chesapeake's ownership interest used in calculating proved reserves and the associated estimated future net revenue were determined after giving effect to the assumed maximum participation by other parties to our farm-out and participation agreements. The prices used in calculating the estimated future net revenue attributable to proved reserves do not reflect market prices for oil and natural gas production sold subsequent to December 31, 2014. The estimated proved reserves may not be produced and sold at the assumed prices.

The Company's estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves as of December 31, 2014, 2013 and 2012, along with the changes in quantities and standardized measure of these reserves for each of the three years then ended, are shown in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of these estimates, and these revisions may be material. Accordingly, reserve estimates often differ from the actual quantities of oil, natural gas and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate.

Reserves Estimation

Chesapeake's Corporate Reserves Department prepared approximately 21% of the proved reserves estimates (by volume) disclosed in this report. Those estimates were based upon the best available production, engineering and geologic data.

Chesapeake's Director - Corporate Reserves is the technical person primarily responsible for overseeing the preparation of the Company's reserve estimates. His qualifications include the following:

• 24years of practical experience working for major oil companies, including 16 years in reservoir engineering responsible for estimation and evaluation of reserves;

• Bachelor of Science degree in Petroleum Engineering;

• registered professional engineer in the state of Texas; and

• member in good standing of the Society of Petroleum Engineers.

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We ensure that the key members of our Corporate Reserves Department have appropriate technical qualifications to oversee the preparation of reserves estimates, including, with respect to our engineers, a minimum of an undergraduate degree in petroleum, mechanical or chemical engineering or other applicable technical discipline. With respect to our engineering technicians, a minimum of a four-year degree in mathematics, economics, finance or other technical/business/science field is required. We maintain a continuous education program for our engineers and technicians on new technologies and industry advancements as well as refresher training on basic skills and analytical techniques.

We maintain internal controls such as the following to ensure the reliability of reserves estimations:

• We follow comprehensive SEC-compliant internal policies to determine and report proved reserves. Reserves estimates are made by experienced reservoir engineers or under their direct supervision.

• The Corporate Reserves Department reviews all of the Company's proved reserves at the close of each quarter.    

• Each quarter, Corporate Reserves Department managers, the Director - Corporate Reserves, the Vice Presidents of our business units, the Vice President of Corporate and Strategic Planning and the Executive Vice Presidents of our operating divisions review all significant reserves changes and all new proved undeveloped reserves additions.    

• The Corporate Reserves Department reports independently of our operating divisions.

We engaged two third-party engineering firms to prepare approximately 79% of our estimated proved reserves (by volume) at year-end 2014. The portion of our estimated proved reserves prepared by each of our third-party engineering firms as of December 31, 2014 is presented below.

	% Prepared (by Volume)	Operating Division
Ryder Scott Company, L.P.	54%	Southern
PetroTechnical Services, Division of Schlumberger Technology Corporation	25%	Northern

Copies of the reports issued by the engineering firms are filed with this report as Exhibits 99.1 and 99.2. The qualifications of the technical person at each of these firms primarily responsible for overseeing his firm's preparation of the Company's reserve estimates are set forth below.

Ryder Scott Company, L.P.

• over 30 years of practical experience in the estimation and evaluation of reserves    

• registered professional engineer in the state of Texas

• member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers

• Bachelor of Science degree in Electrical Engineering

PetroTechnical Services, Division of Schlumberger Technology Corporation

• over 30 years of practical experience in the estimation and evaluation of reserves

• registered professional geologist license in the Commonwealth of Pennsylvania

• member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers

• Bachelor of Science degree in Geological Sciences

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Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

The following table sets forth historical costs incurred in oil and natural gas property acquisitions, exploration and development activities during the periods indicated:

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
Acquisition of Properties:
Proved properties	$	214	$	22	$	332
Unproved properties	1,224		997		2,981
Exploratory costs	421		699		2,353
Development costs	4,204		4,888		6,733
Costs incurred(a)(b)	$	6,063	$	6,606	$	12,399

___________________________________________

(a) Exploratory and development costs are net of joint venture drilling and completion cost carries of $679 million, $884 million and $784 million in 2014, 2013 and 2012, respectively.

(b) Includes capitalized interest and asset retirement obligations as follows:

Capitalized interest	$	604	$	815	$	976
Asset retirement obligations	$	39	$	7	$	32

A summary of our exploration and development, acquisition and divestiture activities in 2014 by operating division is as follows:

	Gross Wells Drilled	Net Wells Drilled	Exploration and Development		Acquisition of Unproved Properties		Acquisition of Proved Properties		Sales of Unproved Properties			Sales of  Proved Properties			Total(a)
	($ in millions)
Southern	1,448	473	$	3,180	$	182	$	—	$	(199	)	$	(289	)	$	2,874
Northern	492	209	1,445		1,042		214		(902		)	(4,461		)	(2,662		)
Total	1,940	682	$	4,625	$	1,224	$	214	$	(1,101	)	$	(4,750	)	$	212

___________________________________________

(a) Includes capitalized internal costs of $230 million and related capitalized interest of $604 million.

Acreage

The following table sets forth, as of December 31, 2014, our gross and net developed and undeveloped oil and natural gas leasehold and fee mineral acreage. "Gross" acres are the total number of acres in which we own a working interest. "Net" acres refer to gross acres multiplied by our fractional working interest. Acreage numbers do not include our unexercised options to acquire additional acreage.

	Developed Leasehold		Undeveloped Leasehold		Fee Minerals		Total
	Gross Acres	Net Acres	Gross Acres	Net Acres	Gross Acres	Net Acres	Gross Acres	Net Acres
	(in thousands)
Southern	6,095	2,996	2,103	1,068	154	28	8,352	4,092
Northern	1,840	1,381	5,844	3,646	687	437	8,371	5,464
Total	7,935	4,377	7,947	4,714	841	465	16,723	9,556

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Most of our leases have a three- to five-year primary term, and we manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our drilling to establish production in paying quantities in order to hold leases by production, timely exercising our contractual rights to pay delay rentals to extend the terms of leases we value, planning noncore divestitures to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. The following table sets forth as of December 31, 2014 the expiration periods of gross and net undeveloped leasehold acres.

	Acres Expiring
	Gross Acres	Net Acres
	(in thousands)
Years Ending December 31:
2015	1,820	1,058
2016	1,703	1,105
2017	1,083	722
After 2017	3,341	1,829
Total(a)	7,947	4,714

___________________________________________

(a) Includes 1.873 million gross (976,000 net) held-by-production acres that will remain in force as our production continues on the subject leases, and other leasehold acreage where management anticipates the lease to remain in effect past the primary term of the agreement due to our contractual option to extend the lease term.

Marketing, Gathering and Compression

Our marketing activities, along with our midstream gathering and compression operations, constitute a reportable segment under accounting guidance for disclosure about segments of an enterprise and related information. See Note 21 of the notes to our consolidated financial statements included in Item 8 of Part II of this report.

Marketing

Chesapeake Energy Marketing, L.L.C., one of our wholly owned subsidiaries, provides oil, natural gas and NGL marketing services, including commodity price structuring, securing and negotiating gathering, hauling, processing and transportation services, contract administration and nomination services for Chesapeake and other interest owners in Chesapeake-operated wells. We also perform marketing services for third-party producers in wells in which we do not have an interest. We attempt to enhance the value of oil and natural gas production by aggregating volumes to be sold to various intermediary markets, end markets and pipelines. This aggregation allows us to attract larger, more creditworthy customers that in turn assist in maximizing the prices received. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments.

Oil production is generally sold under market-sensitive short-term or spot price contracts. Natural gas and NGL production is sold to purchasers under percentage-of-proceeds contracts, percentage-of-index contracts or spot price contracts. By the terms of the percentage-of-proceeds contracts, we receive a percentage of the resale price received from the ultimate purchaser. Under percentage-of-index contracts, the price we receive is tied to published indices. Sales to ExxonMobil Corporation and Plains Marketing, L.P. constituted approximately 12% and 11%, respectively, of our total revenues (before the effects of hedging) for the years ended December 31, 2014 and 2012, respectively. There were no sales to individual customers constituting 10% or more of total revenues (before the effects of hedging) for the year ended December 31, 2013.

Midstream Gathering Operations

Historically, we invested, directly and through affiliates, in gathering systems and processing facilities to complement our natural gas operations in regions where we had significant production and additional infrastructure was required. These systems were designed primarily to gather our production for delivery into major intrastate or interstate pipelines. In addition, our midstream business provided services to joint working interest owners and other third-party customers. We generated revenues from our gathering, treating and compression activities through various gathering rate structures. We also processed a portion of our natural gas at various third-party plants.

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In 2013 and 2012, we sold substantially all of our midstream business, including most of our gathering assets. We continue to own the following midstream assets: (i) certain gathering pipelines primarily associated with vertical well production in the northeastern United States; and (ii) four natural gas processing facilities located in West Virginia. See Note 16 of the notes to the consolidated financial statements included in Item 8 of Part II of this report for further discussion of the midstream sales transactions.

Compression Operations

Since 2003, we have operated our compression business through our wholly owned subsidiaries Compass Manufacturing, L.L.C. (Compass) and MidCon Compression, L.L.C. (MidCon). Compass designs, engineers, fabricates, installs and sells natural gas compression units, accessories and equipment used in the production, treatment and processing of oil and natural gas. Once the compressors are complete, a majority of the completed compressors are sold to MidCon. MidCon operates wellhead and system compressors, with approximately 500,000 horsepower of compression, to facilitate the transportation of natural gas primarily produced from Chesapeake-operated wells.

Spin-Off of Oilfield Services Business

On June 30, 2014, we completed the spin-off of our oilfield services business, which we previously conducted through our indirect, wholly owned subsidiary Chesapeake Oilfield Operating, L.L.C. (COO), into an independent, publicly traded company called Seventy Seven Energy Inc. (SSE). See Note 13 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for additional information regarding the spin-off.

Following the spin-off, we have no ownership interest in SSE. Therefore, we ceased to consolidate SSE’s assets and liabilities as of the spin-off date. Because we expect to have significant continued involvement associated with SSE’s future operations through the various agreements described in Note 13 of the notes to our consolidated financial statements included in Item 8 of Part II of this report, our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations.

Competition

We compete with both major integrated and other independent oil and natural gas companies in all aspects of our business to explore, develop and operate our properties and market our production. Some of our competitors may have larger financial and other resources than ours. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities, and overall economic conditions. We also face indirect competition from alternative energy sources, including wind, solar and electric power. We believe that our technological expertise, our exploration, land, drilling and production capabilities and the experience of our management generally enable us to compete effectively.

Regulation - General

All of our operations are conducted onshore in the United States. The U.S. oil and natural gas industry is regulated at the federal, state and local levels, and some of the laws and regulations that govern our operations carry substantial administrative, civil and criminal penalties for non-compliance. Although we believe we are in material compliance with all applicable laws and regulations, and that the cost of compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations could be, and frequently are, amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance or non-compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, local governments, the courts and federal agencies, such as the U.S. Environmental Protection Agency (EPA), the Federal Energy Regulatory Commission (FERC), the Department of Transportation (DOT), the Department of Interior (DOI) and the U.S. Army Corps of Engineers (USACE). We actively monitor regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems.

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Exploration and Production Operations

The laws and regulations applicable to our exploration and production operations include requirements for permits or approvals to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to such laws and regulations include, but are not limited to, the following:

• seismic operations;

• the location of wells;

• construction and operations activities, including in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species or their habitats;

• the method of drilling and completing wells;

• production operations, including the installation of flowlines and gathering systems;

• air emissions and hydraulic fracturing;

• the surface use and restoration of properties upon which oil and natural gas facilities are located, including the construction of well pads, pipelines, impoundments and associated access roads;

• water withdrawal;

• the plugging and abandoning of wells;

• the generation, storage, transportation treatment, recycling or disposal of hazardous waste, fluids or other substances in connection with operations;

• the construction and operation of underground injection wells to dispose of produced water and other liquid oilfield wastes;

• the construction and operation of surface pits to contain drilling muds and other fluids associated with drilling operations;

• the marketing, transportation and reporting of production; and

• the valuation and payment of royalties.

Delays in obtaining permits or an inability to obtain new permits or permit renewalscould inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.

Our exploration and production activities are also subject to various conservation regulations. These include the regulation of the size of drilling and spacing units (regarding the density of wells that may be drilled in a particular area) and the unitization or pooling of oil and natural gas properties. In this regard, some states, such as Oklahoma, allow the forced pooling or integration of tracts to facilitate exploration, while other states, such as Texas, West Virginia and Pennsylvania, rely on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units and, therefore, more difficult to fully develop a project if the operator owns or controls less than 100% of the leasehold. In addition, some states’ conservation laws establish maximum rates of production from oil and natural gas wells, generally limit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amount of oil and natural gas we can produce and to limit the number of wells and the locations at which we can drill.

Midstream Operations

Historically, Chesapeake invested, directly and through an affiliate, in gathering systems and processing facilities to complement our natural gas operations in regions where we had significant production and additional infrastructure was required. In 2012 and 2013, we sold substantially all of our midstream business, including most of our gathering assets. As a result, the impact on our business of compliance with the laws and regulations described below has decreased significantly since the fourth quarter of 2012.

In addition to the environmental, health and safety laws and regulations discussed below under Regulation -Environment, Health and Safety Matters, a small amount of our midstream facilities is subject to federal regulation by the Pipeline and Hazardous Materials Safety Administration of the DOT pursuant to the Natural Gas Pipeline Safety Act of 1968 (NGPSA) and the Pipeline Safety Improvement Act of 2002, which was reauthorized and amended by the

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Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their assertion of authority and capacity to address pipeline safety. Our natural gas pipelines have inspection and compliance programs designed to keep the facilities in compliance with applicable pipeline safety and pollution control laws and regulations.

Natural gas gathering and intrastate transportation facilities are exempt from the jurisdiction of the FERC under the Natural Gas Act. Although the FERC has made no formal determinations with regard to any of our facilities, we believe that our natural gas pipelines and related facilities are engaged in exempt gathering and intrastate transportation and, therefore, are not subject to the FERC's jurisdiction. Nevertheless, FERC regulation affects our gathering and compression business, generally, in that some of our assets feed into FERC-regulated systems. FERC provides policies and practices across a range of natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, capacity release and market transparency, and market center promotion, which indirectly affect our gathering and compression business. In addition, the distinction between FERC-regulated transmission facilities and federally unregulated gathering and intrastate transportation facilities is a fact-based determination made by the FERC on a case-by-case basis; this distinction has also been the subject of regular litigation and change. The classification and regulation of our gathering and intrastate transportation facilities are subject to change based on future determinations by the FERC, the courts and Congress.

Our natural gas gathering operations are subject to ratable-take and common-purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate typically have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination.

Regulation - Environment, Health and Safety

Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of human health and safety, the environment and natural resources. These laws and regulations can restrict or impact our business activities in many ways, such as:

• requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of wastes and other substances associated with operations;

• limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species and/or species of special statewide concern or their habitats;

• requiring investigatory and remedial actions to address pollution caused by our operations or attributable to former operations;

• requiring noise, lighting, visual impact, odor and/or dust mitigation, setbacks, landscaping, fencing, and other measures;

• restricting access to certain equipment or areas to a limited set of employees or contractors who have proper certification or permits to conduct work (e.g., confined space entry and process safety maintenance requirements); and

• restricting or even prohibiting water use based upon availability, impacts or other factors.

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Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial or restoration obligations, and the issuance of orders enjoining future operations or imposing additional compliance requirements. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, local restrictions, such as state or local moratoria, city ordinances, zoning laws and traffic regulations, may restrict or prohibit the execution of our drilling and production plans. In addition, third parties, such as neighboring landowners, may file claims alleging property damage, nuisance or personal injury arising from our operations or from the release of hazardous substances, hydrocarbons or other waste products into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. We monitor developments at the federal, state and local levels to inform our actions pertaining to future regulatory requirements that might be imposed to mitigate the costs of compliance with any such requirements. We also participate in industry groups that help formulate recommendations for addressing existing or future regulations and that share best practices and lessons learned in relation to pollution prevention and incident investigations.

Below is a discussion of the major environmental, health and safety laws and regulations that relate to our business. We believe that we are in material compliance with these laws and regulations. We do not believe that compliance with existing environmental, health and safety laws or regulations will have a material adverse effect on our financial condition, results of operations or cash flow. At this point, however, we cannot reasonably predict what applicable laws, regulations or guidance may eventually be adopted with respect to our operations or the ultimate cost to comply with such requirements.

Hazardous Substances and Waste

Federal and state laws, in particular the federal Resource Conservation and Recovery Act (RCRA) regulate hazardous and non-hazardous wastes. In the course of our operations, we generate petroleum hydrocarbon wastes, such as drill cuttings, produced water and ordinary industrial wastes. Under a longstanding legal framework, certain of these wastes are not subject to federal regulations governing hazardous wastes, although they are regulated under other federal and state waste laws. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses.

Federal, state and local laws may also require us to remove or remediate wastes or hazardous substances that have been previously disposed of or released into the environment. This can include removing or remediating wastes or hazardous substances disposed of or released by us (or prior owners or operators) in accordance with then current laws, suspending or ceasing operations at contaminated areas, or performing remedial well plugging operations or response actions to reduce the risk of future contamination. Federal laws, including the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) and analogous state laws impose joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered legally responsible for releases of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, persons who disposed of or arranged for the disposal of hazardous substances at the site, and any person who accepted hazardous substances for transportation to the site. CERCLA and analogous state laws also authorize the EPA, state environmental agencies and, in some cases, third parties to take action to prevent or respond to threats to human health or the environment and/or seek recovery of the costs of such actions from responsible classes of persons.

The Underground Injection Control (UIC) Program authorized by the Safe Drinking Water Act prohibits any underground injection unless authorized by a permit. Chesapeake recycles and reuses some produced water and we also dispose of produced water in Class II UIC wells, which are designed and permitted to place the water into deep geologic formations, isolated from fresh water sources. Permits for Class II UIC wells may be issued by the EPA or by a state regulatory agency if EPA has delegated its UIC Program authority. Because some states have become concerned that the disposal of produced water could under certain circumstances contribute to seismicity, they have adopted or are considering adopting additional regulations governing such disposal.

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Air Emissions

Our operations are subject to the federal Clean Air Act (CAA) and comparable state laws and regulations. Among other things, these laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and impose various control, monitoring and reporting requirements. Permits and related compliance obligations under the CAA, each state's development and promulgation of regulatory programs to comport with federal requirements, as well as changes to state implementation plans for controlling air emissions in regional non-attainment or near-non-attainment areas, may require oil and gas exploration and production operators to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies.

In 2012, the EPA published final New Source Performance Standards (NSPS) and National Emissions Standards for Hazardous Air Pollutants (NESHAP) that amended the existing NSPS and NESHAP standards for oil and gas facilities and created new NSPS standards for oil and gas production, transmission and distribution facilities with a compliance deadline of January 1, 2015. In 2013 and 2014, the EPA issued updated rules regarding storage tanks and made additional clarifications to these rules. In December 2014, the EPA issued additional amendments to these rules that, among other things, distinguish between multiple flowback stages during completion of hydraulically fractured wells and clarify that storage tanks permanently removed from service are not affected by any requirements.Further, in 2012, seven states sued the EPA to compel the agency to make a determination as to whether standards of performance limiting methane emissions from oil and gas sources are appropriate and, if so, to promulgate performance standards for methane emissions from existing oil and gas sources. In April 2014, the EPA released a set of five white papers analyzing methane emissions from the industry and, based on responses received, announced in January 2015 that it plans to issue a rule governing methane emissions from oil and gas sources in the summer of 2015. The Bureau of Land Management (BLM) is also expected to address methane emissions from oil and gas sources on federal lands in the summer of 2015.

In 2010, the EPA published rules that require monitoring and reporting of greenhouse gas emissions from petroleum and natural gas systems. We, along with other industry groups, filed suit challenging certain provisions of the rules and are engaged in settlement negotiations to amend and correct the rules. We anticipate final resolution to this litigation in the near future.

In addition, in December 2014, the EPA published its proposal to revise downward the ozone national ambient air quality standard to 65-70 parts per billion. A final rule is expected in 2015. We cannot predict the actions that these regulations will require or prohibit, but our business and operations could be subject to increased operating and compliance costs associated with these regulations.

Discharges into Waters

The federal Water Pollution Control Act, or the Clean Water Act (CWA), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as U.S. waters. In April 2014, the EPA and USACE jointly proposed guidance regarding the definition of waters of the United States that substantially expands the waters regulated under the CWA. The placement of dredge or fill material into jurisdictional water or U.S. wetlands is prohibited, except in accordance with the terms of a permit issued by the USACE. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a state agency delegated with EPA's authority. Further, Chesapeake's corporate policy prohibits discharge of produced water to surface waters. Spill prevention, control and countermeasure regulations require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities and construction activities.

The Oil Pollution Act of 1990 (OPA) establishes strict liability for owners and operators of facilities that release oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A ''responsible party'' under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the United States.

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Health and Safety

The Occupational Safety and Health Act (OSHA) and comparable state laws regulate the protection of the health and safety of our employees. The federal Occupational Safety and Health Administration has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. OSHA also requires employee training and maintenance of records, and the OSHA hazard communication standard and EPA community right-to-know regulations under the Emergency Planning and Community Right-to-Know Act of 1986 require that we organize and/or disclose information about hazardous materials used or produced in our operations.

Hydraulic Fracturing

Hydraulic fracturing is typically regulated by state oil and gas regulatory authorities, including specifically the requirement to disclose certain information related to hydraulic fracturing operations. We follow applicable legal requirements for groundwater protection in our operations that are subject to supervision by state and federal regulators (including the BLM on federal acreage). Furthermore, our well construction practices require the installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into aquifers. Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. In December 2014, the governor of New York announced his intention to create a statewide ban on hydraulic fracturing, replacing the current moratorium. Similar bans have been adopted by local governments, although many of these actions are the subject of legal challenges.

In February 2014, the EPA released its final guidance on the use of diesel additives in hydraulic fracturing operations. The EPA is also engaged in a study of the potential impacts of hydraulic fracturing activities on drinking water resources in these states where the EPA is the permitted authority, including Pennsylvania, with a progress report released in late 2012 and a final draft report expected to be released for public comment and peer review in early 2015. In addition, the BLM published a revised draft of proposed rules in July 2013 that would impose new requirements on hydraulic fracturing operations conducted on federal and tribal lands. It is expected that this rule will become final in early 2015 and will focus on chemical disclosure, wellbore integrity and water management. Further, the EPA issued an Advanced Notice of Proposed Rulemaking in May 2014 seeking comments relating to the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and mechanisms for obtaining this information. These actions, in conjunction with other analyses by federal and state agencies to assess the impacts of hydraulic fracturing could spur further action toward federal and/or state legislation and regulation of hydraulic fracturing activities.

Restrictions on hydraulic fracturing could make it prohibitive to conduct our operations, and also reduce the amount of oil, natural gas and NGL that we are ultimately able to produce in commercial quantities from our properties. For further discussion, see Item 1A. Risk Factors - Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Endangered Species

The Endangered Species Act (ESA) restricts activities that may affect areas that contain endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, as a result of a settlement reached in 2011, the U.S. Fish and Wildlife Service is required to make a determination on the listing of more than 250 species as endangered or threatened over the next several years. The designation of previously unidentified endangered or threatened species in areas where we intend to conduct construction activity or the imposition of seasonal restrictions on our construction or operational activities could materially limit or delay our plans.

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Global Warming and Climate Change

At the federal level, EPA regulations require us to establish and report an inventory of greenhouse gas emissions. Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change, such as the President’s Climate Action Plan which calls for reducing methane emissions, could require us to incur additional operating costs and could adversely affect demand for the oil and natural gas that we sell. The EPA announced it will propose new standards of performance limiting methane emissions from oil and gas sources in 2015. The potential increase in our operating costs could include new or increased costs to (i) obtain permits, (ii) operate and maintain our equipment and facilities (through the reduction or elimination of venting and flaring of methane), (iii) install new emission controls on our equipment and facilities, (iv) acquire allowances authorizing our greenhouse gas emissions, (v) pay taxes related to our greenhouse gas emissions and (vi) administer and manage a greenhouse gas emissions program. In addition to these federal actions, various state governments and/or regional agencies may consider enacting new legislation and/or promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations.

Title to Properties

Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and natural gas industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and natural gas industry. Nevertheless, we are involved in title disputes from time to time which result in litigation.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, Chesapeake could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.

Chesapeake maintains a $75 million control of well policy that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. Chesapeake also carries a $460 million comprehensive general liability umbrella policy and a $150 million pollution liability policy. We provide workers' compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to Chesapeake’s working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.

Facilities

Chesapeake owns an office complex in Oklahoma City and owns or leases various field offices in cities or towns in the areas where we conduct our operations.

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Executive Officers

Robert D. Lawler, President, Chief Executive Officer and Director

Robert D. (“Doug”) Lawler, 48, has served as President and Chief Executive Officer since June 2013. Prior to joining Chesapeake, Mr. Lawler served in multiple engineering and leadership positions at Anadarko Petroleum Corporation. His positions at Anadarko included Senior Vice President, International and Deepwater Operations and member of Anadarko’s Executive Committee from July 2012 to May 2013; Vice President, International Operations from December 2011 to July 2012; Vice President, Operations for the Southern and Appalachia Region from March 2009 to July 2012; and Vice President, Corporate Planning from August 2008 to March 2009. Mr. Lawler began his career with Kerr-McGee Corporation in 1988 and joined Anadarko following its acquisition of Kerr-McGee in 2006.

Domenic J. Dell'Osso, Jr., Executive Vice President and Chief Financial Officer

Domenic J. (“Nick”) Dell'Osso, Jr., 38, has served as Executive Vice President and Chief Financial Officer since November 2010. Mr. Dell'Osso served as Vice President - Finance of the Company and Chief Financial Officer of Chesapeake's wholly owned midstream subsidiary, Chesapeake Midstream Development, L.P., from August 2008 to November 2010.

M. Christopher Doyle, Executive Vice President - Operations, Northern Division

M. Christopher Doyle, 42, has served as Executive Vice President - Operations, Northern Division since January 2015 and previously served as Senior Vice President - Operations, Northern Division since August 2013. Prior to joining Chesapeake, Mr. Doyle served for 18 years at Anadarko in various positions of increasing responsibility within operations, finance and planning including international assignments in Algeria and London. His positions at Anadarko included Vice President of Operations from May to August 2013; Director, Corporate Planning from July 2012 to May 2013; General Manager - Appalachian Basin from June 2009 to July 2012; and Manager, Reserves and Planning - Southern Region from January to June 2009.

Douglas J. Jacobson, Executive Vice President - Acquisitions and Divestitures

Douglas J. Jacobson, 61, has served as Executive Vice President - Acquisitions and Divestitures since 2006. He served as Senior Vice President - Acquisitions and Divestitures from 1999 to 2006.

John M. Kapchinske, Executive Vice President - Exploration & Subsurface Technology

John M. Kapchinske, 64, has served as Executive Vice President - Exploration & Subsurface Technology since January 2015 and previously served as Senior Vice President - Exploration & Subsurface Technology since August 2013. Prior to then, he served as Senior Vice President - Geoscience from May 2011 to August 2013. He served as Vice President - Geoscience from 2005 to May 2011 and Geoscience Manager from 2001 to 2004.

Mikell J. Pigott, Executive Vice President - Operations, Southern Division

Mikell J. (“Jason”) Pigott, 41,has served as Executive Vice President - Operations, Southern Division since January 2015 and previously served as Senior Vice President - Operations, Southern Division since August 2013. Before joining Chesapeake, Mr. Pigott served in various positions at Anadarko and focused on all aspects of developing unconventional resources. His positions at Anadarko included General Manager Eagle Ford from June to August 2013; General Manager East Texas and North Louisiana from October 2010 to June 2013; Southern & Appalachia Planning Manager from October 2009 to October 2010; Reservoir Engineering Manager East Texas and North Louisiana from July to October 2009; and Reservoir Engineering Manager Bossier from 2007 to July 2009.

James R. Webb, Executive Vice President - General Counsel and Corporate Secretary

James R. Webb, 47, has served as Executive Vice President - General Counsel and Corporate Secretary since January 2014. Previously, he served as Senior Vice President - Legal and General Counsel since October 2012 and as Corporate Secretary since August 2013. Mr. Webb first joined Chesapeake in May 2012 on a contract basis as Chief Legal Counsel. Prior to joining Chesapeake, Mr. Webb was an attorney with the law firm of McAfee & Taft from 1995 to October 2012.

Michael A. Johnson, Senior Vice President - Accounting, Controller and Chief Accounting Officer

Michael A. Johnson, 49, has served as Senior Vice President - Accounting, Controller and Chief Accounting Officer since 2000. He served as Vice President of Accounting and Financial Reporting from 1998 to 2000 and as Assistant Controller from 1993 to 1998.

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Other Senior Officer

Cathlyn L. Tompkins, Senior Vice President - Information Technology and Chief Information Officer

Cathlyn L. Tompkins, 54, has served as Senior Vice President - Information Technology and Chief Information Officer since 2006. Ms. Tompkins served as Vice President - Information Technology from 2005 to 2006.

Employees

Chesapeake had approximately 5,500 employees as of December 31, 2014 compared to approximately 10,800 employees as of December 31, 2013. As a result of the spin-off of our oilfield services business in June 2014, we experienced a reduction of approximately 5,100 employees.

Glossary of Oil and Gas Terms

The terms defined in this section are used throughout this report.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bboe. One billion barrels of oil equivalent.

Bcf. Billion cubic feet.

Bcfe. Billion cubic feet of natural gas equivalent.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Boe. Barrel of oil equivalent.

Commercial Well; Commercially Productive Well. A well which produces oil, natural gas and/or NGL in sufficient quantities such that proceeds from the sale of this production exceeds production expenses and taxes.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil, natural gas or NGL, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Drilling Carry Obligation. An obligation of one party to pay certain well costs attributable to another party.

Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Exploratory Well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.

Full Cost Pool. The full cost pool consists of all costs associated with property acquisition, exploration and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.

Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which a working interest is owned.

Henry Hub. Henry Hub is the major exchange for pricing natural gas futures on the NYMEX.

Horizontal Drilling. Drilling at angles greater than 70 degrees from vertical.

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Mboe. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet.

Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.

Mmboe. One million barrels of oil equivalent.

Mmbtu. One million btus.

Mmcf. One million cubic feet.

Natural Gas Liquids (NGL). Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ethane, propane, butane, isobutene, pentane, hexane and natural gasoline.

Net Acres or Net Wells. The sum of the fractional working interests owned in gross acres or gross wells.

NYMEX. New York Mercantile Exchange.

Play. A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil, natural gas and NGL reserves.

Present Value or PV-10. When used with respect to oil, natural gas and NGL reserves, present value, or PV-10, means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average oil and natural gas price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

Price Differential. The difference in the price of oil, natural gas or NGL received at the sales point and the NYMEX price.

Productive Well. A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.

Proved Developed Reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved Properties. Properties with proved reserves.

Proved Reserves. Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of a reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole,

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the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves (PUDs). Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless these techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Realized and Unrealized Gains and Losses on Oil, Natural Gas and NGL Derivatives. Realized gains and losses includes the following items:(i) settlements of non-designated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains and losses related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains and losses include the change in fair value of open derivatives scheduled to settle against future period production revenues offset by amounts reclassified as realized gains and losses during the period. Although we no longer designate our derivatives as cash flow hedges for accounting purposes, we believe these definitions are useful to management and investors in determining the effectiveness of our price risk management program.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty Interest. An interest in a oil and natural gas property entitling the owner to a share of oil, natural gas or NGL production free of costs of production.

Seismic. An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formation (3-D seismic provides three-dimensional pictures).

Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.

Standardized Measure of Discounted Future Net Cash Flows. The discounted future net cash flows relating to proved reserves based on the prices used in estimating the proved reserves, year-end costs and statutory tax rates (adjusted for permanent differences) and a 10% annual discount rate.

Tbtu. One trillion British thermal units.

Undeveloped Acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether the acreage contains proved reserves.

Unproved Properties. Properties with no proved reserves.

Volumetric Production Payment (VPP). As we use the term, a volumetric production payment represents a limited-term overriding royalty interest in oil and natural gas reserves that: (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser's only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain the remaining reserves, if any, after the scheduled production volumes have been delivered.

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Working Interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

West Texas Intermediate (WTI). A grade of crude oil used as a benchmark in oil pricing.

ITEM 1A. Risk Factors

Oil, natural gas and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.

Our revenues, operating results, profitability and ability to grow depend primarily upon the prices we receive for our share of the oil, natural gas and NGL we sell. We require substantial expenditures to replace reserves, sustain production and fund our business plans. Lower oil, natural gas and NGL prices can negatively affect the amount of cash available for capital expenditures and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. In addition, lower prices may result in ceiling test write-downs of our oil and natural gas properties. We urge you to read the risk factors below for a more detailed description of each of these risks.

Historically, the markets for oil, natural gas and NGL have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil, natural gas and NGL prices may result from relatively minor changes in the supply of or demand for oil and natural gas, market uncertainty and other factors that are beyond our control, including:

• domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves;

• weather conditions;

• changes in the level of consumer and industrial demand;

• the price and availability of alternative fuels;

• the effectiveness of worldwide conservation measures;

• the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;

• the level and effect of trading in commodity futures markets, including by commodity price speculators and others;

• potential U.S. exports of oil and/or liquefied natural gas;

• the price and level of foreign imports;

• the nature and extent of domestic and foreign governmental regulations and taxes;

• the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;        

• political instability or armed conflict in oil and natural gas producing regions; and

• domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. Oil and natural gas prices declined significantly in the second half of 2014 and have remained low compared to prices in the first half of 2014. Even with oil and natural gas derivatives currently in place to mitigate price risks associated with our future production (43% of our forecasted 2015 oil production and 43% of our forecasted 2015 natural gas production through swaps and three-way collars), our 2015 revenue and results of operations will be adversely affected if commodity prices remain at current levels. Further, a prolonged extension of prices at these levels will reduce the quantities of reserves that may be economically produced and will require us to impair the carrying value of our oil and natural gas assets in 2015.

We expect to write down the carrying value of our oil and natural gas properties in 2015 if commodity prices remain low.

Under the full cost method of accounting for costs related to our oil and natural gas properties, we are required to write down the carrying value of our oil and natural gas assets if capitalized costs exceed the quarterly ceiling limit, which is based on the average of commodity prices on the first day of the month over the trailing 12-month period. Such write-downs can be material. For example, in 2012, we reported a non-cash impairment charge on our oil and natural gas properties of $3.315 billion, primarily resulting from a 10% decrease in trailing 12-month average first-day-

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of-the-month natural gas prices as of September 30, 2012, as compared to June 30, 2012, and the impairment of certain undeveloped leasehold interests. In the second half of 2014, the NYMEX West Texas Intermediate (WTI) index price of oil declined significantly from $105.37 per bbl as of June 30, 2014 to $53.27 per bbl as of December 31, 2014, and the Henry Hub index price of natural gas declined from $4.46 per mcf to $2.89 per mcf over the same period. Oil prices have declined further in 2015. The NYMEX WTI index price of oil on February 20, 2015 was $50.34 per bbl, and the Henry Hub index price of natural gas was $2.95 per mcf. Based on the first-day-of the-month prices we have received over the 11 months ended February 2015, we expect to have a material write-down in the carrying value of our oil and natural gas properties in the first quarter of 2015. Further material write-downs in subsequent quarters will occur if the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters.

Significant capital expenditures are required to replace our reserves and conduct our business.

Our exploration, development and acquisition activities require substantial capital expenditures. We intend to fund our capital expenditures through cash flows from operations and to the extent that is not sufficient, cash on hand and borrowings under our revolving credit facility. Our ability to generate operating cash flow is subject to many of the risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time. Future cash flows from operations are subject to a number of risks and variables, such as the level of production from existing wells, prices of oil, natural gas and NGL, our success in developing and producing new reserves and the other risk factors discussed herein. If we are unable to fund our capital expenditures as planned, we could experience a curtailment of our exploration and production operations, a loss of properties and a decline in our oil, natural gas and NGL reserves.

If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. In addition, approximately 25% of our total estimated proved reserves (by volume) as of December 31, 2014 were undeveloped. Recovery of such reserves will require significant capital expenditures and successful drilling operations. Our reserve estimates at December 31, 2014 reflect an expected decline in the production rate on our producing properties of approximately 30% in 2015 and 20% in 2016. Thus, our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.

The actual quantities of and future net revenues from our proved reserves may differ from our estimates.

This Form 10-K contains estimates of our proved reserves and the estimated future net revenues from our proved reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil, natural gas and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to future revisions.

Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil, natural gas and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

As of December 31, 2014, approximately 25% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $6.3 billion during the five years ending in 2019. You should be aware that the estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC's reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUDs that are not developed within this five-year time frame.

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You should not assume that the present values included in this report represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The price on the date of estimate is calculated as the average oil and natural gas price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2014 present value is based on $94.98 per bbl of oil and $4.35 per mcf of natural gas before price differential adjustments. These prices are substantially higher than current and expected 2015 prices for oil and natural gas. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.

The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. Any changes in consumption by oil, natural gas and NGL purchasers or in governmental regulations or taxation will also affect the actual future net cash flows from our production. In addition, the 10% discount factor which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and natural gas industry in general will affect the appropriateness of the 10% discount factor.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

We have acquired significant amounts of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We have acquired undeveloped properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such undeveloped properties or wells.

Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling and completion operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing, and a decline in commodity prices, among others. The profitability of wells, particularly in certain of the shale plays in which we operate, may be reduced or eliminated as commodity prices decline. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for oil, natural gas and NGL, costs associated with producing oil, natural gas and NGL and our ability to add reserves at an acceptable cost. We rely to a significant extent on seismic data and other advanced technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of undeveloped properties, or drilling a well, whether oil or natural gas is present or may be produced economically. If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.

Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties.

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Our commodity price risk management activities may reduce the prices we receive for our oil, natural gas and NGL sales, require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.

In order to manage our exposure to price volatility in marketing our production, we enter into oil and natural gas price derivative contracts for a portion of our expected production. Commodity price derivatives may limit the prices we actually realize and therefore reduce oil, natural gas and NGL revenues in the future. Our commodity price risk management activities will impact our earnings in various ways, including recognition of certain mark-to-market gains and losses on derivative instruments. The fair value of our oil and natural gas derivative instruments can fluctuate significantly between periods. In addition, our commodity price risk management transactions may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected.    

Derivative transactions involve the risk that counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. During periods of declining commodity prices, such as the second half of 2014 and continuing into 2015, our commodity price derivative asset positions increase, which increases our counterparty exposure. Although the counterparties to our multi-counterparty secured hedging facility are required to secure their obligations to us under certain scenarios, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes.

Most of our oil and natural gas derivative contracts are with the 17 counterparties to our multi-counterparty hedging facility. Our obligations under the facility are secured by oil and natural gas proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times. Under certain circumstances, such as a spike in volatility measures without a corresponding change in commodity prices, or a decline in commodity prices, the collateral value could fall below the coverage designated, and we would be required to post additional reserve collateral to our hedging facility. If we did not have sufficient unencumbered oil and natural gas properties available to cover the shortfall, we would be required to post cash or letters of credit with the counterparties. Future collateral requirements are dependent to a great extent on oil and natural gas prices.

The ultimate outcome of pending legal and governmental proceedings is uncertain, and there are significant costs associated with these matters.

We expect to be obligated to make a substantial additional payment with regard to the redemption at par on May 13, 2013 of our 6.775% Senior Notes due 2019 (2019 Notes). We proceeded with the redemption in reliance on a judgment of the U.S. District Court for the Southern District of New York declaring that the redemption notice we issued was timely and effective for a redemption at par pursuant to the special early redemption provision of the supplemental indenture governing the 2019 Notes. In November 2014, however, the U.S. Court of Appeals for the Second Circuit reversed the District Court’s declaratory judgment and held that the notice was not effective to redeem the notes at par because it was not timely for that purpose. The Court of Appeals remanded the case to the District Court for a determination whether the redemption notice triggered a redemption at the make-whole price specified in the indenture, instead of at par. We accrued a loss contingency of $100 million and estimate the range of potential loss between $100 million and $380 million, plus prejudgment interest of up to 9%. The high end of this range is based upon the indenture trustee’s request in mid-February 2015 that the Court order us to pay noteholders the “make-whole” amount (as defined in the indenture) less the par amount already paid. Our $100 million accrual is based on an estimate of the remedy required to restore the redeemed noteholders and the Company to the economic positions they would have been in had the 2019 Notes not been redeemed.

The Company is defending against claims by royalty owners alleging, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sales of natural gas and NGL. We have agreed to settle, subject to court approval, with a putative class of Oklahoma royalty owners for 2004-2014 claims for $119 million. An agreed-upon settlement with Pennsylvania royalty owners for approximately $12 million is also subject to court approval. Numerous other cases, primarily in Texas, are pending. The resolution of disputes regarding past payments could cause our future obligations to royalty owners to increase and would negatively impact our future results of operations.

In addition, there are ongoing governmental regulatory investigations and inquiries into such matters as our royalty practices and possible antitrust violations, and we are defending shareholder derivative claims against current and former directors and officers. The outcome of any pending litigation or governmental regulatory matter is uncertain and may adversely affect our results of operations. In addition, we have incurred substantial legal expenses in the past

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three years, and such expenses may continue to be significant in 2015 and future years. Further, attention to these matters by members of our senior management has been required, reducing the time they have available to devote to managing the Company's business.

Our level of indebtedness may limit our financial flexibility.

As of December 31, 2014, we had indebtedness of $11.535 billion, and our net indebtedness represented 30% of our total book capitalization, which we define as the sum of total equity and total current and long-term debt less unrestricted cash.

Our level of indebtedness affects our operations in several ways, including the following:

• a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

• we may be at a competitive disadvantage as compared to similar companies that have less debt;

• the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

• additional financing we may need in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants; and

• a lowering of the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings will increase the interest rate we pay on our revolving credit facility and may subject us to additional covenants under that facility.

Our revolving credit facility is unsecured. However, we will be required to provide collateral and the revolving credit facility will become subject to a borrowing base if our credit rating declines to specified levels. In addition, the institution of a borrowing base or, following any such institution, the reduction of the borrowing base due to a decline in commodity prices or otherwise, could require us to repay indebtedness in excess of the borrowing base, or we might need to further secure the lenders with additional collateral. A prolonged decline in commodity prices could increase the risk of a lower credit rating. We may incur additional debt, including secured indebtedness, in order to develop our properties and make future acquisitions. A higher level of indebtedness increases the risk that we may default on our obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. In addition, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default and acceleration of such indebtedness and lead to cross defaults under our other indebtedness. In this circumstance, our ability to refinance indebtedness may be limited.

We may continue to incur cash and noncash charges that would negatively impact our future results of operations and liquidity.

We may take actions in response to the current market environment and as part of our strategic priorities to reduce financial leverage and complexity that will cause us to recognize various cash and noncash charges in 2015 and future years. These charges could include financing extinguishment costs, charges for unused drilling contract terminations or standby fees and charges for unused transportation and gathering capacity. If incurred, these charges would negatively impact our future results of operations and liquidity.

Oil and natural gas drilling and producing operations can be hazardous and may expose us to liabilities.

Oil and natural gas operations are subject to many risks, including well blowouts, cratering and explosions, pipe failures, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, severe weather, natural disasters, groundwater contamination and other environmental hazards and risks. Some of these risks or hazards could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells, loss of equipment or otherwise negatively impacting the projected economic performance of our prospects. If any of these risks occurs, we could sustain substantial losses as a result of:

• injury or loss of life;

• severe damage to or destruction of property, natural resources or equipment;

• pollution or other environmental damage;

• clean-up responsibilities;    

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• regulatory investigations and administrative, civil and criminal penalties; and

• injunctions resulting in limitation or suspension of operations.

For our non-operated properties, we are dependent on the operator for operational and regulatory compliance.

Our midstream and compression operations are subject to all of the risks and operational hazards inherent in transporting oil and natural gas and natural gas compression, including:

• damages to pipelines, facilities and surrounding properties caused by third parties, severe weather, natural disasters, including hurricanes, and acts of terrorism;

• maintenance, repairs, mechanical or structural failures;

• damages to, loss of availability of and delays in gaining access to interconnecting third-party pipeline;

• disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack; and

• leaks of oil or natural gas as a result of the malfunction of equipment or facilities.

A material event such as those described above could expose us to liabilities, monetary penalties or interruptions in our business operations. While we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase.

We are subject to complex laws and regulations relating to environmental protection that can adversely affect the cost, manner and feasibility of doing business, and further regulation in the future could increase costs, impose additional operating restrictions and cause delays.

Our operations and properties are subject to numerous federal, regional, state and local laws and regulations governing the release of pollutants or otherwise relating to environmental protection. These laws and regulations govern the following, among other things:

• conduct of our exploration, drilling, completion, production and midstream activities;

• amounts and types of emissions and discharges;

• generation, management, and disposition of hazardous substances and waste materials;

• reclamation and abandonment of wells and facility sites; and

• remediation of contaminated sites.

In addition, these laws and regulations may impose substantial liabilities for our failure to comply or for any contamination resulting from our operations, including the assessment of administrative, civil and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of the Company’s activities in a particular area. Future environmental laws and regulations imposing further restrictions on the emission of pollutants into the air, discharges into state or U.S. waters and hydraulic fracturing, or the designation of previously unprotected species as threatened or endangered in areas where we operate, may negatively impact our industry. We cannot predict the actions that future regulation will require or prohibit, but our business and operations could be subject to increased operating and compliance costs if certain regulatory proposals are adopted. In addition, such regulations may have an adverse impact on our ability to develop and produce our reserves.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Several states are considering adopting regulations that could impose more stringent permitting, public disclosure, and/or well construction requirements on hydraulic fracturing operations. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. There are also certain governmental reviews either underway or being proposed that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. These studies

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assess, among other things, the risks of groundwater contamination caused by hydraulic fracturing and other exploration and production activities. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate or even ban such activities. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process.

We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and process prohibitions.

Our ability to produce oil, natural gas and NGL economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Development activities require the use of water. For example, the hydraulic fracturing process that we employ to produce commercial quantities of oil and natural gas from many reservoirs requires the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must be obtained from other sources and transported to the drilling site. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of oil and natural gas.

Potential legislative and regulatory actions addressing climate change could significantly impact our industry and the Company, causing increased costs and reduced demand for oil and natural gas.

Various state governments and regional organizations are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations. At the federal level, the EPA has already made findings and issued regulations that require us to establish and report an inventory of greenhouse gas emissions. There were attempts at comprehensive federal legislation establishing a cap and trade program, but this legislation did not pass. The EPA also issued a final rule that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions, beginning in 2011, under the CAA. However, in June 2014, the U.S. Supreme Court, in UARG v. EPA, limited the application of the GHG permitting requirements under the Prevention of Significant Deterioration and Title V permitting programs to sources that would otherwise need permits based on the emission of conventional pollutants. Additional legislative and/or regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the oil and natural gas that we sell. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Even without federal legislation or regulation of greenhouse gas emissions, states may pursue the issue either directly or indirectly. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and gas industry. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for oil and natural gas. Finally, we note that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as higher sea levels, increased frequency and severity of storms, droughts, floods, and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

The taxation of independent producers is subject to change, and federal and state proposals being considered could increase our cost of doing business.

The federal budget proposed in February 2015 includes provisions thatwould potentially increase and accelerate the payment of federal income taxes of independent producers of oil and natural gas. Proposals that would significantly affect us would repeal the expensing of intangible drilling costs, repeal the percentage depletion allowance and increase the amortization period of geological and geophysical expenses. In addition, legislative changes to increase the

29

severance tax rate have been proposed in Ohio and Pennsylvania. These changes, if enacted, will make it more costly for us to explore for and develop our oil and natural gas resources.

Evolving OTC derivatives regulation could impact the effectiveness of our commodity hedging program.

In July 2010, the U.S. Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), which contains measures aimed at migrating over-the-counter (OTC) derivative markets to exchange-traded and cleared markets. Certain companies that use derivatives to hedge commercial risk, referred to as end-users, are permitted to continue to use OTC derivatives under newly adopted regulations. We maintain an active price and basis risk management program related to the oil and natural gas we produce for our own account in order to manage the impact of low commodity prices and to predict future cash flows with greater certainty. We have used the OTC market exclusively for our oil and natural gas derivative contracts, and we also use OTC derivatives to manage risks arising from interest rate exposure. The Dodd-Frank Act and the rules and regulations promulgated thereunder should permit us, as an end user, to continue to utilize OTC derivatives, but could cause increased costs and reduce liquidity in such markets. Such changes could materially reduce our hedging opportunities which would negatively affect our revenues and cash flow during periods of low commodity prices. New position limits rules proposed under the Dodd-Frank Act could also impact our commodity hedging program and could, if enacted as proposed, affect our ability to continue to use the full scope of OTC derivatives to hedge commodity price risk in the manner that we have in the past.

The oil and gas exploration and production industry is very competitive, and some of our competitors have greater financial and other resources than we do.

We face competition in every aspect of our business, including, but not limited to, buying and selling reserves and leases, obtaining goods and services needed to operate our business and marketing oil, natural gas or NGL. Competitors include multinational oil companies, independent production companies and individual producers and operators. Some of our competitors have greater financial and other resources than we do. As a result, these competitors may be able to address these competitive factors more effectively than we can or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.

Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively will be diminished.

A deterioration in general economic, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.

In recent years, concerns over global economic conditions, energy costs, geopolitical issues, the availability and cost of credit, and the U.S. real estate and financial markets have contributed to economic uncertainty and reduced expectations for the global economy. Meanwhile, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries also could adversely affect the global economy. Concerns about global economic growth have had a significant impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

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Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, and explosions of natural gas transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. For the year ended December 31, 2014, we did not operate approximately 10% of our daily production volumes. We have limited ability to influence or control the operation or future development of these non-operated properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator's breach of the applicable agreements or an operator's failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

Our operations may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions.

In certain shale plays, the capacity of gathering systems and transportation pipelines is insufficient to accommodate potential production from existing and new wells. We rely heavily on third parties to meet our oil, natural gas and NGL gathering needs. Capital constraints could limit the construction of new pipelines and gathering systems by third parties, and we may experience delays in building intrastate gathering systems necessary to transport our natural gas to interstate pipelines. Until this new capacity is available, we may experience delays in producing and selling our oil, natural gas and NGL. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell oil, natural gas or NGL production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.

A portion of our oil, natural gas and NGL production in any region may be interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.

Cyber attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners. We have been the subject of cyber attacks on our internal systems and through those of third parties, but these incidents did not have a material adverse impact on our results of operations. Nevertheless, unauthorized access to our seismic data, reserves information or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. Further, as cyber attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber attacks.

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An interruption in operations at our headquarters could adversely affect our business.

Our headquarters are located in Oklahoma City, Oklahoma, an area that experiences severe weather events, including tornadoes and earthquakes. Our information systems and administrative and management processes are primarily provided to our various drilling projects throughout the United States from this location, which could be disrupted if a catastrophic event, such as a tornado, power outage or act of terror, destroyed or severely damaged our headquarters. Any such catastrophic event could harm our ability to conduct normal operations and could adversely affect our business.

ITEM 1B. Unresolved Staff Comments

Not applicable.

ITEM 2. Properties

Information regarding our properties is included in Item 1 and in the Supplementary Information included in Item 8 of Part II of this report.

ITEM 3. Legal Proceedings

Litigation and Regulatory Proceedings

The Company is involved in a number of litigation and regulatory proceedings (including those described below). Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is currently indeterminate. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for information regarding our estimation and provision for potential losses related to litigation and regulatory proceedings.

July 2008 Common Stock Offering Litigation. On February 25, 2009, a putative class action was filed in the U.S. District Court for the Southern District of New York against the Company and certain of its officers and directors along with certain underwriters of the Company’s July 2008 common stock offering. The plaintiff filed an amended complaint on September 11, 2009 alleging that the registration statement for the offering contained material misstatements and omissions and seeking damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified amount and rescission. The action was transferred to the U.S. District Court for the Western District of Oklahoma on October 13, 2009. Chesapeake and the officer and director defendants moved for summary judgment on grounds of loss causation and materiality on December 28, 2011, and the motion was granted as to all claims as a matter of law on March 29, 2013. On appeal, the U.S. Court of Appeals for the Tenth Circuit affirmed the dismissal on August 8, 2014 and denied the plaintiff’s petition for rehearing on November 12, 2014.

Shareholder Derivative Litigation. A derivative action relating to the July 2008 offering was filed in the U.S. District Court for the Western District of Oklahoma on September 6, 2011. The case was thereafter stayed by stipulation between the parties, and on November 20, 2014, the parties entered a stipulation to have the case voluntarily dismissed. On January 16, 2015, pursuant to Court order, the Company provided notice to shareholders of the voluntary dismissal and allowed eligible shareholders to intervene.

A federal consolidated derivative action and an Oklahoma state court derivative action have been stayed since 2012 pending resolution of a related, previously reported putative federal securities class action. The shareholder derivative actions allege breaches of fiduciary duty, among other things, related to the former CEO’s personal financial practices and purported conflicts of interest, and the Company’s accounting for VPPs. With the dismissal of the federal securities class action now affirmed, the parties have stipulated to continue the stay of the Oklahoma state court derivative action while the plaintiffs pursue their claims in the federal consolidated derivative action. The plaintiffs filed a consolidated derivative complaint on October 31, 2014 and an amended consolidated derivative complaint on February 12, 2015. Chesapeake filed its motion to dismiss on February 23, 2015.

Regulatory Proceedings. The Company has received, from the U.S. Department of Justice (DOJ) and certain state governmental agencies and authorities, subpoenas and demands for documents, information and testimony in connection with investigations into possible violations of federal and state antitrust laws relating to our purchase and lease of oil and gas rights in various states. The Company also has received DOJ and state subpoenas seeking information on the Company’s royalty payment practices. Chesapeake has engaged in discussions with the DOJ and state agency representatives and continues to respond to such subpoenas and demands.

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On March 5, 2014, the Attorney General of the State of Michigan filed a criminal complaint against Chesapeake in Michigan state court alleging misdemeanor antitrust violations and attempted antitrust violations under state law arising out of the Company’s leasing activities in Michigan during 2010. On July 9, 2014, following a preliminary hearing on the complaint, as amended, the 89^th District Court for Cheboygan County, Michigan ruled that one count alleging a bid-rigging conspiracy between Chesapeake and Encana Oil & Gas USA, Inc. regarding the October 2010 state lease auction would proceed to trial and dismissed claims alleging a second antitrust violation and an attempted antitrust violation. A trial date of April 15, 2015 has been set for this case. The Michigan Attorney General filed a second criminal complaint against Chesapeake in the same court on June 5, 2014 which, as amended, alleges that Chesapeake’s conduct in canceling lease offers to Michigan landowners in 2010 violated the state’s criminal enterprises and false pretenses felony statutes. On September 9, 2014, following a preliminary hearing, the Court ruled that all charges in the complaint would be tried. No trial date has been set for this matter.

Redemption of 2019 Notes. See Chesapeake Senior Notes and Contingent Convertible Senior Notes in Note 3 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for a description of pending litigation regarding our redemption in May 2013 of our 2019 Notes.

Business Operations. Chesapeake is involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. With regard to contract actions, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their oil and natural gas interests and pay acreage bonus payments, damages based on breach of contract and/or, in certain cases, punitive damages based on alleged fraud. The Company has successfully defended a number of these failure-to-close cases in various courts, has settled and resolved other such cases and disputes and believes that its remaining loss exposure for these claims will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. In addition, as described above, the Michigan Attorney General has commenced a criminal proceeding against us based on lease offers to Michigan landowners in 2010.

Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits against us allege, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL. The Company has resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. We are currently defending lawsuits seeking damages with respect to royalty underpayment in various states, including cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The Company also has received DOJ and state subpoenas seeking information on the Company’s royalty payment practices.

Plaintiffs have varying royalty provisions in their respective leases and oil and gas law varies from state to state. Royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations, an issue in a putative class action filed in November 2010 in the District Court of Beaver County, Oklahoma on behalf of Oklahoma royalty owners asserting claims dating back to 2004. In July 2014, this case was remanded to the trial court for further proceedings following the reversal on appeal of certification of a statewide class. We and the named plaintiff participated in mediation concerning the claims asserted in the putative class action litigation and have negotiated a settlement requiring the Company to pay $119 million cash to compensate the putative settlement class for alleged past royalty underpayments in exchange for the release of claims for the ten-year period ended December 31, 2014. The plaintiff filed a motion for preliminary approval of the settlement on January 2, 2015. The Company has accrued a loss contingency for the settlement amount in the 2014 consolidated statement of operations. A fairness hearing on the settlement has been scheduled for April 17, 2015. Although Chesapeake believes that its royalty calculation and payment methodologies are appropriate under Oklahoma oil and gas law and denies that it committed any acts or omissions giving rise to any liability, it also believes that settlement is in the best interest of the Company considering the questions of law and fact involved and the uncertainty of continued litigation. There can be no assurance the court will approve the settlement, however, and the final resolution of the Oklahoma royalty claims could differ from the amount accrued.

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Environmental Proceedings

Our subsidiary Chesapeake Appalachia, LLC (CALLC) is engaged in discussions with the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers and the Pennsylvania Department of Environmental Protection (PADEP) regarding potential violations of the permitting requirements of the federal Clean Water Act, the Pennsylvania Clean Streams Law and the Pennsylvania Dam Safety and Encroachments Act in connection with the placement of dredge and fill material during construction of certain sites in Pennsylvania. CALLC identified the potential violations in connection with an internal review of its facilities siting and construction processes and voluntarily reported them to the regulatory agencies. Resolution of the matter may result in monetary sanctions of more than $100,000.

CALLC is also engaged in discussions with the PADEP regarding potential violations of the Pennsylvania Clean Streams Law as a result of pad subsidence allegedly causing material to enter a nearby stream. Since the incident, CALLC and the PADEP have been working to remediate the site and bring it into compliance. Resolution of these matters may result in monetary sanctions of more than $100,000.

ITEM 4. Mine Safety Disclosures

Not applicable.

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PART II

ITEM 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Price Range of Common Stock and Dividends

Our common stock trades on the New York Stock Exchange under the symbol "CHK". The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock as reported by the New York Stock Exchange and the amount of cash dividends declared per share:

	Common Stock				Dividend
	High		Low		Declared
Year Ended December 31, 2014:
Fourth Quarter	$	24.43	$	16.41	$	0.0875
Third Quarter	$	29.92	$	22.77	$	0.0875
Second Quarter	$	31.49	$	25.66	$	0.0875
First Quarter	$	27.54	$	23.92	$	0.0875
Year Ended December 31, 2013:
Fourth Quarter	$	29.06	$	25.06	$	0.0875
Third Quarter	$	27.46	$	20.30	$	0.0875
Second Quarter	$	22.86	$	18.21	$	0.0875
First Quarter	$	22.97	$	16.32	$	0.0875

As of February 9, 2015, there were approximately 2,100 holders of record of our common stock and approximately 325,000 beneficial owners.

Although we expect to continue to pay dividends on our common stock, the payment of future cash dividends is subject to the discretion of our Board of Directors and will depend upon, among other things, our financial condition, our funds from operations, the level of our capital and development expenditures, our future business prospects, contractual restrictions and other factors considered relevant by the Board of Directors.

In addition, our revolving credit facility contains a restriction on our ability to declare and pay cash dividends on our common or preferred stock if an event of default has occurred. The certificates of designation for our preferred stock prohibit payment of cash dividends on our common stock unless we have declared and paid (or set apart for payment) full accumulated dividends on the preferred stock.

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Repurchases of Equity Securities

The following table presents information about repurchases of our common stock during the quarter ended December 31, 2014:

Period	Total Number of Shares Purchased(a)	Average Price Paid Per Share(a)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs
					($ in millions)
October 1, 2014 through October 31, 2014	9,294	$	22.13	—	$	—
November 1, 2014 through November 30, 2014	9,453	$	22.00	—	—
December 1, 2014 through December 31, 2014	39,626	$	18.53	—	1,000		(b)
Total	58,373	$	19.67	—	$	1,000

___________________________________________

(a) Reflects the surrender to the Company of shares of common stock to pay withholding taxes in connection with the vesting of employee restricted stock. Also includes shares of common stock purchased on behalf of Chesapeake’s deferred compensation plan related to participant deferrals and Company matching contributions.

(b) On December 22, 2014, the Company issued a press release announcing that its Board of Directors has authorized the repurchase of up to $1 billion in value of its common stock from time to time. The repurchase program does not have an expiration date, and no repurchases had been made under the program as of December 31, 2014.

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ITEM 6. Selected Financial Data

The following table sets forth selected consolidated financial data of Chesapeake for the years ended December 31, 2014, 2013, 2012, 2011 and 2010. The data are derived from our audited consolidated financial statements, revised to reflect the reclassification of certain items to conform to current period presentation. The table should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements, including the notes thereto, appearing in Items 7 and 8, respectively, of this report.

	Years Ended December 31,
	2014			2013			2012			2011			2010
	($ in millions, except per share data)
REVENUES:
Oil, natural gas and NGL	$	8,180		$	7,052		$	6,278		$	6,024		$	5,647
Marketing, gathering and compression	12,225			9,559			5,431			5,090			3,479
Oilfield services	546			895			607			521			240
Total Revenues	20,951			17,506			12,316			11,635			9,366
OPERATING EXPENSES:
Oil, natural gas and NGL production	1,208			1,159			1,304			1,073			893
Production taxes	232			229			188			192			157
Marketing, gathering and compression	12,236			9,461			5,312			4,967			3,352
Oilfield services	431			736			465			402			208
General and administrative	322			457			535			548			453
Restructuring and other termination costs	7			248			7			—			—
Provision for legal contingencies	234			—			—			—			—
Oil, natural gas and NGL depreciation, depletion and amortization	2,683			2,589			2,507			1,632			1,394
Depreciation and amortization of other assets	232			314			304			291			220
Impairment of oil and natural gas properties	—			—			3,315			—			—
Impairments of fixed assets and other	88			546			340			46			21
Net gains on sales of fixed assets	(199		)	(302		)	(267		)	(437		)	(137		)
Total Operating Expenses	17,474			15,437			14,010			8,714			6,561
INCOME (LOSS) FROM OPERATIONS	3,477			2,069			(1,694		)	2,921			2,805
OTHER INCOME (EXPENSE):
Interest expense	(89		)	(227		)	(77		)	(44		)	(19		)
Earnings (losses) on investments	(80		)	(226		)	(103		)	156			227
Net gain (loss) on sales of investments	67			(7		)	1,092			—			(129		)
Losses on purchases of debt	(197		)	(193		)	(200		)	(176		)	(16		)
Other income	22			26			8			23			16
Total Other Income (Expense)	(277		)	(627		)	720			(41		)	79
INCOME (LOSS) BEFORE INCOME TAXES	3,200			1,442			(974		)	2,880			2,884
INCOME TAX EXPENSE (BENEFIT):
Current income taxes	47			22			47			13			—
Deferred income taxes	1,097			526			(427		)	1,110			1,110
Total Income Tax Expense (Benefit)	1,144			548			(380		)	1,123			1,110
NET INCOME (LOSS)	2,056			894			(594		)	1,757			1,774
Net income attributable to noncontrolling interests	(139		)	(170		)	(175		)	(15		)	—
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	1,917			724			(769		)	1,742			1,774
Preferred stock dividends	(171		)	(171		)	(171		)	(172		)	(111		)
Premium on purchase of preferred shares of a subsidiary	(447		)	(69		)	—			—			—
Earnings allocated to participating securities	(26		)	(10		)	—			—			—
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	1,273		$	474		$	(940	)	$	1,570		$	1,663

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	Years Ended December 31,
	2014			2013			2012			2011			2010
	($ in millions, except per share data)
STATEMENT OF OPERATIONS DATA (continued):
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	1.93		$	0.73		$	(1.46	)	$	2.47		$	2.63
Diluted	$	1.87		$	0.73		$	(1.46	)	$	2.32		$	2.51
CASH DIVIDEND DECLARED PER COMMON SHARE	$	0.35		$	0.35		$	0.35		$	0.3375		$	0.30
CASH FLOW DATA:
Cash provided by operating activities	$	4,634		$	4,614		$	2,837		$	5,903		$	5,117
Cash provided by (used in) investing activities	$	454		$	(2,967	)	$	(4,984	)	$	(5,812	)	$	(8,503	)
Cash provided by (used in) financing activities	$	(1,817	)	$	(1,097	)	$	2,083		$	158		$	3,181
BALANCE SHEET DATA (AT END OF PERIOD):
Total assets	$	40,751		$	41,782		$	41,611		$	41,835		$	37,179
Long-term debt, net of current maturities	$	11,154		$	12,886		$	12,157		$	10,626		$	12,640
Total equity	$	18,205		$	18,140		$	17,896		$	17,961		$	15,264

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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Financial Data

The following table sets forth certain information regarding our production volumes, oil, natural gas and NGL sales, average sales prices received, and other operating income and expenses for the periods indicated:

	Years Ended December 31,
	2014			2013			2012
Net Production:
Oil (mmbbl)	42.3			41.1			31.3
Natural gas (bcf)	1,095.0			1,094.6			1,128.8
NGL (mmbbl)	33.1			20.9			17.6
Oil equivalent (mmboe)(a)	257.8			244.4			237.0
Oil, Natural Gas and NGL Sales ($ in millions):
Oil sales	$	3,682		$	3,911		$	2,829
Oil derivatives - realized gains (losses)(b)	(185		)	(108		)	39
Oil derivatives - unrealized gains (losses)(b)	859			280			857
Total oil sales	4,356			4,083			3,725
Natural gas sales	2,777			2,430			2,004
Natural gas derivatives - realized gains (losses)(b)	(191		)	9			328
Natural gas derivatives - unrealized gains (losses)(b)	535			(52		)	(331		)
Total natural gas sales	3,121			2,387			2,001
NGL sales	703			582			526
NGL derivatives - realized gains (losses)(b)	—			—			(9		)
NGL derivatives - unrealized gains (losses)(b)	—			—			35
Total NGL sales	703			582			552
Total oil, natural gas and NGL sales	$	8,180		$	7,052		$	6,278
Average Sales Price (excluding gains (losses) on derivatives):
Oil ($ per bbl)	$	87.13		$	95.17		$	90.49
Natural gas ($ per mcf)	$	2.54		$	2.22		$	1.77
NGL ($ per bbl)	$	21.27		$	27.87		$	29.89
Oil equivalent ($ per boe)	$	27.78		$	28.33		$	22.61
Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)	$	82.76		$	92.53		$	91.74
Natural gas ($ per mcf)	$	2.36		$	2.23		$	2.07
NGL ($ per bbl)	$	21.27		$	27.87		$	29.37
Oil equivalent ($ per boe)	$	26.32		$	27.92		$	24.12

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	Years Ended December 31,
	2014			2013			2012
Other Operating Income(c) ($ in millions):
Marketing, gathering and compression net margin	$	(11	)	$	98		$	119
Oilfield services net margin	$	115		$	159		$	142
Expenses ($ per boe):
Oil, natural gas and NGL production	$	4.69		$	4.74		$	5.50
Production taxes	$	0.90		$	0.94		$	0.79
General and administrative(d)	$	1.25		$	1.86		$	2.26
Oil, natural gas and NGL depreciation, depletion and amortization	$	10.41		$	10.59		$	10.58
Depreciation and amortization of other assets	$	0.90		$	1.28		$	1.28
Interest expense(e)	$	0.63		$	0.65		$	0.35
Interest Expense ($ in millions):
Interest expense	$	173		$	169		$	84
Interest rate derivatives – realized (gains) losses(f)	(12		)	(9		)	(1		)
Interest rate derivatives – unrealized (gains) losses(f)	(72		)	67			(6		)
Total interest expense	$	89		$	227		$	77

___________________________________________

(a) Oil equivalent is based on six mcf of natural gas to one barrel of oil or one barrel of NGL. This ratio reflects an energy content equivalency and not a price or revenue equivalency.

(b) Realized gains and losses include the following items: (i) settlements of undesignated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains and losses related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains and losses include the change in fair value of open derivatives scheduled to settle against future period production revenues offset by amounts reclassified as realized gains and losses during the period.

(c) Includes revenue and operating costs. See Depreciation and Amortization of Other Assets under Results of Operations for details of the depreciation and amortization associated with our marketing, gathering and compression and former oilfield services operating segments.

(d) Includes share-based compensation but excludes restructuring and other termination costs.

(e) Includes the effects of realized (gains) losses from interest rate derivatives, excludes the effects of unrealized (gains) losses from interest rate derivatives, and is shown net of amounts capitalized.

(f) Realized (gains) losses include settlements related to the current period interest accrual and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item. Unrealized (gains) losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period.

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Overview

For an overview of our business and strategy, please see Our Business and Business Strategy in Item 1 of this report.

Operating Results

We own interests in approximately 45,100 oil and natural gas wells and produced an average of approximately 729 mboe per day in the 2014 fourth quarter, net to our interest. Our 2014 production of 258 mmboe consisted of 42 mmbbls of oil (16% on an oil equivalent basis), 1.1 tcf of natural gas (71% on an oil equivalent basis), and 33 mmbbls of NGL (13% on an oil equivalent basis). Liquids represented 29% of total production for 2014, up from 25% in 2013. Our daily production for 2014 averaged approximately 706 mboe, an increase of 5% from 2013, or 9% when adjusted for asset sales. Compared to 2013, average daily oil production increased by 3%, or approximately 3 mbbls per day; average daily natural gas production remained the same year over year, primarily as a result of asset sales; and average daily NGL production increased by 58%, or approximately 33 mbbls per day. Our oil, natural gas and NGL revenues (excluding gains or losses on oil and natural gas derivatives) increased approximately $239 million to $7.2 billion in 2014 compared to $6.9 billion in 2013, primarily due to an increase in oil and NGL volumes sold and an increase in the price received for our natural gas sold, partially offset by a decrease in the prices received for our oil and NGL sold. See Results of Operations below for additional details.

Capital Expenditures

Our drilling and completion capital expenditures during 2014 were approximately $4.5 billion and capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other plant, property and equipment were approximately $669 million, for a total of approximately $5.1 billion compared to the Company’s forecasted range of $5.0 to $5.4 billion. The level of drilling and completion expenditures represented a decrease of approximately $1.0 billion, or 18%, compared to 2013. In 2014, we operated an average of 64 rigs, a decrease of seven rigs compared to 2013. In addition to a lower rig count, drilling and completion costs were lower in 2014 than in 2013 as a result of improving capital efficiencies. The level of capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other plant, property and equipment decreased approximately $562 million, or 46%, compared to 2013. The reduction is primarily the result of a reduction in costs for construction of our corporate headquarters and field offices and for our former oilfield services business which was spun off in June 2014. Capital expenditures were also lower in 2014 because we sold substantially all of our midstream business and most of our gathering assets in 2012 and 2013.

In addition, we invested approximately $499 million and $240 million in 2014 and 2013, respectively, to purchase rigs and compressors previously sold under long-term lease arrangements to facilitate asset sales and the spin-off of our oilfield services business. In 2014, we also invested approximately $450 million in our Powder River Basin property exchange. Both the spin-off and exchange are discussed below under 2014 Strategic Transactions. Our capitalized interest was approximately $637 million and $816 million in 2014 and 2013, respectively. Including these items, total capital investments were approximately $6.7 billion in 2014 compared to $7.6 billion for 2013.

Based on planned activity levels for 2015, we project that drilling and completion, net leasehold, geological and geophysical and other plant, property and equipment capital expenditures will be $4.0 to $4.5 billion, inclusive of capitalized interest. This decrease from 2014 is primarily driven by substantially lower oil and natural gas prices forecasted in 2015 compared to 2014. See Liquidity and Capital Resources for additional information on how we plan to fund our capital budget.

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2014 Strategic Transactions

We continue to pursue opportunities to high-grade our portfolio so that we can focus on assets that are best aligned with our strategy of profitable growth from captured resources. Significant strategic transactions completed in 2014 are described below.

Sale of Southern Marcellus and Utica Shale Assets

We sold certain assets in the southern Marcellus Shale and a portion of the eastern Utica Shale to a subsidiary of Southwestern Energy Company for aggregate net proceeds of approximately $4.975 billion in December 2014. We sold approximately 413,000 net acres and approximately 1,500 wells in northern West Virginia and southern Pennsylvania, of which 435 wells are in the Marcellus or Utica formations, along with related gathering assets, and property, plant and equipment. Average net daily production from these properties was approximately 57,000 boe in mid-December 2014. As of December 31, 2013, net proved reserves associated with these properties were approximately 221 mmboe, or 8% of total proved reserves.

Spin-Off of Oilfield Services Business

We completed the spin-off of our oilfield services business, which we previously conducted through our indirect, wholly owned subsidiary Chesapeake Oilfield Operating, L.L.C. (COO), into an independent, publicly traded company called Seventy Seven Energy Inc. (SSE). Following the close of business on June 30, 2014, we distributed to Chesapeake shareholders one share of common stock of SSE and cash in lieu of fractional shares for every 14 shares of Chesapeake common stock outstanding on June 19, 2014, the record date for the distribution. Prior to the spin-off, SSE’s services included drilling, hydraulic fracturing, oilfield rentals, rig relocation, and water transport and disposal. We believe the benefits of the spin-off include:

• enhancing the flexibility of the management team of Chesapeake and SSE to make strategic and operational decisions that are in the best interests of their respective businesses;

• optimizing the allocation of capital and corporate resources in a manner that focuses on achieving the strategic priorities of each company;

• enhancing SSE’s ability to attract E&P customers other than Chesapeake;

• enhancing SSE’s reputation as an independent provider of diversified oilfield services;

• enhancing the ability of each company to more efficiently attract and deploy capital; and

• enhancing the ability of Chesapeake and SSE to attract employees with appropriate skill sets, to incentivize their key employees with equity-based compensation that is aligned with the performance of their respective operations, and to retain key employees for the long term.

As a result of the spin-off, we have experienced the following effects:

• a reduction of approximately 5,100 employees;

• a reduction of $1.572 billion in aggregate principal amount of long-term debt as of June 30, 2014, consisting of $650 million of 6.625% Senior Notes due 2019, $500 million of 6.5% Senior Notes due 2022, a $400 million secured term loan and $22 million outstanding under SSE’s new revolving credit facility; and

• the elimination of our oilfield services segment.

Powder River Basin Property Exchange

We exchanged interests in approximately 440,000 gross acres in the Powder River Basin in southeastern Wyoming with RKI Exploration & Production, LLC (RKI). Under the agreement, we conveyed to RKI approximately 137,000 net acres and our interest in 67 gross wells with an average working interest of approximately 22% in the northern portion of the Powder River Basin, where RKI is currently designated operator. In exchange, RKI conveyed to us approximately 203,000 net acres and its interest in 186 gross wells with an average working interest of 48% in the southern portion of the Powder River Basin, where we are currently designated operator. In addition to the exchange, we paid RKI approximately $450 million in cash.

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Repurchase of CHK Utica Preferred Shares

We repurchased all of the outstanding preferred shares of our subsidiary CHK Utica, L.L.C. (CHK Utica) from third-party preferred shareholders for approximately $1.25 billion, or approximately $1,189 per share including accrued dividends. The transaction eliminates approximately $75 million in annual cash dividend payments to third-party preferred shareholders and also eliminates our obligation to drill and complete a minimum number of wells within a specified period for the benefit of CHK Utica. See Note 8 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of this repurchase.

Divestitures of Noncore Oil and Natural Gas Properties

We sold noncore leasehold interests in the Marcellus Shale to a subsidiary of Rice Energy Inc. for proceeds of $233 million. We also sold noncore leasehold interests, producing properties and 61 wellhead compressor units in South Texas to Hilcorp Energy Company for proceeds of $133 million. Operating obligations related to VPP #5 were also transferred. In addition, we sold noncore leasehold interests and producing properties in East Texas and Louisiana for proceeds of $63 million. Operating obligations related to VPP #6 were also transferred. See Volumetric Production Payments in Note 12 of the notes to our consolidated financial statements included in Item 8 of Part II of this report.

Other Asset Sales

Midstream Compression Assets. We sold 102 compressors and related equipment to Access Midstream Partners, L.P. for approximately $159 million, and we sold 499 compressors and related equipment to Exterran Partners, L.P. for approximately $495 million.

Investments. We received $209 million of net proceeds from the sale of our common equity ownership in Chaparral Energy, Inc. We also sold an equity investment in a natural gas trading and management firm for cash proceeds of $30 million.

Buildings and Land. We sold buildings and land, located primarily in the Oklahoma City and Fort Worth areas, for proceeds of approximately $205 million. These assets were deemed noncore to our operations.

Crude Oil Hauling Assets. We sold our crude oil hauling assets for approximately $44 million.

Share Repurchase Authorization

On December 22, 2014, our Board of Directors authorized the repurchase of up to $1 billion in value of our common stock from time to time. The repurchase authorization permits us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, compliance with our debt arrangements and other appropriate factors. Acquisitions under this repurchase authorization are to be made through open market or privately negotiated transactions and may be made pursuant to plans entered into in accordance with Rule 10b5-1 of the Securities Exchange Act of 1934. This repurchase authorization does not obligate us to acquire any particular amount of common stock and may be modified, extended, suspended or discontinued at any time without prior notice. No shares had been repurchased as of February 27, 2015 and no assurance can be given that any particular amount of common stock will be repurchased.

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Liquidity and Capital Resources

Liquidity Overview

Based on budgeted capital expenditures, our forecasted operating cash flow and projected levels of indebtedness, we believe we have sufficient liquidity to fund our current and long-term operations, including our contractual cash commitments to third parties pursuant to various agreements described in Contractual Obligations and Off-Balance Sheet Arrangements below.

As of December 31, 2014, we had approximately $8.093 billion in cash availability (defined as unrestricted cash on hand plus borrowing capacity under our revolving credit facility) compared to $4.909 billion as of December 31, 2013, and we had working capital of approximately $1.373 billion compared to negative working capital of approximately $1.859 billion as of December 31, 2013. The increase in cash availability and working capital from December 31, 2013 to December 31, 2014 is primarily the result of the approximate $4.975 billion of proceeds we received in the 2014 fourth quarter from the sale of certain assets in the southern Marcellus Shale and a portion of the eastern Utica Shale. Working capital deficits have historically existed primarily due to timing differences in the initial capital outlay and the revenue stream we received over time from investing in oil and natural gas properties.

We generate cash needed to fund capital expenditures, debt obligations, dividend payments and other financial commitments primarily from our operating activities. In addition, we have supplemented our needs, enhanced our liquidity and reduced our financial leverage and complexity through divestitures of oil and gas properties, divestitures of other assets and various other transactions discussed above in 2014 Strategic Transactions.

As a result of substantially lower oil and natural gas prices forecasted in 2015 compared to 2014, we plan to operate 35 - 45 rigs in 2015, a decrease from an average of 64 rigs in 2014, and our lowest operated rig activity level since 2004. With a lower rig count, we project that our drilling and completion, net leasehold, geological and geophysical and other capital expenditures will be $4.0 to $4.5 billion in 2015, inclusive of capitalized interest, which represents an approximate 25% reduction from 2014 levels. With this level of activity, expected 2015 prices and our current derivative contracts in place, we anticipate we may need to fund a portion of our planned capital expenditures with cash on hand. We currently have downside price protection on approximately 43% of our projected 2015 oil production at an average price of $93.39 per bbl, of which 11% is hedged under collar arrangements with upside to an average NYMEX price of $90 per bbl and exposure below an average NYMEX price of $80 per bbl. We also have downside price protection on approximately 43% of our projected 2015 natural gas production at an average price of $4.21 per mcf, of which 20% is hedged under collar arrangements with upside to an average NYMEX price of $4.29 per mcf and exposure below an average NYMEX price of $3.37 per mcf.

Management continues to review operation plans for 2015 and beyond, which could result in changes to projected capital expenditures and revenues from sales of oil, natural gas and NGL. We closely monitor the amounts and timing of our sources and uses of funds, particularly as they affect our ability to maintain compliance with the financial covenants of our revolving credit facility. We believe we have adequate flexibility to respond to negative developments if needed; however, adjustments in discretionary capital expenditures could entail penalty payments for certain of our oilfield services and midstream commitments. Our current budget anticipates having enough cash on hand to remain undrawn on our revolving credit facility as of December 31, 2015.

2014 Refinancings

In 2014, we completed refinancing transactions designed to reduce our interest and other costs and lengthen the maturity profile of our outstanding indebtedness. In December 2014, we entered into a new five-year $4.0 billion senior unsecured revolving credit facility to use for general corporate purposes. The new credit facility replaced our then-existing $4.0 billion senior secured revolving credit facility that was scheduled to mature in December 2015. The aggregate commitments under the new facility may be increased up to an additional $1.0 billion, and the December 2019 maturity date may be extended for two one-year periods at our request and with the consent of the participating lenders. As described below under Revolving Credit Facility, the new unsecured facility has investment grade-like terms which allowed us to release nearly $6.0 billion of proved reserve-based collateral.

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In April 2014, we issued $3.0 billion in aggregate principal amount of senior notes at par. The offering included two series of notes: $1.5 billion in aggregate principal amount of Floating Rate Senior Notes due 2019 and $1.5 billion in aggregate principal amount of 4.875% Senior Notes due 2022. We used a portion of the net proceeds of $2.966 billion to repay the borrowings under, and terminate, our $2.0 billion term loan credit facility. We used the remaining proceeds along with cash on hand to redeem the $97 million principal amount of 6.875% Senior Notes due 2018 and to purchase and redeem the $1.265 billion principal amount of the 9.5% Senior Notes due 2015 for $1.454 billion.

Sources of Funds

The following table presents the sources of our cash and cash equivalents for each of the years ended December 31, 2014, 2013 and 2012. See 2014 Strategic Transactions above and Notes 12, 14 and 16 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of sales of oil and natural gas assets, investments and other assets, respectively.

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
Cash Provided by Operating Activities	$	4,634	$	4,614	$	2,837
Sales of Oil and Natural Gas Assets:
Southern Marcellus and Utica	4,970		—		—
South Texas	110		—		—
East Texas and Louisiana	58		—		—
Marcellus	231		490		—
Eagle Ford	—		636		—
Haynesville	—		304		—
SIPC (Mississippian Lime joint venture)	—		1,025		—
Permian Basin	—		—		3,130
Texoma	—		—		572
Chitwood Knox	—		—		540
Volumetric production payments	—		—		744
Joint venture leasehold	33		58		272
Other oil and natural gas properties	411		954		626
Total Sales of Oil and Natural Gas Assets	5,813		3,467		5,884
Sales of Other Assets:
Sale of compressors to Exterran	495		—		—
Sale of compressors to ACMP	159		—		—
Sale of Chesapeake Midstream Operating, L.L.C.	—		—		2,160
Sale of Mid-America Midstream Gas Services, L.L.C.	—		306		—
Sale of Granite Wash Midstream Gas Services, L.L.C.	—		252		—
Sales of other property and equipment	349		364		332
Total Sales of Other Assets	1,003		922		2,492
Other Sources of Cash and Cash Equivalents:
Proceeds from sales of investments	239		115		2,000
Proceeds from long-term debt, net	2,966		2,274		6,985
Proceeds from oilfield services long-term debt, net	888		—		—
Sale of preferred interest and ORRI in CHK C-T	—		—		1,250
Other	37		187		84
Total Other Sources of Cash and Cash Equivalents	4,130		2,576		10,319
Total Sources of Cash and Cash Equivalents	$	15,580	$	11,579	$	21,532

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Cash provided by operating activities was $4.634 billion in 2014 compared to $4.614 billion in 2013 and $2.837 billion in 2012. The increase in cash provided by operating activities from 2013 to 2014 is primarily the result of higher production volumes and decreases in certain of our operating expenses, partially offset by lower realized prices for the oil and NGL we sold. The increase in cash provided by operating activities from 2012 to 2013 is primarily the result of an increase in prices received for oil, natural gas and NGL sold, an increase in oil and NGL volumes sold and decreases in certain of our operating expenses. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items such as depreciation, depletion and amortization, impairments of other assets, deferred income taxes and mark-to-market changes in our derivative instruments. See the discussion below under Results of Operations.

The following table reflects the proceeds received from issuances of debt in 2014, 2013 and 2012. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.

	Years Ended December 31,
	2014				2013				2012
	Principal Amount of Debt Issued		Net Proceeds		Principal Amount of Debt Issued		Net Proceeds		Principal Amount of Debt Issued		Net Proceeds
	($ in millions)
Senior notes(a)	$	3,500	$	3,460	$	2,300	$	2,274	$	1,300	$	1,263
Term loans(a)	400		394		—		—		6,000		5,722
Total	$	3,900	$	3,854	$	2,300	$	2,274	$	7,300	$	6,985

___________________________________________

(a) 2014 amounts include debt issued in connection with the spin-off of our oilfield services business. All deferred charges and debt balances related to the spin-off were removed from our consolidated balance sheet as of June 30, 2014. See Note 13 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the spin-off.

Our $4.0 billion unsecured revolving credit facility and cash and cash equivalents provide other sources of liquidity. We use the facility and cash on hand to fund daily operating activities and capital expenditures as needed. Prior to June 2014, we also utilized a $500 million oilfield services credit facility. This facility was terminated in June 2014 in connection with the spin-off of our oilfield services business. See Note 13 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the spin-off. Prior to June 15, 2012, we also had a $600 million midstream revolving credit facility, which we terminated in June 2012. We borrowed $7.406 billion and repaid $7.788 billion in 2014, borrowed $7.669 billion and repaid $7.682 billion in 2013 and borrowed $20.318 billion and repaid $21.650 billion in 2012 under our revolving credit facilities. As of December 31, 2014, we had no outstanding borrowings under our revolving credit facility and had utilized approximately $15 million of the facility for various letters of credit. Our facility is unsecured; however, we will be required to provide collateral and the facility will be subject to a borrowing base if our credit rating declines to specified levels.

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Uses of Funds

The following table presents the uses of our cash and cash equivalents for 2014, 2013 and 2012:

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
Oil and Natural Gas Expenditures:
Drilling and completion costs(a)	$	4,495	$	5,490	$	8,707
Acquisitions of proved and unproved properties	758		302		2,385
Geological and geophysical costs	35		33		170
Interest capitalized on unproved properties	604		811		829
Total Oil and Natural Gas Expenditures	5,892		6,636		12,091
Other Uses of Cash and Cash Equivalents:
Cash paid to repurchase debt	3,362		2,141		4,000
Additions to other property and equipment	227		732		2,615
Payments on credit facility borrowings, net	382		13		1,332
Cash paid to purchase leased rigs and compressors	499		240		36
Cash paid for prepayment of mortgage	—		55		—
Cash paid to purchase preferred shares of subsidiary	1,254		212		—
Dividends paid	405		404		398
Distributions to noncontrolling interest owners	173		215		218
Cash paid to extinguish other financing	—		141		—
Cash paid for financing derivatives(b)	53		91		37
Additions to investments	17		44		395
Other	45		105		474
Total Other Uses of Cash and Cash Equivalents	6,417		4,393		9,505
Total Uses of Cash and Cash Equivalents	$	12,309	$	11,029	$	21,596

___________________________________________

(a) Net of $679 million, $884 million and $784 million in drilling and completion carries received from our joint venture partners during 2014, 2013 and 2012, respectively.

(b) Reflects derivatives deemed to contain, for accounting purposes, a significant financing element at contract inception.

Our primary use of funds is for capital expenditures for drilling and completion costs on our oil and natural gas properties. Historically, a significant use was also for the acquisition of leasehold and construction and acquisition of other property and equipment. During 2014, our average operated rig count was 64 rigs compared to an average rig count of 71 operated rigs in 2013 and 131 operated rigs in 2012.

Our proved and unproved property acquisition costs were $758 million in 2014 compared to $302 million in 2013 and $2.385 billion in 2012. The increase in 2014 compared to 2013 was primarily due to the Powder River Basin transaction discussed in 2014 Strategic Transactions. Through 2012, we invested heavily in proved and unproved properties and now hold a substantial inventory of resources that provide a foundation for future growth.

Capital expenditures related to our midstream, oilfield services and other fixed assets were $227 million in 2014 compared to $732 million in 2013 and $2.615 billion in 2012, respectively. The reduction of these expenditures in 2014 as compared to 2013 and 2012 is primarily the result of the spin-off of our oilfield services business, divestiture of our midstream and gathering business and reductions in construction expenditures on our corporate headquarters and field offices.

In 2014, we used $3.362 billion of cash to reduce debt. For a discussion of the debt repaid, see 2014 Refinancings above.

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In 2013, we used a portion of the net proceeds of $2.274 billion from senior notes offerings to repay outstanding indebtedness under our revolving credit facility and purchase certain senior notes. We purchased $217 million in aggregate principal amount of our 7.625% Senior Notes due 2013 for $221 million and $377 million in aggregate principal amount of our 6.875% Senior Notes due 2018 for $405 million pursuant to tender offers during 2013. During 2013, we also redeemed $1.3 billion in aggregate principal amount of our 6.775% Senior Notes due 2019 (the 2019 Notes) at par pursuant to notice of special early redemption. This redemption is subject to litigation. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for discussion of the litigation. On July 15, 2013, we retired at maturity the remaining $247 million aggregate principal amount outstanding of our 7.625% Senior Notes due 2013.

In late 2012, we fully repaid the $4.0 billion term loan that we established in May 2012 with cash proceeds from asset sales and proceeds from the issuance of the $2.0 billion term loan that we established in November 2012.

In 2014, 2013 and 2012, we purchased rigs and compressors previously sold under long-term lease arrangements for approximately $499 million, $240 million and $36 million, respectively, as part of a strategic initiative to reduce complexity and future commitments as well as to facilitate asset sales and the spin-off of SSE.

We paid dividends on our common stock of $234 million, $233 million and $227 million in 2014, 2013 and 2012, respectively. We paid dividends on our preferred stock of $171 million in each of 2014, 2013 and 2012.

Revolving Credit Facility

In December 2014, we entered into a new $4.0 billion senior unsecured revolving credit facility that matures in December 2019. As of December 31, 2014, we had no outstanding borrowings under the facility and utilized $15 million of the facility for various letters of credit. Borrowings under the facility bear interest at a variable rate. The applicable interest rates under the facility fluctuate based on our credit ratings. We would be required to post collateral in the event of a downgrade of our credit ratings to specified levels. The financial covenants require us to maintain, as of the last day of each fiscal quarter, (i) a net debt to capitalization ratio (as defined in the credit agreement) that does not exceed 65%, and (ii) a leverage ratio (net debt to consolidated EBITDA, as defined in the credit agreement) that does not exceed 4.0 to 1.0; provided, however, that the leverage ratio will not apply during any period in which our credit ratings, as determined by either Moody’s Investors Services, Inc. or Standard & Poor’s Ratings Services, meet and continue to meet certain investment grade thresholds, as defined in the credit agreement. As of December 31, 2014, our net debt to capitalization ratio was approximately 0.31 to 1.0, and our leverage ratio was approximately 1.55 to 1.0. We were in compliance with all financial covenants under the credit agreement as of December 31, 2014. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the terms of the credit facility.

Hedging Facility

We have a multi-counterparty secured hedging facility with 17 counterparties that have committed to provide approximately 1.031 bboe of hedging capacity for oil, natural gas and NGL price derivatives and 1.031 bboe for basis derivatives with an aggregate mark-to-market capacity of $16.5 billion. For further discussion of the terms of the hedging facility, see Note 11 of the notes to our consolidated financial statements included in Item 8 of this report.

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Senior Note Obligations

Our senior note obligations consisted of the following as of December 31, 2014:

	December 31, 2014
	($ in millions)
3.25% senior notes due 2016	$	500
6.25% euro-denominated senior notes due 2017(a)	416
6.5% senior notes due 2017	660
7.25% senior notes due 2018	669
Floating rate senior notes due 2019	1,500
6.625% senior notes due 2020	1,300
6.875% senior notes due 2020	500
6.125% senior notes due 2021	1,000
5.375% senior notes due 2021	700
4.875% senior notes due 2022	1,500
5.75% senior notes due 2023	1,100
2.75% contingent convertible senior notes due 2035(b)	396
2.5% contingent convertible senior notes due 2037(b)	1,168
2.25% contingent convertible senior notes due 2038(b)	347
Discount on senior notes(c)	(231		)
Interest rate derivatives(d)	10
Total senior notes, net	11,535
Less current maturities of long-term debt(e)	(381		)
Total long-term senior notes, net	$	11,154

___________________________________________

(a) The principal amount shown is based on the exchange rate of $1.2098 to €1.00 as of December 31, 2014. See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for information on our related foreign currency derivatives.

(b) The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date. The first put date, for the 2.75% Contingent Convertible Senior Notes due 2035, is November 15, 2015. The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash and, if applicable, shares of our common stock using a net share settlement process.

(c) Included in this discount as of December 31, 2014 was $224 million associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method.

(d) See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for discussion related to these instruments.

(e) As of December 31, 2014, there was $15 million of discount associated with the equity component of the 2.75% Contingent Convertible Senior Notes due 2035.

For further discussion and details regarding our senior notes and contingent convertible senior notes, see Note 3 of the notes to our consolidated financial statements included in Item 8 of this report.

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Credit Risk

Derivative instruments that enable us to manage our exposure to oil, natural gas and NGL prices, as well as to interest rate and foreign currency volatility, expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment grade and deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2014, our oil, natural gas and interest rate derivative instruments were spread among 18 counterparties. We also invested available cash balances with many of these same counterparties as well as other relationship banks. Additionally, the counterparties under our multi-counterparty secured hedging facility are required to secure their obligations in excess of defined thresholds. We use this facility for substantially all of our oil, natural gas and NGL derivatives.

Our accounts receivable are primarily from purchasers of oil, natural gas and NGL ($1.340 billion as of December 31, 2014) and exploration and production companies that own interests in properties we operate ($691 million as of December 31, 2014). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. During 2014, 2013 and 2012, we recognized nominal amounts of bad debt expense related to potentially uncollectible receivables.

Contractual Obligations and Off-Balance Sheet Arrangements

From time to time, we enter into arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2014, these arrangements and transactions included (i) operating lease agreements, (ii) volumetric production payments (VPPs) (to purchase production and pay related production expenses and taxes in the future), (iii) open purchase commitments, (iv) open delivery commitments, (v) open drilling commitments, (vi) undrawn letters of credit, (vii) open gathering and transportation commitments, and (viii) various other commitments we enter into in the ordinary course of business that could result in a future cash obligation. See Notes 4 and 12 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of commitments and VPPs, respectively.

The table below summarizes our contractual cash obligations for both recorded obligations and certain off-balance sheet arrangements and commitments as of December 31, 2014.

	Payments Due By Period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
	($ in millions)
Long-term debt:
Principal(a)	$	11,756	$	396	$	2,744	$	2,516	$	6,100
Interest	4,028		590		1,109		921		1,408
Operating lease obligations(b)	11		5		5		1		—
Operating commitments(c)	17,012		2,332		4,481		3,319		6,880
Unrecognized tax benefits(d)	45		—		—		45		—
Standby letters of credit	15		15		—		—		—
Deferred premium on call options	181		95		86		—		—
Other	49		12		13		8		16
Total contractual cash obligations(e)	$	33,097	$	3,445	$	8,438	$	6,810	$	14,404

___________________________________________

(a) Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes.

(b) See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease obligations.

(c) See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of gathering, processing and transportation agreements and drilling contracts.

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(d) See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for a description of unrecognized tax benefits.

(e) This table does not include derivative liabilities or the estimated discounted liability for future dismantlement, abandonment and restoration costs of oil and natural gas properties. See Notes 11 and 20, respectively, of the notes to our consolidated financial statements included in Item 8 of this report for more information on our derivatives and asset retirement obligations. This table also does not include our costs to produce reserves attributable to non-expense-bearing royalty and other interests in our properties, including VPPs, which are discussed below.

As the operator of the properties from which VPP volumes have been sold, we bear the cost of producing the reserves attributable to these interests, which we include as a component of production expenses and production taxes in our consolidated statements of operations in the periods these costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining our full cost ceiling test for impairment purposes and in determining our standardized measure. The amount of these VPP-related production expenses and taxes, based on cost levels as of December 31, 2014 pursuant to SEC reporting requirements, was estimated to be approximately $773 million in total and $407 million for the next twelve months on an undiscounted basis and approximately $630 million and $386 million, respectively, on a discounted basis using an annual discount rate of 10%. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet. The costs that will apply in the future will depend on the actual production volumes as well as the production costs and taxes in effect during the periods in which production actually occurs, which could differ materially from our current and historical costs, and production may not occur at the times or in the quantities projected, or at all. We have committed to purchase natural gas and liquids produced that are associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices.

See Notes 4 and 12 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of commitments and VPPs, respectively.

Derivative Activities

Oil, Natural Gas and NGL Derivatives

Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Executive management is involved in all risk management activities and the Board of Directors reviews the Company's derivative program at its quarterly board meetings. We believe we have sufficient internal controls to prevent unauthorized trading. As of December 31, 2014, our oil and natural gas derivative instruments consisted of swaps, collars, options and basis protection swaps. Item 7A. Quantitative and Qualitative Disclosures About Market Risk contains a description of each of these instruments and gains and losses on oil, natural gas and NGL derivatives during 2014, 2013 and 2012. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving our risk management objectives.

Our commodity derivative activities allow us to predict with greater certainty the effective prices we will receive for our hedged production. We closely monitor the fair value of our derivative contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or minimize a loss. Commodity markets are volatile and Chesapeake's derivative activities are dynamic.

Mark-to-market positions under commodity derivative contracts fluctuate with commodity prices. As described under Hedging Facility in Note 11 of the notes to our consolidated financial statements included in Item 8 of this report, our secured multi-counterparty hedging facility allows us to minimize the potential liquidity impact of significant mark-to-market fluctuations in the value of these derivatives by pledging our proved reserves.

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The estimated fair values of our oil and natural gas derivative contracts as of December 31, 2014 and 2013 are provided below. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information concerning the fair value of our oil and natural gas derivative instruments.

	December 31,
	2014			2013
	($ in millions)
Derivative assets (liabilities):
Oil fixed-price swaps	$	471		$	(50	)
Oil three-way collars	40			—
Oil call options	(89		)	(265		)
Oil basis protection swaps	—			1
Natural gas fixed-price swaps	281			(23		)
Natural gas three-way collars	165			(7		)
Natural gas call options	(170		)	(210		)
Natural gas basis protection swaps	23			3
Estimated fair value	$	721		$	(551	)

Changes in the fair value of oil and natural gas derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to the hedged commodities, and locked-in gains and losses of settled designated derivative contracts are recorded in accumulated other comprehensive income and are transferred to earnings in the month of related production. As of December 31, 2014, 2013 and 2012, accumulated other comprehensive income included unrealized losses, net of related tax effects, totaling $136 million, $159 million and $179 million, respectively, associated with commodity derivative contracts. Based upon the market prices at December 31, 2014, we expect to transfer to earnings approximately $23 million of net loss included in accumulated other comprehensive income during the next 12 months. A detailed explanation of accounting for oil, natural gas and NGL derivatives appears under Application of Critical Accounting Policies – Derivatives elsewhere in this Item 7.

Interest Rate Derivatives

To mitigate a portion of our exposure to volatility in interest rates related to our senior notes and revolving credit facility, we enter into interest rate derivatives.

For interest rate derivative contracts designated as fair value hedges, changes in fair values of the derivatives are recorded on the consolidated balance sheets as assets or (liabilities), with corresponding offsetting adjustments to the debt's carrying value. Changes in the fair value of derivatives not designated as fair value hedges, which occur prior to their maturity (i.e., temporary fluctuations in mark-to-market values), are reported currently in the consolidated statements of operations as interest expense.

Gains or losses from interest rate derivative contracts are reflected as adjustments to interest expense on the consolidated statements of operations. The components of interest expense for the years ended December 31, 2014, 2013 and 2012 are presented below in Results of Operations - Interest Expense, and a detailed explanation of accounting for interest rate derivatives appears under Application of Critical Accounting Policies - Derivatives elsewhere in this Item 7.

Foreign Currency Derivatives

On December 6, 2006, we issued €600 million of 6.25% Euro-denominated Senior Notes due 2017. Concurrent with the issuance of the euro-denominated senior notes, we entered into cross currency swaps to mitigate our exposure to fluctuations in the euro relative to the dollar over the term of the notes. In May 2011, we purchased and subsequently retired €256 million in aggregate principal amount of these senior notes following a tender offer, and we simultaneously unwound the cross currency swaps for the same principal amount. A detailed explanation of accounting for foreign currency derivatives appears under Application of Critical Accounting Policies - Derivatives elsewhere in this Item 7.

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Results of Operations

General. For the year ended December 31, 2014, Chesapeake had net income of $2.056 billion, or $1.87 per diluted common share, on total revenues of $20.951 billion. This compares to net income of $894 million, or $0.73 per diluted common share, on total revenues of $17.506 billion for the year ended December 31, 2013 and a net loss of $594 million, or $1.46 per common share, on total revenues of $12.316 billion for the year ended December 31, 2012. The increase in net income in 2014 was primarily driven by an increase in unrealized gains on our oil and natural gas derivative contracts as the future commodity prices moved lower. In addition, 2013 results include charges of approximately $546 million for the impairment of buildings, land, drilling rigs, gathering systems and other assets and $248 million related to restructuring and other termination costs incurred in connection with a workforce reduction, executive officer separations and other employee terminations. The charges reflect actions taken as a result of the company-wide review of our operations, assets and organizational structure in the second half of 2013. The net loss in 2012 was primarily driven by a $2.022 billion after-tax impairment of oil and natural gas properties recorded in the 2012 third quarter. See Impairment of Oil and Natural Gas Properties below.

Oil, Natural Gas and NGL Sales. During 2014, oil, natural gas and NGL sales were $8.180 billion compared to $7.052 billion in 2013 and $6.278 billion in 2012. In 2014, Chesapeake produced and sold 258 mmboe for $7.162 billion at a weighted average price of $27.78 per boe (excluding the effect of derivatives), compared to 244 mmboe produced and sold in 2013 for $6.923 billion at a weighted average price of $28.33 per boe (excluding the effect of derivatives) and 237 mmboe produced and sold in 2012 for $5.359 billion at a weighted average price of $22.61 per boe (excluding the effect of derivatives). The decrease in the price received per boe in 2014 compared to 2013 resulted in a $141 million decrease in revenues, and increased sales volumes resulted in a $380 million increase in revenues, for a net increase in revenues of $239 million (excluding the effect of derivatives).

For 2014, our average price received per barrel of oil was $87.13, compared to $95.17 in 2013 and $90.49 in 2012 (excluding the effect of derivatives). Natural gas prices received per mcf (excluding the effect of derivatives) were $2.54, $2.22 and $1.77 in 2014, 2013 and 2012, respectively. NGL prices received per barrel (excluding the effect of derivatives) were $21.27, $27.87 and $29.89, in 2014, 2013 and 2012, respectively. In 2014, realized prices for natural gas increased due to the higher average Henry Hub price compared to 2013 and 2012, partially offset by higher natural gas gathering and transportation costs, primarily resulting from a fee associated with a production shortfall below the minimum volume commitment under our Barnett and Haynesville gathering agreements. In 2013, realized prices for natural gas were negatively affected by higher year-over-year natural gas gathering and transportation costs, primarily as a result of construction of midstream systems being undertaken in certain of our less mature operating areas and a fee associated with a production shortfall below the minimum volume commitment under our Barnett gathering agreement. For 2015, we expect that we will continue to see increased gathering and transportation costs, including higher minimum volume commitment fees under our Barnett and Haynesville natural gas gathering agreements.

Natural gas prices after gathering, transportation and basis differentials were $1.87 per mcf below the Henry Hub natural gas benchmark price in 2014, as compared to differentials of $1.43 per mcf in 2013 and $1.02 per mcf in 2012. This was primarily the result of significant weakening of Marcellus Shale basis differentials and increased gathering and transportation costs, including higher minimum volume commitment fees under our Barnett and Haynesville natural gas gathering agreements.

Gains and losses from our oil, natural gas and NGL derivatives resulted in a net increase in oil, natural gas and NGL revenues of $1.018 billion, $129 million and $919 million in 2014, 2013 and 2012, respectively. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk of this report for a complete listing of all of our derivative instruments as of December 31, 2014.

A change in oil, natural gas and NGL prices has a significant impact on our revenues and cash flows. Assuming our 2014 production levels and without considering the effect of derivatives, an increase or decrease of $1.00 per barrel of oil sold would result in an increase or decrease in 2014 revenues and cash flows of approximately $42 million and $41 million, respectively, an increase or decrease of $0.10 per mcf of natural gas sold would result in an increase or decrease in 2014 revenues and cash flows of approximately $109 million and $107 million, respectively, and an increase or decrease of $1.00 per barrel of NGL sold would result in an increase or decrease in 2014 revenues and cash flows of $33 million and $32 million, respectively.

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The following tables show our production and average sales prices received by operating division for 2014, 2013 and 2012:

	2014
	Oil		Natural Gas		NGL		Total
	(mmbbl)	($/bbl)(a)	(bcf)	($/mcf)(a)	(mmbbl)	($/bbl)(a)	(mmboe)	%		($/boe)(a)
Southern(b)	35.3	89.04	580.7	2.38	16.9	23.93	148.9	58		33.08
Northern(c)	7.0	77.52	514.3	2.71	16.2	18.49	108.9	42		20.54
Total(d)	42.3	87.13	1,095.0	2.54	33.1	21.27	257.8	100	%	27.78
	2013
	Oil		Natural Gas		NGL		Total
	(mmbbl)	($/bbl)(a)	(bcf)	($/mcf)(a)	(mmbbl)	($/bbl)(a)	(mmboe)	%		($/boe)(a)
Southern(b)	37.6	95.57	692.9	2.09	16.7	26.32	169.7	69		32.30
Northern(c)	3.5	90.82	401.7	2.44	4.2	33.95	74.7	31		19.28
Total(d)	41.1	95.17	1,094.6	2.22	20.9	27.87	244.4	100	%	28.33
	2012
	Oil		Natural Gas		NGL		Total
	(mmbbl)	($/bbl)(a)	(bcf)	($/mcf)(a)	(mmbbl)	($/bbl)(a)	(mmboe)	%		($/boe)(a)
Southern(b)	30.3	90.78	868.0	1.68	15.8	28.78	190.8	81		24.43
Northern(c)	1.0	81.60	260.8	2.10	1.8	39.73	46.2	19		15.11
Total(d)	31.3	90.49	1,128.8	1.77	17.6	29.89	237.0	100	%	22.61

___________________________________________

(a) Average sales prices exclude gains (losses) on derivatives. Decreases in the average sales prices for our oil and NGL sold in 2014 as compared to 2013 and 2012 were primarily driven by a decrease in the West Texas Intermediate (WTI) crude oil price. The increase in the average sales price for our natural gas sold in 2014 as compared to 2013 and 2012 was primarily driven by an increase in the Henry Hub natural gas price partially offset by higher basis differentials in certain of our areas relative to the Henry Hub benchmark natural gas price and increased gathering and transportation costs in certain of our areas.

(b) Our Southern Division includes the Eagle Ford, Granite Wash, Cleveland, Tonkawa and Mississippian Lime unconventional liquids plays and the Haynesville/Bossier and Barnett unconventional natural gas shale plays. The Eagle Ford Shale accounted for approximately 19% of our estimated proved reserves by volume as of December 31, 2014. Production for the Eagle Ford Shale for 2014, 2013 and 2012 was 35.4 mmboe, 31.7 mmboe and 17.8 mmboe, respectively. The Barnett Shale accounted for approximately 17% of our estimated proved reserves by volume as of December 31, 2014. Production for the Barnett Shale for 2014, 2013 and 2012 was 24.0 mmboe, 28.9 mmboe and 30.3 mmboe, respectively. Our gathering agreements for Barnett and Haynesville production require us to pay the service provider a fee for any production shortfall below certain annual minimum gathering volume commitments. These fees amounted to $0.11 per mcf in 2014 and $0.03 per mcf in 2013, and we anticipate incurring shortfall fees in 2015 based on current production estimates.

(c) Our Northern Division includes the Utica and Niobrara unconventional liquids plays and the Marcellus unconventional natural gas play.

(d) 2014, 2013 and 2012 production levels reflect the impact of various asset sales and joint ventures. The decrease in production in the Southern Division in 2014 as compared to 2013 and 2012 is primarily the result of our 2013 asset sale in the Haynesville Shale, along with various asset sales and joint ventures in both 2013 and 2012. The increase in production in the Northern Division in 2014 as compared to 2013 and 2012 is primarily the result of increased processing capacity in the Utica Shale. See Note 12 of the notes to our consolidated financial statements included in Item 8 of this report for information on our oil and natural gas property divestitures and joint ventures.

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Our average daily production of 706 mboe for 2014 consisted of approximately 206,300 bbls of liquids, including approximately 115,800 bbls of oil (16% on an oil equivalent basis) and approximately 90,500 bbls of NGL (13% on an oil equivalent basis) and approximately 3.0 bcf of natural gas (71% on an oil equivalent basis). Our year-over-year growth rate of NGL production was 58%. Oil production increased 3% year over year and our natural gas production remained the same year over year, primarily as a result of asset sales.

Excluding the impact of derivatives, our percentage of revenues from oil, natural gas and NGL is shown in the following table:

	Years Ended December 31,
	2014	2013	2012
Oil	52%	56%	53%
Natural gas	39%	36%	37%
NGL	9%	8%	10%
Total	100%	100%	100%

Marketing, Gathering and Compression Revenues and Expenses. Marketing, gathering and compression revenues and expenses consist of third-party revenues and expenses related to our marketing, gathering and compression operations and exclude depreciation and amortization, general and administrative expenses, impairments of fixed assets and other, net gains or losses on sales of fixed assets and interest expense. See Depreciation and Amortization of Other Assets below for the depreciation and amortization recorded on our marketing, gathering and compression assets. Chesapeake recognized $12.225 billion in marketing, gathering and compression revenues in 2014 with corresponding expenses of $12.236 billion, for a net loss before depreciation of $11 million. This compares to revenues of $9.559 billion, expenses of $9.461 billion and a net margin before depreciation of $98 million in 2013 and revenues of $5.431 billion, expenses of $5.312 billion and a net margin before depreciation of $119 million in 2012. Revenues and operating expenses from our marketing business increased substantially in 2014 and 2013 primarily as a result of an increase in a variety of purchase and sales contracts we entered into with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments. In addition, we marketed more oil and NGL from Chesapeake-operated wells for third parties. The margin decrease in 2014 and 2013 as compared to 2012 was primarily a result of losses on certain sales contracts with third parties entered into to help meet certain of our oil pipeline and other commitments. In addition, margins were reduced as a result of the sale of a significant portion of our compression assets in 2014 and the sale of gathering assets in 2013.

Oilfield Services Revenues and Expenses. Our oilfield services consisted of third-party revenues and expenses related to our former oilfield services operations and excluded depreciation and amortization, general and administrative expenses, impairments of fixed assets and other, net gains or losses on sales of fixed assets and interest expense. See Depreciation and Amortization of Other Assets below for the depreciation and amortization recorded on our oilfield services assets. Chesapeake recognized $546 million in oilfield services revenues in 2014 with corresponding expenses of $431 million, for a net margin before depreciation of $115 million. This compares to revenues of $895 million and $607 million, expenses of $736 million and $465 million with net margins before depreciation of $159 million and $142 million in 2013 and 2012, respectively. As a result of the spin-off of our oilfield services business in June 2014, we did not have oilfield services revenues and expenses in the second half of 2014, and we will not have oilfield services revenues and expenses in future periods.

Oil, Natural Gas and NGL Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $1.208 billion in 2014, compared to $1.159 billion in 2013 and $1.304 billion in 2012. On a unit-of-production basis, production expenses were $4.69 per boe in 2014 compared to $4.74 per boe in 2013 and $5.50 in 2012. The per unit expense decrease in 2014 was primarily the result of a general improvement in operating efficiencies across most of our operating areas. Production expenses in 2014, 2013 and 2012 included approximately $157 million, $177 million and $220 million, or $0.61, $0.72 and $0.93 per boe, respectively, associated with VPP production volumes. We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our VPP agreements decrease and operating efficiencies generally improve. In addition, our obligations with respect to two of our ten VPPs have been assumed by third parties as a result of our divestiture of related properties in 2014 and we purchased the remaining reserves from one of our VPPs in 2012 and subsequently sold the reserves to a buyer of our Permian Basin assets.

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The following table shows our production expenses (excluding ad valorem taxes) by operating division and our ad valorem tax expenses for 2014, 2013 and 2012:

	2014			2013			2012
	Production Expenses		$/boe	Production Expenses		$/boe	Production Expenses		$/boe
	($ in millions, except per unit)
Southern(a)	$	882	5.92	$	925	5.46	$	1,087	5.70
Northern	229		2.10	164		2.19	143		3.10
	1,111		4.31	1,089		4.46	1,230		5.19
Ad valorem tax	97		0.38	70		0.28	74		0.31
Total	$	1,208	4.69	$	1,159	4.74	$	1,304	5.50

___________________________________________

(a) The per unit increase in the Southern Division from 2013 to 2014 is primarily the result of increased artificial lift, repairs and maintenance and a higher percentage of oil produced which has higher lifting costs.

Production Taxes. Production taxes were $232 million in 2014 compared to $229 million in 2013 and $188 million in 2012. On a unit-of-production basis, production taxes were $0.90 per boe in 2014 compared to $0.94 per boe in 2013 and $0.79 per boe in 2012. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil, natural gas and NGL prices are higher. Production taxes in 2014, 2013 and 2012 included approximately $16 million, $22 million and $20 million, or $0.06, $0.09 and $0.08 per boe, respectively, associated with VPP production volumes. We anticipate a continued decrease in production tax expenses associated with VPP production volumes as the contractually scheduled volumes under our VPP agreements decrease. In addition, our obligations with respect to three of our ten VPPs have been terminated as described in the above discussion of production expenses.

General and Administrative Expenses. General and administrative expenses were $322 million in 2014, $457 million in 2013 and $535 million in 2012, or $1.25, $1.86, and $2.26 per boe, respectively. The absolute and per unit expense decrease in 2014 was primarily due to our workforce reduction in the second half of 2013 and efforts to reduce our overhead. In addition, fair value adjustments to performance share units (PSUs), reflecting changes in the trading price of our common stock, were significantly lower in 2014 compared to 2013 and 2012. Included in general and administrative expenses is stock-based compensation of $46 million in 2014, $60 million in 2013 and $71 million in 2012. See Note 9 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our stock-based compensation.

Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, drilling and completion activities are capitalized. We capitalize internal costs that can be directly identified with the acquisition of leasehold, as well as drilling and completion activities, and do not include any costs related to production, general corporate overhead or similar activities. We capitalized $230 million, $317 million and $434 million of internal costs in the 2014, 2013 and 2012, respectively, directly related to our oil and natural gas property acquisition and drilling and completion efforts. The decrease was primarily due to a decrease in our drilling activity, lower costs and increased emphasis on operational efficiencies.

Restructuring and Other Termination Costs. We recorded expense of $7 million, $248 million and $7 million of restructuring and other termination costs in 2014, 2013 and 2012, respectively. The 2014 amount primarily related to costs incurred related to the spin-off of our oilfield services business in June 2014. These costs were partially offset by negative fair value adjustments to PSUs granted to former executives of the Company. See Note 9 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our share-based compensation. The 2013 amount primarily related to workforce reductions, senior management separations and our voluntary separation plan. The 2012 amount related to other termination benefits. The Company committed to a workforce reduction plan in September 2013 that resulted in a reduction of approximately 900 employees. In connection with the workforce reduction plan, we incurred a total charge of $66 million. The acceleration of vesting of stock-based compensation accounted for approximately $45 million of this expense. We also incurred charges of approximately $182 million in 2013 related to the separation from the Company of certain other employees, including approximately $107 million related to our former CEO and other executive officers that were outside the workforce reduction plan.

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See Note 18 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our restructuring and other termination costs.

Provision for Legal Contingencies. We are defending against claims by royalty owners alleging, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sales of natural gas and NGL. Adverse results in these matters would cause our obligations to royalty owners to increase, which would result in a decrease in our future revenues. In 2014, we accrued $134 million of loss contingencies related to royalty claims. See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of royalty claims. In 2014, we also accrued a $100 million loss contingency for litigation regarding our early redemption of our 2019 Notes. See Notes 3 and 4 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of this litigation.

Oil, Natural Gas and NGL Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (DD&A) of oil, natural gas and NGL properties was $2.683 billion, $2.589 billion and $2.507 billion in 2014, 2013 and 2012, respectively. The $94 million increase in 2014 and the $82 million increase in 2013 were driven by increases in our production. The average DD&A rate per boe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $10.41, $10.59 and $10.58 in 2014, 2013 and 2012, respectively.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $232 million in 2014 compared to $314 million in 2013 and $304 million in 2012. Property and equipment costs are depreciated on a straight-line basis over the estimated useful lives of the assets. To the extent company-owned oilfield services equipment was used to drill and complete our wells, a substantial portion of the depreciation (i.e., the portion related to our utilization of the equipment) was capitalized in oil and natural gas properties as drilling and completion costs. In June 2014, we completed the spin-off of our oilfield services business and, therefore, will not incur this expense in future periods. The following table shows depreciation expense by asset class for 2014, 2013 and 2012 and the estimated useful lives of these assets.

	Years Ended December 31,						Estimated Useful Life
	2014		2013		2012
	($ in millions)						(in years)
Oilfield services equipment(a)	$	74	$	122	$	61	3 - 15
Buildings and improvements	42		47		42		10 - 39
Natural gas compressors(b)	37		35		26		3 - 20
Computers and office equipment	32		44		45		3 - 7
Vehicles	24		38		52		0 - 7
Natural gas gathering systems and treating plants(b)	12		13		46		20
Other	11		15		32		2 - 20
Total depreciation and amortization of other assets	$	232	$	314	$	304

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(a) Included in our former oilfield services operating segment.

(b) Included in our marketing, gathering and compression operating segment.

Impairment of Oil and Natural Gas Properties. In 2012, we reported a non-cash impairment charge on our oil and natural gas properties of $3.315 billion, primarily resulting from a 10% decrease in trailing 12-month average first-day-of-the-month natural gas prices as of September 30, 2012 compared to June 30, 2012, and the impairment of certain undeveloped leasehold, primarily in the Williston and DJ Basins. We account for our oil and natural gas properties using the full cost method of accounting, which limits the amount of costs we can capitalize and requires us to write off these costs if the carrying value of oil and natural gas assets in the evaluated portion of our full cost pool exceeds the sum of the present value of expected future net cash flows of proved reserves using a 10% pre-tax discount rate based on pricing and cost assumptions prescribed by the SEC and the present value of oil and natural gas derivative instruments designated as cash flow hedges. See Note 17 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our impairment of oil and natural gas properties.

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The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are low. The NYMEX WTI index price of oil declined significantly from $105.37 per bbl as of June 30, 2014 to $53.27 per bbl as of December 31, 2014, and the Henry Hub index price of natural gas declined from $4.46 per mcf to $2.89 per mcf over the same period. Based on the decline in oil and natural gas prices in the second half of 2014 and into 2015, we expect to have a material write-down of the carrying value of our oil and natural gas properties in the 2015 first quarter. Further material write-downs in subsequent quarters will occur if the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters.

Impairments of Fixed Assets and Other. In 2014, 2013 and 2012, we recognized $88 million, $546 million and $340 million, respectively, of fixed asset impairment losses and other charges. The 2014 amount relates to charges recorded for a joint venture net acreage shortfall and impairments related to a gathering system, drilling rigs, natural gas compressors and buildings and land. The 2013 amount relates to impairments of certain of our gathering systems and treating plants, drilling rigs, buildings and land, a gas gathering termination fee and a contract drilling agreement termination fee. The 2012 amount relates to impairments of buildings and land, drilling rigs and equipment and charges for a joint venture net acreage shortfall. See Note 17 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our impairments of fixed assets and other.

Net Gains on Sales of Fixed Assets. In 2014, net gains on sales of fixed assets were $199 million compared to $302 million in 2013 and $267 million in 2012. The 2014 amount primarily relates to the sale of natural gas compressors and crude hauling assets. The 2013 and 2012 amounts primarily relate to the sale of certain of our midstream gathering systems. See Note 16 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our net gains on sales of fixed assets.

Interest Expense. Interest expense was $89 million in 2014 compared to $227 million in 2013 and $77 million in 2012 as follows:

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Interest expense on senior notes	$	704		$	740		$	732
Interest expense on term loans	36			116			173
Amortization of loan discount, issuance costs and other	42			91			89
Interest expense on credit facilities	28			38			70
Realized gains on interest rate derivatives(a)	(12		)	(9		)	(1		)
Unrealized (gains) losses on interest rate derivatives(b)	(72		)	67			(6		)
Capitalized interest	(637		)	(816		)	(980		)
Total interest expense	$	89		$	227		$	77
Average senior notes borrowings	$	11,653		$	10,991		$	10,487
Average term loan borrowings	$	625		$	2,000		$	2,096
Average credit facilities borrowings	$	306		$	678		$	2,517

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(a) Includes settlements related to the current period interest accrual and the effect of gains (losses) on early- terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item.

(b) Includes changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the current period.

The decrease in 2014 interest expense was primarily due to a decrease in interest expense on our senior notes and term loans as a result of our debt refinancing in April 2014, the elimination of debt related to the spin-off of our oilfield services business and unrealized gains on interest rate derivatives, offset by a decrease in the amount of interest capitalized as a result of a lower average balance of unevaluated oil and natural gas properties, the primary asset on which interest is capitalized. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our debt refinancing. The increase in 2013 interest expense was primarily due to a decrease in the amount of interest capitalized as a result of a lower average balance of unevaluated oil and natural gas properties, the primary asset on which interest is capitalized. Interest expense, excluding unrealized gains or losses on interest

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rate derivatives and net of amounts capitalized, was $0.63 per boe in 2014 compared to $0.65 per boe in 2013 and $0.35 per boe in 2012.

Losses on Investments.Losses on investments were $80 million in 2014 compared to losses of $226 million in 2013 and losses of $103 million in 2012. The 2014 losses primarily relate to our equity in the net losses of FTS International, Inc. (FTS) and Sundrop Fuels, Inc. (Sundrop). Losses in 2013 primarily relate to our equity in the net loss of FTS and Sundrop, offset by our equity in the net income of Chaparral Energy, Inc. Losses in 2012 primarily relate to our equity in the net loss of FTS. See Note 14 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our investments.

Net Gains (Losses) on Sales of Investments. We recorded net gains on sales of investments of $67 million in 2014 compared to net losses of $7 million in 2013 and net gains of $1.092 billion in 2012. In 2014, we sold all of our interest in Chaparral Energy, Inc. for cash proceeds of $215 million and recorded a $73 million gain related to the sale. In addition, we sold an equity investment in a natural gas trading and management firm for cash proceeds of $30 million and recorded a loss of $6 million associated with the transaction.In 2013, we sold all of our shares of Clean Energy Fuels Corp. (Clean Energy) for cash proceeds of $13 million and recorded a $3 million gain related to the sale. We also sold our $100 million investment in Clean Energy convertible notes for cash proceeds of $85 million and recorded a $15 million loss related to the sale. In addition, in 2013 we sold a $1 million equity investment for cash proceeds of $6 million and recorded a $5 million gain. In 2012, we sold all of our common and subordinated units representing limited partner interests in Access Midstream Partners, L.P. (ACMP) and all of our limited liability company interests in the sole member of its general partner for cash proceeds of $2.0 billion. We recorded a $1.032 billion pre-tax gain associated with the transaction. Also in 2012, we sold our investment in Glass Mountain Pipeline, LLC for cash proceeds of $99 million and recorded a $62 million gain.

Losses on Purchases of Debt and Extinguishment of Other Financing. We recorded losses on purchases of debt of $197 million in 2014, $193 million in 2013 and $200 million in 2012. In December 2014, we entered into a new five-year $4.0 billion senior unsecured revolving credit facility to use for general corporate purposes. The new credit facility replaced our then-existing $4.0 billion senior secured revolving credit facility that was scheduled to mature in December 2015. We recognized a loss of approximately $2 million in extinguishment costs related to lenders under the terminated facility that are not lenders under the new facility. In 2014, we repaid the borrowings under and terminated our $2.0 billion term loan credit facility due 2017 and recorded a loss of approximately $90 million, including $40 million in premiums, $30 million of unamortized discount and $20 million of unamortized deferred charges. Also in 2014, we purchased and redeemed $1.265 billion in aggregate principal amount of our 9.5% Senior Notes due 2015. We recorded a loss of approximately $99 million associated with the purchase and redemption, including $87 million in premiums, $9 million of unamortized debt discount and $3 million of unamortized deferred charges. In addition, in 2014, we redeemed $97 million in principal amount of our 6.875% Senior Notes due 2018 at par. We recorded a loss of approximately $6 million associated with the redemption, including $5 million in premiums and $1 million of unamortized deferred charges.

In 2013, we terminated the financing master lease agreement on our real estate surface properties in the Fort Worth, Texas area for $258 million and recorded a loss of approximately $123 million associated with the extinguishment. Also, in 2013, we completed tender offers to purchase $217 million in aggregate principal amount of our 7.625% Senior Notes due 2013 for $221 million and $377 million in aggregate principal amount of our 6.875% Senior Notes due 2018 for $405 million. We recorded a loss of approximately $37 million associated with the tender offers, including $32 million in premiums and $5 million of unamortized deferred charges. In addition, we redeemed $1.3 billion in aggregate principal amount of our 6.775% Senior Notes due 2019 at par pursuant to a notice of special early redemption. We recorded a loss of approximately $33 million associated with the redemption, including $19 million of unamortized deferred charges and $14 million of discount.

In 2012, we used proceeds from asset sales and our November 2012 term loan to fully repay our May 2012 term loans. We recorded $200 million of losses associated with the repayment, including $86 million of deferred charges and $114 million of debt discount.

Other Income. In 2014, other income was $22 million, compared to $26 million in 2013 and $8 million in 2012. The 2014 other income consisted primarily of $3 million of interest income and $19 million of miscellaneous income. The 2013 other income consisted of $5 million of interest income and $21 million of miscellaneous income. The 2012 income consisted of $1 million of interest income and $7 million of miscellaneous income.

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Income Tax Expense (Benefit). Chesapeake recorded income tax expense of $1.144 billion in 2014 and $548 million in 2013 and an income tax benefit of $380 million in 2012. Our effective income tax rate was 35.8% in 2014, 38.0% in 2013 and 39.0% in 2012. Our effective tax rate can fluctuate as a result of the impact of state income taxes and permanent differences. See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of income tax expense (benefit).

Net Income Attributable to Noncontrolling Interests. Chesapeake recorded net income attributable to noncontrolling interests of $139 million, $170 million and $175 million in 2014, 2013 and 2012, respectively. Net income attributable to noncontrolling interests is primarily driven by the dividends paid on preferred stock of our subsidiaries CHK Utica and CHK Cleveland Tonkawa L.L.C. (CHK C-T), in addition to income or loss related to the Chesapeake Granite Wash Trust. The decrease from 2013 to 2014 is primarily due to our repurchase of all of the outstanding preferred shares of CHK Utica from third-party preferred shareholders in 2014. See Note 8 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of these entities.

Application of Critical Accounting Policies

Readers of this report and users of the information contained in it should be aware that certain events may impact our financial results based on the accounting policies in place. The three policies we consider to be the most significant are discussed below. The Company's management has discussed each critical accounting policy with the Audit Committee of the Company's Board of Directors.

The selection and application of accounting policies are an important process that changes as our business changes and as accounting rules are developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment in the specific set of circumstances existing in our business.

Oil and Natural Gas Properties. The accounting for our business is subject to special accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full cost method. Chesapeake follows the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not capitalize any costs related to production, general corporate overhead or similar activities.

Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and natural gas properties are generally calculated on a well by well or lease or field basis versus the aggregated "full cost" pool basis. Additionally, gain or loss is generally recognized on all sales of oil and natural gas properties under the successful efforts method. As a result, our financial statements differ from those of companies that apply the successful efforts method since we generally reflect a higher level of capitalized costs as well as a higher oil and natural gas depreciation, depletion and amortization rate, and we do not have exploration expenses that successful efforts companies frequently have.

Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly. Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless these sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred. Unevaluated properties are grouped by major producing area where individual property costs are not significant.

We review the carrying value of our oil and natural gas properties under the SEC's full cost accounting rules on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for oil and natural gas cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In

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calculating estimated future net revenues, current prices are calculated as the unweighted arithmetic average of oil and natural gas prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. Costs used are those as of the end of the applicable quarterly period. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges.

Two primary factors impacting this test are reserve levels and oil and natural gas prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. See Oil and Natural Gas Properties in Note 1 of the notes to our consolidated financial statements included in Item 8 of this report for further information on the full cost method of accounting.

Derivatives. Chesapeake uses commodity price and financial risk management instruments to mitigate a portion of our exposure to price fluctuations in oil and natural gas prices, changes in interest rates and foreign exchange rates. Gains and losses on derivative contracts are reported as a component of the related transaction. Results of commodity derivative contracts are reflected in oil, natural gas and NGL sales, and results of interest rate and foreign exchange rate derivative contracts are reflected in interest expense. The changes in the fair value of derivative instruments not qualifying, or not elected, for designation as either cash flow or fair value hedges that occur prior to maturity are reported currently in the consolidated statement of operations as unrealized gains (losses) within oil, natural gas and NGL sales or interest expense. Cash settlements of our derivative arrangements are generally classified as operating cash flows unless the derivative is deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statements of cash flows.

Accounting guidance for derivative instruments and hedging activities establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the consolidated balance sheets as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as oil, natural gas and NGL cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings as oil, natural gas and NGL sales. Any change in the fair value resulting from ineffectiveness is recognized immediately in oil, natural gas and NGL sales. For interest rate derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings as interest expense. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent gains or losses on ineffectiveness and are reflected currently in interest expense. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are also recognized currently in earnings. See Derivative Activities above and Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information regarding our derivative activities.

One of the primary factors that can have an impact on our results of operations is the method used to value our derivatives. We have established the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Additionally, in accordance with accounting guidance for derivatives and hedging, to the extent that a legal right of set-off exists, we net the value of our derivative instruments with the same counterparty in the accompanying consolidated balance sheets.

Another factor that can impact our results of operations each period is our ability to estimate the level of correlation between future changes in the fair value of the derivative instruments and the transactions being hedged, both at inception and on an ongoing basis. This correlation is complicated since energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our derivative instruments are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control.

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Due to the volatility of oil, natural gas and NGL prices and, to a lesser extent, interest rates and foreign exchange rates, the Company's financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2014, 2013 and 2012, the fair values of our derivatives were assets of $652 million, liabilities of $649 million and liabilities of $979 million, respectively.

Income Taxes. The amount of income taxes recorded by the Company requires interpretations of complex rules and regulations of both federal and state taxing jurisdictions. Income taxes are accounted for using the asset and liability approach. The Company has recognized deferred tax assets and liabilities for temporary differences between tax and book basis, tax credit carryforwards and net operating loss carryforwards. We routinely assess the realizability of our deferred tax assets and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In assessing the need for additional or adjustments to existing valuation allowances, we consider the preponderance of evidence concerning the realization of the deferred tax asset. Among the more significant types of evidence that we consider are:

• taxable income projections in future years;

• whether the carryforward period is so brief that it would limit realization of the tax benefit;

• future sales and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures; and

• our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition.

Our judgments and assumptions in estimating future taxable income include such factors as future operating conditions and commodity prices. As of December 31, 2014 and 2013, we had deferred tax assets of $1.687 billion and $1.621 billion, respectively, upon which we had a valuation allowance of $222 million and $148 million, respectively, for certain state net operating losses and tax credits that we have concluded are not more likely than not to be utilized prior to expiration.

The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. Accounting guidance for recognizing and measuring uncertain tax positions prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. Tax positions that do not meet or exceed this threshold condition are considered uncertain tax positions. We accrue interest related to these uncertain tax positions which is recognized in interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. Additional information about uncertain tax positions appears in Note 6 of the notes to our consolidated financial statements included in Item 8 of this report.

Disclosures About Effects of Transactions with Related Parties

Our equity method investees are considered related parties. See Note 7 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of transactions with our equity method investees.

Forward-Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act). Forward-looking statements give our current expectations or forecasts of future events. They include expected oil, natural gas and NGL production and future expenses, estimated operating costs, assumptions regarding future oil, natural gas and NGL prices, planned drilling activity, estimates of future drilling and completion and other capital expenditures (including the use of joint venture drilling carries), potential future write-downs of our oil and natural gas assets, anticipated sales, and the adequacy of our provisions for legal contingencies, as well as statements concerning anticipated cash flow and liquidity, ability to comply with financial maintenance covenants and meet contractual cash commitments to third parties, stock repurchases, operating and capital efficiencies, business strategy, and other plans and objectives for future operations. Disclosures concerning the fair values of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility.

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Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results are described under Risk Factors in Item 1A of Part I of this report and include:

• the volatility of oil, natural gas and NGL prices;

• write-downs of our oil and natural gas asset carrying values due to declines in prices;

• the availability of operating cash flow and other funds to finance reserve replacement costs;

• our ability to replace reserves and sustain production;

• uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures;

• our ability to generate profits or achieve targeted results in drilling and well operations;

• leasehold terms expiring before production can be established;

• commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales;

• the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations;

• adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims;

• the limitations our level of indebtedness may have on our financial flexibility;

• charges incurred in response to market conditions and in connection with actions to reduce financial leverage and complexity;

• drilling and operating risks and resulting liabilities;

• effects of environmental protection laws and regulation on our business;

• legislative and regulatory initiatives further regulating hydraulic fracturing;

• our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used;

• federal and state tax proposals affecting our industry;

• potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations;

• impacts of potential legislative and regulatory actions addressing climate change;

• competition in the oil and gas exploration and production industry;

• a deterioration in general economic, business or industry conditions;

• negative public perceptions of our industry;

• limited control over properties we do not operate;

• pipeline and gathering system capacity constraints and transportation interruptions;

• cyber attacks adversely impacting our operations; and

• an interruption in operations at our headquarters due to a catastrophic event.

We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date, and we undertake no obligation to update this information except as required by applicable law. We urge you to carefully review and consider the disclosures made in this report and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.

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ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

Oil, Natural Gas and NGL Derivatives

Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. These instruments allow us to predict with greater certainty the effective prices to be received for our share of production. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.

Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse oil, natural gas and NGL price changes is to hedge into strengthening oil and natural gas futures markets when prices reach levels that management believes are unsustainable for the long term, have material downside risk in the short term or provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas storage inventory levels, industry decline rates for base production and weather trends.

We use a wide range of derivative instruments to achieve our risk management objectives, including swaps, collars and options. All of these are described in more detail below. We typically use swaps, collars and three-way collars for a large portion of the oil and natural gas price risk we hedge. We have also sold calls, taking advantage of premiums associated with market price volatility. In 2012 and 2013, we bought oil and natural gas calls to, in effect, lock in sold call positions. Due to lower oil, natural gas and NGL prices, we were able to achieve this at a low cost to us. In some cases, we deferred the payment of the premium on these trades to the related month of production. Some of our derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception and the cash settlements associated with these instruments are classified as financing cash flows in the accompanying consolidated statements of cash flows.

We determine the volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions would be reversed. The actual fixed price on our derivative instruments is derived from the reference NYMEX price, as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures. All of our derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price payment, resulting in a net amount due to or from the counterparty.

We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering into a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we reviewed when deciding to enter into the original derivative position. Gains or losses related to closed positions will be recognized in the month of related production based on the terms specified in the original contract.

We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our multi-counterparty secured hedging facility which requires counterparties to post collateral if their obligations to Chesapeake are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the fair value measurements associated with our derivatives.

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As of December 31, 2014, our oil and natural gas derivative instruments consisted of the following:

• Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.

• Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.

• Options: Chesapeake sells, and occasionally buys, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty the excess on sold call options, and Chesapeake receives the excess on bought call options. If the market price settles below the fixed price of the call options, no payment is due from either party.

• Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. Chesapeake receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity.

As of December 31, 2014, we had the following open oil and natural gas derivative instruments:

			Weighted Average Price								Fair Value
	Volume		Fixed		Call		Put		Differential		Asset (Liability)
	(mmbbl)		($ per bbl)								($ in millions)
Oil:
Swaps:
Short-term	12.5		$	94.58	$	—	$	—	$	—	$	471
3-Way Collars:
Short-term	4.4		—		98.94		80.00 / 90.00		—		40
Call Options (sold):
Short-term	20.5		—		101.85		—		—		(9		)
Long-term	24.2		—		100.07		—		—		(69		)
Call Options (bought)(a):
Short-term	(8.9	)	—		113.54		—		—		(11		)
Total Oil											$	422

65

			Weighted Average Price									Fair Value
	Volume		Fixed		Call		Put		Differential			Asset (Liability)
	(tbtu)		($ per mmbtu)									($ in millions)
Natural Gas:
Swaps:
Short-term	238		$	4.14	$	—	$	—	$	—		$	265
Long-term	37		3.95		—		—		—			16
3-Way Collars:
Short-term	207		—		4.51		3.37 / 4.29		—			165
Call Options (sold):
Short-term	226		—		6.31		—		—			(1		)
Long-term	393		—		7.93		—		—			(10		)
Call Options (bought)(b):
Short-term	(226	)	—		6.31		—		—			(81		)
Long-term	(200	)	—		6.02		—		—			(78		)
Basis Protection Swaps:
Short-term	52		—		—		—		0.55			29
Long-term	8		—		—		—		(1.02		)	(6		)
Total Natural Gas												$	299
Total Oil and Natural Gas												$	721

__________________________________________

(a) Included in the fair value are deferred premiums of $13 million which will be included in oil, natural gas and NGL sales as realized gains (losses) in 2015.

(b) Included in the fair value are deferred premiums of $82 million and $85 million which will be included in oil, natural gas and NGL sales as realized gains (losses) in 2015 and 2016, respectively.

In addition to the open derivative positions disclosed above, as of December 31, 2014, we had $216 million of net derivative gains related to settled contracts for future production periods that will be recorded within oil, natural gas and NGL sales as realized gains (losses) on derivatives once they are transferred from either accumulated other comprehensive income or unrealized gains (losses) on derivatives in the month of related production, based on the terms specified in the original contract as noted below.

	December 31, 2014
	($ in millions)
Short-term	$	200
Long-term	16
Total	$	216

66

The table below reconciles the changes in fair value of our oil and natural gas derivatives during the year ended 2014. Of the $721 million fair value asset as of December 31, 2014, an $868 million asset relates to contracts maturing in the next 12 months and a $147 million liability relates to contracts maturing after 12 months. All open derivative instruments as of December 31, 2014 are expected to mature by December 31, 2022.

	2014
	($ in millions)
Fair value of contracts outstanding, as of January 1	$	(551	)
Change in fair value of contracts	1,054
Fair value of new contracts when entered into	—
Contracts realized or otherwise settled	202
Fair value of contracts when closed	16
Fair value of contracts outstanding, as of December 31	$	721

The change in oil and natural gas prices during the year ended December 31, 2014 decreased the liability related to our derivative instruments by $1.0 billion. This unrealized gain is recorded in oil, natural gas and NGL sales. We settled contracts in 2014 that were in a liability position for $202 million. The realized losses will be recorded in oil, natural gas and NGL sales in the month of related production. We terminated contracts that were in a liability position for $16 million. The realized gain is recorded in oil, natural gas and NGL sales in the month of related production.

Interest Rate Derivatives

The table below presents principal cash flows and related weighted average interest rates by expected maturity dates, using the earliest demand repurchase date for contingent convertible senior notes. As of December 31, 2014, we had total debt of $11.8 billion, including $10.3 billion of fixed rate debt at interest rates averaging 5.24% and $1.5 billion of floating rate debt at an interest rate of 3.48% (three-month LIBOR plus 3.25%).

	Years of Maturity
	2015			2016			2017			2018			2019			Thereafter			Total
	($ in millions)
Liabilities:
Debt – fixed rate(a)	$	396		$	500		$	2,244		$	1,016		$	—		$	6,100		$	10,256
Average interest rate	2.75		%	3.25		%	4.37		%	5.54		%	—		%	5.83		%	5.24		%
Debt – variable rate	$	—		$	—		$	—		$	—		$	1,500		$	—		$	1,500
Average interest rate	—		%	—		%	—		%	—		%	3.48		%	—		%	3.48		%

___________________________________________

(a) This amount does not include the discount included in debt of $231 million and interest rate derivatives of $10 million.

Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our revolving credit facility and our floating rate senior notes. All of our other indebtedness is fixed rate and, therefore, does not expose us to the risk of fluctuations in earnings or cash flow due to changes in market interest rates. However, changes in interest rates do affect the fair value of our fixed-rate debt.

67

We enter into interest rate derivatives, including fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes and floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our revolving credit facility borrowings. As of December 31, 2014, the following interest rate derivatives were outstanding:

			Weighted Average Rate				Fair Value
	Notional Amount		Fixed		Floating(a)	Fair Value Hedge	Asset (Liability)
	($ in millions)						($ in millions)
Fixed to Floating:
Swaps
Mature 2021	$	450	6.13	%	1 – 3 mL 470 bp	No	$	(12	)
Floating to Fixed:
Swaps
Mature 2015	$	400	2.59	%	6 mL	No	(5		)
							$	(17	)

___________________________________________

(a) Month LIBOR has been abbreviated “mL” and basis points has been abbreviated “bp”.

In addition to the open derivative positions disclosed above, as of December 31, 2014 we had $52 million of net gains related to settled derivative contracts that will be recorded within interest expense as realized gains (losses) once they are transferred from our senior note liability or within interest expense as unrealized gains (losses) over the remaining eight-year term of our related senior notes.

Realized and unrealized gains or losses from interest rate derivative transactions are reflected as adjustments to interest expense on the consolidated statements of operations.

Foreign Currency Derivatives

In December 2006, we issued €600 million of 6.25% Euro-denominated Senior Notes due 2017. Concurrent with the issuance of the euro-denominated senior notes, we entered into cross currency swaps to mitigate our exposure to fluctuations in the euro relative to the dollar over the term of the notes. In May 2011, we purchased and subsequently retired €256 million in aggregate principal amount of these senior notes following a tender offer, and we simultaneously unwound the cross currency swaps for the same principal amount. Under the terms of the remaining cross currency swaps, on each semi-annual interest payment date, the counterparties pay us €11 million and we pay the counterparties $17 million, which yields an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay us €344 million and we will pay the counterparties $459 million. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. Through the cross currency swaps, we have eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates and therefore the swaps are designated as cash flow hedges. The fair values of the cross currency swaps are recorded on the consolidated balance sheet as a liability of $53 million as of December 31, 2014. The euro-denominated debt in long-term debt has been adjusted to $416 million as of December 31, 2014 using an exchange rate of $1.2098 to €1.00.

68

ITEM 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS CHESAPEAKE ENERGY CORPORATION
	Page
Management's Report on Internal Control Over Financial Reporting	70
Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm	71
Consolidated Balance Sheets as of December 31, 2014 and 2013	72
Consolidated Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012	74
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012	75
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012	76
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2014, 2013 and 2012	78
Notes to Consolidated Financial Statements	79
Supplementary Information
Quarterly Financial Data (unaudited)	147
Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities (unaudited)	148

69

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

It is the responsibility of the management of Chesapeake Energy Corporation to establish and maintain adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management utilized the Committee of Sponsoring Organizations of the Treadway Commission's Internal Control-Integrated Framework (2013) in conducting the required assessment of effectiveness of the Company's internal control over financial reporting.

Management has performed an assessment of the effectiveness of the Company's internal control over financial reporting and has determined the Company's internal control over financial reporting was effective as of December 31, 2014.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2014 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.

/s/ ROBERT D. LAWLER      

Robert D. Lawler

President and Chief Executive Officer

/s/ DOMENIC J. DELL'OSSO, JR.

Domenic J. Dell'Osso, Jr.

Executive Vice President and Chief Financial Officer

February 27, 2015

70

Report of Independent Registered Public Accounting Firm

Tothe Board of Directors and Shareholders of Chesapeake Energy Corporation

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Chesapeake Energy Corporation and its subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma    

February 27, 2015

71

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2014			2013
	($ in millions)
CURRENT ASSETS:
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$	4,108		$	837
Restricted cash	38			75
Accounts receivable, net	2,236			2,222
Short-term derivative assets ($16 and $0 attributable to our VIE)	879			—
Deferred income tax asset	—			223
Other current assets	207			299
Total Current Assets	7,468			3,656
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting:
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	58,594			56,157
Unproved properties	9,788			12,013
Oilfield services equipment	—			2,192
Other property and equipment	3,083			3,203
Total Property and Equipment, at Cost	71,465			73,565
Less: accumulated depreciation, depletion and amortization (($251) and ($168) attributable to our VIE)	(39,043		)	(37,161		)
Property and equipment held for sale, net	93			730
Total Property and Equipment, Net	32,515			37,134
LONG-TERM ASSETS:
Investments	265			477
Long-term derivative assets	6			4
Other long-term assets	497			511
TOTAL ASSETS	$	40,751		$	41,782

The accompanying notes are an integral part of these consolidated financial statements.

72

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS – (Continued)

	December 31,
	2014			2013
CURRENT LIABILITIES:
Accounts payable	$	2,049		$	1,596
Current maturities of long-term debt, net	381			—
Accrued interest	150			200
Deferred income tax liabilities	207			—
Short-term derivative liabilities ($0 and $5 attributable to our VIE)	15			208
Other current liabilities ($15 and $22 attributable to our VIE)	3,061			3,511
Total Current Liabilities	5,863			5,515
LONG-TERM LIABILITIES:
Long-term debt, net	11,154			12,886
Deferred income tax liabilities	4,185			3,407
Long-term derivative liabilities	218			445
Asset retirement obligations, net of current portion	447			405
Other long-term liabilities	679			984
Total Long-Term Liabilities	16,683			18,127
CONTINGENCIES AND COMMITMENTS (Note 4)
EQUITY:
Chesapeake Stockholders’ Equity:
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 7,251,515 shares outstanding	3,062			3,062
Common stock, $0.01 par value, 1,000,000,000 shares authorized: 664,944,232 and 666,192,371 shares issued	7			7
Paid-in capital	12,531			12,446
Retained earnings	1,483			688
Accumulated other comprehensive loss	(143		)	(162		)
Less: treasury stock, at cost; 1,614,312 and 2,002,029 common shares	(37		)	(46		)
Total Chesapeake Stockholders’ Equity	16,903			15,995
Noncontrolling interests	1,302			2,145
Total Equity	18,205			18,140
TOTAL LIABILITIES AND EQUITY	$	40,751		$	41,782

The accompanying notes are an integral part of these consolidated financial statements.

73

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2014			2013			2012
	($ in millions except per share data)
REVENUES:
Oil, natural gas and NGL	$	8,180		$	7,052		$	6,278
Marketing, gathering and compression	12,225			9,559			5,431
Oilfield services	546			895			607
Total Revenues	20,951			17,506			12,316
OPERATING EXPENSES:
Oil, natural gas and NGL production	1,208			1,159			1,304
Production taxes	232			229			188
Marketing, gathering and compression	12,236			9,461			5,312
Oilfield services	431			736			465
General and administrative	322			457			535
Restructuring and other termination costs	7			248			7
Provision for legal contingencies	234			—			—
Oil, natural gas and NGL depreciation, depletion and amortization	2,683			2,589			2,507
Depreciation and amortization of other assets	232			314			304
Impairment of oil and natural gas properties	—			—			3,315
Impairments of fixed assets and other	88			546			340
Net gains on sales of fixed assets	(199		)	(302		)	(267		)
Total Operating Expenses	17,474			15,437			14,010
INCOME (LOSS) FROM OPERATIONS	3,477			2,069			(1,694		)
OTHER INCOME (EXPENSE):
Interest expense	(89		)	(227		)	(77		)
Losses on investments	(80		)	(226		)	(103		)
Net gain (loss) on sales of investments	67			(7		)	1,092
Losses on purchases of debt	(197		)	(193		)	(200		)
Other income	22			26			8
Total Other Income (Expense)	(277		)	(627		)	720
INCOME (LOSS) BEFORE INCOME TAXES	3,200			1,442			(974		)
INCOME TAX EXPENSE (BENEFIT):
Current income taxes	47			22			47
Deferred income taxes	1,097			526			(427		)
Total Income Tax Expense (Benefit)	1,144			548			(380		)
NET INCOME (LOSS)	2,056			894			(594		)
Net income attributable to noncontrolling interests	(139		)	(170		)	(175		)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	1,917			724			(769		)
Preferred stock dividends	(171		)	(171		)	(171		)
Redemption of preferred shares of a subsidiary	(447		)	(69		)	—
Earnings allocated to participating securities	(26		)	(10		)	—
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	1,273		$	474		$	(940	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	1.93		$	0.73		$	(1.46	)
Diluted	$	1.87		$	0.73		$	(1.46	)
CASH DIVIDEND DECLARED PER COMMON SHARE	$	0.35		$	0.35		$	0.35
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic	659			653			643
Diluted	772			653			643

The accompanying notes are an integral part of these consolidated financial statements.

74

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
NET INCOME (LOSS)	$	2,056		$	894		$	(594	)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:
Unrealized gain on derivative instruments, net of income tax expense of $0, $1 and $4	1			2			6
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $14, $12 and ($10)	23			20			(17		)
Unrealized loss on investments, net of income tax benefit of $0, ($4) and ($4)	—			(6		)	(5		)
Reclassification of (gain) loss on investment, net of income tax expense of ($3), $3 and $0	(5		)	4			—
Other Comprehensive Income (Loss)	19			20			(16		)
COMPREHENSIVE INCOME (LOSS)	2,075			914			(610		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(139		)	(170		)	(175		)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	1,936		$	744		$	(785	)

The accompanying notes are an integral part of these consolidated financial statements.

75

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$	2,056		$	894		$	(594	)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	2,915			2,903			2,811
Deferred income tax expense (benefit)	1,097			526			(427		)
Derivative gains, net	(1,102		)	(71		)	(926		)
Cash (payments) receipts on derivative settlements, net	(253		)	(104		)	226
Stock-based compensation	59			98			120
Impairment of oil and natural gas properties	—			—			3,315
Net gains on sales of fixed assets	(199		)	(302		)	(267		)
Impairment of fixed assets and other	58			483			316
Losses on investments	80			229			164
Net (gains) losses on sales of investments	(67		)	7			(1,092		)
Restructuring and other termination costs	(15		)	175			2
Provision for legal contingencies	234			—			—
Losses on purchases of debt	63			40			200
Other	100			80			72
(Increase) decrease in accounts receivable and other assets	(21		)	5			(68		)
Decrease in accounts payable, accrued liabilities and other	(371		)	(349		)	(1,015		)
Net Cash Provided By Operating Activities	4,634			4,614			2,837
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(4,581		)	(5,604		)	(8,930		)
Acquisitions of proved and unproved properties	(1,311		)	(1,032		)	(3,161		)
Proceeds from divestitures of proved and unproved properties	5,813			3,467			5,884
Additions to other property and equipment	(726		)	(972		)	(2,651		)
Proceeds from sales of other property and equipment	1,003			922			2,492
Additions to investments	(17		)	(44		)	(395		)
Proceeds from sales of investments	239			115			2,000
Decrease (increase) in restricted cash	37			177			(222		)
Other	(3		)	4			(1		)
Net Cash Provided By (Used In) Investing Activities	454			(2,967		)	(4,984		)

The accompanying notes are an integral part of these consolidated financial statements.

76

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	7,406			7,669			20,318
Payments on credit facilities borrowings	(7,788		)	(7,682		)	(21,650		)
Proceeds from issuance of senior notes, net of discount and offering costs	2,966			2,274			1,263
Proceeds from issuance of oilfield services senior notes, net of discount and offering costs	494			—			—
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	394			—			—
Proceeds from issuance of term loan, net of issuance costs	—			—			5,722
Cash paid to purchase debt	(3,362		)	(2,141		)	(4,000		)
Cash paid for common stock dividends	(234		)	(233		)	(227		)
Cash paid for preferred stock dividends	(171		)	(171		)	(171		)
Cash paid to extinguish other financing	—			(141		)	—
Cash paid on financing derivatives	(53		)	(91		)	(37		)
Cash paid for prepayment of mortgage	—			(55		)	—
Proceeds from sales of noncontrolling interests	—			6			1,077
Proceeds from other financings	—			—			257
Cash paid to purchase preferred shares of a subsidiary	(1,254		)	(212		)	—
Cash held and retained by SSE at spin-off	(8		)	—			—
Distributions to noncontrolling interest owners	(173		)	(215		)	(218		)
Other	(34		)	(105		)	(251		)
Net Cash Provided By (Used In) Financing Activities	(1,817		)	(1,097		)	2,083
Net increase (decrease) in cash and cash equivalents	3,271			550			(64		)
Cash and cash equivalents, beginning of period	837			287			351
Cash and cash equivalents, end of period	$	4,108		$	837		$	287
Supplemental disclosures to the consolidated statements of cash flows are presented below:
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest	$	96		$	43		$	—
Income taxes paid, net of refunds received	$	10		$	26		$	44
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in accrued drilling and completion costs	$	(84	)	$	(63	)	$	(75	)
Change in accrued acquisitions of proved and unproved properties	$	(74	)	$	(1	)	$	242
Change in accrued additions to other property and equipment	$	(11	)	$	(81	)	$	(25	)

The accompanying notes are an integral part of these consolidated financial statements.

77

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
PREFERRED STOCK:
Balance, beginning and end of period	$	3,062		$	3,062		$	3,062
COMMON STOCK:
Balance, beginning and end of period	7			7			7
PAID-IN CAPITAL:
Balance, beginning of period	12,446			12,293			12,146
Stock-based compensation	47			162			174
Exercise of stock options	23			4			3
Increase (decrease) in tax benefit from stock-based compensation	15			(13		)	(30		)
Balance, end of period	12,531			12,446			12,293
RETAINED EARNINGS:
Balance, beginning of period	688			437			1,608
Net income (loss) attributable to Chesapeake	1,917			724			(769		)
Dividends on common stock	(234		)	(233		)	(231		)
Dividends on preferred stock	(171		)	(171		)	(171		)
Spin-off of oilfield services business (Note 13)	(270		)	—			—
Redemption of preferred shares of a subsidiary	(447		)	(69		)	—
Balance, end of period	1,483			688			437
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance, beginning of period	(162		)	(182		)	(166		)
Hedging activity	24			22			(11		)
Investment activity	(5		)	(2		)	(5		)
Balance, end of period	(143		)	(162		)	(182		)
TREASURY STOCK – COMMON:
Balance, beginning of period	(46		)	(48		)	(33		)
Purchase of 34,678, 251,403 and 652,443 shares for company benefit plans	(1		)	(6		)	(16		)
Release of 422,395, 397,098 and 57,252 shares from company benefit plans	10			8			1
Balance, end of period	(37		)	(46		)	(48		)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY	16,903			15,995			15,569
NONCONTROLLING INTERESTS:
Balance, beginning of period	2,145			2,327			1,337
Sales of noncontrolling interests	—			6			1,077
Net income attributable to noncontrolling interests	139			170			175
Distributions to noncontrolling interest owners	(169		)	(215		)	(218		)
Redemption of preferred shares of a subsidiary	(807		)	(143		)	—
Deconsolidation of investments, net	(6		)	—			(44		)
Balance, end of period	1,302			2,145			2,327
TOTAL EQUITY	$	18,205		$	18,140		$	17,896

The accompanying notes are an integral part of these consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Summary of Significant Accounting Policies

Description of Company

Chesapeake Energy Corporation ("Chesapeake" or the "Company") is an oil and natural gas exploration and production company engaged in the acquisition, exploration and development of properties for the production of oil, natural gas and natural gas liquids (NGL) from underground reservoirs. We also own oil and natural gas marketing and natural gas gathering and compression businesses, and prior to June 30, 2014, an oilfield services business (see Note 13). Our operations are located onshore in the United States.

Basis of Presentation

The accompanying consolidated financial statements of Chesapeake were prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated.

Accounting Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in actual results differing significantly from our estimates.

Consolidation

Chesapeake consolidates entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake has the ability to exercise significant influence through its investment. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Investments in securities not accounted for under the equity method have been designated as available-for-sale and, as such, are carried at fair value whenever this value is readily determinable. Otherwise, the investment is carried at cost. See Note 14 for further discussion of our investments. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis.

Noncontrolling Interests

Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests.

Variable Interest Entities

VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Along with a VIE that we consolidate, we also hold a variable interest in another VIE that is not consolidated because we are not the primary beneficiary. We continually monitor both our consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs.

Cash and Cash Equivalents and Restricted Cash

For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. Restricted cash consists of the balance required to be maintained by the terms of the agreement governing the activities of CHK Cleveland Tonkawa, L.L.C. (CHK C-T) and, prior to our repurchase of all of the outstanding preferred shares of CHK Utica, L.L.C. (CHK Utica) in 2014, also consisted of a balance required to be maintained by the terms of the agreement governing the activities of CHK Utica. The repurchase of outstanding preferred shares of CHK Utica eliminated the restricted cash maintenance requirement related to this entity. See Note 8 for further discussion of these entities.

Accounts Receivable

Our accounts receivable are primarily from purchasers of oil, natural gas and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables we believe may be uncollectible. During 2014, 2013 and 2012, we recognized $2 million, $2 million and a nominal amount of bad debt expense related to potentially uncollectible receivables, and we reduced our allowance by $3 million in 2013 as we wrote off specific receivables against our allowance. Accounts receivable as of December 31, 2014 and 2013 are detailed below.

	December 31,
	2014			2013
	($ in millions)
Oil, natural gas and NGL sales	$	1,340		$	1,548
Joint interest	691			417
Oilfield services(a)	—			63
Related parties(b)	—			62
Other	226			150
Allowance for doubtful accounts	(21		)	(18		)
Total accounts receivable, net	$	2,236		$	2,222

___________________________________________

(a) In 2014, in connection with the spin-off of our oilfield services business, accounts receivable related to oilfield services were removed from our consolidated balance sheet.

(b) See Note 7 for discussion of related party transactions.

Oil and Natural Gas Properties

Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with these activities and do not capitalize any costs related to production, general corporate overhead or similar activities (see Supplementary Information - Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. Estimates of our proved reserves as of December 31, 2014 were prepared by independent engineering firms and Chesapeake's internal staff. Approximately 79% of these proved reserves estimates (by volume) as of December 31, 2014 were prepared by independent engineering firms. In addition, our internal engineers review and update our reserves on a quarterly basis.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Proceeds from the sale of oil and natural gas properties are accounted for as reductions of capitalized costs unless these sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized.

The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unproved properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unproved properties are grouped by major prospect area where individual property costs are not significant. In addition, we analyze our unproved leasehold and transfer to proved properties leasehold that can be associated with proved reserves, leasehold that expired in the quarter or leasehold that is not a part of our development strategy and will be abandoned.

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2014 and the year in which the associated costs were incurred.

	Year of Acquisition
	2014		2013		2012		Prior		Total
	($ in millions)
Leasehold acquisition cost	$	577	$	199	$	1,462	$	5,149	$	7,387
Exploration cost	340		90		244		42		716
Capitalized interest	492		421		325		447		1,685
Total	$	1,409	$	710	$	2,031	$	5,638	$	9,788

We also review, on a quarterly basis, the carrying value of our oil and natural gas properties under the full cost accounting rules of the Securities and Exchange Commission (SEC). This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for oil and natural gas derivatives designated as cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The ceiling test calculation uses costs as of the end of the applicable quarterly period and the unweighted arithmetic average of oil, natural gas and NGL prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. As of December 31, 2014, none of our open derivative instruments were designated as cash flow hedges. Our oil and natural gas hedging activities are discussed in Note 11.

Two primary factors impacting the ceiling test are reserves levels and oil, natural gas and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an extended increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value over the ceiling is written off as an expense.

We account for seismic costs as part of our oil and natural gas properties. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. These costs are capitalized as incurred. The Company reviews its unproved properties and associated seismic costs quarterly to determine whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unproved properties, they are included in the amortization base as incurred.

Other Property and Equipment

Other property and equipment consists primarily of natural gas compressors, buildings and improvements, land, vehicles, computer and office equipment, oil and natural gas gathering systems and treating plants. We have no remaining oilfield services equipment as a result of the spin-off of our oilfield services business in 2014 as discussed in Note 13, and substantially all of our natural gas gathering systems and treating plants were sold in 2013 and 2012 as discussed in Note 16. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating costs. See Note 16 for further discussion of our gains and losses on the sales of other property and equipment and a summary of our

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

other property and equipment held for sale as of December 31, 2014 and 2013. Other property and equipment costs, excluding land, are depreciated on a straight-line basis.

Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. During 2014, 2013 and 2012, we determined that certain of our property and equipment was being carried at values that were not recoverable and in excess of fair value. See Note 17 for further discussion of these impairments.

Capitalized Interest

Interest from external borrowings is capitalized on significant projects until the asset is ready for service using the weighted average cost of outstanding borrowings. Capitalized interest is determined by multiplying our weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.

Goodwill

Goodwill represents the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment at least annually. This test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. When the qualitative assessment indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, the quantitative assessment is then performed. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense.

Our goodwill, which is included in other long-term assets on our consolidated balance sheets, was $15 million and $43 million, respectively, as of December 31, 2014 and 2013. The 2014 amount consists of $15 million of excess consideration over the fair value of assets acquired in our Horizon Drilling Services acquisition in 2011. The 2013 amount also included $28 million of excess consideration over the fair value of assets acquired in our Bronco Drilling Company acquisition in 2011. We no longer have the goodwill balance related to Bronco Drilling Company as a result of the spin-off of our oilfield services business in June 2014. We performed annual impairment tests of goodwill in the fourth quarters of 2014 and 2013. Based on these assessments, no impairment of goodwill was required. Goodwill was included in our exploration and production segment as of December 31, 2014 and as of December 31, 2013 was included in our former oilfield services segment.

Accounts Payable

Included in accounts payable as of December 31, 2014 and 2013 are liabilities of approximately $333 million and $397 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts.

Debt Issuance and Hedging Facility Costs

Included in other long-term assets are costs associated with the issuance of our senior notes, revolving credit facility, hedging facility and, as of December 31, 2013, costs associated with our former term loan and former oilfield services credit facility. The remaining unamortized issuance costs as of December 31, 2014 and 2013 totaled $130 million and $145 million, respectively, and are being amortized over the life of the applicable debt or facility using the effective interest method.

Environmental Remediation Costs

Chesapeake records environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Asset Retirement Obligations

We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. See Note 20 for further discussion of asset retirement obligations.

Revenue Recognition

Oil, Natural Gas and NGL Sales. Revenue from the sale of oil, natural gas and NGL is recognized when title passes, net of royalties due to third parties and gathering and transportation charges.

Natural Gas Imbalances. We follow the "sales method" of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of the remaining natural gas reserves on the underlying properties. The natural gas imbalance net liability position as of December 31, 2014 and 2013 was $12 million and $11 million, respectively.

Marketing, Gathering and Compression Sales. Chesapeake takes title to the oil, natural gas and NGL it purchases from other interest owners in operated wells at defined delivery points and delivers the product to third parties, at which time revenues are recorded. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments. In circumstances where we act as a principal rather than an agent, Chesapeake's results of operations related to its oil, natural gas and NGL marketing activities are presented on a "gross" basis. Gathering and compression revenues consist of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated.

Oilfield Services Revenue. Prior to the spin-off of our oilfield services business in June 2014, we reported oilfield services revenue. Our former oilfield services operating segment was responsible for contract drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Our oilfield services revenues prior to the spin-off were as follows:

• Drilling. Revenues were generated by drilling oil and natural gas wells for our customers under daywork contracts and recognized for the days completed based on the dayrate specified in each contract. Revenue generated and costs incurred for mobilization services were recognized over the days of actual mobilization.

• Hydraulic Fracturing. Revenue was recognized upon the completion of each fracturing stage. Typically, one or more fracturing stages per day per active crew was completed during the course of a job. A stage was considered complete when the customer requested or the job design dictated that pumping discontinue for that stage. Invoices typically included a lump sum equipment charge determined by the rate per stage specified in each contract and product charges for sand, chemicals and other products actually consumed during the course of providing fracturing services.

• Oilfield Rentals. Oilfield equipment rentals included drill pipe, drill collars, tubing, blowout preventers, and frac and mud tanks, and services included air drilling services and services associated with the transfer of fresh water to the wellsite. Rentals and services were priced by the day or hour based on the type of equipment rented and the service job performed. Revenue was recognized ratably over the term of the rental.

• Oilfield Trucking. Oilfield trucking provided rig relocation and logistics services as well as fluid handling services. Trucks moved drilling rigs, crude oil, other fluids and construction materials to and from the wellsites and also transported produced water from the wellsites. These services were priced on a per barrel basis based on mileage and revenue was recognized as services were performed.

• Other Operations. A manufacturing subsidiary designed, engineered and fabricated natural gas compressor packages that were purchased primarily by Chesapeake. Compression units were priced based on certain specifications such as horsepower, stages and additional options. Revenue was recognized upon completion and transfer of ownership of the natural gas compression unit.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Fair Value Measurements

Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

The carrying values of financial instruments comprising cash and cash equivalents, restricted cash, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments.

Derivatives

Derivative instruments are recorded on our consolidated balance sheets as derivative assets or derivative liabilities at fair value, and changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. For qualifying commodity derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Locked-in gains and losses of settled cash flow hedges are recorded in accumulated other comprehensive income and are transferred to earnings in the month of production. Changes in the fair value of interest rate derivative instruments designated as fair value hedges are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent hedge ineffectiveness and are recognized currently in earnings. Locked-in gains and losses related to settled fair value hedges are amortized as an adjustment to interest expense over the remaining term of the related senior notes. We have elected not to designate any of our qualifying commodity and interest rate derivatives as cash flow or fair value hedges. Therefore, changes in fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in our consolidated statements of operations within oil, natural gas and NGL sales and interest expense, respectively.

Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our derivative instruments are subject to master netting arrangements by contract type (i.e., commodity, interest rate and cross currency contracts) which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets.

We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. See Note 11 for further discussion of our derivative instruments.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Share-Based Compensation

Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize in our financial statements the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three or four years from the grant date. For directors, although restricted stock grants vest over three years, this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units can only be settled in cash, they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as compensation expense in the consolidated statements of operations.

To the extent compensation cost relates to employees directly involved in the acquisition of oil and natural gas leasehold and exploration and development activities, these amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses, oil, natural gas and NGL production expenses, or marketing, gathering and compression expenses, based on the employees involved in those activities.

Cash inflows resulting from tax deductions in excess of compensation expense recognized for stock options and restricted stock are classified as financing cash inflows, while reductions in tax benefits are classified as operating cash outflows in our consolidated statements of cash flows. See Note 9 for further discussion of share-based compensation.

Reclassifications

Certain reclassifications have been made to the consolidated financial statements for 2012 and 2013 to conform to the presentation used for the 2014 consolidated financial statements.

2. Earnings Per Share

Basic earnings per share (EPS) is calculated using the weighted average number of common shares outstanding during the period and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide dividend rights.

Diluted EPS is calculated assuming the issuance of common shares for all potentially dilutive securities, provided the effect is not antidilutive. For the years ended December 31, 2014, 2013 and 2012, our contingent convertible senior notes did not have a dilutive effect and therefore were excluded from the calculation of diluted EPS. See Note 3 for further discussion of our contingent convertible senior notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

For the years ended December 31, 2014, 2013 and 2012, shares of the following securities and associated adjustments to net income, representing dividends on preferred stock and allocated earnings on participating securities, were excluded from the calculation of diluted EPS as the effect was antidilutive. The impact of our stock options was immaterial in the calculation of diluted EPS for these periods.

	Net Income Adjustments		Shares
	($ in millions)		(in millions)
Year Ended December 31, 2014
Participating securities	$	22	3
Year Ended December 31, 2013
Common stock equivalent of our preferred stock outstanding:
5.75% cumulative convertible preferred stock	$	86	56
5.75% cumulative convertible preferred stock (series A)	$	63	40
5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
4.50% cumulative convertible preferred stock	$	12	6
Participating securities	$	10	5
Year Ended December 31, 2012
Common stock equivalent of our preferred stock outstanding:
5.75% cumulative convertible preferred stock	$	86	56
5.75% cumulative convertible preferred stock (series A)	$	63	39
5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
4.50% cumulative convertible preferred stock	$	12	6
Participating securities	$	—	5

For the year ended December 31, 2014, all outstanding equity securities convertible into common stock were included in the calculation of diluted EPS. A reconciliation of basic EPS and diluted EPS for the year ended December 31, 2014 is as follows: 

	Income (Numerator)		Weighted Average Shares (Denominator)	Per Share Amount
	(in millions, except per share data)
For the Year Ended December 31, 2014:
Basic EPS	$	1,273	659	$	1.93
Effect of Dilutive Securities:
Assumed conversion as of the beginning of the period     of preferred shares outstanding during the period:
Common shares assumed issued for 5.75% cumulative convertible preferred stock	86		59
Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)	63		42
Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)	10		6
Common shares assumed issued for 4.50% cumulative convertible preferred stock	12		6
Diluted EPS	$	1,444	772	$	1.87

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

3. Debt

Our long-term debt consisted of the following as of December 31, 2014 and 2013:

	December 31,
	2014			2013
	($ in millions)
Term loan due 2017(a)	$	—		$	2,000
9.5% senior notes due 2015(b)	—			1,265
3.25% senior notes due 2016	500			500
6.25% euro-denominated senior notes due 2017(c)	416			473
6.5% senior notes due 2017	660			660
6.875% senior notes due 2018(d)	—			97
7.25% senior notes due 2018	669			669
Floating rate senior notes due 2019	1,500			—
6.625% senior notes due 2019(e)	—			650
6.625% senior notes due 2020	1,300			1,300
6.875% senior notes due 2020	500			500
6.125% senior notes due 2021	1,000			1,000
5.375% senior notes due 2021	700			700
4.875% senior notes due 2022	1,500			—
5.75% senior notes due 2023	1,100			1,100
2.75% contingent convertible senior notes due 2035(f)	396			396
2.5% contingent convertible senior notes due 2037(f)	1,168			1,168
2.25% contingent convertible senior notes due 2038(f)	347			347
Revolving credit facility	—			—
Oilfield services revolving credit facility(g)	—			405
Discount on senior notes and term loan(h)	(231		)	(357		)
Interest rate derivatives(i)	10			13
Total debt, net	11,535			12,886
Less current maturities of long-term debt, net(j)	(381		)	—
Total long-term debt, net	$	11,154		$	12,886

___________________________________________

(a) In 2014, we repaid the borrowings outstanding under and terminated the term loan due 2017.

(b) In 2014, we completed a tender offer for a portion of the 9.5% Senior Notes due 2015, and we redeemed the remaining balance of the notes.

(c) The principal amount shown is based on the exchange rate of $1.2098 to €1.00 and $1.3743 to €1.00 as of December 31, 2014 and 2013, respectively. See Note 11 for information on our related foreign currency derivatives.

(d) In 2014, we redeemed all outstanding 6.875% Senior Notes due 2018.

(e) Initial issuers were Chesapeake Oilfield Operating, L.L.C. (COO) and Chesapeake Oilfield Finance, Inc., a wholly owned subsidiary of COO. Chesapeake Energy Corporation is the issuer of all other senior notes and the contingent convertible senior notes. In 2014, in connection with the spin-off of our oilfield services business, the obligations with respect to the COO senior notes were removed from our consolidated balance sheet. See Note 13 for further discussion of the spin-off.

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(f) The repurchase, conversion, contingent interest and redemption provisions of our contingent convertible senior notes are as follows:

Holders’ Demand Repurchase Rights. The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date.

Optional Conversion by Holders. At the holder’s option, prior to maturity under certain circumstances, the notes are convertible into cash and, if applicable, shares of our common stock using a net share settlement process. One such triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the specified period in the fourth quarter of 2014, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash and common stock in the first quarter of 2015 under this provision.

The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. The notes were not convertible under this provision in 2014, 2013 or 2012. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note’s conversion value in excess of the principal amount.

Contingent Interest. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years during certain periods if the average trading price of the notes exceeds the threshold defined in the indenture.

The holders’ demand repurchase dates, the common stock price conversion threshold amounts (as adjusted to give effect to the dividend of SSE common stock paid in the spin-off of our oilfield services business and cash dividends on our common stock) and the ending date of the first six-month period in which contingent interest may be payable for the contingent convertible senior notes are as follows:

Contingent       Convertible       Senior  Notes	Holders' Demand Repurchase Dates	Common Stock  Price Conversion  Thresholds		Contingent Interest First Payable (if applicable)
2.75% due 2035	November 15, 2015, 2020, 2025, 2030	$	45.14	May 14, 2016
2.5% due 2037	May 15, 2017, 2022, 2027, 2032	$	59.71	November 14, 2017
2.25% due 2038	December 15, 2018, 2023, 2028, 2033	$	100.35	June 14, 2019

Optional Redemption by the Company. We may redeem the contingent convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of the notes, payable in cash.

(g) In 2014, in connection with the spin-off of our oilfield services business, we terminated our oilfield services credit facility. See Note 13 for further discussion of the spin-off.

(h) Discount as of December 31, 2014 and 2013 included $224 million and $303 million, respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. Discount also included $33 million as of December 31, 2013 associated with our term loan due 2017 discussed below.

(i) See Note 11 for further discussion related to these instruments.

(j) As of December 31, 2014, there was $15 million of discount associated with the equity component of the 2.75% Contingent Convertible Senior Notes due 2035. As discussed in footnote (f) above, the holders of our 2.75% Contingent Convertible Senior Notes due 2035 could exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the principal amount of the notes.

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Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes, for the five years ended after December 31, 2014 and thereafter are as follows:

	Principal Amount of Debt Securities
	($ in millions)
2015	$	396
2016	500
2017	2,244
2018	1,016
2019	1,500
2020 and thereafter	6,100
Total	$	11,756

Term Loan

In November 2012, we established an unsecured five-year term loan credit facility in an aggregate principal amount of $2.0 billion for net proceeds of $1.935 billion. The term loan provided that it could be voluntarily repaid before November 9, 2015 at par plus a specified premium and at any time thereafter at par. The maturity date of the term loan was December 2, 2017. In 2014, we used a portion of the net proceeds from our offering of $3.0 billion in aggregate principal amount of senior notes to repay the borrowings under, and terminate, the term loan. We recorded a loss of $90 million, consisting of $40 million in premiums, $30 million of unamortized discount and $20 million of unamortized deferred charges, in connection with the termination.

Chesapeake Senior Notes and Contingent Convertible Senior Notes

The Chesapeake senior notes and the contingent convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Chesapeake is a holding company, owns no operating assets and has no significant operations independent of its subsidiaries. Chesapeake’s obligations under the senior notes and the contingent convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect 100% owned subsidiaries. See Note 22 for consolidating financial information regarding our guarantor and non-guarantor subsidiaries.

We may redeem the senior notes, other than the contingent convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale-leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the senior notes and the contingent convertible senior notes do not have any financial or restricted payment covenants. The senior notes and contingent convertible senior notes indentures have cross default provisions that apply to other indebtedness the Company or any guarantor subsidiary may have from time to time with an outstanding principal amount of at least $50 million or $75 million, depending on the indenture.

We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense at the interest rate of similar nonconvertible debt at the time of issuance. The applicable rates for our 2.75% Contingent Convertible Senior Notes due 2035, our 2.5% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038 are 6.86%, 8.0% and 8.0%, respectively.

During 2014, we issued $3.0 billion in aggregate principal amount of senior notes at par. The offering included two series of notes: $1.5 billion in aggregate principal amount of Floating Rate Senior Notes due 2019 and $1.5 billion in aggregate principal amount of 4.875% Senior Notes due 2022. We used a portion of the net proceeds of $2.966 billion to repay the borrowings under, and terminate, our term loan credit facility. We used the remaining proceeds along with cash on hand to redeem the remaining $97 million principal amount of the 6.875% Senior Notes due 2018 and to purchase and redeem the remaining $1.265 billion principal amount of the 9.5% Senior Notes due 2015 for $1.454 billion. We recorded a loss of approximately $6 million associated with the redemption of the 6.875% Senior Notes due 2018, which consisted of $5 million in premiums and $1 million of unamortized deferred charges. We recorded

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a loss of approximately $99 million associated with the purchase and redemption of the 9.5% Senior Notes due 2015, which consisted of $87 million in premiums, $9 million of unamortized discount and $3 million of unamortized deferred charges.

During 2013, we issued $2.3 billion in aggregate principal amount of senior notes at par. The offering included three series of notes: $500 million in aggregate principal amount of 3.25% Senior Notes due 2016; $700 million in aggregate principal amount of 5.375% Senior Notes due 2021; and $1.1 billion in aggregate principal amount of 5.75% Senior Notes due 2023. We used a portion of the net proceeds of $2.274 billion to repay outstanding indebtedness under our revolving credit facility and purchase certain senior notes. We purchased $217 million in aggregate principal amount of our 7.625% Senior Notes due 2013 for $221 million and $377 million in aggregate principal amount of our 6.875% Senior Notes due 2018 for $405 million pursuant to tender offers during 2013. We recorded a loss of approximately $37 million associated with the tender offers, including $32 million in premiums and $5 million of unamortized deferred charges. During 2013, we also redeemed $1.3 billion in aggregate principal amount of our 6.775% Senior Notes due 2019 (the 2019 Notes) at par pursuant to notice of special early redemption. We recorded a loss of approximately $33 million associated with the redemption, including $19 million of unamortized deferred charges and $14 million of discount. As described in the following paragraph, our redemption of the 2019 Notes has been the subject of litigation. On July 15, 2013, we retired at maturity the remaining $247 million aggregate principal amount outstanding of our 7.625% Senior Notes due 2013.

In March 2013, the Company brought suit in the U.S. District Court for the Southern District of New York against The Bank of New York Mellon Trust Company, N.A., the indenture trustee for the 2019 Notes. The Company sought and ultimately obtained a judgment declaring that the notice it issued on March 15, 2013 to redeem all of the 2019 Notes at par (plus accrued interest through the redemption date) was timely and effective for that redemption pursuant to the special early redemption provision of the supplemental indenture governing the 2019 Notes. In May 2013, as a result of that ruling, the 2019 Notes were redeemed at par. In November 2014, the U.S. Court of Appeals for the Second Circuit, on appeal by the indenture trustee, reversed the District Court’s declaratory judgment and held that the notice was not effective to redeem the 2019 Notes at par because it was not timely for that purpose. The Court of Appeals remanded the case to the District Court for a determination whether the redemption notice triggered a redemption at the make-whole price specified in the indenture, instead of at par. The Company sought a rehearing by the Court of Appeals en banc in December 2014, and that petition was denied on February 6, 2015. On February 13, 2015, the indenture trustee filed a motion in the District Court for entry of a judgment requiring the Company to pay the make-whole price, as defined in the indenture, less the par amount paid in the 2013 redemption plus prejudgment interest at the statutory 9% rate from the redemption date. The Company intends to oppose the trustee’s motion vigorously.

On December 30, 2014, six former holders of the 2019 Notes filed a putative class action against the Company on behalf of all former holders who sold the 2019 Notes after the Company issued the notice of early redemption in March 2013 but before the notes were redeemed at par in May 2013. These former holders allege that the Company breached the indenture by issuing a wrongful notice of special early redemption, and that this breach caused the market value of the notes to decline, injuring them when they sold their 2019 Notes. This suit has been assigned to the same District Court judge as the suit described above. The Company intends to defend itself against this claim vigorously.

No scheduled principal payments are required on our senior notes until 2016 unless the holders of our 2.75% Contingent Convertible Senior Notes due 2035 exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the $396 million principal amount of notes.

Revolving Credit Facility

In December 2014, we entered into a new five-year $4.0 billion senior unsecured revolving credit facility to use for general corporate purposes. The new credit facility replaced our then-existing $4.0 billion senior secured revolving credit facility that was scheduled to mature in December 2015. The aggregate commitments under the facility may be increased up to an additional $1.0 billion, and the December 2019 maturity date may be extended for twoone-year periods at our request and with the consent of the participating lenders. As of December 31, 2014, we had no outstanding borrowings under the facility and utilized $15 million of the facility for various letters of credit. Borrowings under the facility are currently unsecured; however, we will be required to provide collateral and the facility will be subject to a borrowing base if our credit rating declines to Ba3 (Moody’s Investors Services, Inc.) or BB- (Standard & Poor’s Ratings Services) or lower.

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Revolving loans under the revolving credit facility bear interest at a fluctuating rate per annum equal to the highest of (i) the federal funds effective rate plus 0.5%, (ii) the administrative agent’s prime rate or (iii) the London interbank offer rate (LIBOR) for a one-month interest period plus 1.0% (alternative base rate (ABR) loans), and/or LIBOR rates (LIBOR loans), at our election, plus an applicable margin rate depending on our credit rating (currently 0.625% per annum for ABR loans and 1.625% per annum for LIBOR loans). The terms of the credit facility include covenants limiting, among other things, the ability of the Company and its restricted subsidiaries to incur additional indebtedness, make investments or loans, create liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates. In addition, the credit facility requires us to maintain, as of the last day of each fiscal quarter, (i) a net debt to capitalization ratio (as defined in the credit agreement) that does not exceed 65%; and (ii) a leverage ratio (net debt to consolidated EBITDA, as defined in the credit agreement) that does not exceed 4.0 to 1.0; provided, however, that the leverage ratio will not apply during any period in which our credit rating, as determined by either Moody’s Investors Services, Inc. or Standard & Poor’s Rating Services, meet and continue to meet certain investment grade thresholds, as defined in the credit agreement.

Our credit facility is fully and unconditionally guaranteed, on a joint and several basis, by certain of our material subsidiaries. The credit agreement includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $125 million or more; bankruptcy; judgments involving liability of $125 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods.

Spin-Off Debt Transactions

Prior to the spin-off of our oilfield services business, COO or its subsidiaries completed the following debt transactions:

• Entered into a five-year senior secured revolving credit facility with total commitments of $275 million and incurred approximately $3 million in financing costs related to entering into the facility.

• Entered into a $400 millionseven-year secured term loan and used the net proceeds of approximately $394 million and borrowings under the new revolving credit facility to repay and terminate COO’s existing credit facility.

• Issued $500 million in aggregate principal amount of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds of approximately $494 million to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility discussed above and for general corporate purposes.

All deferred charges and debt balances related to these transactions were removed from our consolidated balance sheet as of June 30, 2014. See Note 13 for further discussion of the spin-off.

Fair Value of Debt

We estimate the fair value of our exchange-traded debt using quoted market prices (Level 1). The fair value of all other debt, which currently consists of our revolving credit facility and as of December 31, 2013 also consisted of our former oilfield services credit facility and term loan, is estimated using our credit default swap rate (Level 2). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.

	December 31, 2014				December 31, 2013
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
			($ in millions)
Long-term debt (Level 1)	$	11,525	$	12,052	$	10,501	$	11,557
Long-term debt (Level 2)	$	—	$	—	$	2,372	$	2,369

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4. Contingencies and Commitments

Contingencies

Litigation and Regulatory Proceedings

The Company is involved in a number of litigation and regulatory proceedings (including those described below). Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. We estimate and provide for potential losses that may arise out of litigation and regulatory proceedings to the extent that such losses are probable and can be reasonably estimated. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different. Our total estimated liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. We account for legal defense costs in the period the costs are incurred.

July 2008 Common Stock Offering Litigation. On February 25, 2009, a putative class action was filed in the U.S. District Court for the Southern District of New York against the Company and certain of its officers and directors along with certain underwriters of the Company’s July 2008 common stock offering. The plaintiff filed an amended complaint on September 11, 2009 alleging that the registration statement for the offering contained material misstatements and omissions and seeking damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified amount and rescission. The action was transferred to the U.S. District Court for the Western District of Oklahoma on October 13, 2009. Chesapeake and the officer and director defendants moved for summary judgment on grounds of loss causation and materiality on December 28, 2011, and the motion was granted as to all claims as a matter of law on March 29, 2013. On appeal, the U.S. Court of Appeals for the Tenth Circuit affirmed the dismissal on August 8, 2014 and denied the plaintiffs’ petition for rehearing on November 12, 2014.

Shareholder Derivative Litigation. A derivative action relating to the July 2008 offering was filed in the U.S. District Court for the Western District of Oklahoma on September 6, 2011. The case was thereafter stayed by stipulation between the parties, and on November 20, 2014, the parties entered a stipulation to have the case voluntarily dismissed. On January 16, 2015, pursuant to Court order, the Company provided notice to shareholders of the voluntary dismissal and allowed eligible shareholders to intervene.

A federal consolidated derivative action and an Oklahoma state court derivative action have been stayed since 2012 pending resolution of a related, previously reported putative federal securities class action. The shareholder derivative actions allege breaches of fiduciary duty, among other things, related to the former CEO’s personal financial practices and purported conflicts of interest, and the Company’s accounting for volumetric production payments. With the dismissal of the federal securities class action now affirmed, the parties have stipulated to continue the stay of the Oklahoma state court derivative action while the plaintiffs pursue their claims in the federal consolidated derivative action. The plaintiffs filed a consolidated derivative complaint on October 31, 2014 and an amended consolidated derivative complaint on February 12, 2015. Chesapeake filed its motion to dismiss on February 23, 2015.

Regulatory Proceedings. The Company has received, from the U.S. Department of Justice (DOJ) and certain state governmental agencies and authorities, subpoenas and demands for documents, information and testimony in connection with investigations into possible violations of federal and state antitrust laws relating to our purchase and lease of oil and gas rights in various states. The Company also has received DOJ and state subpoenas seeking information on the Company’s royalty payment practices. Chesapeake has engaged in discussions with the DOJ and state representatives and continues to respond to such subpoenas and demands.

On March 5, 2014, the Attorney General of the State of Michigan filed a criminal complaint against Chesapeake in Michigan state court alleging misdemeanor antitrust violations and attempted antitrust violations under state law arising out of the Company’s leasing activities in Michigan during 2010. On July 9, 2014, following a preliminary hearing on the complaint, as amended, the 89^th District Court for Cheboygan County, Michigan ruled that one count alleging a bid-rigging conspiracy between Chesapeake and Encana Oil & Gas USA, Inc. regarding the October 2010 state lease auction would proceed to trial and dismissed claims alleging a second antitrust violation and an attempted antitrust violation. A trial date of April 15, 2015 has been set for this case. The Michigan Attorney General filed a second criminal complaint against Chesapeake in the same court on June 5, 2014 which, as amended, alleges that Chesapeake’s conduct in canceling lease offers to Michigan landowners in 2010 violated the state’s criminal enterprises and false pretenses felony statutes. On September 9, 2014, following a preliminary hearing, the Court ruled that all charges in the complaint would be tried. No trial date has been set for this matter.

Redemption of 2019 Notes. See Note 3 for a description of pending litigation regarding our redemption in May 2013 of our 2019 Notes. As a result of the reversal of the trial court’s decision in our declaratory judgment action against the indenture trustee, we have accrued a loss contingency of $100 million for this matter. We estimate the range of potential loss between $100 million to $380 million, plus prejudgment interest of up to 9%. The high end of this range is based upon the indenture trustee’s request in mid-February 2015 that the Court order us to pay noteholders the “make-whole” amount (as defined in the indenture) less the par amount already paid. Our $100 million accrual is based on an estimate of the remedy required to restore the redeemed noteholders and the Company to the economic positions they would have been in had the 2019 Notes not been redeemed. We are unable to estimate an amount or range of loss with respect to the recently filed putative class action by certain former holders of the 2019 Notes.

Business Operations. Chesapeake is involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. With regard to contract actions, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their oil and natural gas interests and pay acreage bonus payments, damages based on breach of contract and/or, in certain cases, punitive damages based on alleged fraud. The Company has successfully defended a number of these failure-to-close cases in various courts, has settled and resolved other such cases and disputes and believes that its remaining loss exposure for these claims will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. In addition, as described above, the Michigan Attorney General has commenced a criminal proceeding against us based on lease offers to Michigan landowners in 2010.

Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits against us allege, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL. The Company has resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. We are currently defending lawsuits seeking damages for royalty underpayment in various states, including cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The Company also has received DOJ and state subpoenas seeking information on the Company’s royalty payment practices.

Plaintiffs have varying royalty provisions in their respective leases and oil and gas law varies from state to state. Royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations, an issue in a putative class action filed in November 2010 in the District Court of Beaver County, Oklahoma on behalf of Oklahoma royalty owners asserting claims dating back to 2004. In July 2014, this case was remanded to the trial court for further proceedings following the reversal on appeal of certification of a statewide class. We and the named plaintiff participated in mediation concerning the claims asserted in the putative class action litigation and have negotiated a settlement requiring the Company to pay $119 million cash to compensate the putative settlement class for alleged past royalty underpayments in exchange for the release of claims for the ten-year period ended December 31, 2014. The plaintiff filed a motion for preliminary approval of the settlement on January 2, 2015. The Company has accrued a loss contingency for the settlement amount in the 2014 consolidated statement of operations. A fairness hearing on the settlement has been scheduled for April 17, 2015. Although Chesapeake believes that its royalty calculation and payment methodologies are appropriate under Oklahoma oil and gas law and denies that it committed any acts or omissions giving rise to any liability, it also believes that settlement is in the best interest of the Company considering the questions of law and fact involved and the uncertainty of continued litigation. There can be no assurance the court will approve the settlement, however, and the final resolution of the Oklahoma royalty claims could differ from the amount accrued.

We believe losses are reasonably possible in certain of the other pending royalty cases for which we have not accrued a loss contingency, but we are currently unable to estimate an amount or range of loss or the impact the actions could have on our future results of operations or cash flows. In Pennsylvania, three putative statewide class actions and one purported class arbitration have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the Company’s divestiture of substantially all of its midstream business and most of its gathering assets in 2012 and 2013. These Pennsylvania cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and one of the cases includes claims of intentional interference with contractual relations and violations of antitrust laws. Uncertainties in pending royalty cases generally include the complex nature of the claims and defenses, the potential size of the class in class actions, the scope and types of the properties and agreements involved, and the applicable production years.

Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to the Company’s business operations is likely to have a material adverse effect on its future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

Environmental Contingencies

The nature of the oil and gas business carries with it certain environmental risks for Chesapeake and its subsidiaries. Chesapeake has implemented various policies, procedures, training and auditing to reduce and mitigate such environmental risks. Chesapeake conducts periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, Chesapeake may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.

Commitments

Operating Leases

Future operating lease commitments related to other property and equipment are not recorded in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future lease payments are presented below.

	December 31, 2014
	($ in millions)
2015	$	5
2016	4
2017	1
2018	1
Total	$	11

Lease expense for the years ended December 31, 2014, 2013 and 2012 was $33 million, $158 million and $185 million, respectively. Lease expense decreased significantly in 2014 primarily due to the repurchase of all rigs and compressors previously sold under long-term sale-leaseback arrangements.

Gathering, Processing and Transportation Agreements

We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of natural gas and liquids to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded in the accompanying consolidated balance sheets; however, they are reflected as adjustments to oil, natural gas and NGL sales prices used in our proved reserves estimates.

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The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners or credits for third-party volumes, are presented below.

	December 31, 2014
	($ in millions)
2015	$	1,855
2016	1,987
2017	2,003
2018	1,802
2019	1,516
2020 - 2099	6,880
Total	$	16,043

In addition to the gathering, processing and transportation agreements discussed above, we have entered into long-term agreements for certain natural gas gathering and related services within specified acreage dedication areas in exchange for cost-of-service based fees redetermined annually or tiered fees based on volumes delivered relative to scheduled volumes. Future gathering fees will vary depending on the applicable agreement. Two of these agreements, one for production in the Anadarko Basin and the other for production in the Haynesville/Bossier Shales in northwestern Louisiana, contain cost-of-service based fees that are redetermined annually through 2019 and 2020, respectively. The annual upward or downward fee adjustment for these two contracts is capped at 15% of the then-current fees at the time of redetermination. To the extent the actual rate of return on capital expended by the counterparty over the term of the agreement differs from the applicable rate of return, a payment is due to (from) the midstream service company.

Drilling Contracts

We have contracts with various drilling contractors, including those entered into with Seventy Seven Energy Inc. (SSE) in connection with the spin-off of our oilfield services business as discussed in Note 13, to utilize drilling services with terms ranging from three months to three years at market-based pricing. These commitments are not recorded in the accompanying consolidated balance sheets. As of December 31, 2014, the aggregate undiscounted minimum future payments under these drilling service commitments are detailed below.

	December 31, 2014
	($ in millions)
2015	$	232
2016	179
2017	91
Total	$	502

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Pressure Pumping Contracts

As discussed in Note 13, in connection with the spin-off of our oilfield services business we entered into an agreement with a subsidiary of SSE related to pressure pumping services. The services agreement requires us to utilize, at market-based pricing, the lesser of (i) seven, five and three pressure pumping crews in years one, two and three of the agreement, respectively, or (ii) 50% of the total number of all pressure pumping crews working for us in all of our operating regions during the respective year. We are also required to utilize SSE pressure pumping services for a minimum number of fracture stages as set forth in the agreement. We are entitled to terminate the agreement in certain situations, including if SSE fails to provide the overall quality of service provided by similar service providers. The aggregate undiscounted minimum future payments under this agreement are detailed below.

	December 31, 2014
	($ in millions)
2015	$	245
2016	162
2017	59
Total	$	466

Drilling Commitments

We have committed to drill wells for the benefit of CHK Cleveland Tonkawa, L.L.C. and Chesapeake Granite Wash Trust. See Noncontrolling Interests in Note 8 for discussion of these commitments.

Natural Gas and Liquids Purchase Commitments

We regularly commit to purchase natural gas and liquids from other owners in the properties we operate, including owners associated with our volumetric production payment (VPP) transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices. See Note 12 for further discussion of our VPP transactions.

Net Acreage Maintenance Commitments

Under the terms of our joint venture agreements with Total and Sinopec (see Note 12), we are required to extend, renew or replace expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas as of future measurement dates. To date, we have satisfied our replacement commitments under the Sinopec agreement. In 2014, we settled a dispute with Total regarding our acreage maintenance obligation as of December 31, 2012 for $50 million. The payment was based on a shortfall of approximately 20,800 net acres.

Other Commitments

In July 2011, we agreed to invest $155 million in preferred equity securities of Sundrop Fuels, Inc. (Sundrop), a privately held cellulosic biofuels company based in Longmont, Colorado. We also provided Sundrop with a one-time option to require us to purchase up to $25 million in additional preferred equity securities following the full payment of the initial investment, subject to the occurrence of specified milestones. As of December 31, 2014, we had funded our $155 million commitment in full and the milestones related to Sundrop’s preferred equity call option had not been met. See Note 14 for further discussion of this investment.

As part of our normal course of business, we enter into various agreements providing, or otherwise arranging for, financial or performance assurances to third parties on behalf of our wholly owned guarantor subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance.

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In connection with divestitures, our purchase and sale agreements generally provide indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party and/or other specified matters. These indemnifications generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or cannot be quantified at the time of entering into or consummating a particular transaction. For divestitures of oil and gas properties, our purchase and sale agreements may require the return of a portion of the proceeds we receive as a result of uncured title defects.

Certain of our oil and natural gas properties are burdened by non-operating interests such as royalty and overriding royalty interests, including overriding royalty interests sold through our VPP transactions. As the holder of the working interest from which these interests have been created, we have the responsibility to bear the cost of developing and producing the reserves attributable to these interests. See Note 12 for further discussion of our VPP transactions.

While executing our strategic priorities, we have incurred certain cash charges, including contract termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity. As we continue to focus on our strategic priorities, certain actions that may reduce financial leverage and complexity could negatively impact our future results of operations and/or liquidity, and we may incur additional cash and noncash charges.

5. Other Liabilities

Other current liabilities as of December 31, 2014 and 2013 are detailed below.

	December 31,
	2014		2013
	($ in millions)
Revenues and royalties due others	$	1,176	$	1,409
Accrued oil, natural gas and NGL drilling and production costs	385		457
Joint interest prepayments received	189		464
Accrued compensation and benefits	344		320
Other accrued taxes	55		161
Accrued dividends	101		101
Other	811		599
Total other current liabilities	$	3,061	$	3,511

Other long-term liabilities as of December 31, 2014 and 2013 are detailed below.

	December 31,
	2014		2013
	($ in millions)
CHK Utica ORRI conveyance obligation(a)	$	220	$	250
CHK C-T ORRI conveyance obligation(b)	135		149
Financing obligations	30		31
Unrecognized tax benefits	45		317
Other	249		237
Total other long-term liabilities	$	679	$	984

____________________________________________

(a) $14 million and $13 million of the total $234 million and $263 million obligations are recorded in other current liabilities as of December 31, 2014 and 2013, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction.

(b) $23 million and $12 million of the total $158 million and $161 million obligations are recorded in other current liabilities as of December 31, 2014 and 2013, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction.

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6. Income Taxes

The components of the income tax provision (benefit) for each of the periods presented below are as follows:

	Years Ended December 31,
	2014			2013		2012
	($ in millions)
Current
Federal	$	—		$	—	$	—
State	47			22		47
Current Income Taxes	47			22		47
Deferred
Federal	1,115			502		(358		)
State	(18		)	24		(69		)
Deferred Income Taxes	1,097			526		(427		)
Total	$	1,144		$	548	$	(380	)

The effective income tax expense (benefit) differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons:

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Income tax expense (benefit) at the federal statutory rate (35%)	$	1,120		$	505		$	(341	)
State income taxes (net of federal income tax benefit)	68			88			(38		)
Remeasurement of state deferred tax liabilities	(114		)	(38		)	(19		)
Change in valuation allowance	74			(12		)	—
Other	(4		)	5			18
Total	$	1,144		$	548		$	(380	)

During the 2014 fourth quarter, Chesapeake simplified its organizational structure which impacts how income (loss) is allocated and apportioned to various states. This change resulted in a $114 million tax benefit due to the remeasurement of state deferred tax liabilities. Additionally, we reassessed the realizability of our deferred tax assets given the decline in commodity prices. We recorded a $74 million tax expense for the increase in our valuation allowance.

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Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:

	Years Ended December 31,
	2014			2013
	($ in millions)
Deferred tax liabilities:
Oil and natural gas properties	$	(3,950	)	$	(2,631	)
Other property and equipment	(14		)	(371		)
Volumetric production payments	(920		)	(1,216		)
Contingent convertible debt	(443		)	(439		)
Deferred revenue	(102		)	—
Derivative instruments	(428		)	—
Deferred tax liabilities	(5,857		)	(4,657		)
Deferred tax assets:
Net operating loss carryforwards (carrybacks)	945			535
Derivative instruments	—			108
Asset retirement obligations	165			153
Investments	88			130
Deferred stock compensation	50			66
Accrued liabilities	214			120
Noncontrolling interest liabilities	135			152
Alternative minimum tax credits	34			317
Other	56			40
Deferred tax assets	1,687			1,621
Valuation allowance	(222		)	(148		)
Net deferred tax assets	1,465			1,473
Net deferred tax assets (liabilities)	$	(4,392	)	$	(3,184	)
Reflected in accompanying balance sheets as:
Current deferred income tax asset	—			223
Current deferred income tax liability	(207		)	—
Non-current deferred income tax liability	(4,185		)	(3,407		)
Total	$	(4,392	)	$	(3,184	)

As of December 31, 2014, Chesapeake had federal income tax NOL carryforwards of approximately $1.6 billion and state NOL carryforwards of approximately $8.3 billion which excludes the NOL carryforwards related to unrecognized tax benefits and stock compensation windfalls that have not been recognized under U.S. GAAP. The associated deferred tax assets related to these NOL carryforwards were $551 million and $394 million, respectively. Additionally, we had $76 million of alternative minimum tax (AMT) NOL carryforwards, net of unrecognized tax benefits, available as a deduction against future AMT income. The NOL carryforwards expire from 2031 through 2033. The value of these carryforwards depends on the ability of Chesapeake to generate taxable income. As of December 31, 2014 and 2013, we had deferred tax assets of $1.687 billion and $1.621 billion, respectively, upon which we had a valuation allowance of $222 million and $148 million, respectively, for certain state NOL carryforwards and credits that we have concluded are not more likely than not to be utilized prior to expiration. The net change in the valuation allowance of $74 million is reflected as a component of income tax expense.

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Deferred tax assets relating to tax benefits of employee share-based compensation have been reduced for stock options exercised and restricted stock that vested in periods in which Chesapeake was in a net operating loss (NOL) position. Some exercises and vestings result in tax deductions in excess of previously recorded benefits based on the stock option or restricted stock value at the time of grant (windfalls). Although these additional tax benefits or windfalls are reflected in NOL carryforwards in the tax return, the additional tax benefit associated with the windfalls is not recognized until the deduction reduces taxes payable pursuant to accounting for stock compensation under U.S. GAAP. Accordingly, since the tax benefit does not reduce Chesapeake's current taxes payable due to NOL carryforwards, these windfall tax benefits are not reflected in Chesapeake's NOLs in deferred tax assets. Windfalls included in NOL carryforwards but not reflected in deferred tax assets as of December 31, 2014 totaled $18 million. Any shortfalls resulting from tax deductions that were less than the previously recorded benefits were recorded as reductions to additional paid-in capital.

The ability of Chesapeake to utilize NOL carryforwards to reduce future federal taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of these carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Chesapeake.

As of December 31, 2014, we do not believe that an ownership change has occurred that would limit the carryforwards. Due to the spin-off of SSE, the limitation on previously acquired NOLs was increased such that the remaining carryforward became fully available. Future equity transactions by Chesapeake or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOLs.

Accounting guidance for recognizing and measuring uncertain tax positions prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. As of December 31, 2014 and 2013, the amount of unrecognized tax benefits related to NOL carryforwards and state tax liabilities associated with uncertain tax positions was $303 million and $644 million, respectively. Of the 2014 amount, $23 million and $17 million are related to AMT and state tax liabilities, respectively, while the remainder is related to NOL carryforwards. Of the 2013 amount, $4 million is related to state tax liabilities while the remainder is related to NOL carryforwards. If these unrecognized tax benefits are disallowed and our NOL carryforwards are reduced, the reduction will be offset by additional tax basis that will generate future deductions. The uncertain tax positions identified would not have a material effect on the effective tax rate. No material changes to the current uncertain tax positions are expected within the next 12 months. As of December 31, 2014 and 2013, we had accrued liabilities of $5 million and $13 million, respectively, for interest related to these uncertain tax positions. Chesapeake recognizes interest related to uncertain tax positions in interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses.

A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:

	2014			2013		2012
	($ in millions)
Unrecognized tax benefits at beginning of period	$	644		$	599	$	369
Additions based on tax positions related to the current year	13			15		134
Additions to tax positions of prior years	—			30		96
Reductions to tax positions of prior years	(354		)	—		—
Unrecognized tax benefits at end of period	$	303		$	644	$	599

Chesapeake's federal and state income tax returns are routinely audited by federal and state fiscal authorities. The Internal Revenue Service (IRS) is currently auditing our federal income tax returns for 2007 through 2013. The federal tax returns for 1999 through 2006 remain subject to examination for the purpose of determining the amount of remaining tax NOL and other carryforwards. The 2007 through 2014 years remain open for all purposes of examination by the IRS and other taxing authorities in material jurisdictions.

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7. Related Party Transactions

Our equity method investees are considered related parties. During 2014, 2013 and 2012, we had the following transactions with our equity method investees:

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
Purchases(a)	$	—	$	—	$	73
Sales(b)	$	—	$	666	$	392
Services(c)	$	220	$	397	$	480

___________________________________________

(a) Purchase of equipment from FTS International, Inc. (FTS).

(b) In 2013 and 2012, Chesapeake sold produced gas to our 30%-owned investee, Twin Eagle Resource Management LLC (Twin Eagle). We sold our investment in Twin Eagle in 2014.

(c) Hydraulic fracturing and other services provided to us by FTS in the ordinary course of business. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs.

The table below shows the total amounts due from and due to our equity method investees.

	December 31,
	2014		2013		2012
	($ in millions)
Amounts due from equity method investees	$	—	$	47	$	67
Amounts due to equity method investees	$	—	$	1	$	42

8. Equity

Common Stock

The following is a summary of the changes in our common shares issued for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014		2013		2012
	(in thousands)
Shares issued as of January 1	666,192		666,468		660,888
Restricted stock issuances (net of forfeitures and cancellations)(a)	(2,529	)	(599	)	5,038
Stock option exercises	1,281		323		542
Shares issued as of December 31	664,944		666,192		666,468

___________________________________________

(a) In the second quarter of 2013, we began granting restricted stock units (RSUs) in lieu of restricted stock awards (RSAs) to non-employee directors and employees. Shares of common stock underlying RSUs are issued when the units vest, whereas shares of common stock are issued on the date the RSAs are granted. We refer to RSAs and RSUs collectively as restricted stock.

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Preferred Stock

Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2014:

Preferred Stock Series	Issue Date	Liquidation Preference per Share		Holder's Conversion Right	Conversion Rate	Conversion Price		Company's Conversion Right From	Company's Market Conversion Trigger(a)
5.75% cumulative convertible non-voting	May and June 2010	$	1,000	Any time	39.5856	$	25.2617	May 17, 2015	$	32.8402
5.75% (series A) cumulative convertible non-voting	May 2010	$	1,000	Any time	38.2538	$	26.1412	May 17, 2015	$	33.9836
4.50% cumulative convertible	September 2005	$	100	Any time	2.4468	$	40.8693	September 15, 2010	$	53.1301
5.00% cumulative convertible (series 2005B)	November 2005	$	100	Any time	2.7669	$	36.1415	November 15, 2010	$	46.9840

___________________________________________

(a) Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding.

The following reflects the shares outstanding of our preferred stock for the years ended December 31, 2014, 2013 and 2012:

	5.75%	5.75% (A)	4.50%	5.00% (2005B)
	(in thousands)
Shares outstanding as of January 1, 2014, 2013 and 2012 and shares outstanding as of December 31, 2014, 2013 and 2012	1,497	1,100	2,559	2,096

Dividends

Dividends declared on our common stock and preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings exists after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, payments constitute a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital.

Dividends on our outstanding preferred stock are payable quarterly. We may pay dividends on our 5.00% Cumulative Convertible Preferred Stock (Series 2005B) and our 4.50% Cumulative Convertible Preferred Stock in cash, common stock or a combination thereof, at our option. Dividends on both series of our 5.75% Cumulative Convertible Non-Voting Preferred Stock are payable only in cash.

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Accumulated Other Comprehensive Income (Loss)

For the years ended December 31, 2014 and 2013, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below.

	Net Gains (Losses) on Cash Flow Hedges			Net Gains (Losses) on Investments			Total
	($ in millions)
Balance, December 31, 2013	$	(167	)	$	5		$	(162	)
Other comprehensive income before reclassifications	1			—			1
Amounts reclassified from accumulated other comprehensive income	23			(5		)	18
Net other comprehensive income	24			(5		)	19
Balance, December 31, 2014	$	(143	)	$	—		$	(143	)
Balance, December 31, 2012	$	(189	)	$	7		$	(182	)
Other comprehensive income before reclassifications	2			(6		)	(4		)
Amounts reclassified from accumulated other comprehensive income	20			4			24
Net other comprehensive income	22			(2		)	20
Balance, December 31, 2013	$	(167	)	$	5		$	(162	)

For the years ended December 31, 2014 and 2013, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the consolidated statements of operations are detailed below.

Details About Accumulated Other Comprehensive Income (Loss) Components	Affected Line Item in the Statement Where Net Income is Presented	Year Ended December 31, 2014
		($ in millions)
Year Ended December 31, 2014:
Net losses on cash flow hedges:
Commodity contracts	Oil, natural gas and NGL revenues	$	23
Investments:
Sale of investment	Net gain on sale of investment	(5		)
Total reclassifications for the period, net of tax		$	18
Year Ended December 31, 2013:
Net losses on cash flow hedges:
Commodity contracts	Oil, natural gas and NGL revenues	$	20
Investments:
Impairment of investment	Losses on investments	6
Sale of investment	Net gain on sale of investment	(2		)
Total reclassifications for the period, net of tax		$	24

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Noncontrolling Interests

Cleveland Tonkawa Financial Transaction. We formed CHK Cleveland Tonkawa, L.L.C. (CHK C-T) in March 2012 to continue development of a portion of our oil and natural gas assets in our Cleveland and Tonkawa plays. CHK C-T is an unrestricted subsidiary under our revolving credit facility agreement and is not a guarantor of, or otherwise liable for, any of our indebtedness or other liabilities, including indebtedness under our indentures. In exchange for all of the common shares of CHK C-T, we contributed to CHK C-T approximately 245,000 net acres of leasehold and the existing wells within an area of mutual interest in the plays between the top of the Tonkawa and the top of the Big Lime formations covering Ellis and Roger Mills counties in western Oklahoma. In March 2012, in a private placement, third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in the existing wells and up to 1,000 future net wells to be drilled on the contributed play leasehold. Subject to customary minority interest protections afforded the investors by the terms of the CHK C-T limited liability company agreement (the CHK C-T LLC Agreement), as the holder of all the common shares and the sole managing member of CHK C-T, we maintain voting and managerial control of CHK C-T and therefore include it in our consolidated financial statements. Of the $1.25 billion of investment proceeds, we allocated $225 million to the ORRI obligation and $1.025 billion to the preferred shares based on estimates of fair values. The remaining ORRI obligation is included in other current and long-term liabilities and the preferred shares are included in noncontrolling interests on our consolidated balance sheets. Pursuant to the CHK C-T LLC Agreement, CHK C-T is required to retain an amount of cash equal to the next two quarters of preferred dividend payments. The amount reserved, approximately $38 million as of December 31, 2014 and 2013, was reflected as restricted cash on our consolidated balance sheets.

Dividends on the preferred shares are payable on a quarterly basis at a rate of 6% per annum based on $1,000 per share. This dividend rate is subject to increase in limited circumstances in the event that, and only for so long as, any dividend amount is not paid in full for any quarter. As the managing member of CHK C-T, we may, at our sole discretion and election at any time after March 31, 2014, distribute certain excess cash of CHK C-T, as determined in accordance with the CHK C-T LLC Agreement and the development agreement, as amended. The optional distribution of excess cash is allocated 75% to the preferred shares (which is applied toward redemption of the preferred shares) and 25% to the common shares; provided, however, that in certain circumstances, as set forth in the CHK C-T L.L.C. Agreement and the development agreement, as amended, the optional distribution would be allocated 100% to the preferred shares (and applied toward redemption thereof). We may also, at our sole discretion and election, in accordance with the CHK C-T LLC Agreement, cause CHK C-T to redeem all or a portion of the CHK C-T preferred shares for cash. The preferred shares may be redeemed at a valuation equal to the greater of a 9% internal rate of return or a return on investment of 1.35x, in each case inclusive of dividends paid through redemption at the rate of 6% per annum and optional distributions made through the applicable redemption date. In the event that redemption does not occur on or prior to March 31, 2019, the optional redemption valuation will increase to provide a 15% internal rate of return to the investors. The preferred shares can be redeemed on a pro-rata basis in accordance with the then-applicable redemption valuation formula. As of December 31, 2014 and 2013, the redemption price and the liquidation preference were approximately $1,185 and $1,245, respectively, per preferred share.

We initially committed to drill and complete, for the benefit of CHK C-T in the area of mutual interest, a minimum of 37.5 net wells per six-month period through 2013, inclusive of wells drilled in 2012, and 25 net wells per six-month period in 2014 through 2016, up to a minimum cumulative total of 300 net wells. In April 2014, the drilling commitment was amended to require us to drill and complete a minimum cumulative total of (i) 162.5 net wells by June 30, 2014 and (ii) 175 net wells by December 31, 2014. In January 2015, the drilling commitment was suspended. We are not required or allowed to drill any wells with respect to the CHK C-T properties unless we receive written notice from the owners of a majority of the preferred shares electing to lift the drilling prohibition. If we receive written notice at least 45 days prior to June 30, 2015, we will be required to drill and complete a minimum cumulative total of 225 net wells by June 30, 2016, and thereafter the minimum cumulative total will be increased by 25 net wells in each of the subsequent six-month periods ending December 31, 2017. If notice is not received by that time, future drilling commitment dates will be extended, as provided in the January 2015 amendment to the drilling commitment. If we fail to meet the then-current cumulative drilling commitment in any six-month period, any optional cash distributions will be distributed 100% to the investors. If we fail to meet the then-current cumulative drilling commitment in two consecutive six-month periods, the then-applicable internal rate of return to investors at redemption will increase by 3% per annum. In addition, if we fail to meet the then-current cumulative drilling commitment in four consecutive six-month periods, the then-applicable internal rate of return to investors at redemption will be increased by an additional 3% per annum. Any increase in the internal rate of return would be effective only until the end of the first succeeding six-month period in which we have

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met our then-current cumulative drilling commitment. CHK C-T is responsible for all capital and operating costs of the wells drilled for the benefit of the entity. Under the development agreement, approximately 17, 77 and 84 qualified net wells were added in 2014, 2013 and 2012, respectively. Through December 31, 2014, we had met all current drilling commitments associated with the CHK C-T transaction.

The CHK C-T investors’ right to receive, proportionately, a 3.75% ORRI in the contributed wells and up to 1,000 future net wells on our contributed leasehold is subject to an increase to 5% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation, which runs from 2012 through the first quarter of 2025. However, in no event are we required to deliver to investors more than a total ORRI of 3.75% in existing wells and 1,000 future net wells. If at any time CHK C-T holds fewer net acres than would enable us to drill all then-remaining net wells on 160-acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs. CHK C-T retains the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs once we have drilled a minimum of 867 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our oil and natural gas properties. We had met our ORRI conveyance commitment as of December 31, 2013, but we did not meet the 2014 ORRI conveyance commitment as of December 31, 2014.

As of December 31, 2014 and 2013, $1.015 billion of noncontrolling interests on our consolidated balance sheets were attributable to CHK C-T. For 2014, 2013 and 2012, income of $75 million, $75 million and $57 million, respectively, was attributable to the noncontrolling interests of CHK C-T.

Utica Financial Transaction. We formed CHK Utica, L.L.C. (CHK Utica) in October 2011 to develop a portion of our Utica Shale oil and natural gas assets. In exchange for all of the common shares of CHK Utica, we contributed to CHK Utica approximately 700,000 net acres of leasehold and the existing wells within an area of mutual interest in the Utica Shale play covering 13 counties located primarily in eastern Ohio. During November and December 2011, in private placements, third-party investors contributed $1.25 billion in cash to CHK Utica in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3% ORRI in 1,500 net wells to be drilled on certain of our Utica Shale leasehold.

In 2014, we repurchased all of the outstanding preferred shares of CHK Utica from third-party preferred shareholders for approximately $1.254 billion, or approximately $1,189 per share including accrued dividends. The $447 million difference between the cash paid for the preferred shares and the carrying value of the noncontrolling interest acquired is reflected in retained earnings and as a reduction to net income available to common stockholders for purposes of our EPS computations. Pursuant to the transaction, our obligation to pay quarterly dividends to third-party preferred shareholders was eliminated. In addition, the development agreement was terminated pursuant to the transaction, which eliminated our obligation to drill and complete a minimum number of wells within a specified period for the benefit of CHK Utica. Our repurchase of the outstanding preferred shares in CHK Utica did not affect our obligation to deliver a 3% ORRI in 1,500 net wells on certain Utica Shale leasehold.

The CHK Utica investors’ right to receive, proportionately, a 3% ORRI in the first 1,500 net wells drilled on our Utica Shale leasehold is subject to an increase to 4% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation, which runs from 2012 through 2023. However, in no event are we required to deliver to investors more than a total ORRI of 3% in 1,500 net wells. If at any time we hold fewer net acres than would enable us to drill all then-remaining net wells on 150-acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs. We retain the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs once we have drilled a minimum of 1,300 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the future conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our oil and natural gas properties. Because we did not meet our ORRI commitment in 2012, the ORRI increased to 4% for wells earned in 2013, and the ultimate number of wells in which we must assign an interest will be reduced accordingly. We met the 2013 ORRI conveyance commitment as of December 31, 2013 and met the 2014 ORRI conveyance commitment as of December 31, 2014 associated with the CHK Utica transaction.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2014 and 2013, $0 and $807 million, respectively, of noncontrolling interests on our consolidated balance sheets were attributable to CHK Utica. In 2014, 2013 and 2012, income of approximately $43 million, $79 million and $88 million, respectively, was attributable to the noncontrolling interests of CHK Utica.

Chesapeake Granite Wash Trust. In November 2011, Chesapeake Granite Wash Trust (the Trust) sold 23,000,000 common units representing beneficial interests in the Trust at a price of $19.00 per common unit in its initial public offering. The common units are listed on the New York Stock Exchange and trade under the symbol “CHKR”. We own 12,062,500 common units and 11,687,500 subordinated units, which in the aggregate represent an approximate 51% beneficial interest in the Trust. The Trust has a total of 46,750,000 units outstanding.

In connection with the initial public offering of the Trust, we conveyed royalty interests to the Trust that entitle the Trust to receive (i) 90% of the proceeds (after deducting certain post-production expenses and any applicable taxes) that we receive from the production of hydrocarbons from 69 producing wells, and (ii) 50% of the proceeds (after deducting certain post-production expenses and any applicable taxes) in 118 development wells that have been or will be drilled on approximately 45,400 gross acres (29,000 net acres) in the Colony Granite Wash play in Washita County in the Anadarko Basin of western Oklahoma. Pursuant to the terms of a development agreement with the Trust, we are obligated to drill, or cause to be drilled, the development wells at our own expense prior to June 30, 2016, and the Trust is not responsible for any costs related to the drilling of the development wells or any other operating or capital costs of the Trust properties. In addition, we granted to the Trust a lien on our remaining interests in the undeveloped properties that are subject to the development agreement in order to secure our drilling obligation to the Trust, although the maximum amount that may be recovered by the Trust under the lien cannot exceed $263 million initially and will be proportionately reduced as we fulfill our drilling obligation over time. As of December 31, 2014 and 2013, we had drilled or caused to be drilled approximately 102 and 82 development wells, respectively, as calculated under the development agreement, and the maximum amount recoverable under the drilling support lien was approximately $36 million and $79 million, respectively.

The subordinated units we hold in the Trust are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is not less than the applicable subordination threshold for the quarter. If there is not sufficient cash to fund a distribution on all of the Trust units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for the quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. The distribution made with respect to the subordinated units to Chesapeake was either reduced or eliminated for each of the most recent ten quarters of distributions paid. In exchange for agreeing to subordinate a portion of our Trust units, and in order to provide additional financial incentive to us to satisfy our drilling obligation and perform operations on the underlying properties in an efficient and cost-effective manner, Chesapeake is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on the Trust units in any quarter exceeds the applicable incentive threshold for the quarter. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold will be paid to Trust unitholders, including Chesapeake, on a pro rata basis. Through December 31, 2014, no incentive distributions had been made. At the end of the fourth full calendar quarter following our satisfaction of our drilling obligation with respect to the development wells, the subordinated units will automatically convert into common units on a one-for-one basis and our right to receive incentive distributions will terminate. After such time, the common units will no longer have the protection of the subordination threshold, and all Trust unitholders will share in the Trust’s distributions on a pro rata basis.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

For the years ended December 31, 2014, 2013 and 2012, the Trust declared and paid the following distributions:

Production Period	Distribution Date	Cash Distribution per Common Unit		Cash Distribution per Subordinated Unit
June 2014 - August 2014	December 1, 2014	$	0.5079	$	—
March 2014 - May 2014	August 29, 2014	$	0.5796	$	—
December 2013 - February 2014	May 30, 2014	$	0.6454	$	—
September 2013 - November 2013	March 3, 2014	$	0.6624	$	—
June 2013 - August 2013	November 29, 2013	$	0.6671	$	—
March 2013 - May 2013	August 29, 2013	$	0.6900	$	0.1432
December 2012 - February 2013	May 31, 2013	$	0.6900	$	0.3010
September 2012 - November 2012	March 1, 2013	$	0.6700	$	0.3772
June 2012 - August 2012	November 29, 2012	$	0.6300	$	0.2208
March 2012 - May 2012	August 30, 2012	$	0.6100	$	0.4819
December 2011 - February 2012	May 31, 2012	$	0.6588	$	0.6588
September 2011 - November 2011	March 1, 2012	$	0.7277	$	0.7277

We have determined that the Trust is a variable interest entity (VIE) and that Chesapeake is the primary beneficiary. As a result, the Trust is included in our consolidated financial statements. As of December 31, 2014 and 2013, $287 million and $314 million, respectively, of noncontrolling interests on our consolidated balance sheets were attributable to the Trust. In 2014, 2013 and 2012, income of approximately $24 million, $20 million and $35 million, respectively, was attributable to the Trust’s noncontrolling interests in our consolidated statements of operations. See Note 15 for further discussion of VIEs.

Wireless Seismic, Inc. As of December 31, 2014, we no longer consolidated Wireless Seismic, Inc. (Wireless), a privately owned company engaged in research, development and production of wireless seismic systems and related technology that delivers seismic information obtained from standard geophones in real time to personal computers. Because we no longer have a controlling equity interest in Wireless, our interest is included in investments in our consolidated balance sheet and within other in the table in Note 14.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

9. Share-Based Compensation

Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units (PSUs) granted to employees and common stock and restricted stock granted to non-employee directors under our long term incentive plans. The restricted stock and stock options are equity-classified awards and the PSUs are liability-classified awards. In connection with the spin-off of our oilfield services business on June 30, 2014, and pursuant to the terms of our share-based compensation plans and the employee matters agreement between Chesapeake and Seventy Seven Energy Inc., unexercised stock options and unvested restricted stock were modified as of the date of the spin-off. The modifications were designed to ensure that the value of each award of unexercised stock options and unvested restricted stock did not change as a result of the spin-off. The number of stock options and number of shares of restricted stock reported below have been adjusted to reflect modifications on the spin-off date.

Share-Based Compensation Plans

2014 Long Term Incentive Plan. Our 2014 Long Term Incentive Plan (2014 LTIP), which is administered by the Compensation Committee of our Board of Directors, became effective on June 13, 2014 after it was approved by shareholders at our 2014 Annual Meeting. The 2014 LTIP replaced our Amended and Restated Long Term Incentive Plan (2005 LTIP) which was adopted in 2005. The 2014 LTIP provides for up to 36,600,000 shares of common stock that may be issued as long-term incentive compensation to our employees and non-employee directors; provided, however, that the 2014 LTIP uses a fungible share pool under which (i) each share issued pursuant to a stock option or stock appreciation right (SAR) reduces the number of shares available under the 2014 LTIP by 1.0 share; (ii) each share issued pursuant to awards other than options and SARs reduces the number of shares available by 2.12 shares; and (iii) PSUs and other performance awards which are payable solely in cash are not counted against the aggregate number of shares issuable. In addition, the 2014 LTIP prohibits the reuse of shares withheld or delivered to satisfy the exercise price of, or to satisfy tax withholding requirements for, an option or SAR. The 2014 LTIP also prohibits “net share counting” upon the exercise of options or SARs.

The 2014 LTIP authorizes the issuance of the following types of awards: (i) nonqualified and incentive stock options; (ii) SARs; (iii) restricted stock; (iv) performance awards, including PSUs; and (v) other stock-based awards. For both stock options and SARs, the exercise price may not be less than the fair market value of our common stock on the date of grant and the maximum exercise period may not exceed ten years from the date of grant. Awards granted under the plan vest at specified dates and/or upon the satisfaction of certain performance or other criteria, as determined by the Compensation Committee. In 2014, we issued 50,771 and 272,289 shares of restricted stock, net of forfeitures, to non-employee directors and employees, respectively, under the 2014 LTIP. As of December 31, 2014, 36 million shares of common stock remained issuable under the 2014 LTIP.

2005 Long Term Incentive Plan. Chesapeake’s 2005 LTIP, which terminated upon shareholder approval of the 2014 LTIP on June 13, 2014, provided for the issuance of restricted stock, stock options and PSUs to employees, directors and consultants of Chesapeake. Subject to any adjustments as provided by the plan, the aggregate number of shares of common stock available for awards under the plan was limited to 59,300,000 shares. The maximum period for exercise of an option or SAR was not more than ten years from the date of grant, and the exercise price was not less than the fair market value of the shares underlying the option or SAR on the date of grant. Awards granted under the plan became vested at specified dates or upon the satisfaction of certain performance or other criteria determined by a committee of the Board of Directors. The plan was approved by our shareholders. We issued 48,083, 147,108 and 170,151 shares of restricted stock to non-employee directors under the 2005 LTIP in 2014, 2013 and 2012, respectively. We issued options to purchase 993,730, 5.3 million and no shares of common stock to employees and consultants under the 2005 LTIP in 2014, 2013 and 2012, respectively. Additionally, we issued 1.3 million, 2.5 million and 5.0 million shares of restricted stock, net of forfeitures, to employees and consultants under the 2005 LTIP in 2014, 2013 and 2012, respectively.

2003 Stock Award Plan for Non-Employee Directors. Under Chesapeake's 2003 Stock Award Plan for Non-Employee Directors (2003 Non-Employee Director Plan), a maximum of 10,000 shares of Chesapeake's common stock is awarded to each newly appointed non-employee director on his or her first day of service. Subject to any adjustments as provided by the plan, the aggregate number of shares issued may not exceed 250,000 shares. The plan was approved by our shareholders. We issued 10,000, 20,000 and 30,000 shares of common stock to newly appointed non-employee directors under the 2003 Non-Employee Director Plan in 2014, 2013 and 2012, respectively. As of December 31, 2014, there were 120,000 shares remaining available for issuance under the 2003 Non-Employee Director Plan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Equity-Classified Awards

Restricted Stock. We grant restricted stock to employees and non-employee directors. Restricted stock vests over a minimum of three years and the holder receives dividends on unvested shares. A summary of the changes in unvested restricted stock during 2014, 2013 and 2012 is presented below.

	Shares of Unvested Restricted Stock		Weighted Average Grant Date Fair Value
	(in thousands)
Unvested restricted stock as of January 1, 2014	13,400		$	23.38
Granted	5,049		$	25.92
Vested	(4,803	)	$	27.17
Forfeited	(3,555	)	$	28.09
Unvested restricted stock as of December 31, 2014	10,091		$	21.20
Unvested restricted stock as of January 1, 2013	18,899		$	23.72
Granted	9,189		$	19.68
Vested	(12,897	)	$	21.32
Forfeited	(1,791	)	$	22.86
Unvested restricted stock as of December 31, 2013	13,400		$	23.38
Unvested restricted stock as of January 1, 2012	19,544		$	26.97
Granted	9,480		$	21.13
Vested	(8,620	)	$	28.08
Forfeited	(1,505	)	$	24.57
Unvested restricted stock as of December 31, 2012	18,899		$	23.72

The aggregate intrinsic value of restricted stock that vested during 2014 was approximately $130 million based on the stock price at the time of vesting.

As of December 31, 2014, there was approximately $135 million of total unrecognized compensation expense related to unvested restricted stock. The expense is expected to be recognized over a weighted average period of approximately 2.02 years.

The vesting of certain restricted stock grants may result in state and federal income tax benefits, or reductions in these benefits, related to the difference between the market price of the common stock at the date of vesting and the date of grant. During 2014, we recognized an excess tax benefit related to restricted stock of $12 million. During 2013 and 2012, we recognized reductions in tax benefits related to restricted stock of $14 million and $32 million, respectively. Each adjustment was recorded to additional paid-in capital and deferred income taxes.

Stock Options. In 2014 and 2013, we granted members of senior management stock options that vest ratably over a three-year period. In January 2013, we also granted retention awards to certain officers of stock options that vest one-third on each of the third, fourth and fifth anniversaries of the grant date. Each stock option award has an exercise price equal to the closing price of the Company’s common stock on the grant date. Outstanding options generally expire ten years from the date of grant.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method, as there is no adequate historical exercise behavior available. Volatility assumptions are estimated based on an average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account the Company's current dividend policy, over the expected life of the option. The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2014:

Expected option life - years	5.9
Volatility	48.63	%
Risk-free interest rate	1.93	%
Dividend yield	1.33	%

The following table provides information related to stock option activity for 2014, 2013 and 2012: 

	Number of Shares Underlying   Options		Weighted Average Exercise Price Per Share		Weighted   Average Contract Life in Years	Aggregate   Intrinsic Value(a)
	(in thousands)					($ in millions)
Outstanding at January 1, 2014	5,268		$	19.28	6.66	$	41
Granted	994		$	24.43
Exercised	(1,322	)	$	18.71		$	11
Expired	(28	)	$	18.97
Forfeited	(313	)	$	21.05
Outstanding at December 31, 2014	4,599		$	19.55	7.03	$	5
Exercisable at December 31, 2014	1,304		$	18.71	5.70	$	1
Outstanding at January 1, 2013	481		$	12.69	0.96	$	2
Granted	5,264		$	19.32
Exercised	(346	)	$	10.82		$	3
Expired	(131	)	$	19.31
Outstanding at December 31, 2013	5,268		$	19.28	6.66	$	41
Exercisable at December 31, 2013	1,552		$	18.82	1.97	$	13
Outstanding at January 1, 2012	1,051		$	9.84	1.41	$	13
Exercised	(570	)	$	7.45		$	7
Outstanding and exercisable at December 31, 2012	481		$	12.69	0.96	$	2

___________________________________________

(a) The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.

As of December 31, 2014, there was $11 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 2.02 years.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The vesting of certain stock option grants may result in state and federal income tax benefits, or reductions in these benefits, related to the difference between the market price of the common stock at the date of vesting and the date of grant.During 2014, 2013 and 2012, we recognized excess tax benefits related to stock options of $3 million, $1 million and $2 million, respectively. Each adjustment was recorded to additional paid-in capital and deferred income taxes.

Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
General and administrative expenses	$	46	$	60	$	71
Oil and natural gas properties	29		52		71
Oil, natural gas and NGL production expenses	18		21		24
Marketing, gathering and compression expenses	6		7		15
Oilfield services expenses	5		10		10
Total	$	104	$	150	$	191

Liability-Classified Awards

Performance Share Units. In 2012, 2013 and 2014, we granted PSUs to senior management that settle in cash at the end of their respective performance periods and vest ratably over their respective terms. The 2012 awards were granted in one-, two- and three-year tranches and are settled in cash on the first, second and third anniversary dates of the awards, and the 2013 and 2014 awards are settled in cash on the third anniversary of the awards. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors, which include total shareholder return (TSR) and, for certain of the awards, the achievement of operational performance goals such as production and proved reserve growth.

For PSUs granted in 2012, each of the TSR and operational payout components can range from 0% to 125% resulting in a maximum total payout of 250%. For PSUs granted in 2013, the TSR component can range from 0% to 125% and each of the two operational components can range from 0% to 62.5%; however, the maximum total payout is capped at 200%. For PSUs granted in 2014, the TSR component can range from 0% to 200%, with no operational components. For the 2013 and 2014 PSUs, the payout percentage is capped at 100% if the Company’s absolute TSR is less than zero. Compensation expense associated with the PSU grants is recognized over the service period. The number of units settled is dependent upon the Company’s estimates of the underlying performance measures. For the 2014 awards, the Company utilized the Monte Carlo simulation for the TSR performance measure, and the following assumptions to determine the grant date fair value of the PSUs:

Volatility	41.37	%
Risk-free interest rate	0.76	%
Dividend yield for value of awards	1.36	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents a summary of our PSU awards:

	Units	Fair Value as of Grant Date		Fair Value(a)		Liability for Vested Amount
		($ in millions)
2012 Awards (b)
Payable 2015	884,507	$	23	$	12	$	12
2013 Awards
Payable 2016	1,701,941	$	35	$	42	$	39
2014 Awards
Payable 2017	609,637	$	16	$	10	$	7

___________________________________________

(a) As of December 31, 2014.

(b) In 2014 and 2013, we paid $11 million and $2 million, respectively, related to 2012 PSU awards.

PSU Compensation. We recognized the following compensation costs related to PSUs for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014			2013		2012
	($ in millions)
General and administrative expenses	$	(4	)	$	34	$	8
Oil and natural gas properties	3			9		4
Oil, natural gas and NGL production expenses	—			2		1
Marketing, gathering and compression expenses	—			2		1
Oilfield services expenses	—			1		—
Total	$	(1	)	$	48	$	14

Effect of the Spin-off on Share-Based Compensation

The employee matters agreement entered into in connection with the spin-off of our oilfield services business (see Note 13) addresses the treatment of holders of Chesapeake stock options, restricted stock and PSUs. Unvested equity-based compensation awards held by COO employees were canceled and replaced with new awards of SSE, and unvested equity-based compensation awards held by Chesapeake employees were adjusted to account for the spin-off, each as of the spin-off date. The employee matters agreement provides that employees of SSE ceased to participate in benefit plans sponsored or maintained by Chesapeake as of the spin-off date. In addition, the employee matters agreement provides that as of the spin-off date, each party is responsible for the compensation of its current employees and for all liabilities relating to its former employees, as determined by their respective employer on the date of termination.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

10.     Employee Benefit Plans

Our qualified 401(k) profit sharing plan (401(k) Plan) is the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan, which is open to employees of Chesapeake and all our subsidiaries except certain employees of Chesapeake Appalachia, L.L.C. Eligible employees may elect to defer compensation through voluntary contributions to their 401(k) Plan accounts, subject to plan limits and those set by the IRS. Through December 31, 2014, Chesapeake matched employee contributions dollar for dollar (subject to a maximum contribution of 15% of an employee's base salary and performance bonus) with Chesapeake common stock purchased in the open market. The Company contributed $61 million, $81 million and $91 million to the 401(k) Plan in 2014, 2013 and 2012, respectively. Beginning January 1, 2015, Chesapeake will match employee contributions in cash.

Chesapeake also maintains a nonqualified deferred compensation plan (DC Plan). To be eligible to participate in the DC Plan, an active employee must have a base salary of at least $150,000, have a hire date on or before the December 1 immediately preceding the year in which the employee is able to participate, or be designated as eligible to participate. Only the top 10% of Company wage earners are eligible to participate. Additionally, the employee has to have made the maximum contribution allowable under the 401(k) Plan. Chesapeake matches 100% of employee contributions up to 15% of base salary and performance bonus in the aggregate for the DC Plan with Chesapeake common stock, and an employee who is at least age 55 may elect for the matching contributions to be made in any one of the DC Plan’s investment options. The maximum compensation that can be deferred by employees under all Company deferred compensation plans, including the Chesapeake 401(k) Plan, is a total of 75% of base salary and 100% of performance bonus. The Company contributed $7 million, $14 million and $16 million to the DC Plan during 2014, 2013 and 2012, respectively, to fund the match. In addition, in 2012 the Board of Directors adopted a deferred compensation plan for non-employee directors (Director DC Plan). The Company's non-employee directors are able to defer up to 100% of director cash compensation into the Director DC Plan and invest in Chesapeake common stock, but the plan does not provide for Company matching contributions.

Any assets placed in trust by Chesapeake to fund future obligations of the Company's nonqualified deferred compensation plans are subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their deferred compensation in the plans. Chesapeake maintains no post-employment benefit plans except those sponsored by its wholly owned subsidiary Chesapeake Appalachia, L.L.C. Participation in these plans is limited to existing employees who are union members and former employees who were union members. The Chesapeake Appalachia, L.L.C. benefit plans provide health care and life insurance benefits to eligible employees upon retirement. We account for these benefits on an accrual basis. As of December 31, 2014, the Company had accrued approximately $3 million in accumulated post-employment benefit liability.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

11. Derivative and Hedging Activities

Chesapeake uses commodity derivative instruments to secure attractive pricing and margins on expected production, to reduce its exposure to fluctuations in future commodity prices and to protect its expected operating cash flow against significant market movements or volatility. Chesapeake also uses derivative instruments to mitigate a portion of its exposure to interest rate and foreign currency exchange rate fluctuations. All of our derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty.

Oil and Natural Gas Derivatives

As of December 31, 2014 and 2013, our oil and natural gas derivative instruments consisted of the following types of instruments:

• Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.

• Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.

• Options: Chesapeake sells, and occasionally buys, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty the excess on sold call options, and Chesapeake receives the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.

• Call Swaptions: Chesapeake sells call swaptions in exchange for a premium that allows a counterparty, on a specific date, to enter into a fixed-price swap for a certain period of time.

• Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. Chesapeake receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity.

The estimated fair values of our oil and natural gas derivative instrument assets (liabilities) as of December 31, 2014 and 2013 are provided below. 

	December 31, 2014				December 31, 2013
	Volume	Fair Value			Volume	Fair Value
		($ in millions)				($ in millions)
Oil (mmbbl):
Fixed-price swaps	12.5	471			25.3	(50		)
Three-way collars	4.4	40			—	—
Call options	35.8	(89		)	42.5	(265		)
Basis protection swaps	—	—			0.4	1
Total oil	52.7	422			68.2	(314		)
Natural gas (tbtu):
Fixed-price swaps	275	$	281		448	$	(23	)
Three-way collars	207	165			288	(7		)
Call options	193	(170		)	193	(210		)
Call swaptions	—	—			12	—
Basis protection swaps	60	23			68	3
Total natural gas	735	299			1,009	(237		)
Total estimated fair value		$	721			$	(551	)

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

We have terminated certain commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. See further discussion below underEffect of Derivative Instruments - Accumulated Other Comprehensive Income (Loss).

Interest Rate Derivatives

As of December 31, 2014 and 2013, our interest rate derivative instruments consisted of swaps. We enter into fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes. We enter into floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our bank credit facility borrowings.

The notional amount of our interest rate derivatives, associated with our long-term debt, as of December 31, 2014 and 2013 was $850 million and $2.250 billion, respectively. The estimated fair value of our interest rate derivative liabilities as of December 31, 2014 and 2013 was $17 million and $98 million, respectively. 

We have terminated certain fair value hedges related to senior notes. Gains and losses related to these terminated hedges will be amortized as an adjustment to interest expense over the remaining term of the related senior notes. Over the next six years, we will recognize $10 million in net gains related to these transactions.

Foreign Currency Derivatives

We are party to cross currency swaps to mitigate our exposure to foreign currency exchange rate fluctuations that may result from the €344 million principal amount of our euro-denominated senior notes. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. Under the terms of the cross currency swaps we currently hold, on each semi-annual interest payment date, the counterparties pay us €11 million and we pay the counterparties $17 million, which yields an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay us €344 million and we will pay the counterparties $459 million. The swaps are designated as cash flow hedges and, because they are entirely effective in having eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates, changes in their fair value do not impact earnings. The fair values of the cross currency swaps are recorded on the consolidated balance sheet as a liability of $53 million and an asset of $2 million as of December 31, 2014 and 2013, respectively. The euro-denominated debt in long-term debt has been adjusted to $416 million as of December 31, 2014 using an exchange rate of $1.2098 to €1.00.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Effect of Derivative Instruments – Consolidated Balance Sheets

The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2014 and 2013 on a gross basis and after same-counterparty netting: 

Balance Sheet Classification	Gross Fair Value			Amounts Netted in Consolidated Balance Sheet			Net Fair Value Presented in Consolidated Balance Sheet
	($ in millions)
As of December 31, 2014
Commodity Contracts
Short-term derivative asset	$	974		$	(95	)	$	879
Long-term derivative asset	16			(10		)	6
Short-term derivative liability	(105		)	95			(10		)
Long-term derivative liability	(163		)	10			(153		)
Total commodity contracts	722			—			722
Interest Rate Contracts
Short-term derivative liability	(5		)	—			(5		)
Long-term derivative liability	(12		)	—			(12		)
Total interest rate contracts	(17		)	—			(17		)
Foreign Currency Contracts(a)
Long-term derivative liability	(53		)	—			(53		)
Total foreign currency contracts	(53		)	—			(53		)
Total Derivatives	$	652		$	—		$	652
As of December 31, 2013
Commodity Contracts
Short-term derivative asset	$	29		$	(29	)	$	—
Long-term derivative asset	11			(9		)	2
Short-term derivative liability	(231		)	29			(202		)
Long-term derivative liability	(362		)	9			(353		)
Total commodity contracts	(553		)	—			(553		)
Interest Rate Contracts
Short-term derivative liability	(6		)	—			(6		)
Long-term derivative liability	(92		)	—			(92		)
Total interest rate contracts	(98		)	—			(98		)
Foreign Currency Contracts(a)
Long-term derivative asset	2			—			2
Total foreign currency contracts	2			—			2
Total Derivatives	$	(649	)	$	—		$	(649	)

____________________________________________

(a) Designated as cash flow hedging instruments.

As of December 31, 2014 and 2013, we did not have any cash collateral balances for these derivatives.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Effect of Derivative Instruments – Consolidated Statements of Operations

The components of oil, natural gas and NGL sales for the years ended December 31, 2014, 2013 and 2012 are presented below. 

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Oil, natural gas and NGL sales	$	7,162		$	6,923		$	5,359
Gains on undesignated oil and natural gas derivatives	1,055			443			857
Gains (losses) on terminated cash flow hedges	(37		)	(314		)	62
Total oil, natural gas and NGL sales	$	8,180		$	7,052		$	6,278

The components of interest expense for the years ended December 31, 2014, 2013 and 2012 are presented below. 

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Interest expense on senior notes	$	704		$	740		$	732
Interest expense on term loans	36			116			173
Amortization of loan discount, issuance costs and other	42			91			89
Interest expense on credit facilities	28			38			70
Gains on terminated fair value hedges	(3		)	(5		)	(8		)
(Gains) losses on undesignated interest rate derivatives	(81		)	63			1
Capitalized interest	(637		)	(816		)	(980		)
Total interest expense	$	89		$	227		$	77

Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss)

A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.

	Years Ended December 31,
	2014						2013						2012
	Before  Tax			After  Tax			Before  Tax			After  Tax			Before  Tax			After  Tax
	($ in millions)
Balance, beginning of period	$	(269	)	$	(167	)	$	(304	)	$	(189	)	$	(287	)	$	(178	)
Net change in fair value	1			1			3			2			10			6
Gains (losses) reclassified to income	37			23			32			20			(27		)	(17		)
Balance, end of period	$	(231	)	$	(143	)	$	(269	)	$	(167	)	$	(304	)	$	(189	)

Approximately $136 million of the $143 million of accumulated other comprehensive loss as of December 31, 2014 represents the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. These amounts will be recognized in earnings in the month in which the originally forecasted hedged production occurs. As of December 31, 2014, we expect to transfer approximately $23 million of net loss included in accumulated other comprehensive income to net income during the next 12 months. The remaining amounts will be transferred by December 31, 2022.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Credit Risk Considerations

Over-the-counter traded derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment grade and deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2014, our oil, natural gas and interest rate derivative instruments were spread among 18 counterparties.

Hedging Facility

Our secured commodity hedging facility with 17 counterparties provides approximately 1.031 bboe of hedging capacity for oil, natural gas and NGL price derivatives and 1.031 bboe for basis derivatives with an aggregate mark-to-market capacity of $16.5 billion. The facility is secured by proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times at semi-annual collateral redetermination dates and 1.30 times in between those dates, and guarantees by certain subsidiaries that also guarantee our revolving credit facility and indentures. Chesapeake has significant flexibility with regard to releases and/or substitutions of pledged reserves, provided that certain requirements are met including maintaining specified collateral coverage ratios as well as maintaining credit ratings with either of the designated rating agencies at or above current levels. The counterparties’ obligations under the facility must be secured by cash or short-term U.S. treasury instruments to the extent that any mark-to-market amounts they owe Chesapeake exceed defined thresholds. As of December 31, 2014, we had hedged under the facility 164 mmboe of our future production with price derivatives and 10 mmboe with basis derivatives.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Fair Value

The fair value of our derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil and natural gas forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are compared to the values given by our counterparties for reasonableness. Since oil, natural gas, interest rate and cross currency swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives.

The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:

	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Fair Value
			($ in millions)
As of December 31, 2014
Derivative Assets (Liabilities):
Commodity assets	$	—	$	785		$	205		$	990
Commodity liabilities	—		(9		)	(259		)	(268		)
Interest rate liabilities	—		(17		)	—			(17		)
Foreign currency liabilities	—		(53		)	—			(53		)
Total derivatives	$	—	$	706		$	(54	)	$	652
As of December 31, 2013
Derivative Assets (Liabilities):
Commodity assets	$	—	$	25		$	15		$	40
Commodity liabilities	—		(100		)	(493		)	(593		)
Interest rate liabilities	—		(98		)	—			(98		)
Foreign currency assets	—		2			—			2
Total derivatives	$	—	$	(171	)	$	(478	)	$	(649	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2014 and 2013 is presented below.

	Derivatives
	Commodity			Interest Rate
	($ in millions)
Beginning Balance as of January 1, 2014	$	(478	)	$	—
Total gains (losses) (realized/unrealized):
Included in earnings(a)	292			—
Total purchases, issuances, sales and settlements:
Settlements	136			—
Transfers(b)	(4		)	—
Ending Balance as of December 31, 2014	$	(54	)	$	—
Beginning Balance as of January 1, 2013	$	(1,016	)	$	—
Total gains (losses) (realized/unrealized):
Included in earnings(a)	410			(1		)
Total purchases, issuances, sales and settlements:
Sales	—			1
Settlements	128			—
Ending Balance as of December 31, 2013	$	(478	)	$	—

___________________________________________

(a)	Oil, Natural Gas and NGL Sales				Interest Expense
	2014		2013		2014		2013
	($ in millions)
Total gains (losses) included in earnings for the period	$	292	$	410	$	—	$	(1	)
Change in unrealized gains (losses) related to assets still held at reporting date	$	262	$	382	$	—	$	—

(b) The values related to basis swaps were transferred from Level 3 to Level 2 as a result of our ability to begin using data readily available in the public market to corroborate our estimated fair values.

Qualitative and Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements

The significant unobservable inputs for Level 3 derivative contracts include unpublished forward prices of oil and natural gas, market volatility and credit risk of counterparties. Changes in these inputs impact the fair value measurement of our derivative contracts. For example, an increase (decrease) in the forward prices and volatility of oil and natural gas prices decreases (increases) the fair value of oil and natural gas derivatives and adverse changes to our counterparties’ creditworthiness decreases the fair value of our derivatives. The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of December 31, 2014:

Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value December 31, 2014(a)
				($ in millions)
Oil trades	Oil price volatility curves	27.33% - 43.56%	34.09%	$	(49	)
Natural gas trades	Natural gas price volatility curves	18.71% - 63.70%	34.38%	$	(5	)

___________________________________________

(a) Fair value is based on an estimate derived from option models.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

12. Oil and Natural Gas Property Transactions

Under full cost accounting rules, we have accounted for the sale of oil and natural gas properties as an adjustment to capitalized costs, with no recognition of gain or loss as the sales have not involved a significant change in proved reserves or significantly altered the relationship between costs and proved reserves.

2014 Transactions

We sold certain assets in the southern Marcellus Shale and a portion of the eastern Utica Shale to a subsidiary of Southwestern Energy Company for aggregate net proceeds of approximately $4.975 billion. We sold approximately 413,000 net acres and approximately 1,500 wells in northern West Virginia and southern Pennsylvania, of which 435 wells are in the Marcellus or Utica formations, along with related gathering assets and property, plant and equipment.

We exchanged interests in approximately 440,000 gross acres in the Powder River Basin in southeastern Wyoming with RKI Exploration & Production, LLC (RKI). Under the agreement, we conveyed to RKI approximately 137,000 net acres and our interest in 67 gross wells with an average working interest of approximately 22% in the northern portion of the Powder River Basin, where RKI is currently designated operator. In exchange, RKI conveyed to us approximately 203,000 net acres and its interest in 186 gross wells with an average working interest of 48% in the southern portion of the Powder River Basin, where we are currently designated operator. In addition to the exchange, we paid RKI approximately $450 million in cash.

We sold noncore leasehold interests in the Marcellus Shale to a subsidiary of Rice Energy Inc. for net proceeds of approximately $233 million.

We sold noncore leasehold interests, producing properties and 61 wellhead compressor units in South Texas to Hilcorp Energy Company for net proceeds of approximately $133 million. All commitments related to VPP #5 were also transferred. See Volumetric Production Payments below.

We sold noncore leasehold interests and producing properties in East Texas and Louisiana for net proceeds of approximately $63 million. All commitments related to VPP #6 were also transferred. See Volumetric Production Payments below.

Excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds of approximately $379 million related to the divestiture of various other oil and natural gas properties.

2013 Transactions

We sold a wholly owned subsidiary, MKR Holdings, L.L.C. (MKR), to Chief Oil and Gas and two of its working interest partners, Enerplus Corporation and Tug Hill Operating. Net proceeds from the transaction were approximately $490 million. MKR held producing wells and undeveloped acreage in the Marcellus Shale.

We sold assets in the Haynesville Shale to EXCO Operating Company, LP (EXCO) for net proceeds of approximately $257 million. Subsequent to closing, we received approximately $47 million of additional net proceeds for post-closing adjustments. The assets sold included our operated and non-operated interests in approximately 9,600 net acres in DeSoto and Caddo parishes, Louisiana.

We sold noncore leasehold interests and producing properties in the northern Eagle Ford Shale to EXCO for net proceeds of approximately $617 million. Subsequent to closing, we received approximately $57 million and $32 million in 2014 and 2013, respectively, of additional net proceeds and for post-closing adjustments. The assets sold included approximately 55,000 net acres in Zavala, Dimmit, La Salle and Frio counties, Texas.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2012 Transactions

We sold the vast majority of our Permian Basin assets, representing approximately 6% of our total proved reserves as of June 30, 2012, in three separate transactions for total net cash proceeds of approximately $3.091 billion. Following the closing, we received $466 million of additional consideration that was withheld subject to certain title, environmental and other standard contingencies. Of the total proceeds, we allocated approximately $42 million to our Permian Basin midstream and other fixed assets. The remaining proceeds were allocated to our Permian Basin oil and natural gas properties.

We sold approximately 40,000 net acres of noncore leasehold in the Chitwood Knox play in Oklahoma for approximately $540 million in cash.

We sold approximately 72,000 net acres of noncore leasehold in the Utica Shale play in Ohio to affiliates of EnerVest, Ltd. for approximately $358 million in cash.

We sold approximately 60,000 net acres of leasehold in the Texoma Woodford play in Oklahoma to XTO Energy Inc., a subsidiary of Exxon Mobil Corporation, for net proceeds of approximately $572 million.

Joint Ventures

Between July 2008 and June 2013, we entered into eight significant joint ventures with other leading energy companies including Sinopec International Petroleum Exploration and Production (Sinopec), Total S.A. (Total), CNOOC Limited, Statoil, BP America and Freeport-McMoRan Copper & Gold (formerly known as Plains Exploration & Production Company), pursuant to which we sold portions ranging from 20% to 50% of certain leasehold, producing properties and other assets located in eight different resource plays. In return, we received aggregate cash proceeds of $8.0 billion and commitments by our joint venture partners to pay, in the aggregate, our share of future drilling and completion costs of $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all drilling, completion and operations, the majority of leasing and, in certain transactions, marketing activities for the project. Each joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner and, if applicable, pays a specified percentage of our drilling and completion costs in designated wells. As of December 31, 2014, we had utilized all drilling carries from our joint venture partners except for Total’s remaining $51 million commitment to pay 60% of our drilling and completion costs for wells drilled in the Utica Shale play. We fully expect to use this drilling carry commitment prior to its expiration in December 2018.

In 2014, 2013 and 2012, our drilling and completion costs included the benefit of approximately $679 million, $884 million and $784 million, respectively, in drilling and completion carries paid by our joint venture partners.

In 2013, we entered into a joint venture with Sinopec in which Sinopec purchased a 50% undivided interest in approximately 850,000 acres in the Mississippian Lime play in northern Oklahoma for $1.11 billion, including $90 million we received for closing adjustments and $71 million placed in escrow with respect to certain post-closing adjustments. As of December 31, 2014, we had received $64 million of the $71 million held in escrow. There was no drilling and completion carry associated with this transaction.

In addition, in 2014, 2013 and 2012, we sold interests in additional leasehold we acquired in the Marcellus, Barnett, Utica, Eagle Ford and Mid-Continent plays to our joint venture partners for approximately $33 million, $58 million and $272 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Volumetric Production Payments

From time to time, we have sold certain of our producing assets located in more mature producing regions through the sale of VPPs. A VPP is a limited-term overriding royalty interest in oil and natural gas reserves that (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser’s only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain all production beyond the specified volumes, if any, after the scheduled production volumes have been delivered. For all of our VPP transactions, we have novated hedges to each of the respective VPP buyers and these hedges covered all VPP volumes sold. If contractually scheduled volumes exceed the actual volumes produced from the VPP wellbores that are attributable to the ORRI conveyed, either the shortfall will be made up from future production from these wellbores (or, at our option, from our retained interest in the wellbores) through an adjustment mechanism, or the initial term of the VPP will be extended until all scheduled volumes, to the extent produced, are delivered from the VPP wellbores to the VPP buyer. We retain drilling rights on the properties below currently producing intervals and outside of producing wellbores.

As the operator of the properties from which the VPP volumes have been sold, we bear the cost of producing the reserves attributable to these interests, which we include as a component of production expenses and production taxes in our consolidated statements of operations in the periods these costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining our full cost ceiling test for impairment purposes and in determining our standardized measure. Pursuant to SEC guidelines, the estimates used for purposes of determining the cost center ceiling and the standardized measure are based on current costs. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet. The costs that will apply in the future will depend on the actual production volumes as well as the production costs and taxes in effect during the periods in which the production actually occurs, which could differ materially from our current and historical costs, and production may not occur at the times or in the quantities projected, or at all.

For accounting purposes, cash proceeds from the sale of VPPs were reflected as a reduction of oil and natural gas properties with no gain or loss recognized, and our proved reserves were reduced accordingly. We have also committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices.

As of December 31, 2014, our outstanding VPPs consisted of the following:

					Volume Sold
VPP #	Date of VPP	Location	Proceeds		Oil	Natural Gas	NGL	Total
			($ in millions)		(mmbbl)	(bcf)	(mmbbl)	(bcfe)
10	March 2012	Anadarko Basin Granite Wash	$	744	3.0	87	9.2	160
9	May 2011	Mid-Continent	853		1.7	138	4.8	177
8	September 2010	Barnett Shale	1,150		—	390	—	390
4	December 2008	Anadarko and Arkoma Basins	412		0.5	95	—	98
3	August 2008	Anadarko Basin	600		—	93	—	93
2	May 2008	Texas, Oklahoma and Kansas	622		—	94	—	94
1	December 2007	Kentucky and West Virginia	1,100		—	208	—	208
			$	5,481	5.2	1,105	14.0	1,220

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The volumes produced on behalf of our VPP buyers during 2014, 2013 and 2012 were as follows:

	Year Ended December 31, 2014
VPP #	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)
10	403.0	10.6	1,296.5	20.7
9	187.5	15.4	411.0	19.0
8	—	60.1	—	60.1
6(a)	23.1	4.2	—	4.3
5(a)	16.5	4.6	—	4.7
4	48.1	9.0	—	9.2
3	—	7.2	—	7.2
2	—	6.2	—	6.2
1	—	13.8	—	13.8
	678.2	131.1	1,707.5	145.2
	Year Ended December 31, 2013
VPP #	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)
10	547.0	13.5	1,509.0	25.8
9	213.2	17.0	455.7	21.0
8	—	68.1	—	68.1
6	24.0	4.8	—	4.9
5	25.4	7.5	—	7.7
4	54.7	10.2	—	10.5
3	—	8.1	—	8.1
2	—	10.3	—	10.3
1	—	14.5	—	14.5
	864.3	154.0	1,964.7	170.9
	Year Ended December 31, 2012
VPP #	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)
10	727.0	18.1	1,729.1	32.8
9	249.3	18.4	643.6	23.7
8	—	79.7	—	79.7
7(b)	490.3	0.4	—	3.4
6	24.0	5.3	—	5.5
5	27.4	8.8	—	9.0
4	62.8	11.7	—	12.2
3	—	9.3	—	9.3
2	—	11.4	—	11.3
1	—	15.3	—	15.3
	1,580.8	178.4	2,372.7	202.2

____________________________________________

(a) In 2014, we divested the properties associated with VPP #5 and VPP #6.

(b) In 2012, to facilitate the sales process associated with our Permian Basin divestiture packages, we purchased the remaining reserves from our Permian Basin VPP (VPP #7). The reserves purchased were subsequently sold to the buyers of our Permian Basin assets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2014 were as follows:

		Volume Remaining as of December 31, 2014
VPP #	Term Remaining	Oil	Natural Gas	NGL	Total
	(in months)	(mmbbl)	(bcf)	(mmbbl)	(bcfe)
10	86	1.3	38.0	4.7	74.0
9	74	0.8	73.2	1.9	89.9
8	8	—	36.6	—	36.6
4	24	0.1	15.3	—	15.8
3	55	—	23.9	—	23.9
2	52	—	13.8	—	13.8
1	96	—	91.5	—	91.5
		2.2	292.3	6.6	345.5

13. Spin-Off of Oilfield Services Business

On June 30, 2014, we completed the spin-off of our oilfield services business, which we previously conducted through our indirect, wholly owned subsidiary COO, into an independent, publicly traded company called SSE. Following the close of business on June 30, 2014, we distributed to Chesapeake shareholders one share of SSE common stock and cash in lieu of fractional shares for every 14 shares of Chesapeake common stock held on June 19, 2014, the record date for the distribution.

Prior to the completion of the spin-off, we and COO and its affiliates engaged in the following series of transactions:

• COO and certain of its subsidiaries entered into a $275 million senior secured revolving credit facility and a $400 million secured term loan, the proceeds of which were used to repay in full and terminate COO’s existing credit facility.

• COO distributed to us its compression unit manufacturing business, its geosteering business and the proceeds from the sale of substantially all of its crude oil hauling business. See Note 16 for further discussion of the sale.

• We transferred to a subsidiary of COO, at carrying value, certain of our buildings and land, most of which COO had been leasing from us prior to the spin-off.

• COO issued $500 million of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility and for general corporate purposes.

• COO converted from a limited liability company into a corporation named Seventy Seven Energy Inc.

• We distributed all of SSE’s outstanding shares to our shareholders, which resulted in SSE becoming an independent, publicly traded company.

Following the spin-off, we have no ownership interest in SSE. Therefore, we ceased to consolidate SSE’s assets and liabilities as of the spin-off date. Because we expect to have significant continued involvement associated with SSE’s future operations through the various agreements described below, our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations. For segment disclosures, we have labeled our oilfield services segment as “former oilfield services”. See Note 21 for additional information regarding our segments.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In connection with the spin-off, we entered into several agreements to define the terms and conditions of the spin-off and our ongoing relationship with SSE after the spin-off, including a master separation agreement, a tax sharing agreement, an employee matters agreement, a transition services agreement, a services agreement and certain commercial agreements. These agreements, among other things, allocate responsibility for obligations arising before and after the distribution date, including obligations relating to taxes, employees, various transition services and oilfield services.

• The master separation agreement sets forth the agreements between SSE and Chesapeake regarding the principal transactions that were necessary to effect the spin-off and also sets forth other agreements that govern certain aspects of SSE’s relationship with Chesapeake after completion of the spin-off.

• The tax sharing agreement governs the respective rights, responsibilities and obligations of SSE and Chesapeake with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings, and certain other matters regarding taxes.

• The employee matters agreement addresses employee compensation and benefit plans and programs, and other related matters in connection with the spin-off, including the treatment of holders of Chesapeake common stock options, restricted stock and performance share units, and the cooperation between SSE and Chesapeake in the sharing of employee information and maintenance of confidentiality. See Note 9 for additional information regarding the effect of the spin-off on outstanding equity compensation.

• The transition services agreement sets forth the terms on which we provide SSE certain services. Transition services include marketing and corporate communication, human resources, information technology, security, legal, risk management, tax, environmental health and safety, maintenance, internal audit, accounting, treasury and certain other services specified in the agreement. SSE pays Chesapeake a negotiated fee for providing those services.

• The services agreement requires us to utilize, at market-based pricing, certain SSE pressure pumping services. See Note 4 for a summary of the terms of the services agreement.

• We have also entered into drilling agreements that are rig-specific daywork drilling contracts with terms ranging from three months to three years and at market-based rates. We have the right to terminate a drilling agreement in certain circumstances. As of December 31, 2014, the aggregate undiscounted minimum future payments under these drilling agreements were approximately $410 million.

In 2014, our stockholders’ equity decreased by $270 million, net of $151 million of associated deferred tax liabilities, as the result of the spin-off, and we recognized $15 million of charges associated with the spin-off that are included in restructuring and other termination costs on our consolidated statement of operations. See Note 18 for further details regarding these charges.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

14. Investments

A summary of our investments, including our approximate ownership percentage and carrying value as of December 31, 2014 and 2013, is presented below.

		Approximate Ownership %		Carrying Value
	Accounting	December 31,		December 31,
	Method	2014	2013	2014		2013
				($ in millions)
FTS International, Inc.	Equity	30%	30%	$	116	$	138
Sundrop Fuels, Inc.	Equity	56%	56%	130		135
Chaparral Energy, Inc.	Equity	—%	20%	—		143
Other	—	—%	—%	19		61
Total investments				$	265	$	477

FTS International, Inc. FTS, based in Fort Worth, Texas, is a privately held company that, through its subsidiaries, provides hydraulic fracturing and other services to oil and gas companies. In 2014, we recorded negative equity method and other adjustments of $32 million for our share of FTS’s net loss and recorded an accretion adjustment of $10 million related to the excess of our underlying equity in net assets of FTS over our carrying value.

As of December 31, 2014, the carrying value of our investment in FTS was less than our underlying equity in net assets by approximately $44 million, of which $14 million was attributed to non-depreciable assets. The value attributed to depreciable assets is being accreted over the estimated useful lives of the underlying assets.

Sundrop Fuels, Inc. Sundrop Fuels, Inc. (Sundrop), based in Longmont, Colorado, is a privately held cellulosic biofuels company that is constructing a nonfood biomass-based “green gasoline” plant. In 2014, we recorded a $21 million charge related to our share of Sundrop's net loss and $16 million of capitalized interest associated with the construction of Sundrop’s plant. The carrying value of our investment in Sundrop was in excess of our underlying equity in net assets by approximately $78 million as of December 31, 2014 and will be amortized over the life of the plant once it is placed into service.

Sold Investments

Chaparral Energy, Inc. Chaparral Energy, Inc. (Chaparral), based in Oklahoma City, Oklahoma, is a private independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties. In 2014, we sold all of our interest in Chaparral for net cash proceeds of $209 million. We recorded a $73 million gain related to the sale.

Clean Energy Fuels Corp. In 2013, we sold all of our shares of Clean Energy Fuels Corp. (Clean Energy) common stock for cash proceeds of approximately $13 million. We recorded a $3 million gain related to the sale. In 2013, we sold our $100 million investment in convertible notes of Clean Energy for cash proceeds of $85 million. The buyer also assumed our commitment to purchase the third and final $50 million tranche of Clean Energy convertible notes. We recorded a $15 million loss related to this sale.

Gastar Exploration Ltd. In 2013, we sold our investment in Gastar Exploration Ltd. for cash proceeds of $10 million.

Chesapeake Midstream Partners, L.P. In 2012, we sold all of our common and subordinated units representing limited partner interests in Chesapeake Midstream Partners, L.P., now named Access Midstream Partners, L.P., and all of our limited liability company interests in the sole member of its general partner to funds affiliated with Global Infrastructure Partners for cash proceeds of $2.0 billion. We recorded a $1.032 billion gain associated with the transaction.

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Glass Mountain Pipeline, LLC. In 2012, our wholly owned midstream subsidiary, Chesapeake Midstream Development, L.L.C. (CMD), entered into an agreement with two other parties to form Glass Mountain Pipeline, LLC to construct a 210 mile pipeline in western and north central Oklahoma in which CMD had a 50% ownership interest. In 2012, CMD sold its interest for $99 million and recorded a gain of $62 million.

Other. In 2014, we sold an equity investment in a natural gas trading and management firm for cash proceeds of $30 million and recorded a loss of $6 million associated with the transaction.

In 2013, we sold an equity investment for cash proceeds of $6 million and recorded a $5 million gain associated with the transaction.

15. Variable Interest Entities

We consolidate the activities of VIEs for which we are the primary beneficiary. In order to determine whether we own a variable interest in a VIE, we perform qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.

Consolidated VIE

Chesapeake Granite Wash Trust. For a discussion of the formation, operations and presentation of the Trust, see Noncontrolling Interests in Note 8. The Trust is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Trust. Our ownership in the Trust and our obligations under the development agreement and related drilling support lien constitute variable interests. We have determined that we are the primary beneficiary of the Trust because (i) we have the power to direct the activities that most significantly impact the economic performance of the Trust via our obligations to perform under the development agreement, and (ii) as a result of the subordination and incentive thresholds applicable to the subordinated units we hold in the Trust, we have the obligation to absorb losses and the right to receive residual returns that could potentially be significant to the Trust. As a result, we consolidate the Trust in our financial statements, and the common units of the Trust owned by third parties are reflected as a noncontrolling interest.

The Trust is a consolidated entity whose legal existence is separate from Chesapeake and our other consolidated subsidiaries, and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake; however, we have certain obligations to the Trust through the development agreement that are secured by a drilling support lien on our retained interest in the development wells up to a specified maximum amount recoverable by the Trust, which could result in the Trust acquiring all or a portion of our retained interest in the undeveloped portion of an area of mutual interest, if we do not meet our drilling commitment. In consolidation, as of December 31, 2014, $1 million of cash and cash equivalents, $16 million of short-term derivative assets, $488 million of proved oil and natural gas properties, $251 million of accumulated depreciation, depletion and amortization and $15 million of other current liabilities were attributable to the Trust. We have presented parenthetically on the face of the consolidated balance sheets the assets of the Trust that can be used only to settle obligations of the Trust and the liabilities of the Trust for which creditors do not have recourse to the general credit of Chesapeake.

Unconsolidated VIE

Mineral Acquisition Company I, L.P. In 2012, MAC-LP, L.L.C., a wholly owned non-guarantor unrestricted subsidiary of Chesapeake, entered into a partnership agreement with KKR Royalty Aggregator LLC (KKR) to form Mineral Acquisition Company I, L.P. The purpose of the partnership is to acquire mineral interests, or royalty interests carved out of mineral interests, in oil and natural gas basins in the continental United States. We are committed to acquire for our own account (outside the partnership) 10% of any acquisition agreed upon by the partnership up to a maximum of $25 million, and the partnership will acquire the remaining 90% up to a maximum of $225 million, funded entirely by KKR, making KKR the sole equity investor. We have significant influence over the decisions made by the partnership, as we hold two of five seats on the board of directors. We will receive proportionate distributions from the partnership of any cash received from royalties in excess of expenses paid, ranging from 7% to 22.5%. The partnership is considered a VIE because KKR’s control over the partnership is disproportionate to its economic interest. This VIE remains unconsolidated as the power to direct the activities of the partnership is shared between the Company and KKR. We are using the equity method to account for this investment. The carrying value of our investment was $9 million as of December 31, 2014.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

16. Other Property and Equipment

Other Property and Equipment

A summary of other property and equipment held for use and the estimated useful lives thereof is as follows:

	December 31,						Estimated Useful Life
	2014			2013
	($ in millions)						(in years)
Buildings and improvements	$	1,242		$	1,433		10 - 39
Natural gas compressors	551			368			3 - 20
Land	296			212			—
Gathering systems and treating plants	218			292			20
Oilfield services equipment	—			2,192			3 - 15
Other	776			898			2 - 20
Total other property and equipment, at cost	3,083			5,395
Less: accumulated depreciation	(804		)	(1,584		)
Total other property and equipment, net	$	2,279		$	3,811

Net Gains on Sales of Fixed Assets

A summary by asset class of (gains) or losses on sales of fixed assets for the years ended December 31, 2014, 2013 and 2012 is as follows:

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Natural gas compressors	$	(195	)	$	—		$	—
Gathering systems and treating plants	8			(326		)	(286		)
Oilfield services equipment	(7		)	2			10
Buildings and land	(2		)	27			7
Other	(3		)	(5		)	2
Total net gains on sales of fixed assets	$	(199	)	$	(302	)	$	(267	)

Natural Gas Compressors. In 2014, as part of a divestiture of noncore oil and natural gas properties in South Texas, we sold 61 compressors and related equipment to Hilcorp Energy Company for $19 million. We recorded a $6 million gain associated with the compressors sold. Also in 2014, we sold 499 compressors and related equipment to Exterran Partners, L.P. for approximately $495 million. We recorded a $161 million gain associated with the compressors sold. In 2014, we also sold 102 compressors and related equipment to Access Midstream Partners, L.P. (ACMP) for proceeds of approximately $159 million. We recorded a $24 million gain associated with the transaction.

Gathering Systems and Treating Plants. In 2013, we sold our wholly owned midstream subsidiary Mid-America Midstream Gas Services, L.L.C. to SemGas, L.P., a wholly owned subsidiary of SemGroup Corporation, for net proceeds of approximately $306 million. We recorded a $141 million gain associated with the transaction. In 2013, we also sold our wholly owned subsidiary Granite Wash Midstream Gas Services, L.L.C. to MarkWest Oklahoma Gas Company, L.L.C. (MW), a wholly owned subsidiary of MarkWest Energy Partners, L.P., for net proceeds of approximately $252 million. We recorded a $105 million gain associated with this transaction. The transaction with MW included long-term fixed fee arrangements for gas gathering, compression, treating and processing services in the Anadarko Basin. In 2013, we also sold our interest in certain gathering system assets in Pennsylvania to Western Gas Partners, LP for proceeds of approximately $134 million. We recorded a $55 million gain associated with this transaction.

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In 2012, CMD sold its wholly owned subsidiary, CMO, which held a majority of our midstream business, to ACMP for total consideration of $2.16 billion in cash.In connection with the sale, Chesapeake entered into new long-term agreements in which ACMP agreed to perform certain natural gas gathering and related services for us within specified acreage dedication areas in exchange for (i) cost-of-service based fees redetermined annually beginning January 2014 in the Niobrara and Marcellus Shale plays, (ii) cost-of-service based fees redetermined annually beginning October 2013 for the wet gas gathering systems and January 2014 for the dry gas gathering systems in the Utica Shale play, (iii) tiered fees based on volumes delivered relative to scheduled volumes through 2015 and thereafter cost-of-service based fees redetermined annually in the Eagle Ford Shale play, and (iv) annual minimum volume commitments and a fixed fee per mmbtu of natural gas gathered, subject to an annual 2.5% rate escalation, through 2017 and thereafter tiered fees based on volumes delivered relative to scheduled volumes in the Haynesville Shale play. We recorded a $289 million gain associated with this transaction.

In 2012, we sold our oil gathering business and related assets in the Eagle Ford Shale to Plains Pipeline, L.P. for cash proceeds of approximately $115 million. Subsequent to December 31, 2012, we received an additional $10 million of proceeds upon satisfaction of a certain closing contingency. We recorded a $3 million gain associated with this transaction. In connection with the sale, we entered into new gathering and transportation agreements covering acreage dedication areas.

Oilfield Services Equipment. In 2014, we sold substantially all of our crude oil hauling assets for approximately $44 million. We recorded a $23 million gain associated with the transaction. Also, in 2014, we sold 14 rigs for approximately $14 million and recorded a $14 million loss.

Buildings and Land. The net gains in 2014 and the net losses in 2013 on sales of buildings and land were mainly from the sale of certain buildings and land located primarily in our Oklahoma City and Barnett Shale operating area.

Assets Held for Sale

In 2013, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. In addition, as of December 31, 2014, we were continuing to pursue the sale of land located in the Fort Worth, Texas area. Land and buildings are recorded within our other segment. These Oklahoma City and Fort Worth assets are being actively marketed, and we believe it is probable they will be sold over the next 12 months. As a result, these assets are reflected as held for sale as of December 31, 2014. Oil and natural gas properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and gas properties. A summary of the assets held for sale on our consolidated balance sheets as of December 31, 2014 and 2013 is detailed below.

	December 31,
	2014		2013
	($ in millions)
Buildings and land, net of accumulated depreciation	$	93	$	405
Compressors, net of accumulated depreciation	—		285
Oilfield services equipment, net of accumulated depreciation	—		29
Gathering systems and treating plants, net of accumulated depreciation	—		11
Property and equipment held for sale, net	$	93	$	730

In 2014, management determined that certain properties in the Fort Worth area of the Barnett Shale, previously classified as held for sale as of December 31, 2013, would be reclassified as held for use. As of December 31, 2013, management’s development plan for the Barnett Shale did not contemplate the need for the underlying properties (for pad drilling in certain urban locations around Fort Worth) and the properties were marketed for sale. Management modified its development plan and consequently these properties no longer met the criteria to be classified as held for sale. The properties were measured at the lesser of their fair value at the date of the decision not to sell or their carrying amount before being classified as held for sale. During 2014, we reclassified $120 million of these properties to held for use classification. There was no impact to the statement of operations related to this reclassification.

During 2014, we sold compressors previously classified as held for sale to Hilcorp Energy Company and Exterran Partners, L.P. The oilfield services equipment was included in the spin-off of our oilfield services business. See Note 13 for further discussion of the spin-off.

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17. Impairments

Impairments of Oil and Natural Gas Properties

Our oil and natural gas properties are subject to quarterly full cost ceiling tests. As of September 30, 2012, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment in the carrying value of oil and natural gas properties of $3.315 billion. Cash flow hedges as of September 30, 2012, which related to future periods, increased the ceiling test impairment by $279 million. We were not required to record impairments of oil and natural gas properties for any other quarter in 2012 or for any quarters in 2013 or 2014. Based on the decline in oil and natural gas prices in the second half of 2014 and into 2015, we expect to have a material write-down of the carrying value of our oil and natural gas properties in the 2015 first quarter. Further material write-downs in subsequent quarters will occur if the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters.

Impairments of Fixed Assets and Other

We review our long-lived assets, other than oil and natural gas properties, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable. We recognize an impairment loss if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2014, 2013 and 2012 is as follows:

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
Natural gas compressors	$	11	$	—	$	—
Gathering systems and treating plants	13		22		6
Oilfield services equipment	23		71		60
Buildings and land	18		366		248
Other	23		87		26
Total impairments of fixed assets and other	$	88	$	546	$	340

Oilfield Services Equipment. In 2014, we purchased 31 leased rigs and equipment from various lessors for an aggregate purchase price of $140 million. In connection with these purchases, we paid $8 million in early lease termination costs, which are included in impairments of fixed assets and other in the consolidated statement of operations. We recognized an impairment loss of approximately $15 million related to leasehold improvements associated with these assets. In 2013, we purchased 23 leased rigs (two of which were classified as held for sale assets as of December 31, 2013) from various lessors for an aggregate purchase price of $141 million and paid approximately $22 million in early lease termination costs, which is included in impairments of fixed assets and other in the consolidated statement of operations. In addition, we impaired approximately $22 million related to leasehold improvements and other costs associated with these assets. In 2013, we also recognized $27 million of impairment losses on certain of our drilling rigs that qualified as held for sale during 2013 for the difference between the carrying amount and fair value, less the anticipated costs to sell. We estimated the fair value using prices expected to be received. In 2012, we purchased 25 leased rigs from various lessors for an aggregate purchase price of $36 million and paid approximately $25 million in early lease termination costs, which is included in impairments of fixed assets and otherin the consolidated statement of operations. In addition, in 2012, we recognized $26 million of impairment losses on certain of our drilling rigs that we expected would have insufficient cash flow to recover carrying values because of a change in business climate resulting from depressed natural gas prices. In 2012, we also recognized $9 million of impairment losses primarily related to drill pipe and other oilfield services equipment.

Buildings and Land. In 2013, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. We recognized an impairment loss of $186 million on these assets for the difference between the carrying amount and fair value of the assets, less the anticipated costs to sell. Given the impairment losses associated with these assets, we tested other noncore buildings and land that we owned in the Oklahoma City area for recoverability. As a result of this test, we recognized an impairment loss of $69 million on these assets in 2013.

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Due to a decrease in the estimated market prices of certain property classified as held for sale in the Fort Worth area, we recognized an additional impairment loss of $86 million in 2013. We tested other noncore surface land that we owned in the Fort Worth area for recoverability in 2013 and recognized an additional impairment loss of $10 million on these assets for the difference between the carrying amount and fair value of the assets. In addition, in 2012, we recognized $248 million of impairment losses associated with an office building and surface land located in our Barnett Shale operating area. The change in business climate in the Barnett Shale in 2012, evidenced by our significant reduction in Barnett Shale operations and depressed natural gas prices, required us to test these long-lived assets for recoverability. 

Finally, we recorded an impairment loss of approximately $15 million on certain of our buildings and land outside of the Oklahoma City and Fort Worth areas in 2013. All the buildings and land for which impairment losses were recognized in 2014, 2013 and 2012 are included in our other segment.

Other. Under the terms of our joint venture agreements (see Note 12), we are required to extend, renew or replace certain expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas. In 2014, we revised our estimate of our net acreage shortfall as of December 31, 2012 under the terms of our Barnett Shale joint venture agreement with Total and recorded an additional $22 million charge. See Note 4 for additional discussion regarding our net acreage maintenance commitments. In 2013, we recorded approximately $87 million of other charges, including $26 million for the termination of a gas gathering agreement, $28 million for the impairment of certain assets used to promote natural gas demand, $15 million for the termination of a contract drilling agreement with a third party, $2 million related to the estimated 2012 shortfall of our net acreage maintenance commitment with Total in the Barnett Shale and $16 million related to various other assets. In 2012, we recorded a $26 million charge related to the estimated 2012 shortfall of our net acreage maintenance commitment with Total in the Barnett Shale.

Nonrecurring Fair Value Measurements. Fair value measurements for certain of the impairments discussed above were based on recent sales information for comparable assets. As the fair value was estimated using the market approach based on recent prices from orderly sales transactions for comparable assets between market participants, the values were classified as Level 2 in the fair value hierarchy. Fair value measurements of the buildings and land discussed above were based on prices from orderly sales transactions for comparable properties between market participants, purchase offers we received from third parties and, in certain cases, discounted cash flows. As some inputs used were not observable in the market, these values were classified as Level 3 in the fair value hierarchy.

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18. Restructuring and Other Termination Costs

On June 30, 2014, we completed the spin-off of our oilfield services business through a pro rata distribution of SSE common stock to holders of Chesapeake common stock. In connection with the spin-off, in 2014, we incurred restructuring charges of $15 million consisting of transaction costs, stock-based compensation adjustments and debt extinguishment costs. See Note 13 for further discussion of the spin-off.

On September 9, 2013, we committed to a workforce reduction plan as part of a company-wide reorganization effort intended to reduce costs. The reduction was communicated to affected employees on various dates within the months of September and October, and all notifications were completed by October 11, 2013. The plan resulted in a reduction of approximately 900 employees. In connection with the reduction, we incurred a charge of approximately $66 million.

On April 1, 2013, Aubrey K. McClendon, the co-founder of the Company, ceased serving as President and CEO and as a director of the Company pursuant to his agreement with the Board of Directors announced on January 29, 2013. Mr. McClendon’s departure from the Company was treated as a termination without cause under his employment agreement. On April 18, 2013, the Company and Mr. McClendon entered into a Founder Separation and Services Agreement, effective January 29, 2013, regarding his separation from employment and to facilitate the relationship between the Company and Mr. McClendon as joint working interest owners of oil and gas wells, leases and acreage. In 2013, we incurred charges of approximately $69 million related to Mr. McClendon’s departure.

During 2013, we also incurred charges of approximately $50 million related to other workforce reductions, including separations of executive officers other than the former CEO. Substantially all of the restructuring and other termination costs in 2013 are in the exploration and production operating segment.

In December 2012, Chesapeake announced that it had offered a voluntary separation program (VSP) to certain employees as part of the Company's ongoing efforts to improve efficiencies and reduce costs. The VSP was offered to approximately 275 employees who met criteria based upon a combination of age and years of Chesapeake service, and 211 accepted prior to the expiration of the offer in February 2013. We recognized the expense related to their termination benefits over their remaining service period, which resulted in $63 million of expense for 2013.

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Below is a summary of our restructuring and other termination costs for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014			2013		2012
	($ in millions)
Oilfield services spin-off costs:
Transaction costs	$	17		$	—	$	—
Stock-based compensation adjustments for Chesapeake employees	5			—		—
Stock-based compensation forfeitures for SSE employees	(10		)	—		—
Debt extinguishment costs	3			—		—
Total oilfield services spin-off costs	15			—		—
Restructuring charges under workforce reduction plan:
Salary expense	—			20		—
Acceleration of stock-based compensation	—			45		—
Other termination benefits	—			1		—
Total restructuring changes under workforce reduction plan	—			66		—
Termination benefits provided to Mr. McClendon:
Salary and bonus expense	—			11		—
Acceleration of 2008 performance bonus clawback	—			11		—
Acceleration of stock-based compensation	—			22		—
Acceleration of performance share unit awards(a)	(8		)	18		—
Estimated aircraft usage benefits	—			7		—
Total termination benefits provided to Mr. McClendon	(8		)	69		—
Termination benefits provided to VSP participants:
Salary and bonus expense	—			33		1
Acceleration of stock-based compensation	—			29		1
Other termination benefits	—			1		—
Total termination benefits provided to VSP participants	—			63		2
Other termination benefits(a)	—			50		5
Total restructuring and other termination costs	$	7		$	248	$	7

____________________________________________

(a) Amounts for the year ended December 31, 2014 are primarily related to negative fair value adjustments to PSUs granted to former executives of the Company. For further discussion of our PSUs, see Note 9.

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19. Fair Value Measurements

Recurring Fair Value Measurements

Other Current Assets. Assets related to Company matches of employee contributions to Chesapeake’s employee benefit plans are included in other current assets. The fair value of these assets is determined using quoted market prices as they consist of exchange-traded securities.

Other Current Liabilities. Liabilities related to Chesapeake’s deferred compensation plan are included in other current liabilities. The fair values of these liabilities are determined using quoted market prices as the plan consists of exchange-traded mutual funds.

Financial Assets (Liabilities). The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:

	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value
				($ in millions)
As of December 31, 2014
Financial Assets (Liabilities):
Other current assets	$	57		$	—	$	—	$	57
Other current liabilities	(58		)	—		—		(58		)
Total	$	(1	)	$	—	$	—	$	(1	)
As of December 31, 2013
Financial Assets (Liabilities):
Other current assets	$	80		$	—	$	—	$	80
Other current liabilities	(82		)	—		—		(82		)
Total	$	(2	)	$	—	$	—	$	(2	)

See Note 3 for information regarding fair value of other financial instruments. See Note 11 for information regarding fair value measurement of derivatives.

Nonrecurring Fair Value Measurements

See Note 17 regarding nonrecurring fair value measurements.

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20. Asset Retirement Obligations

The components of the change in our asset retirement obligations are shown below.

	Years Ended December 31,
	2014			2013
	($ in millions)
Asset retirement obligations, beginning of period	$	405		$	375
Additions	29			20
Revisions(a)	101			8
Settlements and disposals	(92		)	(20		)
Accretion expense	22			22
Asset retirement obligations, end of period	465			405
Less current portion (b)	18			—
Asset retirement obligation, long-term	$	447		$	405

_________________________________________

(a) Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settlement.

(b) Balance is included in other current liabilities on the consolidated balance sheet.

21. Major Customers and Segment Information

Sales to ExxonMobil Corporation and Plains Marketing, L.P. constituted approximately 12% and 11%, respectively, of our total revenues (before the effects of hedging) for the years ended December 31, 2014 and 2012, respectively. There were no sales to individual customers constituting 10% or more of total revenues (before the effects of hedging) for the year ended December 31, 2013.

As of December 31, 2014, we have two reportable operating segments, each of which is managed separately because of the nature of its operations. The exploration and production operating segment is responsible for finding and producing oil, natural gas and NGL. The marketing, gathering and compression operating segment is responsible for marketing, gathering and compression of oil, natural gas and NGL. In addition, prior to the spin-off described in Note 13, our former oilfield services operating segment was responsible for drilling, oilfield trucking, oilfield rentals, hydraulic fracturing and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations, as reflected in the table below.

Management evaluates the performance of our segments based upon income (loss) before income taxes. Revenues from the sale of oil, natural gas and NGL related to Chesapeake’s ownership interests by our marketing, gathering and compression operating segment are reflected as revenues within our exploration and production operating segment. These amounts totaled $8.565 billion, $7.570 billion and $5.464 billion for the years ended December 31, 2014, 2013 and 2012, respectively. Revenues generated by our former oilfield services operating segment for work performed for Chesapeake’s exploration and production operating segment were reclassified to the full cost pool based on Chesapeake’s ownership interest. Revenues reclassified totaled $544 million, $1.309 billion and $1.315 billion for the years ended December 31, 2014, 2013 and 2012, respectively. No income was recognized in our consolidated statements of operations related to oilfield services performed for Chesapeake-operated wells.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following tables present selected financial information for Chesapeake’s operating segments:

	Exploration and Production			Marketing, Gathering and Compression			Former Oilfield Services			Other			Intercompany Eliminations			Consolidated  Total
	($ in millions)
Year Ended December 31, 2014:
Revenues	$	8,180		$	20,790		$	1,060		$	30		$	(9,109	)	$	20,951
Intersegment revenues	—			(8,565		)	(544		)	—			9,109			—
Total revenues	$	8,180		$	12,225		$	516		$	30		$	—		$	20,951
Unrealized gains on commodity derivatives	$	(1,394	)	$	—		$	—		$	—		$	—		$	(1,394	)
Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,756		$	38		$	145		$	42		$	(66	)	$	2,915
Impairments of fixed assets and other	$	22		$	24		$	23		$	19		$	—		$	88
Net gains on sales of fixed assets	$	(2	)	$	(187	)	$	(8	)	$	(2	)	$	—		$	(199	)
Interest expense	$	(709	)	$	(21	)	$	(42	)	$	3		$	680		$	(89	)
Earnings (losses) on investments	$	2		$	—		$	(6	)	$	(76	)	$	—		$	(80	)
Net gain (loss) on sales of investments	$	(6	)	$	—		$	—		$	73		$	—		$	67
Losses on purchases of debt	$	(197	)	$	—		$	—		$	—		$	—		$	(197	)
Income (Loss) Before Income Taxes	$	2,874		$	326		$	(16	)	$	(30	)	$	46		$	3,200
Total Assets	$	35,381		$	1,978		$	—		$	4,283		$	(891	)	$	40,751
Capital Expenditures	$	6,173		$	298		$	158		$	38		$	—		$	6,667

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Exploration and Production			Marketing, Gathering and Compression			Former Oilfield Services			Other			Intercompany Eliminations			Consolidated  Total
	($ in millions)
Year Ended December 31, 2013:
Revenues	$	7,052		$	17,129		$	2,188		$	29		$	(8,892	)	$	17,506
Intersegment revenues	—			(7,570		)	(1,309		)	(13		)	8,892			—
Total revenues	$	7,052		$	9,559		$	879		$	16		$	—		$	17,506
Unrealized gains on commodity derivatives	$	(228	)	$	—		$	—		$	—		$	—		$	(228	)
Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,674		$	46		$	289		$	49		$	(155	)	$	2,903
Impairments of fixed assets and other	$	27		$	50		$	75		$	394		$	—		$	546
Net (gains) losses on sales of fixed assets	$	2		$	(329	)	$	(1	)	$	26		$	—		$	(302	)
Interest expense	$	(918	)	$	(24	)	$	(82	)	$	(74	)	$	871		$	(227	)
Earnings (losses) on investments	$	3		$	—		$	(1	)	$	(229	)	$	1		$	(226	)
Net gain (loss) on sales of investments	$	—		$	—		$	—		$	(7	)	$	—		$	(7	)
Losses on purchases of debt	$	(193	)	$	—		$	—		$	—		$	—		$	(193	)
Income (Loss) Before Income Taxes	$	2,997		$	511		$	(51	)	$	(727	)	$	(1,288	)	$	1,442
Total Assets	$	35,341		$	2,430		$	2,018		$	5,750		$	(3,757	)	$	41,782
Capital Expenditures	$	6,198		$	299		$	272		$	421		$	—		$	7,190

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Exploration and Production			Marketing, Gathering and Compression			Former Oilfield Services			Other			Intercompany Eliminations			Consolidated  Total
	($ in millions)
Year Ended December 31, 2012:
Revenues	$	6,278		$	10,895		$	1,917		$	21		$	(6,795	)	$	12,316
Intersegment revenues	—			(5,464		)	(1,315		)	(16		)	6,795			—
Total revenues	$	6,278		$	5,431		$	602		$	5		$	—		$	12,316
Unrealized losses on commodity derivatives	$	(561	)	$	—		$	—		$	—		$	—		$	(561	)
Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,624		$	54		$	232		$	46		$	(145	)	$	2,811
Impairment of oil and natural gas properties	$	3,315		$	—		$	—		$	—		$	—		$	3,315
Impairments of fixed assets and other	$	28		$	6		$	60		$	246		$	—		$	340
Net (gains) losses on sales of fixed assets	$	14		$	(298	)	$	10		$	7		$	—		$	(267	)
Interest expense	$	(47	)	$	(20	)	$	(76	)	$	(364	)	$	430		$	(77	)
Earnings (losses) on investments	$	—		$	49		$	—		$	(152	)	$	—		$	(103	)
Net gain (loss) on sales of investments	$	(2	)	$	1,094		$	—		$	—		$	—		$	1,092
Losses on purchases of debt	$	(200	)	$	—		$	—		$	—		$	—		$	(200	)
Income (Loss) Before Income Taxes	$	(1,798	)	$	1,665		$	112		$	(478	)	$	(475	)	$	(974	)
Total Assets	$	37,004		$	2,291		$	2,115		$	2,529		$	(2,328	)	$	41,611
Capital Expenditures	$	12,044		$	852		$	658		$	554		$	—		$	14,108

22. Condensed Consolidating Financial Information

Chesapeake Energy Corporation is a holding company, owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding senior notes and contingent convertible senior notes listed in Note 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries are non-guarantors. Our former oilfield services subsidiaries were separately capitalized and were not guarantors of our debt obligations.

The tables below are condensed consolidating financial statements for Chesapeake Energy Corporation (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012. This financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2014

($ in millions)

	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	4,100	$	2	$	84	$	(78	)	$	4,108
Restricted cash	—		—		38		—			38
Other	55		3,174		93		—			3,322
Intercompany receivable, net	24,527		—		341		(24,868		)	—
Total Current Assets	28,682		3,176		556		(24,946		)	7,468
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	—		28,358		1,112		673			30,143
Other property and equipment, net	—		2,276		3		—			2,279
Property and equipment held for sale, net	—		93		—		—			93
Total Property and Equipment, Net	—		30,727		1,115		673			32,515
LONG-TERM ASSETS:
Other assets	153		618		26		(29		)	768
Investments in subsidiaries and intercompany advances	126		467		—		(593		)	—
TOTAL ASSETS	$	28,961	$	34,988	$	1,697	$	(24,895	)	$	40,751
CURRENT LIABILITIES:
Current liabilities	$	792	$	5,084	$	68	$	(81	)	$	5,863
Intercompany payable, net	—		24,937		—		(24,937		)	—
Total Current Liabilities	792		30,021		68		(25,018		)	5,863
LONG-TERM LIABILITIES:
Long-term debt, net	11,154		—		—		—			11,154
Deferred income tax liabilities	—		3,751		234		200			4,185
Other long-term liabilities	112		1,090		142		—			1,344
Total Long-Term Liabilities	11,266		4,841		376		200			16,683
EQUITY:
Chesapeake stockholders’ equity	16,903		126		1,253		(1,379		)	16,903
Noncontrolling interests	—		—		—		1,302			1,302
Total Equity	16,903		126		1,253		(77		)	18,205
TOTAL LIABILITIES AND EQUITY	$	28,961	$	34,988	$	1,697	$	(24,895	)	$	40,751

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

YEAR ENDED DECEMBER 31, 2013

($ in millions)

	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	799	$	8		$	38	$	(8	)	$	837
Restricted cash	—		37			38		—			75
Other	103		2,465			524		(348		)	2,744
Intercompany receivable, net	25,549		—			860		(26,409		)	—
Total Current Assets	26,451		2,510			1,460		(26,765		)	3,656
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	—		30,933			1,471		189			32,593
Other property and equipment, net	—		2,360			1,452		(1		)	3,811
Property and equipment held for sale, net	—		701			29		—			730
Total Property and Equipment, Net	—		33,994			2,952		188			37,134
LONG-TERM ASSETS:
Other assets	111		1,161			96		(376		)	992
Investments in subsidiaries and intercompany advances	2,169		(209		)	—		(1,960		)	—
TOTAL ASSETS	$	28,731	$	37,456		$	4,508	$	(28,913	)	$	41,782
CURRENT LIABILITIES:
Current liabilities	$	300	$	5,262		$	309	$	(356	)	$	5,515
Intercompany payable, net	—		26,409			—		(26,409		)	—
Total Current Liabilities	300		31,671			309		(26,765		)	5,515
LONG-TERM LIABILITIES:
Long-term debt, net	11,831		—			1,055		—			12,886
Deferred income tax liabilities	209		2,338			773		87			3,407
Other long-term liabilities	396		1,278			504		(344		)	1,834
Total Long-Term Liabilities	12,436		3,616			2,332		(257		)	18,127
EQUITY:
Chesapeake stockholders’ equity	15,995		2,169			1,867		(4,036		)	15,995
Noncontrolling interests	—		—			—		2,145			2,145
Total Equity	15,995		2,169			1,867		(1,891		)	18,140
TOTAL LIABILITIES AND EQUITY	$	28,731	$	37,456		$	4,508	$	(28,913	)	$	41,782

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2014

($ in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	7,765		$	418		$	(3	)	$	8,180
Marketing, gathering and compression	—			12,220			5			—			12,225
Oilfield services	—			41			983			(478		)	546
Total Revenues	—			20,026			1,406			(481		)	20,951
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			1,166			42			—			1,208
Production taxes	—			227			5			—			232
Marketing, gathering and compression	—			12,232			4			—			12,236
Oilfield services	—			53			769			(391		)	431
General and administrative	—			273			49			—			322
Restructuring and other termination costs	—			4			3			—			7
Provision for legal contingencies	100			134			—			—			234
Oil, natural gas and NGL depreciation, depletion and amortization	—			2,523			162			(2		)	2,683
Depreciation and amortization of other assets	—			153			143			(64		)	232
Impairment of oil and natural gas properties	—			—			349			(349		)	—
Impairments of fixed assets and other	—			65			23			—			88
Net gains on sales of fixed assets	—			(192		)	(7		)	—			(199		)
Total Operating Expenses	100			16,638			1,542			(806		)	17,474
INCOME (LOSS) FROM OPERATIONS	(100		)	3,388			(136		)	325			3,477
OTHER INCOME (EXPENSE):
Interest expense	(657		)	(37		)	(42		)	647			(89		)
Losses on investments	—			(77		)	(5		)	2			(80		)
Net gain on sales of investments	—			67			—			—			67
Losses on purchases of debt	(195		)	(2		)	—			—			(197		)
Other income (expense)	502			198			(2		)	(676		)	22
Equity in net earnings (losses) of subsidiary	2,206			(258		)	—			(1,948		)	—
Total Other Income (Expense)	1,856			(109		)	(49		)	(1,975		)	(277		)
INCOME (LOSS) BEFORE INCOME TAXES	1,756			3,279			(185		)	(1,650		)	3,200
INCOME TAX EXPENSE (BENEFIT)	(161		)	1,264			(66		)	107			1,144
NET INCOME (LOSS)	1,917			2,015			(119		)	(1,757		)	2,056
Net income attributable to noncontrolling interests	—			—			—			(139		)	(139		)
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	1,917			2,015			(119		)	(1,896		)	1,917
Other comprehensive income	1			18			—			—			19
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	1,918		$	2,033		$	(119	)	$	(1,896	)	$	1,936

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2013

($ in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	6,439		$	553		$	60		$	7,052
Marketing, gathering and compression	—			9,547			12			—			9,559
Oilfield services	—			221			1,836			(1,162		)	895
Total Revenues	—			16,207			2,401			(1,102		)	17,506
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			1,112			47			—			1,159
Production taxes	—			222			7			—			229
Marketing, gathering and compression	—			9,455			6			—			9,461
Oilfield services	—			239			1,434			(937		)	736
General and administrative	—			375			83			(1		)	457
Restructuring and other termination costs	—			244			4			—			248
Oil, natural gas and NGL depreciation, depletion and amortization	—			2,336			253			—			2,589
Depreciation and amortization of other assets	—			180			281			(147		)	314
Impairment of oil and natural gas properties	—			(2		)	313			(311		)	—
Impairments of fixed assets and other	—			417			129			—			546
Net gains on sales of fixed assets	—			(301		)	(1		)	—			(302		)
Total Operating Expenses	—			14,277			2,556			(1,396		)	15,437
INCOME (LOSS) FROM OPERATIONS	—			1,930			(155		)	294			2,069
OTHER INCOME (EXPENSE):
Interest expense	(921		)	(4		)	(85		)	783			(227		)
Losses on investments	—			(225		)	(1		)	—			(226		)
Net loss on sales of investments	—			(7		)	—			—			(7		)
Losses on purchases of debt	(70		)	(123		)	—			—			(193		)
Other income	3,979			(603		)	13			(3,363		)	26
Equity in net earnings (losses) of subsidiary	(1,129		)	(383		)	—			1,512			—
Total Other Income (Expense)	1,859			(1,345		)	(73		)	(1,068		)	(627		)
INCOME (LOSS) BEFORE INCOME TAXES	1,859			585			(228		)	(774		)	1,442
INCOME TAX EXPENSE (BENEFIT)	1,135			370			(87		)	(870		)	548
NET INCOME (LOSS)	724			215			(141		)	96			894
Net income attributable to noncontrolling interests	—			—			—			(170		)	(170		)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	724			215			(141		)	(74		)	724
Other comprehensive income (loss)	3			19			(2		)	—			20
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	727		$	234		$	(143	)	$	(74	)	$	744

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2012

($ in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	5,920		$	351		$	7		$	6,278
Marketing, gathering and compression	—			5,218			212			1			5,431
Oilfield services	—			154			1,553			(1,100		)	607
Total Revenues	—			11,292			2,116			(1,092		)	12,316
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			1,278			26			—			1,304
Production taxes	—			182			6			—			188
Marketing, gathering and compression	—			5,197			115			—			5,312
Oilfield services	—			301			1,096			(932		)	465
General and administrative	—			431			105			(1		)	535
Restructuring and other termination costs	—			5			2			—			7
Oil, natural gas and NGL depreciation, depletion and amortization	—			2,353			154			—			2,507
Depreciation and amortization of other assets	—			187			266			(149		)	304
Impairment of oil and natural gas properties	—			3,192			123			—			3,315
Impairments of fixed assets and other	—			275			65			—			340
Net gains (losses) on sales of fixed assets	—			(269		)	2			—			(267		)
Total Operating Expenses	—			13,132			1,960			(1,082		)	14,010
INCOME (LOSS) FROM OPERATIONS	—			(1,840		)	156			(10		)	(1,694		)
OTHER INCOME (EXPENSE):
Interest expense	(879		)	45			(84		)	841			(77		)
Losses on investments	—			(167		)	55			9			(103		)
Net gain on sales of investments	—			29			1,063			—			1,092
Losses on purchases of debt	(200		)	—			—			—			(200		)
Other income (loss)	819			203			14			(1,028		)	8
Equity in net earnings (losses) of subsidiary	(610		)	436			—			174			—
Total Other Income (Expense)	(870		)	546			1,048			(4		)	720
INCOME (LOSS) BEFORE INCOME TAXES	(870		)	(1,294		)	1,204			(14		)	(974		)
INCOME TAX EXPENSE (BENEFIT)	(101		)	(675		)	470			(74		)	(380		)
NET INCOME (LOSS)	(769		)	(619		)	734			60			(594		)
Net income attributable to noncontrolling interests	—			—			—			(175		)	(175		)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(769		)	(619		)	734			(115		)	(769		)
Other comprehensive income (loss)	6			(22		)	—			—			(16		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	(763	)	$	(641	)	$	734		$	(115	)	$	(785	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2014

($ in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	4,201		$	462		$	(29	)	$	4,634
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(4,445		)	(136		)	—			(4,581		)
Acquisitions of proved and unproved properties	—			(1,306		)	(5		)	—			(1,311		)
Proceeds from divestitures of proved and unproved properties	—			5,812			1			—			5,813
Additions to other property and equipment	—			(480		)	(246		)	—			(726		)
Other investing activities	—			1,199			60			—			1,259
Net Cash Provided By (Used In) Investing Activities	—			780			(326		)	—			454
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	—			6,689			717			—			7,406
Payments on credit facilities borrowings	—			(6,689		)	(1,099		)	—			(7,788		)
Proceeds from issuance of senior notes, net of discount and offering costs	2,966			—			494			—			3,460
Proceeds from issuance of term loans, net of discount and offering costs	—			—			394			—			394
Cash paid to purchase debt	(3,362		)	—			—			—			(3,362		)
Other financing activities	(439		)	(1,278		)	(169		)	(41		)	(1,927		)
Intercompany advances, net	4,136			(3,709		)	(427		)	—			—
Net Cash Provided By (Used In) Financing Activities	3,301			(4,987		)	(90		)	(41		)	(1,817		)
Net increase (decrease) in cash and cash equivalents	3,301			(6		)	46			(70		)	3,271
Cash and cash equivalents, beginning of period	799			8			38			(8		)	837
Cash and cash equivalents, end of period	$	4,100		$	2		$	84		$	(78	)	$	4,108

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2013

($ in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	4,218		$	439		$	(43	)	$	4,614
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(4,838		)	(766		)	—			(5,604		)
Acquisitions of proved and unproved properties	—			(1,378		)	346			—			(1,032		)
Proceeds from divestitures of proved and unproved properties	—			3,466			1			—			3,467
Additions to other property and equipment	—			(271		)	(701		)	—			(972		)
Other investing activities	—			246			765			163			1,174
Net Cash Provided By (Used In) Investing Activities	—			(2,775		)	(355		)	163			(2,967		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	—			6,452			1,217			—			7,669
Payments on credit facilities borrowings	—			(6,452		)	(1,230		)	—			(7,682		)
Proceeds from issuance of senior notes, net of discount and offering costs	2,274			—			—			—			2,274
Cash paid to purchase debt	(2,141		)	—			—			—			(2,141		)
Proceeds from sales of noncontrolling interests	—			—			6			—			6
Other financing activities	1,819			(2,897		)	(17		)	(128		)	(1,223		)
Intercompany advances, net	(1,381		)	1,462			(81		)	—			—
Net Cash Provided By (Used In) Financing Activities	571			(1,435		)	(105		)	(128		)	(1,097		)
Net increase (decrease) in cash and cash equivalents	571			8			(21		)	(8		)	550
Cash and cash equivalents, beginning of period	228			—			59			—			287
Cash and cash equivalents, end of period	$	799		$	8		$	38		$	(8	)	$	837

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2012

($ in millions)

	Parent(a)			Guarantor Subsidiaries(a)			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	1,711		$	1,182		$	(56	)	$	2,837
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(8,605		)	(325		)	—			(8,930		)
Acquisitions of proved and unproved properties	—			(3,622		)	461			—			(3,161		)
Proceeds from divestitures of proved and unproved properties	—			5,884			—			—			5,884
Additions to other property and equipment	—			(1,736		)	(915		)	—			(2,651		)
Other investing activities	—			5,083			(316		)	(893		)	3,874
Net Cash Used In Investing Activities	—			(2,996		)	(1,095		)	(893		)	(4,984		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	—			18,930			1,388			—			20,318
Payments on credit facilities borrowings	—			(20,651		)	(999		)	—			(21,650		)
Proceeds from issuance of senior notes, net of discount and offering costs	1,263			—			—			—			1,263
Proceeds from issuance of term loans, net of discount and offering costs	5,722			—			—			—			5,722
Cash paid to purchase debt	(4,000		)	—			—			—			(4,000		)
Proceeds from sales of noncontrolling interests	—			63			1,014			—			1,077
Other financing activities	(477		)	(299		)	(820		)	949			(647		)
Intercompany advances, net	(2,282		)	3,242			(960		)	—			—
Net Cash Provided By (Used In) Financing Activities	226			1,285			(377		)	949			2,083
Net increase (decrease) in cash and cash equivalents	226			—			(290		)	—			(64		)
Cash and cash equivalents, beginning of period	2			—			349			—			351
Cash and cash equivalents, end of period	$	228		$	—		$	59		$	—		$	287

___________________________________________

(a) We have revised the amounts presented as cash and cash equivalents in the Guarantor Subsidiaries and Parent columns to properly reflect the cash of the Parent. As of December 31, 2012, $228 million was incorrectly presented in the Guarantor Subsidiaries column. The impact of this error was not material to any previously issued financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

23. Recently Issued Accounting Standards

In April 2014, the FASB issued an accounting standards update that raises the threshold for a disposal or classification as held for sale to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. This accounting standards update is effective for us beginning on January 1, 2015, and it is not expected to have a material impact on our consolidated financial statements.

In May 2014, the FASB issued updated revenue recognition guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and international financial reporting standards. The new standard requires the recognition of revenue to depict the transfer of promised goods to customers in an amount reflecting the consideration the company expects to receive in the exchange. The accounting standards update is effective for us beginning January 1, 2017, including retrospective application to comparative periods, and we are evaluating the impact on our consolidated financial statements.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

Quarterly Financial Data (unaudited)

Summarized unaudited quarterly financial data for 2014 and 2013 are as follows:

	Quarters Ended
	March 31, 2014		June 30, 2014		September 30, 2014		December 31, 2014
	($ in millions except per share data)
Total revenues	$	5,046	$	5,152	$	5,703	$	5,050
Gross profit(a)	$	733	$	610	$	1,174	$	960
Net income attributable to Chesapeake	$	425	$	191	$	662	$	639
Net income available to common stockholders	$	375	$	145	$	169	$	586
Net earnings per common share:
Basic	$	0.57	$	0.22	$	0.26	$	0.89
Diluted	$	0.54	$	0.22	$	0.26	$	0.81

	Quarters Ended
	March 31, 2013		June 30, 2013		September 30, 2013		December 31, 2013
	($ in millions except per share data)
Total revenues	$	3,424	$	4,675	$	4,867	$	4,541
Gross profit(a)	$	217	$	1,167	$	436	$	249
Net income (loss) attributable to Chesapeake(b)	$	58	$	580	$	202	$	(116	)
Net income (loss) available to common stockholders(b)	$	15	$	458	$	156	$	(159	)
Net earnings (loss) per common share:
Basic	$	0.02	$	0.70	$	0.24	$	(0.24	)
Diluted	$	0.02	$	0.66	$	0.24	$	(0.24	)

_________________________________________

(a) Total revenue less operating expenses.

(b) Includes $123 million of losses on the extinguishment of other financing and $203 million of impairments of fixed assets and other for the quarter ended December 31, 2013. See Note 5 and Note 17 for further discussion.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION – (Continued)

Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities (unaudited)

Net Capitalized Costs

Capitalized costs related to Chesapeake's oil, natural gas and NGL producing activities are summarized as follows:

	December 31,
	2014			2013
	($ in millions)
Oil and oil and natural gas properties:
Proved	$	58,594		$	56,157
Unproved	9,788			12,013
Total	68,382			68,170
Less accumulated depreciation, depletion and amortization	(38,238		)	(35,577		)
Net capitalized costs	$	30,144		$	32,593

Unproved properties not subject to amortization as of December 31, 2014, 2013 and 2012 consisted mainly of leasehold acquired through direct purchases of significant oil and natural gas property interests. We capitalized approximately $604 million, $815 million and $976 million of interest during 2014, 2013 and 2012, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full cost pool. We will continue to evaluate our unproved properties, and although the timing of the ultimate evaluation or disposition of the properties cannot be determined, we can expect the majority of our unproved properties not held by production to be transferred into the amortization base over the next five years.

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows:

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
Acquisition of Properties:
Proved properties	$	214	$	22	$	332
Unproved properties	1,224		997		2,981
Exploratory costs	421		699		2,353
Development costs	4,204		4,888		6,733
Costs incurred(a)(b)	$	6,063	$	6,606	$	12,399

___________________________________________

(a) Exploratory and development costs are net of $679 million, $884 million and $784 million in drilling and completion carries received from our joint venture partners during 2014, 2013 and 2012, respectively.

(b) Includes capitalized interest and asset retirement obligations as follows:

Capitalized interest	$	604	$	815	$	976
Asset retirement obligations	$	39	$	7	$	32

In 2014, we invested approximately $1.289 billion, net of drilling and completion cost carries of $73 million, to convert 225 mmboe of PUDs to proved developed reserves.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION – (Continued)

Results of Operations from Oil, Natural Gas and NGL Producing Activities

Chesapeake's results of operations from oil, natural gas and NGL producing activities are presented below for 2014, 2013 and 2012. The following table includes revenues and expenses associated directly with our oil, natural gas and NGL producing activities. It does not include any interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil, natural gas and NGL operations.

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Oil, natural gas and NGL sales	$	8,180		$	7,052		$	6,278
Oil, natural gas and NGL production expenses	(1,208		)	(1,159		)	(1,304		)
Production taxes	(232		)	(229		)	(188		)
Impairment of oil and natural gas properties	—			—			(3,315		)
Depletion and depreciation	(2,683		)	(2,589		)	(2,507		)
Imputed income tax provision(a)	(1,485		)	(1,169		)	404
Results of operations from oil, natural gas and NGL producing activities	$	2,572		$	1,906		$	(632	)

___________________________________________

(a) The imputed income tax provision is hypothetical (at the effective income tax rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision (benefit) will be payable (receivable).

Oil, Natural Gas and NGL Reserve Quantities

Chesapeake's petroleum engineers and independent petroleum engineering firms estimated all of our proved reserves as of December 31, 2014, 2013 and 2012. Independent petroleum engineering firms estimated an aggregate of 79%, 81% and 89% of our estimated proved reserves (by volume) as of December 31, 2014, 2013 and 2012, respectively, as set forth below.

	December 31,
	2014		2013		2012
Ryder Scott Company, L.P.	54	%	51	%	44	%
PetroTechnical Services, Division of Schlumberger Technology Corporation	25	%	30	%	24	%
Netherland, Sewell & Associates, Inc.	—	%	—	%	21	%

Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGL which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be

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SUPPLEMENTARY INFORMATION – (Continued)

assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Developed oil, natural gas and NGL reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

The information below on our oil, natural gas and NGL reserves is presented in accordance with regulations prescribed by the SEC. Our reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates will change as future information becomes available and as commodity prices change. These changes could be material and could occur in the near term.

Presented below is a summary of changes in estimated reserves for 2014, 2013 and 2012.

	Oil		Gas		NGL		Total
	(mmbbl)		(bcf)		(mmbbl)		(mmboe)
December 31, 2014
Proved reserves, beginning of period	423.8		11,734		299.0		2,678
Extensions, discoveries and other additions	108.6		1,567		78.2		448
Revisions of previous estimates	(51.1	)	(129	)	21.3		(51	)
Production	(42.3	)	(1,095	)	(33.1	)	(258	)
Sale of reserves-in-place	(23.3	)	(1,421	)	(101.7	)	(362	)
Purchase of reserves-in-place	5.1		36		2.6		14
Proved reserves, end of period(a)	420.8		10,692		266.3		2,469
Proved developed reserves:
Beginning of period	201.3		8,584		177.1		1,809
End of period	229.3		8,615		198.5		1,864
Proved undeveloped reserves:
Beginning of period	222.5		3,150		121.9		869
End of period(b)	191.5		2,077		67.8		605

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SUPPLEMENTARY INFORMATION – (Continued)

	Oil		Gas		NGL		Total
	(mmbbl)		(bcf)		(mmbbl)		(mmboe)
December 31, 2013
Proved reserves, beginning of period	495.5		10,933		297.3		2,615
Extensions, discoveries and other additions	96.3		2,160		68.0		524
Revisions of previous estimates	(61.1	)	388		(32.9	)	(30	)
Production	(41.1	)	(1,095	)	(20.9	)	(244	)
Sale of reserves-in-place	(66.4	)	(657	)	(13.1	)	(189	)
Purchase of reserves-in-place	0.6		5		0.6		2
Proved reserves, end of period(c)	423.8		11,734		299.0		2,678
Proved developed reserves:
Beginning of period	162.9		7,174		132.1		1,491
End of period	201.3		8,584		177.1		1,809
Proved undeveloped reserves:
Beginning of period	332.6		3,759		165.2		1,124
End of period(b)	222.5		3,150		121.9		869
December 31, 2012
Proved reserves, beginning of period	291.6		15,515		253.9		3,132
Extensions, discoveries and other additions	374.0		3,317		139.4		1,065
Revisions of previous estimates	(67.5	)	(6,080	)	(47.3	)	(1,127	)
Production	(31.3	)	(1,129	)	(17.6	)	(237	)
Sale of reserves-in-place	(75.5	)	(704	)	(31.7	)	(225	)
Purchase of reserves-in-place	4.2		14		0.6		7
Proved reserves, end of period(d)	495.5		10,933		297.3		2,615
Proved developed reserves:
Beginning of period	124.0		8,578		130.6		1,684
End of period	162.9		7,174		132.1		1,491
Proved undeveloped reserves:
Beginning of period	167.6		6,937		123.3		1,447
End of period(b)	332.6		3,759		165.2		1,124

___________________________________________

(a) Includes 2 mmbbls of oil, 46 bcf of natural gas and 5 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbls of oil, 22 bcf of natural gas and 2 mmbbls of NGL of which are attributable to the noncontrolling interest holders.

(b) As of December 31, 2014, 2013 and 2012, there were no PUDs that had remained undeveloped for five years or more.

(c) Includes 2 mmbbls of oil, 61 bcf of natural gas and 6 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbls of oil, 30 bcf of natural gas and 3 mmbbls of NGL of which are attributable to the noncontrolling interest holders.

(d) Includes 4 mmbbls of oil, 91 bcf of natural gas and 9 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 2 mmbbls of oil, 45 bcf of natural gas and 4 mmbbls of NGL of which are attributable to the noncontrolling interest holders.

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SUPPLEMENTARY INFORMATION – (Continued)

During 2014, we acquired approximately 14 mmboe of proved reserves through purchases of oil and natural gas properties for consideration of $168 million, and we sold 362 mmboe of proved reserves for approximately $4.7 billion. We recorded downward revisions of 51 mmboe, which was comprised of a 78 mmboe reduction of previous estimates partially offset by a 27 mmboe increase resulting primarily from higher natural gas prices in 2014. The oil and natural gas prices used in computing our reserves as of December 31, 2014 were $94.98 per bbl and $4.35 per mcf, respectively, before price differentials. Including the effect of price differential adjustments, the prices used in computing our reserves as of December 31, 2014 were $89.09 per barrel of oil, $2.68 per mcf of natural gas and $24.10 per barrel of NGL.

During 2013, we acquired approximately 2 mmboe of proved reserves through purchases of oil and natural gas properties for consideration of $22 million, and we sold 189 mmboe of proved reserves for approximately $1.621 billion. During 2013, we recorded downward revisions of 30 mmboe to the December 31, 2012 estimates of our reserves. Included in the revisions were 162 mmboe of upward revisions resulting from higher oil, natural gas and NGL prices in 2013 and 192 mmboe of downward revisions resulting from changes to previous estimates. Higher prices increase the economic lives of the underlying oil and natural gas properties and thereby increase the estimated future reserves. The oil and natural gas prices used in computing our reserves as of December 31, 2013 were $96.82 per bbl and $3.67 per mcf, respectively, before price differentials. Including the effect of price differential adjustments, the prices used in computing our reserves as of December 31, 2013 were $95.89 per barrel of oil, $2.37 per mcf of natural gas and $25.78 per barrel of NGL. Included in the non-price revisions were 355 mmboe of downward revisions to our estimated PUD reserves, offset by 163 mmboe of upward revisions for performance.

During 2012, we acquired approximately 7 mmboe of proved reserves through purchases of oil and natural gas properties for consideration of $332 million, and we sold 225 mmboe of our proved reserves for approximately $2.381 billion. During 2012, we recorded downward revisions of 1.127 bboe to the December 31, 2011 estimates of our reserves. Included in the revisions were 902 mmboe of downward revisions resulting from lower natural gas prices in 2012 and 225 mmboe of downward revisions resulting from changes to previous estimates. Lower prices decrease the economic lives of the underlying oil and natural gas properties and thereby decrease the estimated future reserves. The oil and natural gas prices used in computing our reserves as of December 31, 2012 were $94.84 per bbl and $2.76 per mcf, respectively, before price differentials. Including the effect of price differential adjustments, the prices used in computing our reserves as of December 31, 2012 were $91.78 per barrel of oil, $1.75 per mcf of natural gas and $30.81 per barrel of NGL. The non price-related revisions were primarily the result of our continued execution of our strategy to shift the Company’s drilling focus from natural gas to liquids-rich areas and to drill in the "core of the core" of our acreage positions. As rigs were reallocated, PUDs were removed from various noncore areas resulting in downward revisions.

Standardized Measure of Discounted Future Net Cash Flows

Accounting Standards Codification Topic 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Chesapeake has followed these guidelines which are briefly discussed below.

Future cash inflows and future production and development costs as of December 31, 2014, 2013 and 2012 were determined by applying the average of the first-day-of-the-month prices for the 12 months of the year and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the prices and costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for that year. Estimated future income taxes are computed using current statutory income tax rates including consideration of the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

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SUPPLEMENTARY INFORMATION – (Continued)

The following summary sets forth our future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure:

	Years Ended December 31,
	2014				2013				2012
	($ in millions)
Future cash inflows	$	72,557		(a)	$	76,094		(b)	$	73,754		(c)
Future production costs	(17,036		)		(18,196		)		(18,809		)
Future development costs	(7,556		)		(9,563		)		(12,656		)
Future income tax provisions	(12,494		)		(12,196		)		(9,824		)
Future net cash flows	35,471				36,139				32,465
Less effect of a 10% discount factor	(18,338		)		(18,749		)		(17,799		)
Standardized measure of discounted future net cash flows(d)	$	17,133			$	17,390			$	14,666

___________________________________________

(a) Calculated using prices of $94.98 per bbl of oil and $4.35 per mcf of natural gas, before field differentials.

(b) Calculated using prices of $96.82 per bbl of oil and $3.67 per mcf of natural gas, before field differentials.

(c) Calculated using prices of $94.84 per bbl of oil and $2.76 per mcf of natural gas, before field differentials.

(d) Excludes future cash inflows attributable to production volumes sold to VPP buyers and includes future cash outflows attributable to the costs of production. See Note 12.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Standardized measure, beginning of period(a)	$	17,390		$	14,666		$	15,630
Sales of oil and natural gas produced, net of production costs(b)	(5,722		)	(5,535		)	(3,867		)
Net changes in prices and production costs	(634		)	2,021			(2,720		)
Extensions and discoveries, net of production and development costs	5,156			6,008			11,115
Changes in future development costs	1,946			1,287			3,687
Development costs incurred during the period that reduced future development costs	1,178			1,582			1,046
Revisions of previous quantity estimates	(715		)	(805		)	(8,699		)
Purchase of reserves-in-place	215			26			285
Sales of reserves-in-place	(1,788		)	(1,976		)	(3,246		)
Accretion of discount	2,168			1,777			1,988
Net change in income taxes	(593		)	(1,180		)	1,142
Changes in production rates and other	(1,468		)	(481		)	(1,695		)
Standardized measure, end of period(a)(c)(d)	$	17,133		$	17,390		$	14,666

___________________________________________

(a) The impact of cash flow hedges has not been included in any of the periods presented.

(b) Excluding gains (losses) on derivatives.

(c) Effect of noncontrolling interest of the Chesapeake Granite Wash Trust is immaterial.

(d) The standardized measure of discounted future net cash flows does not include estimated future cash inflows attributable to future production of VPP volumes sold and does include estimated future cash outflows attributable to the costs of future production of VPP volumes sold.

153

ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

ITEM 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of Chesapeake’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2014.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the period ended December 31, 2014, which materially affected, or was reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. Other Information

Not applicable.

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance

The names of executive officers and certain other senior officers of the Company and their ages, titles and biographies as of the date hereof are incorporated by reference from Item 1 of Part I of this report. The other information called for by this Item 10 is incorporated herein by reference to the definitive proxy statement to be filed by Chesapeake pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2015 (the “2015 Proxy Statement”).

ITEM 11. Executive Compensation

The information called for by this Item 11 is incorporated herein by reference to the 2015 Proxy Statement.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information called for by this Item 12 is incorporated herein by reference to the 2015 Proxy Statement.

ITEM 13. Certain Relationships and Related Transactions and Director Independence

The information called for by this Item 13 is incorporated herein by reference to the 2015 Proxy Statement.

ITEM 14. Principal Accountant Fees and Services

The information called for by this Item 14 is incorporated herein by reference to the 2015 Proxy Statement.

154

PART IV

ITEM 15. Exhibits and Financial Statement Schedules

____________________________________________

(a) The following financial statements, financial statement schedules and exhibits are filed as a part of this report:

1. Financial Statements. Chesapeake's consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements.

2. Financial Statement Schedules. Schedule II is included in Item 8 of Part II of this report with our consolidated financial statements. No other financial statement schedules are applicable or required.

3. Exhibits. The exhibits listed below in the Index of Exhibits (following the signatures page) are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.

155

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	CHESAPEAKE ENERGY CORPORATION
Date: February 27, 2015	By:	/s/ ROBERT D. LAWLER
		Robert D. Lawler
		President and Chief Executive Officer

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints Robert D. Lawler and Domenic J. Dell'Osso, Jr., and each of them, either one of whom may act without joinder of the other, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all amendments to this Annual Report on Form 10-K, and to file the same, with all, exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each, and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, and each of them, or the substitute or substitutes of any or all of them, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Capacity	Date
/s/ ROBERT D. LAWLER	President and Chief Executive Officer (Principal Executive Officer)	February 27, 2015
Robert D. Lawler
/s/ DOMENIC J. DELL'OSSO, JR.	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 27, 2015
Domenic J. Dell'Osso, Jr.
/s/ MICHAEL A. JOHNSON	Senior Vice President - Accounting, Controller and Chief Accounting Officer (Principal Accounting Officer)	February 27, 2015
Michael A. Johnson
/s/ ARCHIE W. DUNHAM	Chairman of the Board	February 27, 2015
Archie W. Dunham
/s/ VINCENT J. INTRIERI	Director	February 27, 2015
Vincent J. Intrieri
/s/ JOHN J. LIPINSKI	Director	February 27, 2015
John J. Lipinski
/s/ R. BRAD MARTIN	Director	February 27, 2015
R. Brad Martin
/s/ MERRILL A. MILLER, JR.	Director	February 27, 2015
Merrill A. Miller, Jr.
/s/ FREDRIC M. POSES	Director	February 27, 2015
Frederic M. Poses
/s/ LOUIS A. RASPINO	Director	February 27, 2015
Louis A. Raspino
/s/ THOMAS L. RYAN	Director	February 27, 2015
Thomas L. Ryan

INDEX TO EXHIBITS

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed or Furnished Herewith
2.1.1*	Purchase and Sale Agreement by and between Chesapeake Appalachia, L.L.C. and Southwestern Energy Production Company dated October 14, 2014.					X
2.1.2*	Amendment to Purchase and Sale Agreement by and between Chesapeake Appalachia, L.L.C. and SWN Production Company, LLC (formerly Southwestern Energy Production Company) dated December 22, 2014.					X
2.1.3	Settlement Agreement by and between Chesapeake Appalachia, L.L.C. and SWN Production Company, LLC (formerly Southwestern Energy Production Company) dated December 22, 2014.					X
3.1.1	Chesapeake’s Restated Certificate of Incorporation.	10-Q	001-13726	3.1.1	8/6/2014
3.1.2	Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2005B), as amended.	10-Q	001-13726	3.1.4	11/10/2008
3.1.3	Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock, as amended.	10-Q	001-13726	3.1. 6	8/11/2008
3.1.4	Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock (Series A).	8-K	001-13726	3.2	5/20/2010
3.1.5	Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock, as amended.	10-Q	001-13726	3.1.5	8/9/2010
3.2	Chesapeake’s Amended and Restated Bylaws.	8-K	001-13726	3.2	6/9/2014
4.1**	Indenture dated as of August 16, 2005 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 6.5% Senior Notes due 2017.	8-K	001-13726	4.1	8/16/2005
4.2**	Indenture dated as of November 8, 2005 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 6.875% Senior Notes due 2020.	8-K	001-13726	4.12.1	11/15/2005
4.3**	Indenture dated as of November 8, 2005 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 2.75% Contingent Convertible Senior Notes due 2035.	8-K	001-13726	4.12.2	11/15/2005

4.4**	Indenture dated as of December 6, 2006 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, The Bank of New York Mellon Trust Company, N.A., as Trustee, AIB/BNY Fund Management (Ireland) Limited, as Irish Paying Agent and Transfer Agent, and The Bank of New York, London Branch, as Registrar, Transfer Agent and Paying Agent, with respect to 6.25% Senior Notes due 2017.	8-K	001-13726	4.1	12/6/2006
4.5**	Indenture dated as of May 15, 2007 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 2.5% Contingent Convertible Senior Notes due 2037.	8-K	001-13726	4.1	5/15/2007
4.6**	Indenture dated as of May 27, 2008 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 7.25% Senior Notes due 2018.	8-K	001-13726	4.1	5/29/2008
4.7**	Indenture dated as of May 27, 2008 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 2.25% Contingent Convertible Senior Notes due 2038.	8-K	001-13726	4.2	5/29/2008
4.8.1**	Indenture dated as of August 2, 2010 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and the Bank of New York Mellon Trust Company, N.A., as Trustee.	S-3	333-168509	4.1	8/3/2010
4.8.2	First Supplemental Indenture dated as of August 17, 2010 to Indenture dated as of August 2, 2010 with respect to 6.875% Senior Notes due 2018.	8-A	001-13726	4.2	9/24/2010
4.8.3	Second Supplemental Indenture, dated as of August 17, 2010 to Indenture dated as of August 2, 2010 with respect to 6.625% Senior Notes due 2020.	8-A	001-13726	4.3	9/24/2010
4.8.4	Fifth Supplemental Indenture dated February 11, 2011 to Indenture dated as of August 2, 2010 with respect to 6.125% Senior Notes due 2021.	8-A	001-13726	4.2	2/22/2011
4.8.5	Fourteenth Supplemental Indenture dated March 18, 2013 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and Deutsche Bank Trust Company Americas, as Trustee, to Indenture dated as of August 2, 2010.	S-3	333-168509	4.17	3/18/2013
4.8.6	Fifteenth Supplemental Indenture dated April 1, 2013 to Indenture dated as of August 2, 2010 with respect to 3.25% Senior Notes due 2016.	8-A	001-13726	4.2	4/8/2013
4.8.7	Sixteenth Supplemental Indenture dated April 1, 2013 to Indenture dated as of August 2, 2010 with respect to 5.375% Senior Notes due 2021.	8-A	001-13726	4.3	4/8/2013

4.8.8	Seventeenth Supplemental Indenture dated April 1, 2013 to Indenture dated as of August 2, 2010 with respect to 5.75% Senior Notes due 2023.	8-A	001-13726	4.4	4/8/2013
4.9.1**	Indenture dated as of April 24, 2014 by and among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and Deutsche Bank Trust Company Americas, as Trustee.	8-K	001-13726	4.1	4/29/2014
4.9.2	First Supplemental Indenture dated as of April 24, 2014 to Indenture dated as of April 24, 2014 with respect to Floating Rate Senior Notes due 2019.	8-K	001-13726	4.2	4/29/2014
4.9.3	Second Supplemental Indenture dated as of April 24, 2014 to Indenture dated as of April 24 2014 with respect to 4.875% Senior Notes due 2022.	8-K	001-13726	4.3	4/29/2014
4.10**	Credit Agreement dated December 15, 2014 by and among: Chesapeake Energy Corporation, as borrower; MUFG Union Bank N.A., as administrative agent, co-syndication agent, a swingline lender and a letter of credit issuer; Wells Fargo Bank and National Association, as co-syndication agent, a swingline lender and a letter of credit issuer; Bank of America, N.A., Crédit Agricole Corporate and Investment Bank and JPMorgan Chase Bank, N.A., as co-documentation agents and letter of credit issuers; and certain other lenders named therein.	8-K	001-13726	10.1	12/16/2014
10.1.1†	Chesapeake's 2003 Stock Incentive Plan, as amended.	10-Q	001-13726	10.1.1	11/9/2009
10.1.2†	Form of 2013 Restricted Stock Award Agreement for Chesapeake's 2003 Stock Incentive Plan.	10-K	001-13726	10.1.3	3/1/2013
10.2†	Chesapeake's 2003 Stock Award Plan for Non-Employee Directors, as amended.	10-Q	001-13726	10.7	8/6/2013
10.3.1†	Chesapeake's 2005 Amended and Restated Long Term Incentive Plan.	8-K	001-13726	10.1	6/20/2013
10.3.2†	Form of 2013 Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.	8-K	001-13726	10.3	2/4/2013
10.3.3†	Form of Nonqualified Stock Option Agreement for 2005 Amended and Restated Long Term Incentive Plan.	8-K	001-13726	10.1	2/4/2013
10.3.4†	Form of Retention Nonqualified Stock Option Agreement for 2005 Amended and Restated Long Term Incentive Plan.	8-K	001-13726	10.2	2/4/2013
10.3.5†	Form of 2013 Non-Employee Director Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.	10-K	001-13726	10.13.7	3/1/2013
10.3.6†	Form of 2013 Performance Share Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.	10-K	001-13726	10.13.9	3/1/2013
10.3.7†	Form of 2014 Performance Share Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.	10-K	001-13726	10.4.7	2/26/2014

10.3.8†	Form of Restricted Stock Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.	10-Q	001-13726	10.8	8/6/2013
10.3.9†	Form of Non-Employee Director Restricted Stock Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan.	10-Q	001-13726	10.9	8/6/2013
10.3.10†	Form of Pension and Equity Makeup Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan for Robert D. Lawler.	10-Q	001-13726	10.10	8/6/2013
10.4†	Chesapeake Energy Corporation Amended and Restated Deferred Compensation Plan, as amended.					X
10.5†	Chesapeake Energy Corporation Deferred Compensation Plan for Non-Employee Directors.	10-K	001-13726	10.16	3/13/2013
10.6†	Employment Agreement dated as of May 20, 2013 between Robert D. Lawler and Chesapeake Energy Corporation.	8-K	001-13726	10.1	5/23/2013
10.7†	Employment Agreement dated as of January 1, 2013 between Domenic J. Dell'Osso, Jr. and Chesapeake Energy Corporation.	10-K	001-13726	10.19	3/1/2013
10.8†	Employment Agreement dated as of January 1, 2013 between James R. Webb and Chesapeake Energy Corporation.					X
10.9†	Employment Agreement dated as of August 14, 2013 between M. Christopher Doyle and Chesapeake Energy Corporation.	10-Q/A	001-13726	10.1	11/7/2013
10.10†	Employment Agreement dated as of August 4, 2013 between Mikell Jason Pigott and Chesapeake Energy Corporation.	10-Q/A	001-13726	10.2	11/7/2013
10.11†	Form of Employment Agreement dated as of January 1, 2013 between Executive Vice President/Senior Vice President and Chesapeake Energy Corporation.	8-K	001-13726	10.1	1/7/2013
10.12†	Form of Indemnity Agreement for officers and directors of Chesapeake Energy Corporation and its subsidiaries.	8-K	001-13726	10.3	6/27/2012
10.13†	Chesapeake Energy Corporation 2013 Annual Incentive Plan.	DEF 14A	001-13726	Exhibit G	5/3/2013
10.14.1†	Chesapeake Energy Corporation 2014 Long Term Incentive Plan.	DEF 14A	001-13726	Exhibit F	4/30/2014
10.14.2†	Form of Restricted Stock Unit Award Agreement for 2014 Long Term Incentive Plan.	10-Q	001-13726	10.2	8/6/2014
10.14.3†	Form of Restricted Stock Award Agreement for 2014 Long Term Incentive Plan.	10-Q	001-13726	10.3	8/6/2014
10.14.4†	Form of Nonqualified Stock Option Agreement for 2014 Long Term Incentive Plan.	10-Q	001-13726	10.4	8/6/2014

10.14.5†	Form of Performance Share Unit Award Agreement for 2014 Long Term Incentive Plan.	10-Q	001-13726	10.5	8/6/2014
10.14.6†	Form of Director Restricted Stock Unit Award Agreement for 2014 Long Term Incentive Plan.	10-Q	001-13726	10.6	8/6/2014
12	Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends.					X
21	Subsidiaries of Chesapeake Energy Corporation.					X
23.1	Consent of PricewaterhouseCoopers LLP.					X
23.2	Consent of PetroTechnical Services, Division of Schlumberger Technology Corporation.					X
23.3	Consent of Ryder Scott Company, L.P.					X
31.1	Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X
31.2	Domenic J. Dell'Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X
32.1	Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.					X
32.2	Domenic J. Dell'Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.					X
99.1	Report of PetroTechnical Services, Division of Schlumberger Technology Corporation.					X
99.2	Report of Ryder Scott Company, L.P.					X
101 INS	XBRL Instance Document.					X
101 SCH	XBRL Taxonomy Extension Schema Document.					X
101 CAL	XBRL Taxonomy Extension Calculation Linkbase Document.					X
101 DEF	XBRL Taxonomy Extension Definition Linkbase Document.					X
101 LAB	XBRL Taxonomy Extension Labels Linkbase Document.					X
101 PRE	XBRL Taxonomy Extension Presentation Linkbase Document.					X
*	The Company agrees to furnish supplementally a copy of omitted exhibits and schedules to the Securities and Exchange Commission upon request.
**	The Company agrees to furnish a copy of any of its unfiled long-term debt instruments to the Securities and Exchange Commission upon request.
†	Management contract or compensatory plan or arrangement.

EX-2.1.1

Exhibit 2.1.1

PURCHASE AND SALE AGREEMENT

by and between

CHESAPEAKE APPALACHIA, L.L.C.

(the “Seller”)

and

SOUTHWESTERN ENERGY PRODUCTION COMPANY

(the “Buyer”)

October 14, 2014

4373280v1

TABLE OF CONTENTS

1.		Definitions and References	1
	1.1.	Definitions	1
	1.2.	References; Construction	18
2.		Purchase and Sale; Purchase Price	19
	2.1.	Title and Environmental Defects	19
	2.2.	Preferential Purchase Rights; Required Consents	24
	2.3.	Gas Imbalances	26
	2.4.	Casualty Loss	26
	2.5.	Certain Upward Adjustments	26
	2.6.	Certain Downward Adjustments	27
	2.7.	Closing Date Estimates	27
	2.8.	Final Accounting	28
	2.9.	Payments	29
	2.10.	Administration of Unleased Accounts	29
	2.11.	Tax Allocation	30
3.		Seller’s Representations and Warranties	30
	3.1.	Organization and Good Standing.	30
	3.2.	Legal Requirements	30
	3.3.	No Breach	30
	3.4.	Litigation	31
	3.5.	Taxes	31
	3.6.	Permits	31
	3.7.	Compliance with Laws	31
	3.8.	Contracts	32
	3.9.	Environmental and Safety Matters	33
	3.10.	Authority	33
	3.11.	Broker’s or Finder’s Fees	34
	3.12.	Bankruptcy	34
	3.13.	Preferential Purchase Rights and Required Consents	34
	3.14.	Gas Balancing	34
	3.15.	Payment of Royalties and Expenses	34

	3.16.	Current Commitments	34
	3.17.	Advance Payments	34
	3.18.	Condemnation	35
	3.19.	Payout Balances	35
	3.20.	Compliance with Anti-Bribery Laws	35
4.		Buyer’s Representations and Warranties	35
	4.1.	Organization and Good Standing.	35
	4.2.	Powers	35
	4.3.	No Restriction	35
	4.4.	Authorization	35
	4.5.	No Breach	36
	4.6.	Governmental Consent	36
	4.7.	Litigation	36
	4.8.	Broker’s or Finder’s Fees	36
	4.9.	Qualifications	36
	4.10.	Bankruptcy	36
	4.11.	Funding; Investment	36
	4.12.	Compliance with Anti-Bribery Laws	37
5.		Covenants	37
	5.1.	Access to Properties and Information	37
	5.2.	Conduct of Business	38
	5.3.	Revenues Held For Benefit of the Other Party	40
	5.4.	Revenues and Expenses	41
	5.5.	Suspended Funds	41
	5.6.	HSR Act	41
	5.7.	Governmental Bonds	42
	5.8.	Gathering Agreements	42
	5.9.	Limitations on Representations and Warranties	45
	5.10.	Operatorship	47
	5.11.	FERC Matters	47
	5.12.	Satisfaction of Conditions	48
	5.13.	Confidentiality	48
	5.14.	Development Agreement	48

	5.15.	Selling Affiliates	49
6.		Buyer’s Conditions Precedent	49
7.		Seller’s Conditions Precedent	50
8.		The Closing	51
	8.1.	Buyer’s Deliveries	52
	8.2.	Seller’s Deliveries	52
	8.3.	Post-Closing Adjustments	54
	8.4.	Post-Closing Deliveries	54
	8.5.	Costs	54
	8.6.	Risk of Loss	54
9.		Press Releases	54
10.		Indemnification	54
	10.1.	Assumed Obligations	54
	10.2.	Seller’s Indemnification	54
	10.3.	Buyer’s Indemnification	55
	10.4.	EXTENT OF INDEMNIFICATION	55
	10.5.	Indemnification Procedure	56
	10.6.	Defense	56
	10.7.	Certain Limitations on Indemnity Obligations	57
11.		Termination	58
	11.1.	Right to Terminate	58
	11.2.	Effect of Termination	59
12.		Default	59
13.		Arbitration	59
	13.1.	Consolidation	60
	13.2.	Initiation; Selection of Arbitrators	60
	13.3.	Expenses	60
	13.4.	Procedure	60
	13.5.	Enforcement; Remedies	61
	13.6.	Award of Fees	61
14.		Miscellaneous	61
	14.1.	Time	61
	14.2.	Notices	61

14.3.	Survival	62
14.4.	Cooperation	63
14.5.	No Third Party Beneficiaries	63
14.6.	Cumulative Remedies	63
14.7.	Choice of Law	63
14.8.	Entire Agreement	63
14.9.	Assignment	64
14.10.	Amendment	64
14.11.	Severability	64
14.12.	Attorney Fees	64
14.13.	Waiver	64
14.14.	Counterparts; Facsimiles; Electronic Transmission	64
14.15.	JOINT ACKNOWLEDGMENT	64
14.16.	WAIVER OF JURY TRIAL, SPECIAL DAMAGES, ETC	65
14.17.	Mutuality	65
14.18.	Schedules	65
14.19.	1031 Like-Kind Exchange	65
14.20.	Sharing of Certain Financial Information Subsequent to the Execution Date	66
14.21.	No Recourse to Financing Sources	67

EXHIBITS AND SCHEDULES

EXHIBITS
Exhibit A	Real Property Interests, Wells and Allocated Values
Exhibit A-1	Other Assets
Exhibit A-2	Transferred Gathering Systems
Exhibit B-1	Form of Assignment, Bill of Sale and Conveyance for certain Properties
Exhibit B-2	Forms of Assignment for Other Assets and Transferred Gathering Assets
Exhibit C	Contracts
Exhibit D	Consent Decree Agreement
Exhibit E	Form of Fee Minerals Lease
Exhibit F	Form of Non-Foreign Status Certificate
Exhibit G	Form of Consent Letter

SCHEDULES
Schedule 1.1	Knowledge Persons
Schedule 1.2	Map of Contract Area and Utica Area
Schedule 3.2	Governmental Consents
Schedule 3.3	No Breaches
Schedule 3.4	Litigation
Schedule 3.5	Taxes
Schedule 3.8	Contracts
Schedule 3.9	Environmental and Safety Matters
Schedule 3.13	Preferential Purchase Rights and Required Consents
Schedule 3.14	Gas Balancing
Schedule 3.16	Current Commitments
Schedule 3.17	Advance Payments
Schedule 3.19	Payout Balances
Schedule 5.8.1	Buyer ATEX Volume
Schedule 5.8.2	Midstream Consent Contracts
Schedule 5.11	FERC Jurisdictional Contracts

PURCHASE AND SALE AGREEMENT

This PURCHASE AND SALE AGREEMENT (this “Agreement”) is entered into this 14^th day of October, 2014 (“Execution Date”), between CHESAPEAKE APPALACHIA, L.L.C., an Oklahoma limited liability company (the “Seller”), and SOUTHWESTERN ENERGY PRODUCTION COMPANY, a Texas corporation (the “Buyer”). The Buyer and the Seller are referred to herein, individually, as a “Party” and, collectively, as the “Parties”.

RECITALS

WHEREAS, the Seller desires to sell and the Buyer desires to purchase all of the Seller’s right, title and interest in and to the Properties (as hereinafter defined); and

WHEREAS, the purchase and sale of the Properties will be consummated on the terms and conditions set forth in this Agreement;

NOW, THEREFORE, for and in consideration of the mutual covenants herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

1.Definitions and References. Capitalized terms used throughout this Agreement including the Recitals above and not defined in Section 1.1 below shall have the meaning ascribed to them elsewhere in this Agreement.

1.1. Definitions. The following terms have the meanings given in this Section 1.1 or in the Section referred to below:

“AAA” means the American Arbitration Association.

“Accounting Referee” means BDO USA, LLP, or such other nationally recognized accounting firm mutually agreed upon by the Parties; provided, however, that if BDO USA, LLP will not serve as the Accounting Referee and the Parties have not mutually agreed on another Accounting Referee within thirty (30) days after the date on which a candidate for a replacement Accounting Referee is first proposed in writing by either Party, then the Accounting Referee shall be selected by the AAA from firms that shall not have performed any work for either of the Parties or any of their respective Affiliates during the five (5) year period preceding such selection.

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly (through one or more intermediaries or otherwise) Controls, is Controlled by, or is under common Control with the first Person.

“Aggregate Defect Threshold” has the meaning specified in Section 2.1.2.

“Allocated Value” means, with respect to a Property, the portion of the Purchase Price allocated to such Property as shown on Exhibit A, provided however that

PURCHASE AND SALE AGREEMENT 1

such Allocated Value is only attributable to the portion of such Property as to which the term Defensible Title applies.

“Arbitrable Dispute” means (except for: (i) disputes involving Title Defects or Environmental Defects or any cure relating thereto, or involving Title Benefits, each of which will be resolved as provided in Section 2.1.11, or (ii) any matters to be resolved by the Accounting Referee as provided in Section 2.8) any and all disputes, claims, counterclaims, demands, causes of action, controversies and other matters in question arising out of or relating to this Agreement or the alleged breach hereof, or in any way relating to matters that are the subject of this Agreement or the transactions contemplated hereby or the relationship between the Parties created by this Agreement, regardless of whether (a) allegedly extra-contractual in nature, (b) sounding in contract, tort or otherwise, (c) provided for by Law or otherwise, or (d) seeking damages or any other relief, whether at Law, in equity or otherwise.

“Assignment” means (a) the Assignment, Bill of Sale and Conveyance in substantially the same form attached hereto as Exhibit B-1 with respect to the Properties other than the Other Assets and the Transferred Gathering Systems; and (b) the Assignments in substantially the same forms attached hereto as Exhibit B-2 with respect to the Other Assets and the Transferred Gathering Assets.

“Assumed Obligations” means: (a) all claims, demands, violations, actions, assessments, penalties, fines, liabilities, costs, expenses, duties and obligations of every kind and character with respect to the Properties or to the ownership, use, operation or other disposition thereof for periods from and after the Effective Time, including, without limitation, under the terms of all oil, gas and mineral leases, easements and similar agreements constituting part of the Properties, as well as under the terms and provisions of all Contracts constituting part of the Properties, including, without limitation, any Contracts entered into by the Seller after the Execution Date and prior to Closing which are both attributable to, and constitute part of, the Properties and are entered into in compliance with Section 5.2; (b) all liabilities, costs, expenses, duties and obligations of every kind and character with respect to the Properties or to the ownership, use, operation or other disposition thereof, whether or not attributable to periods before or after the Effective Time, arising out of or relating to: (i) Gas Imbalances, (ii) the payment of the balance of the Suspended Funds, (iii) all real estate, use, occupation, ad valorem, severance, production and personal property taxes on the Properties for calendar year 2014 and thereafter (it being acknowledged that such taxes for calendar year 2014 are being prorated pursuant to Section 2.6(b)), (iv) all liabilities, costs, expenses, duties and obligations to properly plug and abandon and decommission wells, flowlines, gathering lines or other facilities, equipment or other personal property or fixtures located on or comprising part of the Properties; and (v) all liabilities, costs, expenses, duties and obligations to restore the surface of Real Property Interests or the Lands and any other obligations relating to the failure of the Properties or the ownership or operation thereof to

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comply with Environmental Laws, including any and all obligations to bring the Properties into compliance with applicable Environmental Laws (including conducting any remediation activities that may be required on or otherwise in connection with activities on the Properties), regardless of whether such obligations or conditions or events giving rise to such obligations, arose, occurred or accrued before or after the Effective Time; (c) all losses, claims, liabilities, demands, costs and expenses arising out of, incident to or in connection with the accounting for, failure to pay or the incorrect payment to any royalty owner, overriding royalty owner, working interest owner or other interest holder under the Lands and/or units comprising a part of the Properties insofar as the same are attributable to periods and Hydrocarbons produced and marketed with respect to the Properties from and after the Effective Time; and (d) the DA Assumed Obligations, if applicable pursuant to the terms of Section 5.14.

“ATEX Agreement” has the meaning specified in Section 5.8.1.

“Basket” has the meaning specified in Section 10.7.1.

“Business Day” means any day other than Saturday or Sunday or a day on which banking institutions in Oklahoma City, Oklahoma or Houston, Texas are authorized by Law to close.

“Buyer Indemnified Parties” has the meaning specified in Section 10.2.

“Casualty” means volcanic eruptions, acts of God, terrorist acts, fire, explosion, gathering line failure, earthquake, wind storm, flood, drought, condemnation, the exercise of eminent domain, confiscation or seizure.

“Casualty Loss” has the meaning specified in Section 2.4.

“CEMI” means Chesapeake Energy Marketing, Inc. or other hydrocarbon marketing Affiliate of the Seller.

“Claimant” has the meaning specified in Section 13.2.

“Closing” means the closing and consummation of the transactions contemplated by this Agreement.

“Closing Date” means the date on which the Closing occurs, which will be the later of (a) December 9, 2014, and (b) the date that is ten (10) Business Days after the date on which all of the conditions to Closing set forth in Sections 6 and 7 (other than those that, by their nature, are satisfied at Closing) have been satisfied (or waived in writing), unless otherwise changed by the mutual written agreement of the Parties.

“Closing Statement” has the meaning specified in Section 2.7.

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“Confidentiality Agreement” means that certain confidentiality agreement dated July 17, 2014, executed by the Parties or their Affiliates.

“Consent Decree Agreement” means the Consent Decree Agreement in the form attached hereto as Exhibit D to be entered into between the Seller and the Buyer regarding the Seller’s retention of liabilities and certain rights with respect to the Seller’s performance under that certain Consent Decree issued by the United States District Court for the Northern District of West Virginia on March 11, 2014.

“Consultant” has the meaning specified in Section 2.1.11.

“Contract Area” means, with respect to the Lands, the area outlined on the map attached hereto as Schedule 1.2.

“Contracts” has the meaning specified in the definition of Properties.

“Control” means the possession, directly or indirectly, of the power, directly or indirectly, to direct or cause the direction of the management or policies of the controlled Person, whether through the ownership of equity interests in or voting rights attributable to the equity interests in such Person, by contract or agency, by the general partner of a Person that is a partnership, or otherwise; and “Controls” and “Controlled” have meanings correlative thereto.

“Cure Period” has the meaning specified in Section 2.1.10.

“Customary Post-Closing Consents” has the meaning specified in the definition of Permitted Encumbrances.

“DA Assumed Obligations” has the meanings specified in Section 5.14.

“Defect Notice” has the meaning specified in Section 2.1.

“Defect Notice Date” has the meaning specified in Section 2.1.

“Defensible Title” means title that, although not constituting perfect, merchantable or marketable title, is evidenced by instruments filed of record or other documentation so as to be sufficient against competency claims of bona fide purchasers for value or other persons entitled to protection of applicable recording laws, which, as of the Closing Date: (a) relative to a Real Property Interest, entitles the Seller to receive throughout the productive life of such Real Property Interest not less than the NRI shown for such Real Property Interest on Exhibit A in and to all Hydrocarbons produced and saved or sold from or allocated to the Marcellus Formation, and, if within the Utica Area, the Utica Formation of such Real Property Interest, and if relative to a Well, entitles the Seller to receive throughout the productive life of such Well not less than the NRI shown for such Well on Exhibit A in and to all Hydrocarbons produced and saved or sold from or allocated to the Producing Formation for such Well (except, in the case of each of

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the foregoing, for (i) decreases in connection with any operation in which the owner of such Property may elect after the Closing to be a non-consenting co-owner, (ii) decreases resulting from the establishment after the Execution Date of pools or units and (iii) decreases required to allow other working interest owners, pipelines or plants to make up past underproduction); (b) obligates the Seller to bear, with respect to a Well, not greater than the Working Interest set forth in Exhibit A allocated to the Producing Formation of such Well, except increases in such Working Interest that result in at least a proportionate increase in the Seller’s NRI for such Well; (c) entitles the Seller to not less than the respective number of Net Acres shown on Exhibit A for a Real Property Interest with respect to the Marcellus Formation and, if within the Utica Area, the Utica Formation of such Real Property Interest; (d) with respect to any interest not yet earned under a farm-out agreement, entitles the Seller to the right to earn the interest described in Exhibit A in accordance with the terms of such farm-out agreement; (e) subject to Permitted Encumbrances, is free and clear of all Liens; and (f) with respect to a Real Property Interest, is not subject to an Early Lease Expiration.

“Deposit” has the meaning specified in Section 2.

“Development Agreement” means that certain Development Agreement dated November 24, 2008, as amended, entered into between the Seller and SUSA.

“DOJ” has the meaning specified in Section 5.6.

“Dollar” means the United States of America dollar.

“Early Lease Expiration” means, with respect to a Real Property Interest, that (a) such Real Property Interest is not being held by production or operations, and is not capable of being held beyond the primary term thereof by payment of delay rentals, shut-in payments, or by any other means pursuant to the terms of such Real Property Interest (other than by either drilling a new well on such lease or by paying an option fee to extend the term of the lease beyond the expiration date thereof), and (b) assuming the full and timely payment of all rentals and royalties, and except as a consequence of any breach or default under such Real Property Interest by the Buyer or any of its successors-in-interest, such Real Property Interest will expire pursuant to the terms thereof prior to both (i) the expiration date set forth for such Real Property Interest on Exhibit A and (ii) eighteen (18) months following the Effective Time.

“Easements” has the meaning specified in the definition of Properties.

“Effective Time” means 7:00 a.m. Central Time, July 1, 2014.

“Environmental Claim” has the meaning specified in Section 3.9.2.

“Environmental Defect” means a violation of applicable Environmental Laws existing prior to the Closing Date on or under any Real Property Interest or other Property that requires, if known, or will require, once discovered, reporting to a

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Governmental Authority, investigation, monitoring, removal, cleanup, remediation, restoration or correction under Environmental Laws.

“Environmental Law” means any Law relating to the environment, health and safety, hazardous materials, industrial hygiene, Hydrocarbon well construction, the environmental conditions on, under, or about any of the Properties, including soil, groundwater, and indoor and ambient air conditions or the reporting or remediation of environmental contamination and includes, without limitation, the Comprehensive Environmental Response, Compensation and Liability Act, including the Superfund Amendments and Reauthorization Act of 1986, 42 U.S.C. § 9601 etseq.; the Resource Conservation and Recovery Act, including the Hazardous and Solid Waste Amendments Act of 1984, 42 U.S.C. § 6901 etseq.; the Federal Water Pollution Control Act, 33 U.S.C. § 1251 etseq.; the Clean Air Act, 42 U.S.C. § 7401 etseq.; the Hazardous Materials Transportation Act, 49 U.S.C. § 1471 etseq.; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 etseq.; the Emergency Planning and Community Right to Know Act, 42 U.S.C. § 11001 etseq.; the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; the Rivers and Harbors Act of 1899, 33 U.S.C. § 401 etseq.; and the Occupational Safety and Health Act, 29 U.S.C. § 651 etseq.; as any of the foregoing may be amended and any other Law the purpose of which is to conserve or protect human health, the environment, wildlife or natural resources.

“Excluded Assets” means: (a) the Seller’s minute books, financial and income tax records and legal records (other than title records); (b) any existing or future refund of costs, Taxes or expenses borne by any of the Seller, its Affiliates or its or their respective predecessors in title attributable to the period prior to the Effective Time; (c) any and all proceeds from production and from the settlements of contract disputes with purchasers of Hydrocarbons or byproducts from the Lands, including settlement of take-or-pay disputes, insofar as said proceeds are attributable to periods of time prior to the Effective Time; (d) all rights and interests of the Seller or any of its Affiliates (i) under any policy or agreement of insurance or indemnity (including any rights, claims or causes of action of the Seller and its Affiliates against Third Parties under any indemnities or hold harmless agreements and any indemnities received in connection with the Seller’s or any of its Affiliates’ prior acquisition of any of the Properties) to the extent and only to the extent such rights and interests relate to the ownership of the Properties prior to the Effective Time and (ii) under any bond; (e) all Hydrocarbons produced from the Properties with respect to all periods prior to the Effective Time and all proceeds from the disposition thereof other than inventory for which an adjustment is made under Section 2.5(a); (f) all of the Seller’s and its Affiliates’ proprietary computer software, patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property; (g) all accounts receivable and audit rights arising under any of the applicable contracts or otherwise with respect to the Properties with respect to any period prior to the Effective Time or to any of the Excluded Assets, except for any Gas Imbalances; (h) (i) all Geological and Geophysical Information (provided however that Seller

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shall grant to Buyer at Closing a license to all proprietary seismic data owned by Seller within the Contract Area), and (ii) all other information which the Seller is prohibited from sharing by agreement with a Third Party; (i) all claims of the Seller or any of its Affiliates for refunds of or loss carry forwards with respect to (1) production, ad valorem or any other Taxes attributable to any period prior to the Effective Time, (2) income or franchise taxes, or (3) any Taxes attributable to the Seller’s Excluded Assets; (j) (1) all “virtual courthouses” of the Seller or any of its Affiliates,(2) all of the Seller or any of its Affiliates respective exclusive use arrangements with title abstract facilities and all documents and instruments of the Seller or any of its Affiliates that may be protected by an attorney-client privilege and (3) all data that cannot be disclosed to the Buyer as a result of confidentiality arrangements under agreements with Third Parties (other than title opinions and other title records relating to the Properties); (k) all surface fee interests, surface leasehold and other surface property interests and all buildings, offices, field offices and yards (but excluding the Other Assets and Easements); (l) all non-Lease Owned equipment, including compressors on the wellheads of the Wells operated by the Seller or its Affiliates owned by or leased from MidCon Compression, L.L.C. or Third Parties; (m) automation systems including meters and related telemetry, licensed radio frequencies and associated communications infrastructure including towers, antennas, data links and network circuits, except any such items which are Lease Owned equipment; (n) all drilling rigs and related equipment, work over rigs and related equipment, tools and other equipment brought onto a well site temporarily for purposes of drilling, reworking or maintaining a well, all vehicles, and any other non-Lease Owned equipment, inventory, machinery, tools and other personal property; (o) all non-Lease Owned salt water disposal wells, systems and related equipment and clean water wells, systems and equipment (but excluding any such items included in the Other Assets); (p) all Gathering Assets except for the Transferred Gathering Systems; (q) (1) all mineral interests and lessor royalties owned by the Seller and its Affiliates including, without limitation, any and all mineral interests burdened by or relating to any of the Real Property Interests or burdened by other oil, gas and mineral leases, and (2) all overriding royalty interests owned by the Seller or its Affiliates, to the extent they do not, individually or in the aggregate, reduce the Seller’s interest in any Property below the Net Revenue Interest for such Property as described in Exhibit A; (r) all rights, title and interest of the Seller under the Development Agreement (except as and to the extent described in Section 5.14); (s) the Midstream Consent Contracts not transferred pursuant to Section 5.8.2; (t) the ATEX Agreement; and (u) the FERC Jurisdictional Contracts, unless assigned to the Buyer pursuant to the terms of Section 5.11.

“Execution Date” has the meaning specified in the introductory paragraph.

“Expiration Date” has the meaning specified in Section 14.3.

“Fee Mineral Lease” one or more oil, gas and mineral leases to be entered into at Closing in the form attached hereto as Exhibit E with Seller and/or its Affiliates as Lessor and Buyer as Lessee covering the fee minerals described on Exhibit A

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under the heading Fee Mineral Lease, to the extent they cover the lands described on Exhibit A.

“FERC Jurisdictional Contracts” has the meaning specified in Section 5.11.1.

“FERC Waivers” has the meaning specified in Section 5.11.1.

“Final Statement” has the meaning specified in Section 2.8.

“Finance Related Parties” means the respective Affiliates, officers, directors, employees and representatives of the Financing Sources, any lender participating in the Financing and permitted successors and assigns of the Financing Sources, but specifically excluding the Buyer and its Affiliates, and its and their respective officers, directors, employees, representatives, successors and assigns.

“Financing” means the debt financing which the Financing Sources, subject only to the terms and conditions set forth in the Financing Commitment, have committed to provide or cause to be provided to the Buyer in the amounts set forth therein in connection with the transactions contemplated hereby.

“Financing Commitment” means the financing commitment set forth in that certain Commitment Letter, dated October 14, 2014, provided to the Buyer and its Affiliates in connection with the Financing.

“Financing Sources” means the financial institutions identified in the Financing Commitment.

“FTC” has the meaning specified in Section 5.6.

“G&G Licenses” has the meaning specified in the definition of Properties.

“GAAP” means generally accepted accounting principles, consistently applied, as recognized by the U.S. Financial Accounting Standards Board (or any generally recognized successor). The requisite that such principles be consistently applied means that the accounting principles in a current period are comparable in all material respects to those applied in preceding periods.

“Gas Imbalances” means any gas production, pipeline, storage, processing, transportation or other imbalance or unsatisfied through-put obligations attributable to Hydrocarbons produced from the Seller’s interest in the Lands.

“Gathering Assets” means all of the gathering lines, flow lines, gas lines, gas processing and gathering line compression facilities, processing plants, storage rights and transportation capacity (including downstream transportation capacity), tubing, pumps, motors, gauges, meters, valves, SCADA and other automation equipment and other machinery and equipmentconstituting part of or comprising the gas gathering systems or assets owned by any Affiliate of Chesapeake Energy Corporation, including all of the rights of way, surface interests, surface lease

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agreements, surface use agreements, railroad crossings, easements and similar real estate interests related thereto and all contracts, Permits, pipeline and plant imbalances, and Records relating to the ownership, operation or maintenance.

“Geological and Geophysical Information” means engineering, geological and/or geophysical studies (including seismic data, studies, analyses and interpretations), and other similar information and records, in each case relating to the Properties.

“Governmental Authority” means any foreign, national, state, local, municipal, tribal or other government or division thereof; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal or arbitrator.

“HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the applicable rules and regulations promulgated thereunder.

“Hydrocarbons” means crude oil, natural gas, casinghead gas, condensate, natural gas liquids, and other liquid or gaseous hydrocarbons.

“Individual Claim” has the meaning specified in Section 10.7.1.

“Individual Defect Threshold” has the meaning specified in Section 2.1.1.

“Knowledge” of a fact or matter means the actual knowledge with respect to such fact or matter of any of the following listed individuals, following reasonable inquiry: (a) with respect to the Buyer, the individuals listed in subpart 1 of Schedule 1.1, and (b) with respect to the Seller, the respective individuals listed in subpart 2 of Schedule 1.1.

“Lands” means the lands covered by the Real Property Interests and all lands pooled or unitized therewith.

“Late Lease Expiration” means, with respect to a Real Property Interest, that (a) as of the Execution Date such Real Property Interest is neither being held by production or operations nor is capable of being held beyond the primary term thereof by payment of delay rentals, shut-in payments, or by any other means pursuant to the terms of such Real Property Interest (other than by either drilling a new well on such lease or by paying an option fee to extend the term of the lease beyond the expiration date thereof), (b) assuming the full and timely payment of all rentals and royalties and except as a consequence of any breach or default under such Real Property Interest by the Buyer or any of its successors-in-interest, the actual expiration date of such Real Property Interest set forth in the applicable lease is later than the expiration date set forth for such Real Property Interest on Exhibit A, and (c) the expiration date set forth for such Real Property Interest on Exhibit A is prior to the date that is eighteen months following the Effective Time.

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“Laws” means any and all applicable laws, statutes, ordinances, permits, decrees, writs, injunctions, orders, codes, judgments, principles of common law, rules or regulations (including Environmental Laws) which are promulgated, issued or enacted by a Governmental Authority having jurisdiction.

“Lease Owned” means any personal property or fixture asset in which the Seller owns an interest related to the operation of a Well or Wells which was charged to the joint account of the working interest owners in such Well or Wells, excluding items considered part of overhead; provided, however that “Lease Owned” does not include any “Excluded Assets”.

“Lien” means any lien, mortgage, security interest, pledge, charge or encumbrance or other arrangements substantially equivalent thereto, but does not include any production payment, net profits interest, overriding royalty interest or similar interest to the extent any such interest does not reduce the Seller’s NRI below that shown for the Seller on Exhibit A.

“Log” has the meaning specified in the definition of Marcellus Formation.

“Marcellus Formation” means, the geological formations that are known as the Marcellus Shale formations, which generally include the stratigraphic equivalent of the formations found in the James Messenger ETZ 3H U well (API#4710302973) located in Wetzel County, West Virginia, with the top (being the top of the Marcellus Shale formation) at the correlative stratigraphic equivalent to that point found at a measured depth of 7,298 feet on the Gamma-Ray (GM) log of such well (the “Log”) and the base (being the top of the Onondaga formation) at the correlative stratigraphic equivalent to that point found at a measured depth of 7,346 feet on the Log, recognizing that the actual depth will vary across the Lands.

“Marketing Rate” has the meaning specified in Section 5.11.2.

“Material Adverse Effect” means any result, consequence, condition, or matter which (a) materially adversely affects or could be reasonably expected to materially adversely affect the Seller’s Properties or the operations, rights, results of operations or the value of the Properties, taken as a whole, or (b) materially impairs, prevents or materially delays the Seller’s ability to perform its obligations under the Transaction Documents or to consummate the transactions contemplated by this Agreement; provided, however, that, in any event, the following shall not be deemed to constitute, create or cause a Material Adverse Effect: any changes, circumstances or effects (i) that affect generally the oil and gas industry, such as fluctuations in the price of oil and gas, or that result from international, national, regional, state or local economic conditions, from general developments or from other general economic conditions, facts or circumstances, including changes in Tax policy or other fiscal conditions, that are not subject to the control of the relevant Party, (ii) that result from any of the transactions contemplated in this Agreement or the public announcement thereof, or (iii) that

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result from conditions or events resulting from an outbreak or escalation of hostilities, whether nationally or internationally, or the occurrence of any other calamity or crisis, whether nationally or internationally, including the occurrence of one or more terrorist attacks.

“Material Contracts” has the meaning specified in Section 3.8.1.

“Midstream Agreements” has the meaning specified in Section 5.8.3.

“Midstream Assignments” has the meaning specified in Section 5.8.3.

“Midstream Consent Contracts” has the meaning specified in Section 5.8.2.

“Net Acres” means, as calculated separately with respect to each Real Property Interest, (a) the number of gross acres of land covered by such leasehold interest, multiplied by (b) the lessor’s interest in the Marcellus Formation Hydrocarbons and, if such land lies within the Utica Area, the Utica Formation Hydrocarbons in the lands covered by such leasehold interest, multiplied by (c) the Seller’s undivided interest in such leasehold interest (provided, however, if items (b) and (c) vary as to different areas of such lands covered by such leasehold interest, a separate calculation shall be performed with respect to each such area).

“Net Revenue Interest” (or “NRI”) means, with respect to the Real Property Interests, the decimal interest in and to all production of the Marcellus Formation Hydrocarbons within the Contract Area and, if applicable, the Utica Formation Hydrocarbons within the Utica Area of such Real Property Interest, and with respect to any Well, the decimal interest in and to all production of Hydrocarbons from the respective Producing Formation, in the case of each of the foregoing, that are produced and saved or sold from or allocated to the relevant Property after giving effect to all valid lessors’ royalties, overriding royalties and/or other burdens against production.

“NORM” has the meaning specified in Section 5.9.3.

“Ordinary Course of Business” means in the ordinary course of business consistent with past custom and practice.

“Other Assets” means those real and personal property assets and other rights and interests described on Exhibit A-1.

“Party” and “Parties” have the meanings specified in the introductory paragraph.

“Permits” has the meaning specified in the definition of Properties.

“Permitted Encumbrances” means (a) royalties, overriding royalties and similar burdens on production to the extent they do not, individually or in the aggregate, reduce the Seller’s NRI or increase the Seller’s Working Interest (without at least a proportionate corresponding increase in the Seller’s NRI) in any Property from

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that shown for the Seller on Exhibit A; (b) Liens for Taxes for which payment is not due or which are being contested in good faith by appropriate proceedings; (c) Liens of mechanics, materialmen, warehousemen, landlords, vendors, and carriers and any similar Liens arising by operation of Law which, in each instance, arise in the Ordinary Course of Business, for sums not yet due or which are being contested in good faith by appropriate proceedings; (d) operating agreements, unit agreements, unitization and pooling designations and declarations, and all other Contracts that either are not Material Contracts or are listed in Schedule 3.8 to the extent they do not, individually or in the aggregate, reduce the Seller’s NRI or increase the Seller’s Working Interest (without at least a proportionate corresponding increase in the Seller’s NRI) in any Property from that shown for the Seller on Exhibit A; (e) easements, surface leases, and other rights and plat restrictions, zoning laws, restrictive covenants and conditions, regulatory authority of Governmental Authorities, and building and other land use laws and similar encumbrances; (f) all rights to consent by, required notices to, filings with or other actions by Governmental Authorities in connection with the sale, disposition, transfer or conveyance of federal, state, tribal, or other governmental oil and gas leases or interests therein or related thereto, or the transfer of operations of any of the Wells, where the same are customarily obtained subsequent to the assignment, disposition or transfer of such oil and gas leases or interests therein, or such operations (“Customary Post-Closing Consents”); (g) conventional rights of reassignment obligating the lessee to reassign or offer to reassign its interests in any lease prior to a release or abandonment of such lease; (h) required non-governmental Third Party consents to assignments which have been obtained or waived by the appropriate parties or which cannot be unreasonably withheld, and preferential rights to purchase which have been waived by the appropriate parties or for which the time period for asserting such rights has expired without the exercise of such rights; (i) rights of tenants-in-common in and to the Properties; (j) all defects or irregularities of title, if any, affecting the Seller’s Properties which do not, individually or in the aggregate, adversely interfere in any material way with the present or future operation or use of the Properties subject thereto or affected thereby and which would be accepted by a reasonably prudent and sophisticated buyer engaged in the business of owning, developing and operating oil and gas properties in the same geographical location with knowledge of all the facts and appreciation of their legal significance; (k) all defects or irregularities (i) arising out of lack of corporate authorization or a variation in corporate name, (ii) that have been cured or remedied by applicable statutes of limitation or statutes for prescription, (iii) consisting of the failure to recite marital status in documents or omissions of heirship proceedings, (iv) that have been cured by possession under applicable statutes of limitation, (v) resulting from lack of survey or failure to record releases of liens, production payments or mortgages that have expired by their own terms or the enforcement of which are barred by applicable statutes of limitation, or (vi) to the extent affecting any depths other than the Marcellus Formation, and if within the Utica Area, the Utica Formation, or if relative to a Well, the Producing Formation for such Well; (l) rights vested in or reserved to any Governmental

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Authority to regulate the Properties, to terminate any right, power, franchise, license or permit afforded by such Governmental Authority, or to purchase, condemn or expropriate any of the Properties; (m) requirements to coordinate activities and operations with those having coal, gas storage, utility, timber or other similar rights and operations on, above or below the Properties and any drilling and operating limitations to which the Properties may be subject by reason of rights in favor of any such surface or subsurface owners or operators arising as a matter of law or regulation or pursuant to the terms or provisions of any Real Property Interests or of any Contracts listed on Schedule 3.8; and (n) “free gas” arrangements for household or agricultural or domestic or similar use under the terms of any oil and gas lease that is part of the Properties.

“Person” means an individual, corporation, partnership, limited liability company, joint venture, association, joint stock company, trust, unincorporated organization or other entity or Governmental Authority.

“Pipeline Waivers” has the meaning specified in Section 5.11.1.

“PPR” has the meaning specified in Section 2.2.

“Proceedings” means any and all proceedings, suits, causes of action and administrative proceedings by or before any Governmental Authority.

“Producing Formation” means, with respect to the wellbore of any Well, each geological zone and depth open to production from which Hydrocarbons are being produced as of the Effective Time.

“Properties” means the Seller’s and its Affiliates’ right, title and interest in and to the following (but excluding the Excluded Assets): (a) the oil, gas and mineral leases shown on Exhibit A, and the operating rights, working interests, net revenue interests, and other rights to Hydrocarbons therein, whether producing or non-producing (“Real Property Interests”); (b) the oil and gas wells shown on Exhibit A (“Wells”), and all Lease Owned tangible personal property, equipment, fixtures and improvements, including all injection wells, salt water disposal facilities, well heads, casing, tubing, pumps, motors, gauges, valves, heaters, treaters, water lines, vessels, tanks, boilers, separators, treating equipment, compressors, other equipment, automation systems including meters and related telemetry on wells, power lines, telephone and communication lines and other appurtenances owned in connection with production, treating, storing, transportation or marketing of Hydrocarbons from the Wells, to the extent each of the foregoing is Lease Owned; (c) all presently existing unitization, pooling and/or communitization agreements, declarations or designations and statutorily, judicially or administratively created drilling, spacing and/or production units, whether recorded or unrecorded, insofar as the same are attributable or allocated to the Lands, and the Seller’s interest in and to the properties covered or units created thereby which are attributable to the Real Property Interests; (d) all presently existing and valid Hydrocarbon sales agreements, operating agreements,

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gathering agreements, transportation agreements, farmout and farmin agreements, unitization, pooling and communitization agreements, purchase agreements, exploration agreements, area of mutual interest agreements, exchange and processing contracts and agreements, partnership and joint venture agreements and any other contracts, agreements and instruments, other than the Development Agreement (except as and to the extent described in Section 5.14), in each case, to the extent the above agreements cover, are attributable to or relate to the Lands or the Wells or any interests pooled, communitized or unitized therewith or any of the Other Assets or Transferred Gathering Systems, including, without limitation, those contracts and agreements described on Exhibit C (“Contracts”); (e) all Hydrocarbons in, on, under or produced from or attributable to the Lands from and after the Effective Time and the proceeds thereof; (f) all rights and privileges with respect to the use of the surface, including rights of ingress and egress, and subsurface depths under the lands covered by or subject to any of the Real Property Interests, or otherwise arising under or derived from the Properties or any of the Transferred Gathering Systems, in each case, to the extent related to the ownership and operation of, or which may be necessary for the use, development or operation of, the Properties or any of the Transferred Gathering Systems, including, but not limited to, all easements, subsurface easements, surface leases, servitudes and rights of way used or held for use in connection with the production of Hydrocarbons from the Lands (“Easements”); (g) all rights, benefits and obligations arising from or in connection with any Gas Imbalances as of the Effective Time; (h) all licenses, orders, franchises, registrations, permits, consents, approvals, variances, exemptions, waivers, rights, water rights (including water withdrawal, storage, discharge, treatment, injection and disposal rights related to the Properties) and other authorizations of all Governmental Authorities that are required to permit its operation of the Properties as presently operated by the Seller (the “Permits”), but only to the extent such Permits are transferrable; (i) the Other Assets (except for the Geological and Geophysical Information described on the attached Exhibit A-1) and the Transferred Gathering Systems; (j) licenses (the “G&G Licenses”) granted by the Seller to the Buyer (in forms reasonably acceptable to both Parties) covering the Geological and Geophysical Information described on the attached Exhibit A-1; and (k) the Seller’s Records.

“Purchase Price” has the meaning specified in Section 2.

“Real Property Interests” has the meaning specified in the definition of Properties.

“Records” means the Seller’s files, records and data (including electronic data) to the extent specifically related to the Properties, including but not limited to lease files, land files, well files, raw data (including core data, logs, fluid/gas data, water sample data, production data and pressure data), if any, division order files, ownership decks, abstracts, title files, engineering and/or production files, regulatory files, environmental files, maps and accounting and Tax records; provided, however, “Records” does not include (a) any of the Excluded Assets

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and (b) any files, records and data which the Seller or its Affiliates are prohibited, by agreement, from sharing with a third party, provided that the Seller shall make commercially reasonable efforts (at no cost to the Seller) to obtain waivers of any such prohibitions.

“Required Consent” means a consent by a Third Party that, if not obtained prior to the assignment of a Real Property Interest, Well or Easement, either (a) automatically voids or nullifies the applicable Assignment with respect to such Property or (b) automatically terminates, or permits a lessor to terminate (legally and pursuant to the express terms of the underlying lease), the Seller’s interest in the Property subject to such consent; provided, however, “Required Consent” does not include any consent which by its terms cannot be unreasonably withheld or any Customary Post-Closing Consent.

“Respondent” has the meaning specified in Section 13.2.

“Retained Liabilities” means those liabilities and obligations of the Seller arising from the following: (a) all losses, claims, liabilities, demands, costs and expenses arising out of or in connection with the Seller’s failure to pay or incorrect payment of any ad valorem, severance or similar taxes allocable to the Properties with respect to periods prior to the Effective Time (specifically excluding any Assumed Obligations and any sales or transfer taxes arising from the transactions contemplated hereunder to occur at the Closing, which are to be treated in accordance with Section 8.5); (b) all claims, demands, violations, actions, damages, assessments, penalties, fines, costs, expenses, obligations, or other liabilities with respect to the ownership, operation or maintenance of the Properties prior to the Effective Time, insofar as the claims (or portions thereof) are attributable or allocable to the interest in the Properties, but excluding the obligations specifically assumed by the Buyer under the definition of Assumed Obligations; (c) all claims, demands, violations, actions, damages, assessments, penalties, fines, costs, expenses, obligations or other liabilities with respect to the Excluded Assets whether attributable to periods before or after the Effective Time (excluding the DA Assumed Obligations, if applicable pursuant to the terms of Section 5.14); and (d) the obligations of the Seller under the Consent Decree Agreement and the Consent Decree described in the definition of Consent Decree Agreement.

“Seller Indemnified Parties” has the meaning specified in Section 10.3.

“Special Damages” has the meaning specified in Section 14.16.

“SUSA” means Statoil USA Onshore Properties Inc., a Delaware corporation.

“Suspended Funds” means funds which the Seller is holding as of the Closing Date which are owing to Third Party owners of royalty, overriding royalty, working or other interests in respect of past production of oil, gas or other

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Hydrocarbons attributable to the Seller’s Properties; provided that the “Suspended Funds” shall not include the Unleased Revenue.

“Taxes” means taxes of any kind, levies, or other like assessments, customs, duties, imposts, charges or fees of any Governmental Authority, including gross receipts, ad valorem, value added, excise, real or personal property, asset, sales, use, royalty, license, payroll, transaction, capital, net worth and franchise taxes, withholding, employment, social security, workers compensation, utility, severance, production, unemployment compensation, occupation, premium, windfall profits, transfer and gains taxes or other governmental taxes imposed or payable to the United States or any other Governmental Authority, and in each instance such term shall include any interest, penalties or additions to tax attributable to any such Tax, including penalties for the failure to file any tax return or report.

“Third Party” means any Person other than a Party or an Affiliate of a Party.

“Title Benefit” has the meaning specified in Section 2.1.9.

“Title Defect” means, as to (i) any Real Property Interest, any condition that causes the Seller’s title to the Marcellus Formation of such Property, and, if within the Utica Area, the Utica Formation of such Property, to be less than Defensible Title as of the Closing Date; and (ii) any Well, any condition that causes the Seller’s title to the Producing Formation of such Well, to be less than Defensible Title as of the Closing Date. For the avoidance of doubt, a single matter (such as an individual mortgage or lien) shall be treated as a single Title Defect even if affecting more than one Property. Notwithstanding the foregoing, the following shall not be considered Title Defects:

(a)defects based solely on lack of information in the Seller’s files;

(b)defects arising out of lack of corporate or other entity authorization unless the Buyer provides affirmative written evidence that the action was not authorized and results in another party’s superior claim of title;

(c)defects based on failure to record leases issued by any federal governmental body, or any assignments of such leases, in the real property, conveyance or other records of the county in which the Property is located;

(d)defects arising out of a lack of a survey, unless a survey is expressly required by applicable laws;

(e)defects in the chain of title consisting of the failure to recite marital status in a document or omissions of successions of heirship or estate proceedings, unless the Buyer provides affirmative evidence that such failure or omission has resulted in another party’s superior claim of title;

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(f)defects that have been cured by the passage of time, the doctrine of adverse possession, applicable laws of limitation or prescription or such other matter that would render such defect invalid according to applicable law;

(g)defects based solely on a legal description that includes the lessor’s mineral estate but describes a tract of land larger than that owned by the lessor;

(h)defects that are a result of an assignment of interests in a Property from the Seller to another joint working interest owner that has been delivered and recorded or that has yet to be delivered and/or recorded to the extent such assignments do not, individually or in the aggregate, reduce the Seller’s Net Revenue Interest or increase the Seller’s Working Interest (without at least a proportionate corresponding increase in the Seller’s Net Revenue Interest) in any Well or Real Property Interest or reduce the Seller’s Net Acres with respect to any Real Property Interest from that shown for the Seller on Exhibit A;

(i)defects relative to (i) Real Property Interests, to the extent affecting intervals, formations, strata and depths outside of the Marcellus Formation, or, if within the Utica Area, the Utica Formation, in such Real Property Interests, and (ii) Wells, to the extent affecting intervals, formations, strata and depths outside of the Producing Formation in the wellbore only of such Wells, and defects affecting any other geologic zone or depth specifically excluded from Sellers ownership as further described under the heading entitled Depth Limitations on the attached Exhibit A;

(j)expiration of, or other defects affecting, Real Property Interests that are described on Exhibit A as having an expiration date on or prior to the Closing Date;

(k)defects based on a gap in the chain of title, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain or runsheet, which documentation shall be provided by Buyer to Seller in the Defect Notice;

(l)defects based on the fact that a Third Party owns or controls the coal underlying the lands underlying any of the Properties;

(m)defects as a consequence of cessation of production, insufficient production or failure to conduct operations on any of the Properties held by production, or on the Lands, except to the extent that such cessation of production, insufficient production or failure to conduct operations (taking into account any cessation of production that is permitted under the terms of the applicable lease) (i) is affirmatively proven by the Buyer to have occurred after September 30, 2004, and (ii) caused the affected Real

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Property Interest to expire or gives rise to a right to terminate the Real Property Interest in question, which evidence shall be included in the Defect Notice; and

(n)an unsubordinated mortgage that is not in default.

“Transaction Documents” means this Agreement, the Assignments and the documents and instruments to be delivered at Closing.

“Transferred Gathering Systems” means the Gathering Systems described on Exhibit A-2.

“Unleased A/R” has the meaning specified in Section 2.10.

“Unleased Accounts” has the meaning specified in Section 2.10.

“Unleased Revenue” has the meaning specified in Section 2.10.

“Utica Area” means that subpart of the Contract Area designated as the “Utica Area” on the map attached hereto as Schedule 1.2.

“Utica Formation” meansthe geological formations that are known as the Utica Shale formations, which generally include the stratigraphic equivalent of the formations found in the James Messenger ETZ 3H U well (API#4710302973) located in Wetzel County, West Virginia, with the top (being the top of the Point Pleasant formation) at the correlative stratigraphic equivalent to that point found at a measured depth of 12,282 feet on the Log and the base (being the top of the Trenton formation) at the correlative stratigraphic equivalent to that point found at a measured depth of 12,395 feet on the Log, recognizing that the actual depth will vary across the Lands.

“Wells” has the meaning specified in the definition of Properties.

“Working Interest” (or “WI”) means, with respect to the Wells, the decimal interest in the full and entire leasehold estate in any Property and all rights and obligations of every kind and character pertinent thereto or arising therefrom, without regard to any valid lessor royalties, overriding royalties and/or other burdens against production, insofar as said interest in said leasehold is burdened with the obligation to bear and pay the cost of exploration, development and operation.

1.2. References; Construction. All references in this Agreement to Exhibits, Schedules, Sections, paragraphs, subsections and other subdivisions refer to the corresponding Exhibits, Schedules, Sections, paragraphs, subsections and other subdivisions of or to this Agreement unless expressly provided otherwise. Titles appearing at the beginning of any Sections, subsections or other subdivisions of this Agreement are for convenience only, do not constitute any part of this Agreement, and shall be disregarded in construing the language hereof. The

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words “this Agreement,” “herein,” “hereby,” “hereunder” and “hereof,” and words of similar import, refer to this Agreement as a whole and not to any particular subdivision unless expressly so limited. The words “this Section” and “this subsection,” and words of similar import, refer only to the Section or subsection hereof in which such words occur. A defined term has its defined meaning throughout this Agreement regardless of whether it appears before or after the place where it is defined. The word “or” is disjunctive but not necessarily exclusive, and has the inclusive meaning represented by the phrase “and/or” and the word “including” (in its various forms) means including without limitation. Examples are not to be construed to limit, expressly or by implication, the matter they illustrate. Each accounting term not defined herein, and each accounting term partly defined herein to the extent not defined, will have the meaning given to it under GAAP. All references to prices, values or monetary amounts refer to Dollars. Pronouns in masculine, feminine or neuter genders shall be construed to state and include any other gender, and words, terms and titles (including terms defined herein) in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires. Exhibits and Schedules referred to herein are attached to and by this reference incorporated herein for all purposes.

2.Purchase and Sale; Purchase Price. At the Closing, and upon the terms and subject to the conditions of this Agreement, the Seller agrees to sell and convey to the Buyer all of its Properties, and the Buyer agrees to purchase, accept and pay for the Properties and to assume all of the Assumed Obligations. In consideration for the sale of the Properties, the Buyer will pay to the Seller the purchase price of FIVE BILLION THREE HUNDRED SEVENTY-FIVE MILLION DOLLARS ($5,375,000,000.00) (the “Purchase Price”, subject to adjustments as provided in this Agreement) in immediately available funds at Closing (pursuant to wire transfer instructions designated in advance by the Seller to the Buyer in writing). Within two (2) Business Days after the Execution Date, the Buyer will pay to the Seller an earnest money deposit equal to five percent (5%) of the unadjusted Purchase Price (the “Deposit”). At Closing, the Deposit will be applied against the Purchase Price payable to the Seller in accordance with the provisions of this Agreement. The Purchase Price will be adjusted (without duplication) as set forth below in this Section 2.

2.1. Title and Environmental Defects. The Purchase Price will be (a) decreased only for those uncured Title Defects and uncured Environmental Defects that are in excess of the respective Individual Defect Thresholds and the Aggregate Defect Threshold and (b) increased for Title Benefits, in each case, in accordance with this Section 2.1. The Buyer may deliver to the Seller, on or before the Defect Notice Date, one or more written notices specifying each defect associated with the Seller’s Properties that the Buyer asserts constitutes a Title Defect or an Environmental Defect, a specific description of each such Title Defect or Environmental Defect and the basis for such assertion under the terms of this Agreement, the amount of the adjustment to the Purchase Price that the Buyer asserts based on such Title Defect or Environmental Defect and its method of calculating such adjustment, together with all data and information reasonably necessary for the Seller to verify the existence of the alleged Title Defect or

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Environmental Defect (“Defect Notice”). The term “Defect Notice Date” means (i) 5:00 p.m. Central Time on the one hundred twentieth (120^th) day following the Closing Date in the case of Title Defects and (ii) 5:00 p.m. Central Time on the fifth (5^th) Business Day prior to the Closing Date in the case of Environmental Defects. Any matters that may otherwise constitute Title Defects or Environmental Defects, but of which the Seller has not been notified by the Buyer in writing by the respective Defect Notice Date, shall be deemed to have been waived by the Buyer for all purposes; provided, however, that no failure to provide any such notice by the respective Defect Notice Date shall be deemed a waiver of any right or remedy under the Assignment with respect to any breach of the special warranty of title to be given by the Seller in the Assignment. All adjustments to the Purchase Price based on Title Defects will be based on the Allocated Values attributable to the affected Properties. Upon timely delivery of a Defect Notice under this Section 2.1, the Buyer and the Seller will in good faith negotiate the validity of the claim and the amount of any adjustment to the Purchase Price using the following criteria:

2.1.1 No single Title Defect or Title Benefit shall be taken into account unless the value of such defect or benefit is determined to be more than (i) Twenty-Five Thousand Dollars ($25,000) with respect to any Well or (ii) Fifteen Thousand Dollars ($15,000) with respect to any Real Property Interest, and no single Environmental Defect shall be taken into account unless the value of such defect is determined to be more than Fifty Thousand Dollars ($50,000) (each an “Individual Defect Threshold”).

2.1.2 No adjustment will be made to the Purchase Price for either uncured Title Defects or for uncured Environmental Defects unless the total of all individual adjustments for such Title Defects and Environmental Defects that exceed the respective Individual Defect Thresholds exceeds one and one-tenth (1.1%) of the unadjusted Purchase Price in the aggregate (the “Aggregate Defect Threshold”) after first offsetting any Title Benefits. In the event that the total of all such individual adjustments for uncured Title Defects and uncured Environmental Defects exceeds the Aggregate Defect Threshold, the adjustment to the Purchase Price shall only be for the amount by which the total of all such individual adjustments for uncured Title Defects and uncured Environmental Defects exceeds the Aggregate Defect Threshold plus the total value of all individual adjustments for any Title Benefits. In no event will the aggregate amount of Title Defect adjustments with respect to a Property exceed the Allocated Value of such Property. With respect to any Title Defects or Environmental Defects for which an adjustment equal to the entire Allocated Value of the affected Property is made to the Purchase Price hereunder, at the Seller’s option, as a condition precedent to such adjustment, the Buyer will execute and deliver to the Seller an assignment (in substantially the same form as the Assignment) of such Property.

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2.1.3 If the adjustment is based on the Seller owning an NRI in a Real Property Interest or Well which is less than that shown on Exhibit A, then the downward adjustment with respect to such Property shall be calculated by multiplying the Allocated Value shown for such Property on Exhibit A by a fraction, the numerator of which is an amount equal to the NRI shown for such Property on Exhibit A less the NRI to which the Seller is actually entitled taking such Title Defect into account, and the denominator of which is the NRI shown for such Property on Exhibit A.

2.1.4 If the adjustment is based on the Seller owning a Working Interest in a Well which is larger than the Working Interest shown for such Property on Exhibit A, but without a proportionate increase in the NRI for such Property, then the downward adjustment shall be calculated by determining the effective NRI that results from such larger Working Interest, determining what the NRI would be using such effective NRI and the Working Interest shown for such Property on Exhibit A and then calculating the adjustment in the manner set forth in Section 2.1.3.

2.1.5 If the adjustment is based on the Seller owning fewer Net Acres in a Real Property Interest than those shown for such Real Property Interest on Exhibit A, then the downward adjustment shall be calculated by multiplying the Allocated Value shown for such Property on Exhibit A by a fraction, the numerator of which is the number of Net Acres shown for such Property on Exhibit A minus the actual Net Acres actually owned in such Property, and the denominator of which is the number of Net Acres shown for such Property on Exhibit A.

2.1.6 If the adjustment is based on a Lien upon the Seller’s Real Property Interest or Well that is liquidated in amount, then the downward adjustment is the lesser of the amount necessary to remove such Lien from such Property or the Allocated Value of such Property.

2.1.7 If the adjustment is based on an Early Lease Expiration, then the downward adjustment shall be calculated by multiplying the Allocated Value shown for such Real Property Interest on Exhibit A by a fraction, (a) the numerator of which is (i) the lesser of 547 days and the number of days within the period beginning on the Effective Time and ending on the expiration date of the Real Property Interest as set forth on Exhibit A, minus (ii) the number of days within the period beginning on the Effective Time and ending on the actual expiration date of the Real Property Interest as set forth in the applicable lease, and (b) the denominator of which is the lesser of 547 days and number of days within the period beginning on the Effective Time and ending on the expiration date of the Real Property Interest as set forth on Exhibit A. Alternatively, if an adjustment is based on a Late Lease Expiration, then the upward adjustment shall be calculated by multiplying the Allocated Value shown for such Real Property Interest on Exhibit A by a fraction, (a) the numerator of which is (i) the lesser of

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547 days and the number of days within the period beginning on the Effective Time and ending on the actual expiration date of the Real Property Interest as set forth in the applicable lease, minus (ii) the number of days within the period beginning on the Effective Time and ending on the expiration date of the Real Property Interest as set forth on Exhibit A, and (b) the denominator of which is the number of days within the period beginning on the Effective Time and ending on the expiration date of the Real Property Interest as set forth on Exhibit A; provided, however, no adjustment based on a Late Lease Expiration shall exceed an amount equal to the Allocated Value shown for the respective Real Property Interest on Exhibit A.

2.1.8 If the adjustment is based on a liability to remediate or otherwise cure an Environmental Defect related to a Real Property Interest, then the downward adjustment with respect to such Property is that portion of the amount necessary to implement and complete any remedial, removal, response, construction, closure, disposal or other corrective actions, or monitoring required under Environmental Laws to correct or remove such Environmental Defect in the most cost effective manner reasonably available and consistent with common industry practices for which the Buyer would be liable after Closing.

2.1.9 If the Seller determines that a Real Property Interest is subject to a Late Lease Expiration or that its ownership of (a) any Well entitles the Seller to a larger NRI or a smaller Working Interest (without a proportionately smaller NRI) than that shown for such Property on Exhibit A or (b) any Real Property Interest entitles the Seller to a larger NRI or a greater number of Net Acres than that shown for such Property on Exhibit A (each, a “Title Benefit”), then the Seller shall notify the Buyer of such Title Benefit in writing on or before the Defect Notice Date for Title Defects, which notice shall include a reasonably detailed description of such Title Benefit, the Dollar value that the Seller asserts is attributable to such Title Benefit and the Seller’s method of calculating such amount. The Seller shall be deemed to have conclusively waived any Title Benefits of which it fails to notify the Buyer in the manner and by the date specified in the preceding sentence. The upward adjustment to the Purchase Price in respect of each Title Benefit shall be determined using the same principles as provided in this Section 2.1 with respect to Title Defects. For the avoidance of doubt, a single matter shall be treated as a single Title Benefit even if affecting more than one Property.

2.1.10 If a Title Defect or an Environmental Defect is reasonably susceptible of being cured, then the Seller will have the right to cure such defect for a period of up to sixty (60) days after the respective Defect Notice Date (such period for Title Defects and such period for Environmental Defects, the respective “Cure Period”). The Buyer shall provide the Seller and its representatives access to the Properties and the Records after Closing in

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connection with the Seller’s efforts to cure alleged defects. The Seller will be deemed to have adequately completed the cure of an Environmental Defect after the implementation and completion of any remedial, removal, response, construction, closure, disposal or other corrective actions required under Environmental Laws to correct or remove such Environmental Defect.

2.1.11 If after the respective Cure Period the Seller and the Buyer are not in agreement as to (a) whether a Defect Notice or notice of Title Benefit complies with the terms hereof, (b) the existence of or value attributable to a Title Defect, Title Benefit or Environmental Defect, (c) whether a Title Defect or Environmental Defect has been cured during the respective Cure Period, or (d) the amount of any adjustments to be made to the Purchase Price in respect of any uncured Title Defect, Title Benefit or uncured Environmental Defect, then the Seller and the Buyer will submit the dispute to arbitration as provided in this Section following written notice from one Party to the other Party on or before the date thirty (30) days after the end of the respective Cure Period that such Party is initiating dispute resolution in accordance with this Section, such notice to describe in reasonable detail the nature and specifics of the dispute. The Buyer, with respect to Environmental Defects, shall be deemed to have conclusively waived any unresolved Environmental Defect, or cure thereof, which is not submitted for resolution as provided in this Section on or before the date one hundred twenty (120) days after the end of the Cure Period applicable to Environmental Defects. The Buyer, with respect to Title Defects, and the Seller, with respect to Title Benefits, shall be deemed to have conclusively waived any unresolved Title Defect, or cure thereof, or any unresolved Title Benefit which is not submitted for resolution as provided in this Section on or before the date one hundred twenty (120) days after the end of the Cure Period applicable to Title Defects. The matter to be arbitrated shall be submitted to a title attorney licensed to practice in the state in which the applicable Property is located selected by the Seller and the Buyer, in the case of a Title Defect or Title Benefit, or to an environmental expert in the state in which the applicable Property is located selected by the Seller and the Buyer, in the case of an Environmental Defect (each such title attorney or environmental expert hereinafter, a “Consultant”). If the Seller and the Buyer are unable to agree on any Consultant within thirty (30) days after receipt of the initiating notice, then the Seller on the one hand and the Buyer on the other hand will each appoint one Consultant within ten (10) days thereafter and the two Consultants so appointed will appoint a third Consultant within ten (10) days after the second Consultant is appointed, and the three Consultants so appointed will resolve such matter. The cost of each Consultant shall be paid fifty percent (50%) by the Seller and fifty percent (50%) by the Buyer. The Seller and the Buyer shall each present to the Consultant(s), with a simultaneous copy to the other Party, a single written statement of its position on the defect or benefit in question,

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together with a copy of this Agreement and any supporting material that such Party desires to furnish, not later than the fifth (5th) Business Day after appointment of the Consultant(s). In making their determination, the Consultant(s) shall be bound by the terms of this Agreement and, without any additional or supplemental submittals by either Party, may consider available legal and industry matters as in their opinion are necessary or appropriate to make a proper determination. By the twentieth (20th) day following the submission of the matter to the Consultant(s), applying the principles set forth in this Section 2.1, the Consultant(s) shall make a determination of the matter submitted. The decision of the Consultant(s) shall be in writing and conclusive and binding on the Seller and the Buyer and shall be enforceable against the Parties in any court of competent jurisdiction. The Consultant(s) shall act as experts for the limited purpose of determining the specific title or environmental dispute presented to them, shall not act as arbitrators, may not hear or decide any matters except the specific title or environmental disputes presented to them and may not award damages, interest, costs or penalties to either Party.

2.1.12 If the Parties have mutually agreed upon (or the Consultant(s) shall have finally determined) the amount of any Purchase Price adjustment required to be made pursuant to the terms of this Section 2.1 in respect of a Title Benefit or in respect of an Title Defect or Environmental Defect that the Seller have elected not to cure or that otherwise remains uncured after expiration of the respective Cure Period, in each case, (a) prior to the date the Closing Statement is initially delivered by the Seller to the Buyer pursuant to Section 2.7, then such amount will be included in the Purchase Price adjustments to be made at Closing in accordance with the Closing Statement, or (b) after the foregoing date but prior to the date the Final Statement is initially delivered by the Seller to the Buyer pursuant to Section 2.8, then such amount will be included in the Purchase Price adjustments to be made after Closing in accordance with the Final Statement, or (c) after both such dates, then such amount will be paid after the Closing in accordance with Section 2.9.

2.2. Preferential Purchase Rights; Required Consents. Within ten (10) Business Days (two (2) Business Days in the case of SUSA) after the Execution Date, the Seller shall provide any required notifications of a preferential purchase right, right of first refusal or other agreement which gives a Third Party a right to purchase a Real Property Interest or Well (or any part thereof) (“PPR”), requesting waivers thereof, in connection with the transactions contemplated hereby and otherwise in material compliance with the contractual provisions applicable to such PPR. Within ten (10) Business Days (two (2) Business Days in the case of SUSA) after the Execution Date, the Seller will send letters seeking (a) the SUSA consents, agreements and waivers described in Sections 6.4 and 7.5 and (b) all applicable Required Consents, excluding Customary Post-Closing Consents. The Seller will thereafter use commercially reasonable efforts (at no cost to the Seller) to ensure

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that all such waivers and consents are promptly granted, and after Closing, the Buyer will reasonably assist the Seller in obtaining any remaining waivers and consents.

2.2.1 If, as of the Closing Date, (i) a holder of a PPR has notified the Seller that it elects to exercise its PPR with respect to the Properties (or portions thereof) to which its PPR applies (determined by and in accordance with the agreement under which the PPR arises), or (ii) no waiver, consent or exercise notice has been received by the Seller from the holder of a PPR but the time for exercising such PPR has not expired, then in each such case the Properties (or portions thereof) covered by the applicable PPR will not be sold to the Buyer (subject to the remaining provisions in this Section 2.2), and the Purchase Price will be reduced by the Allocated Value of the Properties (or portions thereof) subject to such PPR. If, as of the Closing Date, a holder of a Required Consent has not yet delivered such Required Consent, then the Properties (or portions thereof) covered by that Required Consent (i) will not be conveyed to the Buyer at Closing but shall still be considered part of the Properties in accordance with the provisions of Section 2.2.2, (ii) adjustments to the Purchase Price will still be made pursuant to Sections 2.5 and 2.6 with respect to such Property, and (iii) the Purchase Price will not be reduced as a result of such non-conveyance.

2.2.2 If Properties (or portions thereof) have been excluded from the Properties sold to the Buyer at the Closing (i) due to a pre-Closing exercise of a PPR, and if for any reason the purchase and sale of such Properties is not or cannot be consummated with the holder of such PPR that exercised such PPR and the Seller is thereby permitted to transfer such Properties (or portions thereof) to the Buyer pursuant to the terms of such PPR, or (ii) due to the Seller having not received a waiver, consent or exercise notice from the holder of a PPR and the time for exercising such PPR had not expired as of the Closing Date, and if the Seller subsequently receives such a waiver or consent, or if the Seller does not receive an exercise notice from the holder of the PPR with in the period for exercising such PPR, then in each such case the Seller shall so notify the Buyer and, within ten (10) Business Days after the Buyer’s receipt of such notice, the Seller shall sell, assign, and convey to the Buyer and the Buyer shall purchase and accept from the Seller such Properties pursuant to the terms of this Agreement and for the Allocated Value of such Properties, subject to adjustments in accordance with Sections 2.5 and 2.6. If Properties (or portions thereof) have been excluded from the Properties conveyed to the Buyer at the Closing due to the Seller having not received a Required Consent as of the Closing Date in accordance with Section 2.2.1, and if the Required Consent has been received or deemed received pursuant to the terms of the underlying agreement on or before the one (1) year anniversary of the Closing Date, then in each such case the Seller shall so notify the Buyer and, within ten (10) Business Days after the Buyer’s

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receipt of such notice, the Seller shall assign and convey to the Buyer and the Buyer shall accept from the Seller such Properties pursuant to the terms of this Agreement. As between the Buyer and the Seller, with respect to any Property for which a Required Consent has not been obtained by the Closing, (a) the Seller shall hold such Property as nominee for the Buyer, effective as of the Effective Time, (b) the Buyer shall pay any costs and expenses associated with that Property, and (c) the Seller shall pay the Buyer any revenues received by the Seller that are associated with such Property for time periods from and after the Effective Time. If any Required Consent has not been received or deemed received on or before the one (1) year anniversary of the Closing Date, then the Seller shall no longer hold such Property as nominee for the Buyer, and each Party shall repay to the other Party any amounts previously paid hereunder in respect of the Property, and such Property will be deemed not to have been conveyed to the Buyer hereunder and shall be an Excluded Asset. From the Closing until the date of conveyance (or until the one year anniversary, if not to be conveyed pursuant to this Section 2.2.2 due to expiration of such period), with respect to those Properties not conveyed at Closing solely pursuant to Section 2.2.1 and which Seller continues thereafter to operate, Seller will continue to conduct its operations with respect to such Properties consistent with the provisions of Section 5.2, subject to the caveats and liability limitations contained therein.

2.2.3 Properties excluded pursuant to this Section 2.2 will not be deemed to be affected by Title Defects or be subject to Section 2.1.

2.3. Gas Imbalances. The Purchase Price will be adjusted upward or downward, as applicable, by (a) the net mcf amount of the Seller’s aggregate wellhead gas imbalances as of the Effective Time multiplied by $2.75 per mcf (upward for underage and downward for overage); and (b) the mmbtu amount of any pipeline imbalances or unsatisfied throughput obligations attributable to the Seller or the Properties as of the Effective Time multiplied by $2.75 per mmbtu (upward for over deliveries and downward for under deliveries).

2.4. Casualty Loss. If, after the Execution Date but prior to the Closing Date, any portion of the Properties is damaged, destroyed or taken by condemnation or eminent domain or suffers a reduction in value as a result of a Casualty (a “Casualty Loss”), the Buyer will nevertheless be required to close and the Purchase Price will be adjusted in an amount equal to the lesser of (a) the Allocated Value of the Property affected by such Casualty Loss or (b) the amount of such Casualty Loss.

2.5. Certain Upward Adjustments. The Purchase Price shall be increased by the following (without duplication): (a) the value of all merchantable allowable oil or other liquid Hydrocarbons in storage above the pipeline connection at the Effective Time that is credited to the Properties in accordance with gauging and other customary industry procedures, such value to be the current market price at

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the Effective Time, less taxes and gravity adjustments deducted by the purchaser of such oil or other liquid Hydrocarbons; (b) the amount of all expenditures incurred and paid by or on behalf of the Seller in connection with the ownership, operation and maintenance of the Properties (including rentals, overhead, royalties, prepayments, operating, drilling and completion costs and other charges and expenses billed under applicable operating agreements) attributable to the period on or after the Effective Time, excluding any such amounts to cure or remediate any Title Defect or Environmental Defect; (c) all expenses of the type referenced in (b) paid by or on behalf of the Seller in connection with unleased interests and incurred subsequent to the Effective Time; (d) the amount of any proceeds from the sale of Hydrocarbons produced prior to the Effective Time from the Properties that are received by Buyer on behalf of the unleased interests; and (e) any other amount agreed upon by the Buyer and the Seller, or otherwise required to be reflected pursuant to the other provisions of this Section 2.

2.6. Certain Downward Adjustments. The Purchase Price shall be decreased by the following (without duplication): (a) the amount of any proceeds actually received by the Seller from the sale of Hydrocarbons produced from and after the Effective Time from the Properties (net of royalties and other burdens, and production, severance, sales, use and similar Taxes measured by or payable out of production; provided, that on oil the amount shall be the amount paid by the purchaser to the Seller) net of marketing fees; (b) the amount equal to all unpaid ad valorem, property, production, severance and similar Taxes (excluding income, capital gains, franchise or similar Taxes) based upon or measured by the ownership of the Properties or the production of Hydrocarbons therefrom or the receipt of proceeds attributable thereto, which accrue to or are chargeable against the Properties in accordance with GAAP prior to the Effective Time, which amount shall, to the extent not actually assessed or known, be computed based upon such Taxes for the immediately preceding calendar year, or, if such Taxes are assessed on other than a calendar year basis, for the Tax period last ended; (c) the amount of all unpaid costs and expenditures in connection with the ownership, operation and maintenance of the Properties (including rentals, overhead, royalties, prepayments, operating, drilling and completion costs and other charges and expenses billed under applicable operating agreements) attributable to periods prior to the Effective Time and that are subsequently paid by or on behalf of Buyer; (d) the amount of any proceeds of the type referenced in (a) attributable to periods after the Effective Time received by Seller on behalf of the unleased interests; (e) all expenses of the type referenced in (c) paid by or on behalf of the Buyer in connection with unleased interests and incurred prior to the Effective Time; and (f) any other amount agreed upon by the Buyer and the Seller, or otherwise required to be reflected pursuant to the other provisions of this Section 2.

2.7. Closing Date Estimates. On or before three (3) Business Days prior to the Closing Date, the Seller (with the cooperation of the Buyer) will prepare, in accordance with the provisions of this Agreement, and deliver to the Buyer a statement (the “Closing Statement”) setting forth each adjustment to the

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Purchase Price required under this Agreement (except as otherwise set forth in Section 2.1.12) and showing the calculation of such adjustments. The Closing Statement will be used to adjust the Purchase Price at Closing. Any final adjustments, if necessary, will be made pursuant to Section 2.8 of this Agreement.

2.8. Final Accounting. On or before one hundred twenty (120) days after the Closing Date, the Seller (with the cooperation of the Buyer) will prepare, in accordance with the provisions of this Agreement, and deliver to the Buyer, a post-closing statement setting forth a detailed calculation of all final adjustments to the Purchase Price which takes into account all such adjustments provided in this Agreement (except as otherwise set forth in Section 2.1.12) (the “Final Statement”). If the Buyer disputes any items in or the accuracy and completeness of the Final Statement, then as soon as reasonably practicable, but in no event later than fifteen (15) days after its receipt of the Final Statement, the Buyer will deliver to the Seller a written exception report containing any changes the Buyer proposes to be made to the Final Statement. If the Buyer fails to deliver such exception report to the Seller within that period, the Final Statement as delivered by the Seller will be deemed to be true and correct, binding upon and not subject to dispute by any Party. If the Buyer delivers a timely exception report, as soon as reasonably practicable, but in no event later than thirty (30) days after the Seller receives the Buyer’s exception report, the Parties will meet and undertake to agree on the final post-Closing adjustments to the Purchase Price. If the Parties fail to agree on the final post-Closing adjustments within sixty (60) days after the Seller’s receipt of the Buyer’s exception report, any Party will be entitled to submit the dispute for resolution by the Accounting Referee. The cost of the Accounting Referee shall be paid fifty percent (50%) by the Seller and fifty percent (50%) by the Buyer. The Seller and the Buyer shall each present to the Accounting Referee, with a simultaneous copy to the other Party, a single written statement of its position on the dispute in question, together with a copy of this Agreement, the Closing Statement, the proposed Final Statement, and the Buyer’s written exception report and any supporting material that such Party desires to furnish, not later than ten (10) Business Days after appointment of the Accounting Referee. In making its determination, the Accounting Referee shall be bound by the terms of this Agreement and, without any additional or supplemental submittals by either Party, may consider such other accounting and financial standards matters as in its opinion are necessary or appropriate to make a proper determination. The Parties shall direct the Accounting Referee to resolve the disputes within thirty (30) days after receipt of the written statements submitted for review and to render a decision in writing based upon such written statements. The Accounting Referee shall act as an expert for the limited purpose of determining the specific Final Statement dispute presented to it, shall not act as an arbitrator, shall not consider any other disputes or matters and may not award damages, interest, costs or penalties to either Party. In addition, the Accounting Referee shall agree in writing to keep strictly confidential the specifics and existence of such dispute as well as all proprietary records of the Parties reviewed by the Accounting Referee in the process of resolving such dispute. Upon agreement of the Parties to the adjustments to the

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Final Statement, or upon resolution of such adjustments by the Accounting Referee, as the case may be, the Final Statement (as adjusted pursuant to such agreement or resolution by the Accounting Referee) will be deemed final and binding on all of the Parties and the aggregate amount due to either the Buyer or the Seller pursuant to such Final Statement will be paid in accordance with Section 2.9. If any Properties are assigned to Buyer after Closing or re-assigned to Seller in each case pursuant to Section 2.1.2 or 2.2.2, any such finally determined adjustments with respect to the Properties so assigned or re-assigned will be reflected in the amounts paid by Buyer in the event of such an assignment or refunded/unwound in the event of such a re-assignment.

2.9. Payments. Payments to be made following the Closing under this Section 2 shall be made (i) except as otherwise set forth in Section 2.1.12, within five (5) Business Days after the final determination is made that such payments are due and payable and (ii) by wire transfer of immediately available funds (pursuant to wire transfer instructions designated in advance by the receiving Party to the paying Party writing) for the account of the receiving Party.

2.10. Administration of Unleased Accounts. Until the date five (5) years after the Effective Time, the Seller shall retain all rights to the unleased owner joint interest billing account balances (the “Unleased A/R”) and unleased owner revenue account balances (the “Unleased Revenue”), as of the Effective Time (the Unleased A/R and the Unleased Revenue are collectively referred to herein as the “Unleased Accounts”). For a period of five (5) years following the Effective Time, the Seller shall retain the Unleased Accounts pursuant to this section, and the Seller shall be entitled to all proceeds recovered by the Buyer from unleased owners with Unleased A/R (up to the full Unleased A/R account balance for each such owner as of the Effective Time) as a result of any purchase of unleased property, mineral leasing or payment of a revised joint interest billing by any such Person (including Buyer) following a unit reduction. The Seller shall retain a copy of any decks related to the Unleased Accounts as of the Effective Time, and the Buyer agrees to provide the Seller quarterly updates regarding the Buyer’s purchase, leasing, unit reduction and revised joint interest billing activities affecting the Unleased Accounts. The Buyer further agrees to promptly deliver to the Seller all resulting proceeds on a quarterly basis. The Seller shall thereafter deliver to the Buyer corresponding Unleased Revenue that is then due to any Person (including Buyer) on account of payment by the Buyer to the Seller of such proceeds. Upon receipt of any Unleased Revenue, the Buyer shall assume all payment obligations relating to such Unleased Revenue and shall be liable for the payment thereof to the proper Persons. The Seller waives any and all rights to the Unleased A/R and Unleased Revenue from and after the five (5) year anniversary of the Effective Time, and at such time the Seller shall deliver all Unleased Revenue not previously delivered hereunder and supply all necessary data, and the Buyer shall assume all payment obligations and shall be responsible and liable for the payment thereof to the proper Persons.

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2.11. Tax Allocation. The Seller and the Buyer shall cooperate in the preparation of Internal Revenue Service Form 8594 to report the allocation of the Purchase Price among the Properties. The Buyer shall prepare and deliver to the Seller a draft Form 8594 within twenty (20) days after the determination of the Final Statement and any further adjustments to the Purchase Price relative to title or environmental issues pursuant to this Agreement. If the Seller disputes any items in the Buyer's draft Form 8594, then as soon as reasonably practicable, but in no event later than twenty (20) days after receipt of such draft Form 8594, the Seller will deliver to the Buyer a written exception report containing any changes the Seller proposes to be made to the Form 8594. The Parties agree to use reasonable efforts to reach an agreement on any and all disputed items in the draft Form 8594 within twenty (20) days after the later of the Seller’s receipt of the Buyer's draft Form 8594 or Buyer's receipt of any exceptions timely submitted by the Seller; provided, however, that if the Parties are unable to agree upon a final Form 8594, then the Parties agree to engage an Accounting Referee to resolve such dispute in accordance with the procedures set forth in Section 2.8 of this Agreement.

3.Seller’s Representations and Warranties. The Seller represents and warrants to the Buyer, as of the date of this Agreement, as follows:

3.1. Organization and Good Standing. The Seller is duly formed, validly existing and in good standing under the laws of the State of its formation. Seller is duly qualified and/or licensed, as may be required, to do business as a foreign limited liability company or corporation, as applicable, in and is in good standing in the State of West Virginia and the Commonwealth of Pennsylvania.

3.2. Legal Requirements. The Seller has all requisite power and authority to own and operate its Properties as now being operated by the Seller and to carry on its business as now conducted. Except as set forth on Schedule 3.2, no consent, approval, or authorization of, or designation, or filing with, any Governmental Authority is required on the part of Seller in connection with the valid execution and delivery of the Transaction Documents or the consummation of transactions they contemplate, except the filing and other requirements of the HSR Act, if applicable, and any Customary Post-Closing Consents.

3.3. No Breach. Except as disclosed in Schedule 3.3, the execution, delivery, performance of the Transaction Documents and the consummation of the transactions they contemplate do not and will not: (a)(i) violate, conflict with or constitute a default or an event that, with notice or lapse of time or both, would be a default, breach, or violation under any term or provision of any governing document of the Seller or (ii) any instrument, agreement, contract, commitment, license, promissory note, indenture, mortgage, deed of trust, lease or other arrangement to which the Seller is a party or by which the Seller or its interest in any of the Properties is bound; (b) violate, conflict with or constitute a breach of any Law applicable to the Seller or by which the Seller or its interest in any of the Properties is bound; or (c) except with respect to Permitted Encumbrances, result in the creation, imposition or continuation of any Lien on or affecting the Seller’s

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its interest in the Properties or give rise to any right of early termination, cancellation or acceleration under any of the terms, conditions or provisions of any Real Property Interests, Contracts, note, bond, mortgage or indenture to which the Seller is a party or by which the Seller or its Properties may be bound; except where the conflict, violation, breach, default, creation, imposition, continuation or arisen right would not constitute a Material Adverse Effect.

3.4. Litigation. Except as disclosed in Schedule 3.4, (a) there are no Proceedings or arbitration proceedings pending or, to the Seller’s Knowledge, threatened in writing against the Seller or, to Seller’s Knowledge, for which Seller would be liable involving its interest in the Properties or, if applicable, the operation by the Seller thereof or questioning the validity of or seeking to prevent the consummation of this the Transaction Documents or any other action taken or to be taken in connection therewith, and (b) there are no Proceedings or investigations pending or, to the Seller’s Knowledge, threatened before or by any Governmental Authority involving its interest in the Properties or, if applicable, the operation by the Seller thereof or questioning the validity of or seeking to prevent the consummation of Transaction Documents or any other action taken or to be taken in connection therewith. To the Seller’s Knowledge, there exist no unsatisfied judgments of any Governmental Authority that would result in impairment or loss of the Seller’s interest in any part of the Properties.

3.5. Taxes. Except as disclosed in Schedule 3.5, to the Seller’s Knowledge, all Taxes based on or measured by the Seller’s ownership of property comprising its interest in the Properties or the production or removal of Hydrocarbons or the receipt of proceeds therefrom (including applicable escheatment requirements) have been timely paid when due and are not in arrears. The Seller is neither a “foreign person” within the meaning of Section 1445 of the Code nor a disregarded entity within the meaning of Section 1.1445-2(b)(2)(iii) of the United States Treasury Regulations promulgated under the Internal Revenue Code of 1986, as amended.

3.6. Permits. The Seller (a) has obtained all of its Permits, except where the absence of which, singly or in the aggregate, would not have a Material Adverse Effect, and (b) is not in violation with respect to or in default under, nor to the Seller’s Knowledge has it received any written notice from any Governmental Authority of any violation with respect to or any default under, any of its Permits that has not been (or will not be prior to Closing) corrected or settled, except where the violation or default would not have a Material Adverse Effect.

3.7. Compliance with Laws. During the period that the Seller or its Affiliates have operated any of the Properties and, to the Seller’s Knowledge, during the period any Third Party has operated any of the Properties, those Properties have been operated in compliance with the provisions and requirements of all applicable Laws (other than Environmental Laws), except for prior instances of non-compliance that have been fully and finally resolved to the satisfaction of all Governmental Authorities with jurisdiction over such matters.

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3.8. Contracts.

3.8.1 Excluding the Development Agreement, joint operating agreements (except as otherwise set forth in subpart (i) below), and oil, gas and mineral leases, the Seller has listed in Schedule 3.8: (a)  all farm-in, farm-out, exploration, development, participation, joint venture, partnership, area of mutual interest, purchase and/or acquisition Contracts, Contracts containing options to acquire any of the Properties, Contracts containing obligations not to compete, and any other similar Contracts, in the case of each of the foregoing, of which any terms remain executory which relate to or affect its interest in any of the Properties and which will be binding on the Buyer after Closing; (b) all material Hydrocarbon purchase and/or sale Contracts, gathering Contracts, processing Contracts, transportation Contracts, marketing Contracts, treating Contracts and all other similar material Contracts affecting its interest in any of the Properties which are not, by the terms thereof, subject to termination (without penalty) upon sixty (60) days or less notice; (c) all material water, sourcing, impoundment, storage, disposal or injection Contracts; (d) all production payments or net profits interests burdening its interest in any of the Properties; (e) all Contracts relating to the Properties that can reasonably be expected to result in aggregate payments by or revenues to the Seller of more than $200,000 during any calendar year; (f) all Contracts that constitute a lease under which the Seller is the lessor or the lessee of real or personal property, which lease cannot be terminated by the Seller without penalty upon thirty (30) days or less notice and involves an annual base rental of more than $200,000; (g) Contracts containing calls on production, if any; (h) all Contracts with any Affiliate of the Seller; (i) joint operating agreements that contain any of the contractual provisions expressly described in subparts (a), (b), (d), (g) or (h) above, and which provisions are not customary and generally considered unusual to be included within a joint operating agreement; and (j) all coal disturbance agreements or other agreements regarding the accommodation of coal mining operations or gas storage operations, in each case, which are not, by the terms thereof, subject to termination (without penalty) upon sixty (60) days or less notice (the Contracts required to be listed in Schedule 3.8, together with the Development Agreement but only if the Buyer partially assumes the Development Agreement as and only to the extent described in Sections 5.14, 6.4 and 7.5, collectively, the “Material Contracts”).

3.8.2 The Seller has made available or caused to be made available to Buyer true, correct and complete copies of the Material Contracts and all amendments thereto, but excluding a copy of the Development Agreement (except if and when a copy is required to be provided by Seller pursuant to Section 5.14). The Seller is not in default of any of its material obligations under any

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Material Contract and, to the Seller’s Knowledge, has not received written notice of its being in breach of or default under any Material Contract. All Material Contracts to which the Seller is a party are valid and binding upon the Seller and, to the Seller’s Knowledge, each Material Contract is in full force and effect and enforceable against the other parties thereto. To the Seller’s Knowledge, no other party to any such Material Contract is in material default thereunder. To the Seller’s Knowledge, no currently effective notices have been received by the Seller of the exercise of any premature termination, price redetermination, market-out or curtailment under any Material Contract.

3.9. Environmental and Safety Matters. Insofar as it pertains to the Properties, except as set forth in Schedule 3.9:

3.9.1 During the period that the Seller has operated any of the Properties and, to the Seller’s Knowledge, during the period any other party operated any of the Properties, such Properties have been operated in material compliance with all applicable Environmental Laws and with the terms and conditions of all environmental Permits, except for prior instances of non-compliance that have been fully and finally resolved to the satisfaction of all Governmental Authorities with jurisdiction over such matters.

3.9.2 There are no Proceedings relating to an alleged breach of Environmental Laws on or with respect to the Properties, and the Seller has not received any written notice of any environmental, health or safety claim, demand, filing, investigation, administrative proceeding, or other Proceeding relating to the Properties (an “Environmental Claim”) or notice of any alleged or actual violation or non-compliance with any Environmental Law or of non-compliance with the terms or conditions of any environmental permits, arising from, based upon, associated with or related to the Properties or the ownership or operation of any thereof.

3.9.3 During the period that the Seller has operated any of the Properties and, to the Seller’s Knowledge, during the period any other party operated any of the Properties, no pollutant, waste, contaminant or hazardous, extremely hazardous or toxic material, substance, chemical or waste identified, defined or regulated under any Environmental Law is present or has been handled, managed, stored, transported, processed, treated, disposed of, released, migrated or escaped on, in, from, under or in connection with the Properties or the ownership or operation of any thereof, such as to cause a condition or circumstance that would reasonably be expected to result in an Environmental Claim or a violation of an Environmental Law.

3.10. Authority. The Seller has taken all necessary action to authorize the execution, delivery and performance of the Transaction Documents to which it is a party and has adequate power, authority and legal right to enter into, execute, deliver and perform such Transaction Documents and to consummate the transactions they contemplate. This Agreement is, and upon delivery at the Closing as contemplated by this Agreement the other Transaction Documents will be, legal,

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valid and binding with respect to the Seller and enforceable in accordance with its terms, except as the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditors’ rights generally.

3.11. Broker’s or Finder’s Fees. The Seller has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees in respect of the transactions contemplated by the Transaction Documents for which the Buyer will have any responsibility whatsoever.

3.12. Bankruptcy. There are no bankruptcy, reorganization or arrangement proceedings pending, being contemplated by or, to the Seller’s Knowledge, threatened against the Seller or any Affiliate of the Seller.

3.13. Preferential Purchase Rights and Required Consents. Except as set forth in Schedule 3.13, no interest of the Seller in a Property is subject to any preferential right of purchase, right of first refusal or other agreement which gives a Third Party the right to purchase any interest of the Seller in a Property or Required Consent of any Third Party to the sale and conveyance of the Seller’s interest in the Properties as provided for in this Agreement.

3.14. Gas Balancing. Except as set forth in Schedule 3.14, the Seller has no obligation to deliver gas (or cash in lieu thereof) from its interest in the Properties to other owners of interest as a result of past production by the Seller or its predecessors in excess of the share to which they are entitled, nor any right to receive deliveries of gas (or cash in lieu thereof) with respect to its interest in the Properties from other owners of interest as a result of past production by the Seller or its predecessors of less than the share to which they were entitled.

3.15. Payment of Royalties and Expenses. Except for such items that are being held in suspense as permitted pursuant to applicable Laws and the Unleased Revenue, the Seller has paid or caused to be paid all rentals, delay rentals, shut-in royalties, royalties, overriding royalties and other burdens upon, measured by or payable out of production, and other payments, in each case, due by the Seller under, with respect to or in connection with the ownership and/or operation of the Seller’s Properties or, if not paid, is contesting the same in good faith in the normal course of business.

3.16. Current Commitments. Except for the continuing operations and other matters set forth in Schedule 3.16, the Seller is not legally obligated for any future commitments requiring an expenditure by the Seller in excess of Two Hundred Thousand Dollars ($200,000.00) (net to the Seller’s interest) relating to any of the Properties.

3.17. Advance Payments. Except as set forth in Schedule 3.17, the Seller is not obligated by virtue of any take or pay payment, advance payment or other similar payment (other than gas balancing arrangements) to deliver Hydrocarbons, or

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proceeds from the sale thereof, attributable to the Properties at some future time without receiving payment therefor at or after the time of delivery.

3.18. Condemnation. The Seller has not received any written notice of any pending or threatened condemnation of any portion of its Properties.

3.19. Payout Balances. Schedule 3.19 contains a list, which is complete and accurate in all material respects, of the status of the Payout Balance, as of the Effective Time, for each Well in which the Seller has an interest. “Payout Balance” means the status, as of the dates of the calculations, of the recovery by the Seller or a third party of a cost amount specified in the contract relating to a well out of the revenue from such well where the net revenue interest of the Seller therein will be reduced or the working interest therein will be increased when such amount has been recovered.

3.20. Compliance with Anti-Bribery Laws. The Seller is not in violation of and no event has occurred or that would constitute a violation of any applicable State or Federal statute prohibiting bribery in any form.

4.Buyer’s Representations and Warranties. The Buyer represents and warrants to the Seller, as of the date of this Agreement, as follows:

4.1. Organization and Good Standing. The Buyer is duly formed, validly existing and in good standing under the laws of the State of Texas. The Buyer has the power and authority to acquire and own the Properties and to conduct business in the Commonwealth of Pennsylvania and the State of West Virginia.

4.2. Powers. The Buyer is duly authorized and empowered to execute, deliver and perform the Transaction Documents to which it is, or will be, a party and to consummate the transactions they contemplate. Neither the certificate of formation nor the bylaws of the Buyer, nor any other instrument to which the Buyer is a party or is bound, nor any court order or governmental law, rule or regulation, will be violated by the Buyer’s execution and consummation of the Transaction Documents.

4.3. No Restriction. The Buyer is not subject to any order, judgment or decree, or the subject of any litigation, claim or Proceeding, pending or threatened or any other restriction of any kind or character specific to the Buyer (other than restrictions imposed by the HSR, if applicable), which would affect the Buyer’s ability to carry out the transactions contemplated by the Transaction Documents.

4.4. Authorization. The Buyer has taken all necessary action to authorize the execution, delivery and performance of the Transaction Documents to which it is, or will be, a party and has adequate power, authority and legal right to enter into, execute, deliver and perform such Transaction Documents and to consummate the transactions they contemplate. This Agreement is, and upon delivery at the Closing as contemplated by this Agreement the other Transaction Documents will be, legal, valid and binding with respect to the Buyer and enforceable in

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accordance with its terms, except as the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditors’ rights generally.

4.5. No Breach. The execution, delivery, performance, and consummation of the Transaction Documents and the transactions they contemplate do not and will not: (a) violate any provision of any governing document of the Buyer; or (b) breach or violate, or result (with notice or lapse of time or both) in the breach, violation, acceleration or termination of, any contract, indenture, Lien, note, lease, agreement, license or Law to which the Buyer is subject or by which any of its assets are bound or subject, except, with respect to any such breach, violation, acceleration or termination which would not reasonably be expected to prevent the consummation of the transactions contemplated hereby by the Buyer or result in the Seller incurring any loss or liability therefrom.

4.6. Governmental Consent. No consent, approval, or authorization of, or designation, or filing with, any Governmental Authority is required on the part of the Buyer in connection with the valid execution and delivery of the Transaction Documents to which it is or will be a party or the consummation of transactions they contemplate, except the filing and other requirements of the HSR Act, if applicable, and any Customary Post-Closing Consents.

4.7. Litigation. There are no Proceedings pending or, to the Buyer’s Knowledge, threatened in writing against the Buyer questioning the validity of or seeking to prevent the consummation of the Transaction Documents or any other action taken or to be taken in connection herewith, or which would have a material adverse effect on the Buyer or its ability to consummate the transactions contemplated hereby.

4.8. Broker’s or Finder’s Fees. The Buyer has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees in respect of the transactions contemplated by the Transaction Documents for which the Seller will have any responsibility whatsoever.

4.9. Qualifications. On the Closing Date the Buyer will be qualified with all applicable Governmental Authorities to own and operate the Properties.

4.10. Bankruptcy. There are no bankruptcy, reorganization or arrangement proceedings pending, being contemplated by or, to the Buyer’s Knowledge, threatened against the Buyer or any Affiliate of the Buyer.

4.11. Funding; Investment. On the Closing Date the Buyer will have available (through cash on hand or existing credit arrangements or otherwise) all of the funds necessary for the acquisition of all of the Properties pursuant to the Transaction Documents, as and when needed, and to perform its obligations thereunder. The Buyer is experienced in and knowledgeable about the oil and gas business and the acquisition of oil and gas properties and the Buyer is aware of the risks of such investments. The Buyer acknowledges that the Seller has not made any

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representation or warranty, expressed or implied, as to the accuracy or completeness of any information regarding the Properties except as expressly set forth in the Transaction Documents, and the Seller shall have no liability to the Buyer or any of the Buyer’s successors or assigns for its reliance on any information regarding the Seller or the Properties that is not contained in the Transaction Documents. The Buyer is acquiring the Properties for its own account and not with the intent to make any distribution of undivided interests thereof which would violate any applicable Laws.

4.12. Compliance with Anti-Bribery Laws. The Buyer is not in violation of and no event has occurred or that would constitute a violation of any applicable State or Federal statute prohibiting bribery in any form.

5.Covenants. The Parties hereby covenant and agree to perform the following:

5.1. Access to Properties and Information. Buyer will have the opportunity to conduct, prior to the Defect Notice Date and at its sole risk and expense, an environmental assessment of the Properties, including a Phase I assessment as that term is defined by the ASTM E1527-13 All Appropriate Inquiry Standard. Seller will provide reasonable access for this purpose to Properties operated by Seller. Notwithstanding anything herein to the contrary, Buyer shall not conduct any ASTM Phase II environmental review or any test drilling or sampling or other invasive activities without prior notice to and consent of Seller (which notice shall be sent at least fifteen (15) daysprior to the Defect Notice Date, and which consent Seller may give or withhold in its sole discretion, and which consent will be considered denied by Seller if Seller fails to respond within five (5) Business Days after receiving such notice). Buyer shall provide Seller with a minimum of three (3) Business Days’ advance notice of its proposed environmental assessment activities prior to entering the Property to be assessed and Buyer shall (a) coordinate the conduct of such environmental assessment with Seller’s representatives, (b) not interfere with the normal operation of the Properties, and (c) comply with all applicable Laws and all requirements and safety policies of Seller and, if Seller is not the operator of the Properties, the operator of the Properties. If Buyer or any of its consultants, agents and representatives prepares an environmental assessment, Buyer will furnish a copy thereof to Seller upon request and (until and unless Closing occurs and Buyer purchases the relevant Properties) will keep (and cause its consultants, agents and representatives to keep) any and all such assessments and reports strictly confidential. In connection with the granting of such access, Buyer represents that it is adequately insured and, except to the extent caused by the gross negligence or willful misconduct of the Seller Indemnified Parties, Buyer waives, releases and agrees to defend and indemnify the Seller Indemnified Parties against any and all claims for injury to, or death of, persons or for damage to property arising in any way from the access afforded to Buyer hereunder or the activities of Buyer related to such access or any environmental assessment. This waiver, release and indemnity by Buyer shall survive termination of this Agreement. If Buyer conducts a Phase I assessment that indicates that a Phase II assessment as that term is defined by

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the ASTM E1903 – 11 should be conducted and if Buyer timely requests the consent of Seller to such a Phase II assessment but Seller’s consent is denied (or deemed denied as provided above), then Buyer may exclude the affected Property from the Transaction Documents, in which case the Purchase Price shall be reduced by an amount equal to the Allocated Value of the affected Property and that Property shall thereafter constitute an Excluded Asset.

Insofar as related to the Properties, the Seller will give to the Buyer and its agents and representatives, reasonable access to all of the Records and the Seller will cause its officers and employees to furnish to the Buyer and its agents and representatives such operating data and other information with respect to the Properties as the Buyer may, from time to time, reasonably request; provided, however, (a) any such investigation will be conducted in such manner as not to interfere unreasonably with the operation of the business of the Seller, and (b) the Seller shall not be required to provide any of the foregoing information to the extent that the Seller is prohibited by any Third Party agreement from sharing such information with the Buyer (provided that the Seller shall use commercially reasonable efforts (at no cost to the Seller) to obtain the consent of such Third Parties to the sharing of such information). Buyer acknowledges that, pursuant to its right of access to the Records, Buyer will become privy to confidential and other information of the Seller and that such confidential information shall not be used for any purpose other than assessing the transactions contemplated by this Agreement and shall be held confidential by Buyer in accordance with the terms of the Confidentiality Agreement. If the Closing should occur, the foregoing confidentiality restriction on Buyer, including those contained in the Confidentiality Agreement to the extent related to the Records, shall terminate (except as to (a) any Properties that are excluded from the transactions contemplated hereby pursuant to the provisions of this Agreement, (b) the Excluded Assets and (c) information related to any assets other than the Properties, which confidentiality obligations shall terminate in accordance with the Confidentiality Agreement).

5.2. Conduct of Business.

5.2.1 From and after the Execution Date until Closing, the Seller will:

(a) to the extent the Seller operates any Properties, operate such Properties as a prudent operator in accordance with all Contracts and all applicable Laws in the Ordinary Course of Business;

(b) maintain its books of account and records relating to the Properties in the usual, regular and ordinary manner, in accordance with the usual accounting practices of the Seller and GAAP;

(c) pay, as they become due, that portion of the expenses related to the Properties that are attributable or allocated to the Seller’s interest in the Properties, except for amounts contested in good faith;

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(d) notify Buyer of any election that the Seller is required to make under any Contract, specifying the nature and time period associated with such election, and consult with the Buyer (and attempt in good faith to reach a mutually acceptable agreement with the Buyer regarding such election);

(e) notify Buyer, in a timely manner, of any Real Property Interest expirations or intention not to conduct any continuous drilling or other operations obligations that would result in any termination or expiration of any Real Property Interest prior to the Closing Date, and consult with the Buyer (and attempt in good faith to reach a mutually acceptable agreement with the Buyer regarding actions, if any, to be taken in connection therewith); and

(f) act in a reasonably prudent manner to maintain in full force and effect its Permits.

5.2.2 Except as provided in the Contracts, as required by Law or Permit, or as specifically contemplated by this Agreement, from and after the Execution Date until Closing, the Seller shall not:

(a) convey, encumber (except for Permitted Encumbrances), abandon or otherwise dispose of any part of the Properties, other than: (i) the sale of Hydrocarbons or obsolete machinery and equipment in the Ordinary Course of Business, unless the Buyer shall otherwise consent in writing (such consent not to be unreasonably delayed, conditioned or withheld) or (ii) the assignment of interests to another joint working interest owner to the extent such assignments do not, individually or in the aggregate, reduce the Seller’s Net Revenue Interest or increase the Seller’s Working Interest (without at least a proportionate corresponding increase in the Seller’s Net Revenue Interest) in any Well or Real Property Interest or reduce the Seller’s Net Acres with respect to any Real Property Interest from that shown for the Seller on Exhibit A;

(b) except in emergencies, enter into any material agreement, contract or commitment which, if entered into prior to the Execution Date, would be required to be listed in a Schedule attached to this Agreement, or materially amend or change the terms of, or terminate, extend, violate, breach or default under any such agreement, contract or commitment, or waive any right thereunder, in each case, without first consulting with the Buyer (and attempting in good faith to reach a mutually acceptable agreement with the Buyer regarding such agreement, contract or commitment);

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(c) enter into any transaction, the effect of which would be to reduce the Seller’s NRI in a Property from that shown on Exhibit A; provided, however, for clarity, this Section 5.2.2(c) shall not apply to any decision to become a non-consenting party in any operation proposed with respect to any of the Properties;

(d) become a non-consenting party in any operation proposed with respect to any of the Properties without first consulting with the Buyer (and attempting in good faith to reach a mutually acceptable agreement with the Buyer regarding such election);

(e) relinquish voluntarily its position as operator with respect to any Property without first consulting with the Buyer (and attempting in good faith to reach a mutually acceptable agreement with the Buyer regarding the operatorship of such Property);

(f) except for those existing as of the Execution Date, encumber any Property of the Seller with any Required Consent or PPR in favor of any Third Party; or

(g) waive, compromise or settle any material claim involving the Properties without first consulting with the Buyer (and attempting in good faith to reach a mutually acceptable agreement with the Buyer regarding such claim).

The Buyer acknowledges that the Seller owns an undivided interest in certain of the Properties with respect to which the Seller is not the operator, and Buyer agrees that the acts or omissions of the other Working Interest owners (including the operators) who are not the Seller or an Affiliate of the Seller shall not constitute a breach of the provisions of this Section 5.2, nor shall any action required by a vote of Working Interest owners constitute such a breach so long as the Seller, in either case, has voted its interest in a manner that complies with the provisions of this Section 5.2.

Without expanding any obligations which Seller may have to Buyer, it is expressly agreed that Seller shall never have any liability to Buyer with respect to any breach or failure of Section 5.2 greater than that which it might have as the operator to a non-operator under the applicable operating agreement (or, in the absence of such an agreement, under the AAPL 610 (1989 Revision) form Operating Agreement), IT BEING RECOGNIZED THAT, UNDER SUCH AGREEMENTS AND SUCH FORM, THE OPERATOR IS NOT RESPONSIBLE FOR ITS OWN NEGLIGENCE, AND HAS NO RESPONSIBILITY OTHER THAN FOR GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.

5.3. Revenues Held For Benefit of the Other Party. In the event either (a) the Buyer receives production or other revenues attributable to any of the Properties for any

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periods prior to the Effective Time or (b) the Seller receives production or other revenues attributable to any of the Properties for any periods after the Effective Time, the receiving Party will hold such revenues for the exclusive benefit of the Party entitled thereto and, if not taken into account for purposes of the Final Statement, shall promptly deliver such funds to the appropriate Party.

5.4. Revenues and Expenses. For all purposes, including adjustments to the Purchase Price under Section 2 of this Agreement, the Seller and the Buyer will properly allocate revenues and expenses before and after the Effective Time and will make payments to each other to the extent necessary for such proper allocation. All expenses incurred in the operation of the Properties before the Effective Time will be borne by the Seller and all proceeds from the sale of Hydrocarbons produced from or attributable to the Properties prior to the Effective Time will be the property of the Seller, and all expenses incurred in the operation of the Properties after the Effective Time will be borne by the Buyer and all proceeds from the sale of Hydrocarbons produced from or attributable to the Properties after the Effective Time will be the property of the Buyer. Ad valorem Taxes, property Taxes and other similar obligations will be prorated between the Seller and the Buyer as of the Effective Time.

5.5. Suspended Funds. As part of the final accounting in connection with the Final Statement pursuant to Section 2.8, the Seller will deliver to the Buyer the Suspended Funds along with an “Excel” spreadsheet containing the owner name, owner number, social security or federal ID number, reason for suspense, and the amount of Suspended Funds payable for each entry, together with monthly line item production detail including gross and net volumes and deductions for all suspense entries. Upon receipt of such information, the Buyer shall administer all such accounts and assume all payment obligations relating to the Suspended Funds in accordance with all applicable Laws, and shall be liable for the payment thereof to the proper parties, except that the Seller will retain all responsibility and liability for (a) statutory penalties and interest, if any, owing to any interest owner attributable to the Suspended Funds accruing prior to the Effective Time and (b) penalties and interest, if any, attributable to the Suspended Funds accruing prior to the Effective Time, payable to any state under existing escheat or unclaimed property statutes. If any such penalties or interest are due to the respective suspense account owner or any state under such statutes and the Seller fails to promptly reimburse such sums to the Buyer, then the Buyer shall return to the Seller the Suspended Funds in such account that existed as of the Effective Time, and the Seller shall thereupon assume all obligations for the final payment and settlement of any such claims and accompanying Suspended Funds.

5.6. HSR Act. In the event the Parties determine that filings by the Parties are required under the HSR Act, within ten (10) days following the execution by the Buyer and the Seller of this Agreement, the Buyer and the Seller will each prepare and simultaneously file with the Department of Justice (“DOJ”) and Federal Trade Commission (“FTC”) the notification and report form required for the transactions contemplated by this Agreement by the HSR Act, and request early

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termination of the waiting period thereunder. The Buyer and the Seller agree to respond promptly to any inquiries from the DOJ or the FTC concerning such filings and to comply in all material respects with the filing requirements of the HSR Act. The Buyer and the Seller shall cooperate with each other and, subject to the terms of the Confidentiality Agreement, shall promptly furnish all information to the other Party that is necessary in connection with the Buyer’s and the Seller’s compliance with the HSR Act. The Buyer and the Seller shall keep each other fully advised with respect to any requests from or communications with the DOJ or FTC concerning such filings and shall consult with each other with respect to all responses thereto. Each of the Seller and the Buyer shall use its reasonable efforts to take all actions reasonably necessary and appropriate in connection with any HSR Act filing to consummate the transactions consummated hereby. All filing fees incurred in connection with the filings made pursuant to this Section 5.6 shall be borne by the Buyer.

5.7. Governmental Bonds. Buyer acknowledges that none of the bonds, letters of credit and guarantees, if any, posted by Seller or its Affiliates with Governmental Authorities or other Third Parties and relating to the Properties will be transferred to Buyer. Prior to Closing, Buyer shall post all bonds and other security with all applicable Governmental Authorities (in each case meeting the requirements of such authorities) as are necessary for Buyer to own and operate the Properties. In addition, at or immediately following Closing, Buyer shall replace those bonds, letters of credit and guarantees of Seller or its Affiliates related to the Properties and of which Buyer has been notified by Seller at least ten (10) Business prior to Closing. Thereafter, if either Party identifies any additional bond, letter of credit or guarantee of Seller or its Affiliates related to any Properties and which has not been released, then such Party shall promptly notify the other Party and promptly thereafter Buyer shall replace such bond, letter of credit or guarantee. Promptly following request by Seller, Buyer shall deliver to Seller evidence of Buyer’s posting of the bonds, security, letters of credit and guarantees required to be posted or replaced by Buyer pursuant to this Section 5.7.

5.8. Gathering Agreements.

5.8.1 ATEX Agreement. The Buyer and the Seller will jointly contact Enterprise (defined below) to request Enterprise’s consent to the Seller partially assigning to the Buyer a portion of the Transportation Services Agreement dated November 17, 2011 (the “ATEX Agreement”), between Enterprise Liquids Pipeline LLC (as assigned to Enterprise TE Products Pipeline Company, LLC (“Enterprise”) and CEMI, and if Enterprise refuses to consent to such partial assignment of the ATEX Agreement to Buyer upon terms acceptable to both the Seller and the Buyer in each Party’s sole discretion, the ATEX Agreement will not be assigned to the Buyer, however, the Buyer will be responsible for the volume as detailed in Schedule 5.8.1 (the “Buyer ATEX Volume”) under the ATEX agreement as set forth below. If Enterprise refuses to consent to such partial assignment of the ATEX Agreement to Buyer upon terms

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acceptable to both the Seller and the Buyer in each Party’s sole discretion, prior to Closing, the Buyer will enter into and the Seller will cause CEMI to enter into: (a) a capacity use agreement with Enterprise, wherein the Buyer, as agent for CEMI, transports the Buyer ATEX Volume under the ATEX Agreement and delivers such Buyer ATEX Volume at the delivery points under the ATEX Agreement for sale or marketing by the Buyer; and (b) an agreement detailing CEMI’s and the Buyer’s obligations to each other under the capacity use agreement, including, without limitation, the Buyer’s obligations to reimburse costs and expenses under the ATEX Agreement that are attributable to the Buyer ATEX Volume to CEMI. If Enterprise does not agree to enter into a capacity use agreement with the Buyer and CEMI, then the Buyer will enter into, and Seller will cause CEMI to enter into, a buy-sell agreement, whereby CEMI will purchase the Buyer ATEX Volume at the inlet to the ATEX pipeline and redeliver to the Buyer the Buyer ATEX Volume at any delivery point available (without additional cost and with the Buyer responsible for all ATEX Agreement charges attributable to the Buyer ATEX Volume) to CEMI per the Buyer’s instructions. CEMI will not be responsible for any incremental storage, transfer, or other handling fees the Buyer may be subject to under the buy-sell agreement. Notwithstanding anything to the contrary in this Agreement, if the Buyer is unable to take assignment of the Ethane Purchase Agreement between CEMI and Westlake Petrochemicals LLC dated January 17, 2012 (the “Westlake Agreement”), then the Buyer will sell to CEMI (or CEMI will not sell back to the Buyer if a buy-sell agreement is in effect) the volumes necessary to fulfill the Buyer’s share of the obligations retained by CEMI under the Westlake Agreement at the price in effect under the Westlake Agreement net of midstream fees and deductions.

5.8.2 Consents. Within seven (7) Business Days after the Execution Date, the Seller will send letters seeking consents to the assignment of the Contracts listed on Schedule 5.8.2 (“Midstream Consent Contracts”). The Seller and the Buyer will thereafter use commercially reasonable efforts (at no cost to the Seller) to obtain such consents. At or prior to Closing, the Buyer will use its commercially reasonable efforts to furnish to the Seller a written acknowledgement from the counterparty to each Midstream Consent Contract that (a) any required consent thereunder to assignment of such Midstream Consent Contract has been granted, (b) the Buyer meets the creditworthiness standard, if any, set forth in such Midstream Consent Contract, and (c) upon the Seller’s assignment of such Midstream Consent Contract to the Buyer, the Seller and/or CEMI, as applicable, will be released from all obligations under such Midstream Consent Contracts (with respect to each Midstream Consent Contract, the “Applicable Consent”). The Buyer agrees to supply such guaranties or other credit support necessary to replace the credit support provided by CEMI or its Affiliates or otherwise reasonably required by such counterparty to meet any such creditworthiness standard. If the Buyer is unable or otherwise

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fails to furnish to the Seller at or prior to Closing the Applicable Consent with respect to any Midstream Consent Contract, then, in any such event, such Midstream Consent Contract will not be assigned and, if the applicable Midstream Consent Contract is a gas sales contract, processing contract or similar contract for the sales of hydrocarbons, the Buyer will sell all hydrocarbons currently flowing under such Midstream Consent Contract to CEMI at the receipt points under such Midstream Consent Contract for a price equal to 100% of CEMI’s sale price of such hydrocarbons less the Applicable Deductions (as hereinafter defined), and if the applicable Midstream Consent Contract is a gathering contract, field services contract or other contract for the provision of gathering, transportation, compression or treating services for a fee or rate, CEMI will schedule, nominate and purchase all volumes delivered by Buyer in accordance with such Midstream Consent Contract at the inlet to the applicable system and redeliver to the Buyer the volume or quantity to which CEMI is entitled under the applicable Midstream Consent Contract at any delivery point available (less Applicable Deductions) to CEMI per the Buyer’s instructions, until the earlier of: (i) the termination of such Midstream Consent Contract; (ii) the expiration of the term of such Midstream Consent Contract; or (iii) the counterparties’ consent to the assignment to the Buyer and the release of the Seller and/or CEMI, as applicable, under such Midstream Consent Contract. As used herein, “Applicable Deductions” means (x) during the period from the Closing Date through the end of the second month after the month the Closing occurs, reimbursement to CEMI for all fees and deductions charged to or paid by CEMI in connection therewith (the “Initial Period”); and (y) commencing on the first day of the month following the end of the Initial Period, an amount equal to one and one-half percent (1½ %) of the sales price of such Hydrocarbons plus all midstream fees and deductions charged to or paid by CEMI in connection therewith.

5.8.3 Form of Assignment. Prior to Closing, the Seller and the Buyer will negotiate in good faith mutually acceptable forms of assignment, assumption and, as applicable, and consent and release agreements to effect, in accordance with the terms of this Agreement, the assignments to the Buyer at Closing of the Midstream Consent Contracts (subject to Section 5.8.2) and all other gathering Contracts set forth on Exhibit C (collectively, the “Midstream Agreements” and such assignment, assumption and consent agreements for the Midstream Agreements, collectively, the “Midstream Assignments”). Upon Closing, the Seller will assign (and cause CEMI to assign) its rights and obligations contained in the Midstream Agreements (subject to Section 5.8.2), and the Buyer will assume (and, upon delivery by the Seller of the Assignment, the Buyer shall be deemed to have assumed), and thereafter will be bound by and comply with and perform, all of the obligations of CEMI and the Seller contained in the assigned Midstream Agreements; in such each

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case, from and after the Effective Time and solely to extent pertaining to the Properties. 

5.9. Limitations on Representations and Warranties. EXCEPT FOR THE EXPRESS AND SPECIFIC REPRESENTATIONS AND WARRANTIES OF THE SELLER IN THIS AGREEMENT (AS BROUGHT DOWN BY SELLER’S CERTIFICATE DELIVERED AT CLOSING), THE ASSIGNMENTS OR OTHER TRANSACTION DOCUMENTS (IF ANY) THAT CONTAIN REPRESENTATIONS AND WARRANTIES, THE BUYER ACKNOWLEDGES THAT THE SELLER HAS NOT MADE, AND THE SELLER HEREBY EXPRESSLY DISCLAIMS AND NEGATES, AND THE BUYER HEREBY EXPRESSLY WAIVES, ANY REPRESENTATION OR WARRANTY, EXPRESS, IMPLIED, AT COMMON LAW, BY STATUTE OR OTHERWISE IN ANY WAY RELATED TO THIS AGREEMENT, THE TRANSACTION DOCUMENTS, OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY, INCLUDING RELATING TO (a)PRODUCTION RATES, RECOMPLETION OPPORTUNITIES, DECLINE RATES, GAS BALANCING INFORMATION, OR THE QUALITY, QUANTITY OR VOLUME OF THE RESERVES OF HYDROCARBONS, IF ANY, ATTRIBUTABLE TO THE PROPERTIES OR THE SELLER’S INTEREST THEREIN, (b)THE ACCURACY, COMPLETENESS OR MATERIALITY OF ANY RECORDS, INFORMATION, DATA OR OTHER MATERIALS (WRITTEN OR ORAL) NOW, HERETOFORE OR HEREAFTER FURNISHED TO THE BUYER BY OR ON BEHALF OF THE SELLER, AND (c)THE ENVIRONMENTAL OR OTHER CONDITION OF THE PROPERTIES.

5.9.1 EXCEPT FOR THE EXPRESS REPRESENTATIONS AND WARRANTIES OF THE SELLER IN THIS AGREEMENT (AS BROUGHT DOWN BY SELLER’S CERTIFICATE DELIVERED AT CLOSING), THE ASSIGNMENTS OR OTHER TRANSACTION DOCUMENTS (IF ANY) THAT CONTAIN REPRESENTATIONS AND WARRANTIES, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, THE SELLER EXPRESSLY DISCLAIMS AND NEGATES, AND THE BUYER HEREBY WAIVES, AS TO PERSONAL PROPERTY, EQUIPMENT, INVENTORY, MACHINERY AND FIXTURES CONSTITUTING A PART OF THE PROPERTIES (a) ANY IMPLIED OR EXPRESS WARRANTY OF MERCHANTABILITY, (b) ANY IMPLIED OR EXPRESS WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE, (c) ANY IMPLIED OR EXPRESS WARRANTY OF CONFORMITY TO MODELS OR SAMPLES OF MATERIALS, (d) ANY RIGHTS OF PURCHASERS UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, (e) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM

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DEFECTS, WHETHER KNOWN OR UNKNOWN, (f) ANY AND ALL IMPLIED WARRANTIES EXISTING UNDER APPLICABLE LAW, AND (g) ANY IMPLIED OR EXPRESS WARRANTY REGARDING ENVIRONMENTAL LAWS, THE RELEASE OF SUBSTANCES, WASTES OR MATERIALS INTO THE ENVIRONMENT, OR PROTECTION OF THE ENVIRONMENT OR HEALTH, IT BEING THE EXPRESS INTENTION OF THE BUYER AND THE SELLER THAT THE PERSONAL PROPERTY, EQUIPMENT, INVENTORY, MACHINERY AND FIXTURES IN WHICH THE SELLER HAS ANY INTEREST ARE BEING ACCEPTED BY THE BUYER, “AS IS, WHERE IS, WITH ALL FAULTS” AND IN THEIR PRESENT CONDITION AND STATE OF REPAIR.

5.9.2 THE SELLER AND THE BUYER AGREE THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN WARRANTIES CONTAINED IN THIS SECTION 5.9.3ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSES OF ANY APPLICABLE LAW, RULE OR ORDER.

5.9.3 THE BUYER ACKNOWLEDGES THAT THE PROPERTIES HAVE BEEN USED FOR EXPLORATION, DEVELOPMENT, AND PRODUCTION OF OIL AND GAS AND THAT EQUIPMENT AND SITES INCLUDED IN THE PROPERTIES MAY CONTAIN ASBESTOS, NATURALLY OCCURRING RADIOACTIVE MATERIAL (“NORM”) OR OTHER HAZARDOUS SUBSTANCES. NORM MAY AFFIX OR ATTACH ITSELF TO THE INSIDE OF WELLS, MATERIALS, AND EQUIPMENT AS SCALE, OR IN OTHER FORMS. THE WELLS, MATERIALS, AND EQUIPMENT LOCATED ON THE PROPERTIES OR INCLUDED IN THE PROPERTIES MAY CONTAIN NORM AND OTHER WASTES OR HAZARDOUS SUBSTANCES. NORM CONTAINING MATERIAL AND/OR OTHER WASTES OR HAZARDOUS SUBSTANCES MAY HAVE COME IN CONTACT WITH VARIOUS ENVIRONMENTAL MEDIA, INCLUDING AIR, WATER, SOILS OR SEDIMENT. SPECIAL PROCEDURES MAY BE REQUIRED FOR THE ASSESSMENT, REMEDIATION, REMOVAL, TRANSPORTATION, OR DISPOSAL OF ENVIRONMENTAL MEDIA, WASTES, ASBESTOS, NORM AND OTHER HAZARDOUS SUBSTANCES FROM THE PROPERTIES. NOTHING CONTAINED IN THIS SECTION 5.9.3 WILL LIMIT, RESTRICT OR OTHERWISE AFFECT THE BUYER’S RIGHTS TO RAISE ENVIRONMENTAL DEFECTS UNDER SECTION 2.1 OF THIS AGREEMENT.

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5.10. Operatorship. At Closing, the Seller shall send notices to co-owners of those Properties that the Seller (or any Affiliate of the Seller) currently operates indicating that the Seller (or such Affiliate) is resigning as operator, effective upon the Closing Date, and recommending that Buyer be elected successor operator. The Seller makes no representations or warranties to Buyer as to the transferability of operatorship of any Properties which the Seller (or its Affiliates) currently operate. Rights and obligations associated with operatorship of the Properties are governed by operating agreements or similar agreements and will be decided in accordance with the terms of such agreements.

5.11. FERC Matters.

5.11.1 The Buyer and the Seller and their Affiliates will cooperate in obtaining (a) waivers from the FERC of its capacity release regulations and any other applicable FERC regulations (the “FERC Waivers”), and (b) related approvals, including but not limited to securing any and all timely consents to transfer from interstate pipelines providing transportation service pursuant to the FERC Jurisdictional Contracts (the “Pipeline Waivers”), and (c) execution of all necessary documents, as may be reasonably necessary to facilitate the permanent transfer from the Seller and its Affiliates to the Buyer or its designee of those contracts set forth on Schedule 5.11 (or any renewals, extensions or replacements thereof) (collectively, the “FERC Jurisdictional Contracts”). Upon receipt of such FERC Waivers and any or all of the Pipeline Waivers, the Seller or its Affiliate will assign or release to the Buyer or its designee their interests in the FERC Jurisdictional Contracts, on rates, terms and conditions identical to those being paid by the Seller, their Affiliates or their designees prior to the contemplated transfer.

5.11.2 From and after the later of Closing or the commencement of services under any FERC Jurisdictional Contract, until the earlier of (a) the effective date of the transfer of each such FERC Jurisdictional Contract to the Buyer or its designee in accordance with this Section 5.11.1 or to a Third Party pursuant to Section 5.11.3, or (b) if such transfer of a FERC Jurisdictional Contract does not occur, termination of the applicable FERC Jurisdictional Contract; the Seller shall, or shall cause its Affiliates to purchase hydrocarbons produced from the Properties at a price equal to 100% of the weighted average sales price of the products marketed, including natural gas liquids, if applicable, less applicable transportation fees and expenses and a marketing fee equal to one and one-half percent (1½%). Seller will cause its parent, Chesapeake Energy Corporation, to provide Buyer with a performance guaranty of the obligations under such purchase arrangement .

5.11.3 In the event that the Parties are unable to obtain the FERC Waivers or the Pipeline Waivers, the Buyer may request at any time, and upon receipt of such request from the Buyer, the Seller shall, and shall cause their

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Affiliates to, cooperate with arranging for each counterparty under the FERC Jurisdictional Contracts to post the Seller’s and its Affiliates’ pre-arranged permanent capacity release to the Buyer or its designee of their interests in the FERC Jurisdictional Contracts, and if the release of such FERC Jurisdictional Contracts is not at the maximum recourse rate, the Buyer or its designee will have the right to match any higher bid pursuant to the tariffs of the interstate pipelines providing transportation service pursuant to the FERC Jurisdictional Contracts. If the rate for any FERC Jurisdictional Contract is a negotiated rate, then the Buyer and the Seller shall cooperate to seek any waivers necessary to enable the Seller or its Affiliates to release that FERC Jurisdictional Contract at a rate that results in the permanent release of the Seller or its Affiliate, without further payment obligations to the relevant pipeline. If Seller releases capacity to Buyer without FERC Waivers pursuant to this Section 5.11.3, Seller agrees to exercise any rights of first refusal or extension options under the FERC Jurisdictional Contract(s) involved at Buyer’s direction, cost and expense. After the date that is six (6) months after Closing, the Seller may take the action described above without first obtaining the Buyer’s request or consent.

5.12. Satisfaction of Conditions. The Parties agree to use commercially reasonable efforts to take all actions and to do all things necessary to consummate, make effective and comply with all of the terms of this Agreement (including satisfaction, but not waiver, of the Closing conditions for which they are responsible or otherwise in control).

5.13. Confidentiality. From the Execution Date until Closing, unless this Agreement is terminated, the Seller shall maintain the Records (including, as applicable, any confidentiality thereof) as would a reasonably prudent owner and operator of oil and gas properties, subject to the requirements of the Real Property Interests and any other applicable contracts. Without limiting Seller’s obligations under Section 8.4, if Closing occurs, then for a period of one (1) year after the Closing Seller shall maintain in confidence those Records to the extent related to the Properties that are conveyed to Buyer. The foregoing obligations of confidentiality shall not apply to (a) any information that is or becomes generally available to the public through no fault of Seller, or that is or was communicated to Seller by a Third Party free of any obligation of confidence known to Seller, or (b) any Records to the extent related to any Property not conveyed to Buyer or to the extent related to any Retained Liabilities. Seller may disclose any information to the extent necessary and appropriate to company with applicable Law, or to attorneys of litigants or Governmental Authorities to comply with any obligation imposed on Seller or its Affiliates in connection with a proceeding in a court or other Governmental Authority of competent jurisdiction.

5.14. Development Agreement. If the conditions set forth in Sections 6.4(a), 6.4(b), 7.5(a) and 7.5(b) are satisfied, but SUSA does not agree in writing that the Properties to be assigned to the Buyer hereunder will, effective upon such

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assignment, cease to be subject to the Development Agreement in all respects and cease to be “Joint Interests” under the Development Agreement, then promptly thereafter Seller will deliver a copy of the Development Agreement to Buyer and Buyer agrees to keep the Development Agreement strictly confidential pursuant to the terms of the Confidentiality Agreement. Within five (5) Business Days after Buyer’s receipt of a copy of the Development Agreement, Buyer will notify Seller in writing as to whether Buyer is willing to assume and accept at Closing all of Seller’s rights, duties and obligations under the Development Agreement to the extent such rights, duties and obligations relate to the Properties conveyed to Buyer pursuant to this Agreement or to the lands located in the Contract Area (as so limited, the “DA Assumed Obligations”). If Buyer notifies Seller that Buyer is willing to assume and accept at Closing the DA Assumed Obligations, then (a) the conditions set forth in Sections 6.4(c) and 7.5(c) will be satisfied and (b) Buyer will assume and be assigned, and Seller will be fully released from, the DA Assumed Obligations pursuant to an assignment and assumption agreement to be executed and delivered by the Parties at Closing in form and substance sufficient to accomplish (and that satisfies the requirements of the Development Agreement with respect to) such assignment, assumption and release.

5.15. Selling Affiliates. To the extent any of the Properties or any of the fee minerals described on Exhibit A under the heading Fee Mineral Lease are held by any Affiliates of Seller, then, subject to the other terms of this Agreement, Seller will cause such Affiliates (a) to transfer title to such Properties by an assignment substantially in the form of the Assignment or to deliver the corresponding Fee Mineral Lease, as applicable, to Buyer, in each case, at the Closing and (b) to comply with any other terms of this Agreement to the extent specifically pertaining to such Properties or Fee Mineral Leases.

6.Buyer’s Conditions Precedent. The obligation of the Buyer to consummate the transactions contemplated by this Agreement is, at the option of Buyer, subject to the satisfaction or waiver in writing by the Buyer (subject to applicable Laws) on or prior to the Closing Date of each of the following conditions precedent:

6.1 (a) No preliminary or permanent injunction or other order will have been issued (and remain in force) by any Governmental Authority having appropriate jurisdiction preventing consummation of the transactions contemplated by the Transaction Documents, and (b) to the extent required to be obtained prior to Closing, the consents, approvals and other items on Schedule 3.2 shall have been obtained;

6.2 No Proceeding will have been commenced by any Third Party against any of the Seller, the Buyer or any of their respective Affiliates, associates, officers or directors seeking to restrain, enjoin, prevent or challenge the transactions contemplated by the Transaction Documents or seeking material damages arising from the transactions contemplated by the Transaction Documents;

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6.3 All representations and warranties of the Seller contained herein (a) that are qualified by the term “material” or contain terms such as “material adverse change,” “material adverse effect” or other terms or Dollar amounts of similar import or effect (whether or not capitalized) shall be true and correct as of the Closing Date as though such representations and warranties were made at such time (except to the extent that a representation specifically relates to an earlier date, in which case as of such earlier date), and (b) that are not so qualified shall be true and correct in all material respects as of the Closing Date as though such representations and warranties were made at such time (except to the extent that a representation specifically relates to an earlier date, in which case as of such earlier date);

6.4 The Seller shall provide written evidence to Buyer that (a) SUSA has unconditionally consented to the assignment of the Seller’s interests in the Properties to the Buyer pursuant to this Agreement by countersigning a form of consent letter substantially in the form of Exhibit G; (b) SUSA has waived its PPR under the Development Agreement or such PPR has otherwise expired in accordance with the terms of the Development Agreement; and (c) either (i) the Buyer shall have notified the Seller, pursuant to Section 5.14, that the Buyer is willing to assume and accept at Closing the DA Assumed Obligations or (ii) SUSA shall have agreed in writing that the Properties actually assigned to the Buyer hereunder will, effective upon such assignment, cease to be subject to the Development Agreement in any respect and will cease to be “Joint Interests” under the Development Agreement;

6.5 Consummation of the transactions contemplated under the terms of the Transaction Documents is not prevented from occurring by (and the required waiting period, if any, has expired under) the HSR Act and the rules and regulations of the FTC and the DOJ thereunder; and

6.6 The Seller will have performed or satisfied in all material respects on or prior to the Closing Date all obligations, covenants and agreements contained in this Agreement to be performed or complied with by the Seller on or prior to the Closing Date.

7.Seller’s Conditions Precedent. The obligation of the Seller to consummate the transactions contemplated by this Agreement is, at the option of the Seller, subject to the satisfaction or waiver in writing by the Seller (subject to applicable Laws) on or prior to the Closing Date of each of the following conditions precedent:

7.1 (a) No preliminary or permanent injunction or other order will have been issued (and remain in force) by any Governmental Authority having appropriate jurisdiction preventing consummation of the transactions contemplated by the Transaction Documents, and (b) to the extent required to be obtained prior to Closing, the consents, approvals and other items on Schedule 3.2 shall have been obtained;

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7.2 No Proceeding will have been commenced by any Third Party against the Seller, the Buyer or any of their respective Affiliates, associates, officers or directors seeking to restrain, enjoin, prevent or challenge the transactions contemplated by the Transaction Documents or seeking material damages arising from the transactions contemplated by the Transaction Documents;

7.3 All representations and warranties of the Buyer contained herein (a) that are qualified by the term “material” or contain terms such as “material adverse change,” “material adverse effect” or other terms or Dollar amounts of similar import or effect (whether or not capitalized) shall be true and correct as of the Closing Date as though such representations and warranties were made at such time (except to the extent that a representation specifically relates to an earlier date, in which case as of such earlier date), and (b) that are not so qualified shall be true and correct in all material respects as of the Closing Date as though such representations and warranties were made at such time (except to the extent that a representation specifically relates to an earlier date, in which case as of such earlier date);

7.4 The Buyer will have performed or satisfied in all material respects on or prior to the Closing Date all obligations, covenants and agreements contained in this Agreement to be performed or complied with by the Buyer on or prior to the Closing Date;

7.5 The Seller shall have received written evidence that is reasonably satisfactory to the Seller that (a) SUSA has unconditionally consented to the assignment of the Seller’s interests in the Properties to the Buyer pursuant to this Agreement by countersigning a form of consent letter substantially in the form of Exhibit G, and (b) SUSA has waived its PPR under the Development Agreement or such PPR has otherwise expired in accordance with the terms of the Development Agreement; and (c) either (i) the Buyer shall have notified the Seller, pursuant to Section 5.14, that the Buyer is willing to assume and accept at Closing the DA Assumed Obligations or (ii) SUSA shall have agreed in writing that the Properties actually assigned to the Buyer hereunder will, effective upon such assignment, cease to be subject to the Development Agreement in any respect and will cease to be “Joint Interests” under the Development Agreement;

7.6 If applicable, consummation of the transactions contemplated under the terms of the Transaction Documents is not prevented from occurring by (and the required waiting period, if any, has expired under) the HSR Act and the rules and regulations of the FTC and the DOJ thereunder; and

7.7 The Deposit shall have been made to the Seller in accordance with Section 2

8.The Closing. Subject to the terms and conditions hereof, unless extended as provided herein, the Closing will take place at 10:00 a.m. local time in the offices of the Seller, at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118 on the Closing Date.

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8.1. Buyer’s Deliveries. At the Closing, and subject to the simultaneous performance by the Seller of its obligations under Section 8.2, the Buyer will execute and deliver or cause to be executed and delivered to the Seller the following items:

8.1.1 Purchase Price. The Purchase Price as directed in writing by the Seller (as adjusted pursuant to Section 2.7 and less the Deposit);

8.1.2 Buyer’s Certificate. A certificate dated as of the Closing Date executed by an authorized officer of Buyer certifying on behalf of Buyer that the conditions set forth in Section 7.3 and Section 7.4 have been satisfied;

8.1.3 Secretary’s Certificate. A certificate duly executed by Buyer’s secretary or assistant secretary, dated as of the Closing Date, (i) attaching and certifying complete and correct copies of (A) the certificate of formation of Buyer in effect as of the Closing and (B) the resolutions of the board of directors of Buyer authorizing the execution, delivery and performance by Buyer of the Transaction Documents to which it is a party and the transactions they contemplate and (ii) certifying on behalf of Buyer the incumbency of each officer of Buyer executing each of the Transaction Documents to which it is a party;

8.1.4 Closing Statement. An original counterpart of the Closing Statement signed on behalf of the Buyer;

8.1.5 Consent Decree Agreement. An original counterpart of the Consent Decree Agreement signed on behalf of the Buyer;

8.1.6 Fee Minerals Lease. An original counterpart of the Fee Minerals Lease(s) signed on behalf of Buyer; and

8.1.7 Additional Documents. Such additional documents customary in similar transactions as might be reasonably requested by the Seller and are reasonably required to consummate the transactions contemplated by this Agreement, including, without limitation, the written acknowledgements and the such consents or agreements as my be required to satisfy the Buyer’s obligations under Sections 5.8 and 5.11.

8.2. Seller’s Deliveries. At the Closing, and subject to the simultaneous performance by the Buyer of its obligations under Section 8.1, the Seller will execute and deliver or cause to be executed and delivered to the Buyer the following items:

8.2.1 Assignments. An original counterpart of the Assignment for each County in which its Real Property Interests or Wells are located, executed by an authorized officer of the Seller and covering all of the Seller’s interest in the Properties (other than the Other Assets, the Transferred Gathering Systems, the Fee Minerals Lease(s) and those Properties to be excluded in accordance with the terms hereof) in recordable form, and an original counterpart of an Assignment of the Other Assets and the Transferred

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Gathering Systems for each County in which any of the Other Assets or Transferred Gathering Systems are located, executed by an authorized officer of the Seller or its Affiliate which owns such Other Assets or Transferred Gathering Systems;

8.2.2 State and Federal Assignments. The Seller shall execute, acknowledge and deliver assignments, on appropriate forms, of state and of federal Real Property Interests, if any, in sufficient counterparts for filing with the applicable Governmental Authority;

8.2.3 Non-Foreign Status Certificate. A non-foreign entity certificate, in substantially the form of Exhibit F attached hereto;

8.2.4 Seller’s Certificate. A certificate dated as of the Closing Date executed by an authorized officer of the Seller certifying on behalf of the Seller that the conditions set forth in Section 6.3 and Section 6.4 have been satisfied;

8.2.5 Secretary’s Certificate. A certificate duly executed by Seller’s secretary or assistant secretary, dated as of the Closing Date, (i) attaching and certifying complete and correct copies of (A) the certificate of formation of Seller in effect as of the Closing and (B) the resolutions of the board of directors or other governing body of Seller authorizing the execution, delivery and performance by Seller of the Transaction Documents to which it is a party and the transactions they contemplate and (ii) certifying on behalf of Seller the incumbency of each officer of Seller executing each of the Transaction Documents to which it is a party;

8.2.6 Closing Statement. An original counterpart of the Closing Statement signed on behalf of the Seller;

8.2.7 Letters in Lieu. Letters in lieu of division and transfer orders executed by it relating to such Properties in form reasonably acceptable to the Buyer to reflect the conveyance by the Seller contemplated hereby;

8.2.8 Change of Operator. With respect to any Wells operated by the Seller, counterparts of such documents as are required to transfer the regulatory authority to operate such Wells to Buyer;

8.2.9 Consent Decree Agreement. An original counterpart of the Consent Decree Agreement signed on behalf of the Seller;

8.2.10 G&G License. The G&G License executed by an authorized officer of the Seller.

8.2.11 Fee Minerals Lease. An original counterpart of the Fee Minerals Lease(s) signed on behalf of Seller; and

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8.2.12 Additional Documents. Such additional documents customary in similar transactions as might be reasonably requested by the Buyer and are reasonably required to consummate the transactions contemplated by this Agreement, including, without limitation, the written acknowledgements and such consents or agreements as my be required to satisfy the Seller’s obligations under Sections 5.8 and 5.11.

8.3. Post-Closing Adjustments. The Buyer and the Seller agree that the Purchase Price may be further adjusted after the Closing Date in accordance with the provisions of Section 2 of this Agreement.

8.4. Post-Closing Deliveries. The Seller shall deliver the Records to the Buyer promptly after Closing, but no later than forty-five (45) days after the Closing Date.

8.5. Costs. The Seller will pay its attorney fees and other expenses; and the Buyer will pay the Buyer’s attorney fees and other expenses including, without limitation, the recording costs for the Assignmentsand all taxes (including sales taxes and transfer taxes), duties, levies or other governmental charges imposed on the transfers of the Properties pursuant to the Transaction Documents.

8.6. Risk of Loss. As of the consummation of the Closing, beneficial ownership and the risk of loss of the Properties will pass from the Seller to the Buyer effective from and after the Effective Time.

9.Press Releases. No Party shall make any press release or other public announcements concerning this transaction, without the consent of the other Party, which consent shall not be unreasonably withheld. Any Party desiring to make a public announcement shall first give the other Party twenty-four (24) hours written notification of its desire to make such a public announcement. The written notification shall include (a) a request for consent to make the announcement, and (b) a written draft of the text of such public announcement. Nothing contained herein shall prohibit any Party from issuing or making a public announcement or statement if such Party deems it necessary to do so in order to comply with any applicable Law, or the rules of any stock exchange upon which the Party’s capital stock is traded, provided that such Party provides the other Party with a written draft of the text of such public announcement prior to issuing or making such public announcement.

10.Indemnification. Upon and after the Closing of the transactions contemplated by this Agreement, the Parties will indemnify each other as follows:

10.1. Assumed Obligations. Upon the Closing, the Buyer shall assume all of the Assumed Obligations (and, upon delivery by the Seller of the Assignment, the Buyer shall be deemed to have assumed the Assumed Obligations).

10.2. Seller’s Indemnification. Upon the Closing, the Seller shall agree (and, upon the delivery of the Assignment to the Buyer, the Seller shall be deemed to have agreed) to pay, defend, indemnify, reimburse and hold harmless the Buyer, its Affiliates and their respective directors, officers, agents and employees (the

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“Buyer Indemnified Parties”) for, from and against any loss, damage, diminution in value, claim, liability, debt, obligation or expense (including interest, reasonable legal fees, and expenses of litigation and attorneys’ fees in enforcing this indemnity) incurred, suffered, paid by or resulting to any of the Buyer Indemnified Parties and which results from, arises out of or in connection with, is based upon, or exists by reason of: (a) the breach of any representation or warranty of the Seller set forth in this Agreement (as brought down by the Seller’s certificate delivered at Closing) or any failure by the Seller to perform any of its covenants or obligations set forth in this Agreement (other than any covenant contained in Section 5.2) which is not cured as provided in Section 12 of this Agreement; (b) any failure by the Seller to perform any of its covenants or obligations set forth in Sections 5.2 of this Agreement which is not cured as provided in Section 12 of this Agreement; or (c) any of the Retained Liabilities.

10.3. Buyer’s Indemnification. Upon the Closing, the Buyer shall agree (and, upon the delivery by the Seller to the Buyer of the Assignment, the Buyer shall be deemed to have agreed) to pay, defend, indemnify, reimburse and hold harmless the Seller, its Affiliates and their respective directors, partners, members, managers, officers, agents and employees (the “Seller Indemnified Parties”) for, from and against any loss, damage, diminution in value, claim, liability, debt, obligation or expense (including interest, reasonable legal fees, and expenses of litigation and attorneys’ fees in enforcing this indemnity) incurred, suffered, paid by or resulting to any of the Seller Indemnified Parties and which results from, arises out of or in connection with, is based upon, or exists by reason of: (a) the breach of any representation or warranty of the Buyer set forth in this Agreement (as brought down by the Buyer’s certificate delivered at Closing); (b) or any failure by the Buyer to perform any of its covenants or obligations set forth in this Agreement which is not cured as provided in Section 12 of this Agreement; or (c) any of the Assumed Obligations (except matters which constitute “Assumed Obligations” but which arise out of a breach by the Seller of its covenants in Section 5.2 of this Agreement for which the Seller is required to indemnify the Buyer under Section 10.2(b) at the time notice of a claim related to such matter is first presented under this Agreement).

10.4. EXTENT OF INDEMNIFICATION. WITHOUT LIMITING OR ENLARGING THE SCOPE OF THE INDEMNIFICATION, DEFENSE AND ASSUMPTION PROVISIONS SET FORTH IN THIS AGREEMENT, TO THE FULLEST EXTENT PERMITTED BY LAW, AN INDEMNIFIED PERSON SHALL BE ENTITLED TO INDEMNIFICATION HEREUNDER IN ACCORDANCE WITH THE TERMS OF SECTIONS 10.2 OR 10.3, REGARDLESS OF WHETHER THE ACT, OCCURRENCE OR CIRCUMSTANCE GIVING RISE TO ANY SUCH INDEMNIFICATION OBLIGATION IS THE RESULT OF THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY, BREACH OF DUTY (STATUTORY OR OTHERWISE), OR OTHER FAULT OR VIOLATION OF ANY LAW OF OR BY ANY SUCH INDEMNIFIED PERSON, PROVIDED THAT NO SUCH

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INDEMNIFICATION SHALL BE APPLICABLE TO THE EXTENT OF ANY GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF THE INDEMNIFIED PERSON. NOTWITHSTANDING ANYTHING TO THE CONTRARY CONTAINED IN THIS AGREEMENT, THE INDEMNIFICATION SET FORTH IN SECTIONS 10.2 AND 10.3 (AS LIMITED IN THIS AGREEMENT) SHALL CONSTITUTE THE SOLE AND EXCLUSIVE POST-CLOSING REMEDIES OF THE PARTIES AGAINST EACH OTHER WITH RESPECT TO BREACHES OF ANY REPRESENTATION, WARRANTY, COVENANT OR AGREEMENT CONTAINED IN SECTION 3, 4, OR 5.2 (AND AS THE FOREGOING REPRESENTATIONS, WARRANTIES, COVENANTS AND AGREEMENTS ARE AFFIRMED IN THE CERTIFICATES DELIVERED AT CLOSING). FOR THE AVOIDANCE OF DOUBT, EACH PARTY SHALL HAVE ALL RIGHTS AND REMEDIES AVAILABLE AT LAW OR IN EQUITY FOR THE BREACH OF ANY OTHER COVENANT OR AGREEMENT CONTAINED IN THIS AGREEMENT (EXCLUDING THE REPRESENTATIONS, WARRANTIES, COVENANTS AND AGREEMENTS CONTAINED IN SECTIONS 3, 4, AND 5.2).

10.5. Indemnification Procedure. If any indemnified party discovers or otherwise becomes aware of an indemnification claim arising under this Agreement, such party will give written notice to the indemnifying Party, specifying such claim, and may thereafter exercise any remedies available to such indemnified party under this Agreement; provided, however, the failure of any indemnified party to give notice as provided herein will not relieve the indemnifying Party of any obligations hereunder, to the extent the indemnifying Party is not materially prejudiced thereby. Further, promptly after receipt by an indemnified party hereunder of written notice of the commencement of any action or proceeding with respect to which a claim for indemnification may be made against any indemnifying Party, the indemnified party will give written notice to the indemnifying Party of the commencement of such action; provided, however, the failure of any indemnified party to give notice as provided herein will not relieve the indemnifying Party of any obligations hereunder, to the extent the indemnifying Party is not materially prejudiced thereby.

10.6. Defense. If any action is brought against an indemnified party by a Third Party with respect to a matter subject to indemnification under this Agreement, the indemnifying Party will be entitled to participate in and to assume the defense thereof to the extent that it may wish, and after notice from the indemnifying Party to such indemnified party of the indemnifying Party’s election to assume the defense thereof, the indemnifying Party shall not be liable to such indemnified party for any legal or other expenses subsequently incurred by the latter in connection with the defense thereof unless the indemnifying Party has failed to assume and diligently prosecute the defense of such claim. Notwithstanding any of the foregoing to the contrary, the indemnified party will be entitled to select its own counsel and assume the defense of any action brought against it if the indemnifying Party fails to assume or diligently prosecute such defense, the

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expenses of such defense to be paid by the indemnifying Party. As a condition to the indemnifying Party’s obligations hereunder, the indemnified party will in good faith cooperate with and assist the indemnifying Party in the prosecution or defense of such indemnified claim at no unreasonable expense to the indemnified party. No indemnifying Party shall consent to entry of any judgment or enter into any settlement with respect to a claim either (a) without the consent of the indemnified party, which consent shall not be unreasonably withheld, or (b) unless such judgment or settlement includes as an unconditional term thereof the giving by the claimant or plaintiff to such indemnified party of a release from all liability with respect to such claim. No indemnified party shall consent to entry of any judgment or enter into any settlement of any such action, the defense of which has been assumed by an indemnifying Party, without the consent of such indemnifying Party, which consent shall not be unreasonably withheld.

10.7. Certain Limitations on Indemnity Obligations.

10.7.1 No claim of the Buyer or the Buyer Indemnified Parties pursuant to Section 10.2(a) shall be made hereunder unless the amount of such claim exceeds an amount equal to Two Hundred Thousand Dollars ($200,000.00) (each an “Individual Claim”). No claim of the Buyer or the Buyer Indemnified Parties pursuant to Section 10.2(a) shall be made hereunder until the total of all Individual Claims exceeds one and one-tenth percent (1.1%) of the unadjusted Purchase Price (the “Basket”). If the total amount of all of the Buyer’s or the Buyer Indemnified Parties’ Individual Claims exceeds the Basket, then the Seller’s obligations under Section 10.2(a) shall be limited to the amount by which the aggregate amount of such Individual Claims exceeds the Basket. All of the representations and warranties set forth in this Agreement or any certificate that are qualified as to “material,” “materiality,” “material respects,” “material adverse effect,” “Material Adverse Effect” or words of similar import or effect shall be deemed to have been made without any such qualification solely for purposes of determining whether a claim exceeds the Individual Claim threshold or Basket or whether the Buyer is entitled to indemnification under Section 10.2(a) for a breach by the Seller of a representation or warranty contained in Section 3.6 (and, for the avoidance of doubt, not for purposes of determining whether a Closing condition has been satisfied or whether the Buyer is entitled to indemnification under Section 10.2(a) for a breach by the Seller of any other representation or warranty contained in Section 3).

10.7.2 In no event will the Seller’s aggregate liability under Section 10.2(a), other than claims for breaches of the representations and warranties made in Sections 3.1, 3.2, 3.3(a)(i), 3.10 and 3.11, exceed twenty percent (20%) of the unadjusted Purchase Price.

10.7.3 The amount of any indemnification provided under Section 10.2 or 10.3 shall be net of any corresponding insurance proceeds, from insurance

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policies carried by the Party otherwise entitled to such indemnification or its Affiliates, in each case, that are actually realized by such Party.

10.7.4 Notwithstanding anything stated herein to the contrary: (a) neither Party will have any liability to the other Party or such other Party’s indemnified parties under this Section 10 with respect to any item for which an adjustment has already been made to the Purchase Price under the terms of this Agreement; and (b) the Seller will have no liability to the Buyer or the Buyer Indemnified Parties under this Section 10 for any matter (including any breach of a representation or warranty under Section 3) which constitutes a Title Defect or an Environmental Defect. Claims for Title Defects or Environmental Defects, whether or not resulting in a Purchase Price adjustment because the applicable Aggregate Defect Threshold is not exceeded, are not subject to the terms of this Section 10, may not be claimed under this Section 10, may not be included for purposes of determining whether the limitations set forth in this Section 10.7 have been met and may not be included in the Basket for purposes of the limitations set forth in this Section 10.7.

10.7.5 The Parties specifically agree that the Buyer will not have any right to pursue a claim under the special warranty of title in the Assignment with respect to any matters which existed on or before the Effective Time that were raised by the Buyer as a Title Defect under Section 2.1 of this Agreement.

11.Termination. The Parties agree that this Agreement is subject to termination as follows:

11.1. Right to Terminate. Subject to Section 11.2, this Agreement may be terminated (except for the provisions referenced in Section 11.2) at any time prior to the consummation of the Closing upon the occurrence of any one or more of the following: (a) by mutual consent of the Seller and the Buyer; (b) by the Buyer, if the Seller has materially breached this Agreement and such breach causes any of the conditions to Closing set forth in Section 6 not to be satisfied (or, if prior to Closing, is of such a magnitude or effect that it will not be possible for such condition to be satisfied); provided, however, that in the case of a breach that is capable of being cured, the Seller shall have a period of ten (10) days following receipt of such notice to attempt to cure the breach and the termination under this Section 11.1(b) shall not become effective unless the Seller fails to cure such breach prior to the end of such ten (10) day period; (c) by the Seller if the Buyer has materially breached this Agreement and such breach causes any of the conditions to Closing set forth in Section 7 not to be satisfied (or, if prior to Closing, is of such a magnitude or effect that it will not be possible for such condition to be satisfied); provided, however, that in the case of a breach that is capable of being cured, the Buyer shall have a period of ten (10) days following receipt of such notice to attempt to cure the breach and the termination under this Section 11.1(c) shall not become effective unless the Buyer fails to cure such breach prior to the end of such ten (10) day period; (d) by the Seller or the Buyer

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if the Closing shall not have occurred on or before March 15, 2015, provided that such failure does not result primarily from the terminating Party’s material breach of its representations, warranties or covenants contained in this Agreement; or (e) by either the Seller or the Buyer, if under the HSR Act or otherwise, the FTC or the DOJ shall have commenced or threatened to commence any proceeding to delay or enjoin or seek damages in respect of the transactions evidenced by this Agreement (“threatened,” for purposes of this Section 11.1(e), means an actual vote of the Commissioners of the Federal Trade Commission to commence such a proceeding).

11.2. Effect of Termination. In the event of termination, written notice thereof will be given to the other Party or Parties specifying the provision pursuant to which such termination is made. Except as specifically provided in Section 12, on the termination of this Agreement the Deposit will be refunded to the Buyer. If this Agreement is terminated in accordance with Section 11.1, the provisions contained in this Section 11.2 and in Sections 8.5, 9, 12, 13, 14.1, 14.2, 14.5 through 14.17, and such defined terms in Section 1 as may be required to give meaning to such sections, shall survive termination of this Agreement. No termination of this Agreement under Section 11 shall relieve any Party of liability for breach of this Agreement arising prior to such termination.

12.Default. If any Party fails to perform any material obligation contained in this Agreement that is to be performed at or prior to Closing, and Closing has not yet occurred, the Party claiming default will serve written notice to the other Party specifying the nature of such default and demanding performance. If such a material default by the Seller has not been cured within the sooner of ten (10) days after receipt of such default notice or the date specified in Section 11.1(d) above, and each of the conditions contained in Section 7 has been either fulfilled in all material respects or waived in writing (other than conditions pertaining to the execution and delivery of documents and payment of monies by the Buyer the fulfillment of which is expressly provided to occur at the Closing), then the Buyer will be entitled to exercise all remedies arising at law or in equity by reason of such default, including termination of this Agreement pursuant to Section 11. If such a material default by the Buyer has not been cured within the sooner of ten (10) days after receipt of such default notice or the date specified in Section 11.1(d) above, and each of the conditions contained in Section 6 has been either fulfilled in all material respects or waived in writing (other than conditions pertaining to the execution and delivery of documents the fulfillment of which is expressly provided to occur at the Closing), then the Seller will be entitled to retain the Deposit as liquidated damages in lieu of all other damages (and as the Seller’s sole remedy in such event, other than termination of this Agreement). The Parties hereby acknowledge that the extent of damages to the Seller occasioned by such failure or refusal by the Buyer would be impossible or extremely impractical to ascertain and that the amount of the Deposit is a fair and reasonable estimate of such damages under the circumstances.

13.    Arbitration. Except with respect to disputes and matters required to be resolved by the Consultant(s) or the Accounting Referee, which will be resolved as provided in Sections 2.1.11 or 2.8, any and all Arbitrable Disputes must be resolved through the use of binding arbitration in accordance with the Commercial Arbitration Rules of the AAA, as supplemented to

PURCHASE AND SALE AGREEMENT 59

the extent necessary to determine any procedural appeal questions by the Federal Arbitration Act (Title 9 of the United States Code). If there is any inconsistency between this Section 13 and the Commercial Arbitration Rules or the Federal Arbitration Act, the terms of this Section 13 shall control the rights and obligations of the Parties.

13.1. Consolidation. If there is more than one (1) Arbitrable Dispute that involves the same facts and Parties as the facts and Parties with respect to which arbitration has been initiated pursuant to this Agreement, such disputes shall be consolidated into the first arbitration initiated pursuant to this Agreement.

13.2. Initiation; Selection of Arbitrators. Arbitration may be initiated by a Party (“Claimant”) serving written notice on the other Party (“Respondent”) that the Claimant has referred the Arbitrable Dispute to binding arbitration. Claimant’s notice initiating binding arbitration must describe in reasonable detail the nature of the Arbitrable Dispute and the facts and circumstances relating thereto and identify the arbitrator Claimant has appointed. Respondent shall respond to Claimant within thirty (30) days after receipt of Claimant’s notice, identifying the arbitrator Respondent has appointed. All arbitrators must be neutral parties who have never been officers, directors or employees of, or have performed material work for, any of the Parties or their Affiliates within the preceding five (5) year period. Arbitrators must have a formal education or training in the area of dispute resolution and must have not less than seven (7) years’ experience as a lawyer in the energy industry with experience in exploration and production issues. The two (2) arbitrators so chosen shall select a third arbitrator within thirty (30) days after the second arbitrator has been appointed. If either the Respondent fails to name its Party-appointed arbitrator within the time permitted, or if the two arbitrators are unable to agree on a third arbitrator within thirty (30) days from the date the second arbitrator has been appointed, then the missing arbitrator(s) shall be selected by the AAA with due regard given to the selection criteria above and input from the Parties and other arbitrators. The AAA shall select the missing arbitrator(s) not later than ninety (90) days from initiation of arbitration. In the event the AAA should fail to select the third arbitrator within ninety (90) days from initiation of arbitration, then either Party may petition the Chief United States District Judge for the Northern District of Texas to select the third arbitrator. Such selection shall be consistent with the selection criteria above and with due regard given to input from the Parties and other arbitrators.

13.3. Expenses. Claimant and Respondent shall each pay one-half of the compensation and expenses of the AAA and the arbitrator(s).

13.4. Procedure. The hearing shall be conducted in Dallas, Texas and commence within sixty (60) days after the selection of the third arbitrator, unless delayed by order of the arbitrators. The hearing shall be based upon written position papers submitted by Claimant and Respondent within twenty (20) Business Days after the selection of the third arbitrator, stating such Party’s proposed resolution of the dispute. The Parties and the arbitrators shall proceed diligently and in good faith in order that the award may be made as promptly as possible. The arbitrators

PURCHASE AND SALE AGREEMENT 60

shall determine the Arbitrable Disputes and render a final award on or before thirty (30) days following the completion of the hearing. The arbitrators’ decision shall be in writing and set forth the reasons for the award. In rendering the award the arbitrators shall abide by (a) the terms and conditions of this Agreement including, without limitation, any and all restrictions, prohibitions or limitations on damages or remedies set forth in this Agreement and (b) the law of the State of Texas. The arbitrators shall not have jurisdiction or authority to add to, detract from or alter in any way the provisions of this Agreement.

13.5. Enforcement; Remedies. A Party may, prior to the appointment of the third arbitrator, seek temporary injunctive relief from any court of competent jurisdiction, provided that the Party seeking such relief shall (if arbitration has not already been commenced) simultaneously commence arbitration. Such court-ordered relief shall not continue more than ten (10) days after the appointment of the arbitrators and in no event for longer than ninety (90) days. In order to prevent irreparable harm, the arbitrators shall have the power to grant temporary or permanent injunctive or other equitable relief. Except as provided in the Federal Arbitration Act, the decision of the arbitrators shall be binding on and non-appealable by the Parties. Each Party agrees that any arbitration award against it may be enforced in any court of competent jurisdiction and that any Party may authorize any such court to enter judgment on the arbitrators’ decisions. The arbitrators may not grant or award indirect, consequential, punitive or exemplary damages or damages for lost profits.

13.6. Award of Fees. In any action under this Agreement, the prevailing Party or Parties (or other indemnified Persons) shall be entitled to recover arbitration and court costs and attorneys’ fees in addition to any other relief to which such Party or Persons are entitled.

14.Miscellaneous. It is further agreed as follows:

14.1. Time. Time is of the essence of this Agreement.

14.2. Notices. All notices and communications required or permitted under this Agreement shall be in writing addressed as indicated below, and any communication or delivery hereunder shall be deemed to have been duly delivered upon the earliest of: (a) actual receipt by the Party to be notified; (b) if sent by U.S. certified mail, postage prepaid, return receipt requested, then the date shown as received on the return notice; (c) if by facsimile transmission, then upon confirmation by the recipient of receipt, provided that if such facsimile is received after 5:00 pm local time of such recipient, such facsimile will be deemed to have been received on the following Business Day; (d) if by email, then upon an affirmative reply by email by the intended recipient that such email was received, provided that if such email is received after 5:00 pm local time of such recipient, such email will be deemed to have been received on the following Business Day; or (e) if by Federal Express overnight delivery (or other reputable overnight

PURCHASE AND SALE AGREEMENT 61

delivery service), the date shown on the notice of delivery. Addresses for all such notices and communication shall be as follows:

To the Seller:	Chesapeake Appalachia, L.L.C. 6100 North Western Avenue Oklahoma City, Oklahoma 73118 Attention: Mr. Douglas J. Jacobson Telephone: (405) 935-9233 Facsimile: (405) 849-9233 Email: doug.jacobson@chk.com
With a copy to:	Commercial Law Group, P.C. 5520 North Francis Avenue Oklahoma City, Oklahoma 73118 Attention: Mr. Ray Lees Telephone: (405) 254-5725 Facsimile: (405) 232-5553 Email: rlees@clgroup.org
To the Buyer:	Southwestern Energy Production Company 2350 N. Sam Houston Parkway East, Suite 125 Houston, Texas 77032 Attention: Jeff Sherrick Telephone: (281) 618-4002 Facsimile: (281) 618-3095 Email: jeff_sherrick@swn.com
With a copy to:	Southwestern Energy Production Company 2350 N. Sam Houston Parkway East, Suite 125 Houston, Texas 77032 Attention: Associate General Counsel Telephone: (281) 618-4819 Facsimile: (281) 618-4820 Email: rick_ogle@swn.com

Either Party may, upon written notice to the other Party, change the address(es) and person(s) to whom such communications are to be directed.

14.3. Survival. The representations and warranties of the Seller contained in this Agreement or in any certificate delivered in connection with this Agreement (other than the representations and warranties in Sections 3.1, 3.5, 3.10, 3.11, 4.1, 4.4 and 4.8), together with the indemnification rights with respect thereto, will survive the Closing Date for a period of twelve (12) months and shall thereafter be of no further force or effect (the “Expiration Date”); provided, however, any representation or warranty as to which a claim shall have been asserted prior to the Expiration Date shall survive until such claim and the indemnity with respect thereto are resolved. The representations and warranties in Sections 3.1, 3.5,

PURCHASE AND SALE AGREEMENT 62

3.10, 3.11, 4.1, 4.4 and 4.8 shall survive the Closing until the expiration of the applicable statute of limitations. Except as otherwise set forth in this Agreement, the remainder of this Agreement shall survive the Closing without time limit. The special warranty of title set forth in the Assignment will survive the Closing Date for a period of five (5) years and shall thereafter be of no further force or effect except that any claim under such special warranty of title which has been asserted prior to the end of such five (5) year period shall survive until such claim with respect thereto is resolved. The intended effect of termination of representations and warranties (and the indemnification rights with respect thereto) and the special warranty of title is to bar, from and after the date of termination, any claim or cause of action based on the alleged inaccuracy of such representation or breach of such warranty, or with regard to claims for indemnity with respect thereto or with respect to such special warranty of title.

14.4. Cooperation. Prior to termination of this Agreement and at all times following the consummation of this Agreement, the Parties agree to execute and deliver, or cause to be executed and delivered, such documents and do, or cause to be done, such other acts and things as might reasonably be requested by any Party to this Agreement to assure that the benefits of this Agreement are realized by the Parties.

14.5. No Third Party Beneficiaries. Except for the indemnification rights of the Seller Indemnified Parties and the Buyer Indemnified Parties under Section 10, nothing in this Agreement, express or implied, is intended to confer upon anyone, other than the Parties hereto and their respective successors and assigns, any rights or remedies under or by reason of this Agreement or to constitute any Person a third party beneficiary of this Agreement; provided, however that the Financing Sources are intended beneficiaries of, and shall be entitled to enforce, Sections 14.10, 14.21 and this Section 14.5.

14.6. Cumulative Remedies. Subject to the other provisions hereof, no failure on the part of any Party to this Agreement to exercise and no delay in exercising any right thereunder will operate as a waiver thereof, nor will any single or partial exercise by any Party hereto of any right hereunder preclude any other or further right of exercise thereof or the exercise of any other right.

14.7. Choice of Law. This Agreement will be interpreted, construed and enforced in accordance with the laws of the State of Texas, without giving effect to any rules or principles of conflicts of law that might otherwise refer to the laws of another jurisdiction.

14.8. Entire Agreement. The Transaction Documents constitute the entire agreement between the Parties with respect to the subject matter hereof and there are no agreements, understandings, warranties or representations except as set forth herein or therein.

PURCHASE AND SALE AGREEMENT 63

14.9. Assignment. No Party may assign such Party’s rights nor delegate such Party’s duties under this Agreement without the express written consent of the other Party to this Agreement.

14.10. Amendment. Neither this Agreement nor any of the provisions thereof can be changed, waived, discharged or terminated, except by an instrument in writing signed by the Party against whom enforcement of the change, waiver, discharge or termination is sought. The Parties agree that the provisions of Section 14.5, this Section 14.10 and Section 14.21 and the definitions of Financing, Financing Commitment, Financing Sources and Finance Related Parties shall not be amended in a manner adverse to the Financing Sources under the Financing Commitments without their prior written consent.

14.11. Severability. If any clause or provision of this Agreement is illegal, invalid or unenforceable under any present or future law, the remainder of this Agreement will not be affected thereby. It is the intention of the Parties that if any such provision is held to be illegal, invalid or unenforceable, there will be added in lieu thereof a provision as similar in terms to such provisions as is possible to make such provision legal, valid and enforceable.

14.12. Attorney Fees. If any Party institutes an action or proceeding against any other Party relating to the provisions of this Agreement, including arbitration, the Party to such action or proceeding which does not prevail will reimburse the prevailing Party therein for the reasonable expenses of attorneys’ fees and disbursements incurred by the prevailing Party.

14.13. Waiver. Waiver of performance of any obligation or term contained in this Agreement by any Party, or waiver by one Party of the other’s default hereunder will not operate as a waiver of performance of any other obligation or term of this Agreement or a future waiver of the same obligation or a waiver of any future default.

14.14. Counterparts; Facsimiles; Electronic Transmission. This Agreement may be executed in multiple counterparts, each of which will be an original instrument, but all of which will constitute one agreement. The execution and delivery of this Agreement by any Party may be evidenced by facsimile or other electronic transmission (including scanned documents delivered by email), which shall be binding upon all Parties.

14.15. JOINT ACKNOWLEDGMENT. THIS WRITTEN AGREEMENT REPRESENTS THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

PURCHASE AND SALE AGREEMENT 64

14.16. WAIVER OF JURY TRIAL, SPECIAL DAMAGES, ETC. EACH OF THE BUYER AND THE SELLER HEREBY KNOWINGLY, VOLUNTARILY, INTENTIONALLY AND IRREVOCABLY (a) WAIVES, TO THE MAXIMUM EXTENT NOT PROHIBITED BY LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY A JURY IN RESPECT OF ANY LITIGATION BASED HEREON, OR DIRECTLY OR INDIRECTLY AT ANY TIME ARISING OUT OF, UNDER OR IN CONNECTION WITH THIS AGREEMENT OR ANY TRANSACTION CONTEMPLATED HEREBY OR ASSOCIATED HEREWITH, (b) WAIVES, TO THE MAXIMUM EXTENT NOT PROHIBITED BY LAW, ANY RIGHT IT MAY HAVE TO CLAIM OR RECOVER IN ANY SUCH LITIGATION OR ARBITRATION ANY “SPECIAL DAMAGES,” AS DEFINED BELOW, AND (c) ACKNOWLEDGES THAT IT HAS BEEN INDUCED TO ENTER INTO THIS AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS CONTAINED IN THIS SECTION, IN EACH CASE IT BEING THE EXPRESS INTENT, UNDERSTANDING, AND AGREEMENT OF THE PARTIES THAT SUCH WAIVERS ARE TO BE GIVEN THE FULLEST EFFECT, NOTWITHSTANDING THE NEGLIGENCE (WHETHER SOLE, JOINT OR CONCURRENT), STRICT LIABILITY OR OTHER LEGAL FAULT OF ANY PARTY. AS USED IN THIS SECTION, “SPECIAL DAMAGES” MEANS ALL SPECIAL, CONSEQUENTIAL, EXEMPLARY OR PUNITIVE DAMAGES (REGARDLESS OF HOW NAMED), BUT DOES NOT INCLUDE ANY PAYMENTS OR FUNDS WHICH ANY PARTY HERETO HAS EXPRESSLY PROMISED TO PAY OR DELIVER TO ANY OTHER PARTY HERETO OR ANY CLAIMS OF ANY THIRD PARTY FOR WHICH ONE PARTY HAS AGREED TO INDEMNIFY THE OTHER PARTY UNDER THIS AGREEMENT.

14.17. Mutuality. The Parties acknowledge and declare that this Agreement is the result of extensive negotiations between them. Accordingly, if there is any ambiguity in this Agreement, there shall be no presumption that this instrument was prepared solely by any Party.

14.18. Schedules. The inclusion of any information (including dollar amounts) in any section of the disclosure Schedules hereto shall not be deemed to be an admission or acknowledgment by the Seller that such information is required to be listed on such Schedule or is material to or outside the Ordinary Course of Business of the Seller. The information contained in this Agreement, the Exhibits and the Schedules hereto is disclosed solely for purposes of this Agreement, and no information contained herein or therein shall be deemed to be an admission by any Party hereto to any Third Party of any matter whatsoever (including any violation of a legal requirement or breach of contract).

14.19. 1031 Like-Kind Exchange. The Seller and Buyer agree that the Seller or Buyer may elect to treat the acquisition or sale of the Properties as an exchange of like-

PURCHASE AND SALE AGREEMENT 65

kind property (an “Exchange”) under section 1031 of the Internal Revenue Code of 1986, as amended (the “Code”); provided, that the Closing shall not be delayed or affected by reason of the Exchange. Each Party agrees to use reasonable efforts to cooperate with the other Parties in the completion of such an Exchange including an Exchange subject to the procedures outlined in Section 1.1031(k)-1 of the United States Treasury Regulations promulgated under the Code (the “Treasury Regulations”) and/or Internal Revenue Service Revenue Procedure 2000-37. Each of the Parties shall have the right at any time prior to Closing to assign all or a portion of its rights under this Agreement to a qualified intermediary (as that term is defined in Treasury Regulation Section 1.1031(k)-1(g)(4)(iii)) or an exchange accommodation titleholder (as that term is defined in Internal Revenue Service Revenue Procedure 2000-37) to effect an Exchange. In connection with any such Exchange, any exchange accommodation title holder shall have taken all steps necessary to own the Properties under applicable Law. Each Party acknowledges and agrees that neither an assignment of a Party’s rights under this Agreement nor any other actions taken by a Party or any other person in connection with the Exchange shall release any Party from, or modify, any of their respective liabilities and obligations (including indemnity obligations to each other) under this Agreement, and no Party makes any representations as to any particular tax treatment that may be afforded to any other Party by reason of such assignment or any other actions taken in connection with the Exchange. Any Party electing to treat the acquisition or sale of the Properties as an Exchange shall be obligated to pay all additional costs incurred hereunder as a result of the Exchange, and in consideration for the cooperation of the other Parties, the Party electing Exchange treatment shall agree to pay all costs associated with the Exchange and to indemnify and hold the other Party, its affiliates and former, current and future partners, members, shareholders, owners, officers, directors, managers, employees, agents and representatives harmless from and against any and all liabilities and taxes arising out of, based upon, attributable to or resulting from the Exchange or transactions or actions taken in connection with the Exchange that would not have been incurred by the other Parties but for the electing Party’s Exchange election.

14.20. Sharing of Certain Financial Information Subsequent to the Execution Date. After the Execution Date, the Seller shall give the Buyer (and/or any of its Affiliates) and its (and/or their, as applicable) representatives reasonable access during normal business hours to those Financial Records (as hereinafter defined), including data necessary for disclosures pursuant to ASC 805, ASC 932 or other requirements of GAAP or the Securities and Exchange Commission, necessary for the Buyer’s or its respective Affiliate’s preparation of financial statements and other financial data relating to the Properties that (a) is necessary to enable the Buyer to furnish the Financing Sources with such financial information regarding the historical performance of the Properties of the type customarily included, and required to be included, in the offering documentation reasonably requested by the Buyer and customary for public offerings of debt and equity securities or (b) may be required to be included in any current or future filing by the Buyer (and/or

PURCHASE AND SALE AGREEMENT 66

any of its Affiliates) with the Securities and Exchange Commission or other Governmental Authority (collectively, the “Financial Statements”).

14.20.1 The Financial Statements data shall be prepared and audited or reviewed at the sole cost and expense of the Buyer. If requested in writing, the Seller shall execute and deliver to the external independent accounting firm that audits, reviews or assists the Buyer or its respective Affiliate in the preparation of the Financial Statements or such other independent accounting firm designated by the Buyer to provide such procedures (the “Audit Firm”), such representation letters, in form and substance customary for representation letters provided to external audit firms by management of the company whose financial statements are the subject of an audit or are the subject of a review pursuant to Public Company Accounting Oversight Board (PCAOB) AU Section 722 (Interim Financial Information), as may be reasonably requested by the Audit Firm, with respect to the Financial Statements, including, as requested, representations regarding internal accounting controls and disclosure controls. As used in this Section 14.20, the term “Financial Records” means all ledgers, books, data, files, and accounting and financial records (whether in physical or electronic form) in the possession of the Seller and its Affiliates, in each case, solely to the extent related to the Properties; provided, however, “Financial Records” does not include any records or information (a) that the Seller considers to be confidential and proprietary, or (b) that may be protected by an attorney-client privilege, or (c) that cannot be disclosed to the Buyer or its representatives as a result of confidentiality arrangements with third parties.

14.20.2 The obligations of the Seller under this Section 14.20 shall expire on the earlier of (a) termination of this Agreement or (b) ninety (90) days after the close of the 2014 fiscal year of the Seller unless a request with respect to Financial Statements has been made prior to such time, in which event the obligations of the Seller shall continue until the preparation of such Financial Statements has been completed.

14.21. No Recourse to Financing Sources. Notwithstanding any provision of this Agreement, the Seller agrees on its behalf and on behalf of its Affiliates that no Financing Source or Finance Related Parties under any Financing Commitment nor any other Financing Source shall have any liability or obligation to the Seller and its Affiliates relating to this Agreement or any of the transactions contemplated hereby (including the Financing), whether at law, in equity, in contract, in tort or otherwise, in each case, whether arising, in whole or in part, out of comparative, contributory or sole negligence by any Financing Source or any Finance Related Party.

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IN WITNESS WHEREOF, the Seller has executed this Agreement on the Execution Date.

	SELLER:
	CHESAPEAKE APPALACHIA, L.L.C.,
	an Oklahoma limited liability company
By:	/s/ Douglas J. Jacobson
	Douglas J. Jacobson, Executive Vice President

SIGNATURE PAGE TO PURCHASE AND SALE AGREEMENT

IN WITNESS WHEREOF, the Buyer has executed this Agreement on the Execution Date.

	BUYER:
	SOUTHWESTERN ENERGY PRODUCTION COMPANY,
	a Texas corporation
By:	/s/ Jeffrey B. Sherrick
	Jeffrey B. Sherrick, Executive Vice President, Corporate Development

SIGNATURE PAGE TO PURCHASE AND SALE AGREEMENT

EX-2.1.2

Exhibit 2.1.2

AMENDMENT TO
PURCHASE AND SALE AGREEMENT

This AMENDMENT TO PURCHASE AND SALE AGREEMENT (this “Amendment”) is entered into this 22^nd day of December, 2014, between CHESAPEAKE APPALACHIA, L.L.C., an Oklahoma limited liability company (the “Seller”), and SWN PRODUCTION COMPANY, LLC, a Texas limited liability company, formerly known as SOUTHWESTERN ENERGY PRODUCTION COMPANY, a Texas corporation (the “Buyer”). The Buyer and the Seller are referred to herein, individually, as a “Party” and, collectively, as the “Parties”. Capitalized terms used and not otherwise defined herein will have the meanings given such terms in the Purchase and Sale Agreement entered into by the Parties on October 14, 2014 (the “PSA”).

WHEREAS, the Parties entered into the PSA, pursuant to which the Seller agreed to sell, and the Buyer agreed to purchase, all of the Seller’s right, title and interest in and to the Properties; and

WHEREAS, the Parties desire to amend the PSA in accordance with the terms and conditions set forth herein;

NOW, THEREFORE, for and in consideration of the mutual covenants herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby amend the PSA as follows:

1.    Amendment of Section 8.1. Section 8.1 of the PSA is hereby amended by: (a) the deletion of the word “and” at the end of Section 8.1.6, (b) the addition thereto of a new subpart 8.1.7, as follows: “Transition Agreement. An original counterpart of a Transition Services Agreement signed on behalf of the Buyer in a form agreed by the Parties; and”, and (c) the renumbering of the existing Section 8.1.7 as Section 8.1.8.

2.Amendment of Section 8.2. Section 8.2 of the PSA is hereby amended by: (a) the deletion of the word “and” at the end of Section 8.2.11, (b) the addition thereto of a new subpart 8.2.12, as follows: “Transition Agreement. An original counterpart of a Transition Services Agreement signed on behalf of the Seller in a form agreed by the Parties; and”, and (c) the renumbering of the existing Section 8.2.12 as Section 8.2.13.

3.Replacement of Certain Exhibits. Each of Exhibit A-1, Exhibit A-2,Exhibit B-1, Exhibit C, Exhibit E and Exhibit Gto the PSA is hereby deleted in its entirety and Exhibit A-1, Exhibit A-2, Exhibit C and Exhibit G attached to this Amendment are hereby substituted therefor in all respects. The foregoing replacements of Exhibit A-1, Exhibit A-2, Exhibit B-1, Exhibit C, Exhibit E and Exhibit G to the PSA shall be effective for all purposes as of the Execution Date and shall not affect the Purchase Price. Any references to any of Exhibit A-1, Exhibit A-2, Exhibit B-1, Exhibit C, Exhibit E or Exhibit G in the PSA shall be deemed to be references to the corresponding replacement Exhibit A-1, Exhibit A-2, Exhibit B-1, Exhibit C, Exhibit Eor Exhibit G attached hereto.

4.Replacement of Schedule 3.8 and Schedule 5.8.1. Each of Schedule 3.8 and Schedule 5.8.1attached to the PSA is hereby deleted in its entirety, and Schedule 3.8 and Schedule 5.8.1

attached to this Amendment are hereby substituted therefor in all respects. The foregoing replacement of Schedule 3.8 and Schedule 5.8.1shall be effective for all purposes as of the Execution Date. Any references to Schedule 3.8 or Schedule 5.8.1in the PSA shall be deemed to be references to the corresponding replacement Schedule 3.8 or Schedule 5.8.1 attached hereto.

5.Midstream Assignments. Section 5.8.3 is hereby deleted in its entirety and replaced with the following:

5.8.3    Form of Assignment. Prior to February 1, 2015 (the “Midstream Assignment Date”), the Seller and the Buyer will negotiate in good faith mutually acceptable forms of assignment, assumption and, as applicable, and consent and release agreements to effect, in accordance with the terms of this Agreement, the assignments, on or before the Midstream Assignment Date, to the Buyer of the Midstream Consent Contracts (subject to Section 5.8.2) and all other gathering Contracts set forth on Exhibit C (collectively, the “Midstream Agreements” and such assignment, assumption and consent agreements for the Midstream Agreements, collectively, the “Midstream Assignments”). On or before the Midstream Assignment Date, the Seller will assign (and cause CEMI to assign) its rights and obligations contained in the Midstream Agreements (subject to Section 5.8.2), and, subject to the provisions of the Transition Agreement, the Buyer will assume (and, upon delivery by the Seller of the Assignment, the Buyer shall be deemed to have assumed), and thereafter will be bound by and comply with and perform, all of the obligations of CEMI and the Seller contained in the assigned Midstream Agreements; in each such case, from and after the Effective Time and solely to the extent pertaining to the Properties. Seller will continue to conduct its operations with respect to the Midstream Agreements consistent with the provisions of Section 5.2, subject to the caveats and liability limitations contained therein until the Midstream Assignment Date.

6.Amendment Compliance. The Parties acknowledge that this Amendment complies with the requirements to alter or amend the Agreement, as stated in Section 14.10 of the Agreement.

7.Entire Agreement. The PSA, as amended hereby, and the other documents to be executed under the PSA, as amended hereby, and the exhibits and schedules thereto, as amended hereby, constitute the entire agreement between the Parties with respect to the subject matter thereof, and there are no other agreements, understandings, warranties or representations except as set forth herein and therein. In the event of a conflict between the terms of this Amendment and the terms of the PSA, the terms of this Amendment will control.

8.Counterparts; Facsimiles, Electronic Transmission. This Amendment may be executed in multiple counterparts, each of which will be an original instrument, but all of which will constitute one amendment. The execution and delivery of this Amendment by any Party may be evidenced by facsimile or other electronic transmission (including scanned documents delivered by email), which will be binding upon all Parties.

2

9.Ratification. Each of the Seller and the Buyer hereby adopts, ratifies, and confirms the PSA, as amended hereby, and declares the PSA, as amended hereby, to be in full force and effect. All references to the PSA shall be considered to be references to the PSA as modified by this Amendment, and, except as modified hereby, the PSA shall remain in full force and effect.

10.Construction. This Amendment will be interpreted, construed and enforced in accordance with the laws of the State of Texas. The provisions of Sections 13 and 14 of the Agreement are incorporated herein, with any necessary modifications.

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3

IN WITNESS WHEREOF, the Seller has executed this Amendment on the date first above written but effective as of the Execution Date.

	SELLER:
	CHESAPEAKE APPALACHIA, L.L.C.,
	an Oklahoma limited liability company
By:	/s/ Douglas J. Jacobson
	Douglas J. Jacobson, Executive Vice President

SIGNATURE PAGE TO AMENDMENT TO PURCHASE AND SALE AGREEMENT

IN WITNESS WHEREOF, the Buyer has executed this Amendment on the date first above written but effective as of the Execution Date.

	BUYER:
	SWN PRODUCTION COMPANY, LLC, a Texas limited liability company, formerly known as SOUTHWESTERN ENERGY PRODUCTION COMPANY, a Texas corporation
By:	/s/ Jeffrey B. Sherrick
	Jeffrey B. Sherrick, Executive Vice President, Corporate Development

SIGNATURE PAGE TO AMENDMENT TO PURCHASE AND SALE AGREEMENT

EX-2.1.3

Exhibit 2.1.3

SETTLEMENT AGREEMENT

THIS SETTLEMENT AGREEMENT (this “Agreement”) is made and entered into as of this 22^nd day of December, 2014, by and between CHESAPEAKE APPALACHIA, L.L.C., an Oklahoma limited liability company (the “Seller”), and SWN PRODUCTION COMPANY, LLC, a Texas limited liability company, formerly known as SOUTHWESTERN ENERGY PRODUCTION COMPANY, a Texas corporation (the “Buyer”). The Buyer and the Seller are referred to herein, individually, as a “Party” and, collectively, as the “Parties”. Capitalized terms used and not otherwise defined herein will have the meanings given such terms in the Purchase and Sale Agreement entered into by the Parties on October 14, 2014 (the “PSA”).

WHEREAS, certain disputes have arisen between the Parties regarding various representations, covenants and other matters under the terms and provisions of the PSA; and,

WHEREAS, the Parties desire to resolve those disputes in accordance with the terms and conditions of this Agreement.

NOW THEREFORE, for and in consideration of the mutual benefits to be derived by the Parties, the receipt and sufficiency of which are hereby acknowledged, together with the mutual covenants, conditions and obligations contained herein, the Parties hereby agree as follows:

1. Settlement. In exchange for the Seller’s agreement to: (a) waive and release all rights of the Seller to claim Title Benefits under the PSA, and (b) a downward adjustment to the Purchase Price in the amount of Four Hundred Million Dollars ($400,000,000.00), the Buyer hereby waives and releases: (i) with respect to any of the Properties, (A) all rights of the Buyer to make any claims for Environmental Defects or Title Defects or (B) with respect to the special warranty of title under the Assignments and Fee Mineral Leases, except to the extent specifically set forth below, (ii) any breaches of the covenants and agreements of Seller under Section 5.2.1(e) of the PSA, (iii) any breaches of any representations, warranties or covenants including Sections 3.8 and 5.2 as a result of the omission from Exhibit C or Schedule 3.8 of the PSA of that certain Amended and Restated Gas Gathering Contract and Novation dated effective as of July 1, 2012, by and among Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Seller and Appalachia Midstream Services, L.L.C., (iv) any breaches of any representations, warranties or covenants including Sections 3.8 and 5.2 as a result of the Seller failing to disclose the release of the Seller’s rights to Train 6 under that certain Second Amended and Restated Gas Processing Agreement dated April 24, 2012, by and between Markwest Liberty Midstream & Resources, L.L.C. and Chesapeake Energy Marketing, Inc. or otherwise relating to the Seller releasing the Seller’s rights to Train 6 under such Markwest agreement, and (v) any and all rights of the Buyer to claim indemnities under Section 10.2 of the PSA with respect to any of the matters set forth in subparts (i), (ii), (iii) and (iv) of this Section 1. The waiver and release with respect to the special warranty of title set forth in subpart (i)(B) above will not apply to claims made with respect to title to the Properties by any person claiming by, through or under the Seller with respect to actions by the Seller during the period from the Effective Time to the Closing Date. The Parties hereby agree that the Assignments and Fee Mineral Leases

will be revised in accordance with the waiver and release of the special warranty of title and limited exception thereto as set forth in this Section 1.

2. Effective Date of Settlement. The Seller and the Buyer hereby acknowledge and agree that the terms of conditions of the settlement set forth in Section 1 of this Agreement will not be effective until such time as the Buyer, the Seller and SUSA have each executed and delivered that certain Consent and Confirmation attached as Exhibit G to the Amendment to the PSA dated December 22, 2014 between the Seller and the Buyer (the “Consent”). Upon the date of execution and delivery of the Consent (the “Effective Date”) by the Buyer, the Seller and SUSA, this Agreement and all of the terms and conditions set forth herein shall be effective and binding upon the Parties as of the Effective Date including, without limitation, the Seller’s waiver and release of any Title Benefits and agreement to adjust the Purchase Price under subparts (a) and (b) of Section 1 hereof and the waivers and releases of the Buyer under subparts (i), (ii), (iii), (iv) and (v) of Section 1 hereof.

3. Entire Agreement. This instrument constitutes the entire and complete understanding of the Parties hereto with respect to the subject matter hereof, constitutes their full and final settlement with respect to the matters set forth herein, and supersedes all prior agreements, arrangements and representations relating to the subject matter of this Agreement.

4. Representations and Acknowledgments. Each Party to this Agreement acknowledges that no representations, inducements, promises, understandings or agreements, oral or otherwise, have been made by the other Party, or anyone acting on behalf of the other Party, that are not embodied herein. Each Party has relied upon such advice as it has deemed necessary together with its own judgment, and enters into this Agreement of its own free will, to accomplish the mutual intent of the Parties hereto, and not based upon any representation, inducement, promise, understanding or assurance made by the other Party. Each Party represents and acknowledges that such Party has had the opportunity to seek the advice of any person necessary to fully evaluate this Agreement, including counsel, regarding the effect, implications and ramifications of the terms of this Agreement.

5. No Admissions. The Parties agree that nothing contained herein, and no actions taken by either Party hereto with regard to this Agreement, shall be construed as an admission by either Party of liability as to any of the matters settled. No action taken by either Party in effecting this Agreement may be used in any future or pending demand, administrative proceeding, litigation, or similar action involving the Parties, as an admission of liability in any respect.

6. No Third Party Beneficiaries. Nothing in this Agreement, express or implied, is intended to confer upon anyone, other than the Parties hereto and their respective successors and assigns, any rights or remedies under or by reason of this Agreement or to constitute any Person a third party beneficiary of this Agreement.

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7. Counterparts; Facsimiles, Electronic Transmission. This Agreement may be executed in multiple counterparts, each of which will be an original instrument, but all of which will constitute one amendment. The execution and delivery of this Agreement by either Party may be evidenced by facsimile or other electronic transmission (including scanned documents delivered by email), which will be binding upon both Parties.

8. Construction. This Amendment will be interpreted, construed and enforced in accordance with the laws of the State of Texas. The provisions of Sections 13 and 14 of the PSA are incorporated herein, with any necessary modifications.

9. Mutuality. The Parties acknowledge and declare that this Agreement is the result of extensive negotiations between them. Accordingly, if there is any ambiguity in this Agreement, there shall be no presumption that this instrument was prepared solely by either Party.

10. Binding Effect. This Agreement shall be binding upon and shall inure to the benefit of the Parties to this Agreement and their respective successors and assigns.

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK
SIGNATURE PAGES FOLLOW]

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IN WITNESS WHEREOF, the Buyer has executed this Agreement as of the date first above written but effective for all purposes as of the Effective Date.

	BUYER:
	SWN PRODUCTION COMPANY, LLC, a Texas limited liability company, formerly known as SOUTHWESTERN ENERGY PRODUCTION COMPANY, a Texas corporation
By:	/s/ Jeffrey B. Sherrick
	Jeffrey B. Sherrick, Executive Vice President, Corporate Development

SIGNATURE PAGE TO SETTLEMENT AGREEMENT

IN WITNESS WHEREOF, the Seller has executed this Agreement as of the date first above written but effective for all purposes as of the Effective Date.

	SELLER:
	CHESAPEAKE APPALACHIA, L.L.C.,
	an Oklahoma limited liability company
By:	/s/ Douglas J. Jacobson
	Douglas J. Jacobson, Executive Vice President

SIGNATURE PAGE TO SETTLEMENT AGREEMENT

EX-10.4

Exhibit 10.4

CHESAPEAKE ENERGY CORPORATION

AMENDED AND RESTATED DEFERRED COMPENSATION PLAN

EFFECTIVE JANUARY 1, 2008

Chesapeake Energy Corporation Amended and Restated Deferred

Compensation Plan

ARTICLE I
Establishment and Purpose	1
ARTICLE II
Definitions	1
ARTICLE III
Eligibility and Participation	10
ARTICLE IV
Deferrals	10
ARTICLE V
Company Contributions	14
ARTICLE VI
Benefits	16
ARTICLE VII
Modifications to Payment Schedules	21
ARTICLE VIII
Valuation of Account Balances; Investments	22
ARTICLE IX
Administration	23
ARTICLE X
Amendment and Termination	25
ARTICLE XI
Informal Funding	25
ARTICLE XII
Claims	26
ARTICLE XIII
General Provisions	32

Chesapeake Energy Corporation Amended and Restated Deferred

Compensation Plan

ARTICLE I

Establishment and Purpose

Chesapeake Energy Corporation (the "Company") established the Chesapeake Energy Corporation Deferred Compensation Plan, effective as of January 1, 2003, and the Chesapeake Energy Corporation 401(k) Make-Up Plan, also effective as of January 1, 2003 (the "Prior Plans"). The Company hereby amends and restates the Prior Plans, effective January 1, 2008, into a single plan, to be hereafter known as the Chesapeake Energy Corporation Amended and Restated Deferred Compensation Plan" (the "Plan").

This amendment and restatement applies only to amounts deferred under the Prior Plans on or after January 1, 2005, and to amounts deferred prior to January 1, 2005 that were not vested as of December 31, 2004. Amounts deferred under the Prior Plans prior to January 1, 2005 that were vested as of December 31, 2004 (the "Grandfathered Accounts") shall be subject to the provisions of the Prior Plans as in effect on October 3, 2004, as the same may be amended from time to time by the Company without material modification, it being expressly intended that such Grandfathered Accounts are to remain exempt from the requirements of Code Section 409A. The provisions of the Plan applicable to Grandfathered Accounts are reflected in this document for ease of reference.

The purpose of the Plan continues to be to attract and retain key employees and Directors by providing each Participant with an opportunity to defer receipt of a portion of their salary, bonus, and other specified compensation. The Plan is not intended to meet the qualification requirements of Code Section 401(a), but is intended to meet the requirements of Code Section 409A, and shall be operated and interpreted consistent with that intent.

The Plan constitutes an unsecured promise by a Participating Employer to pay benefits in the future. Participants in the Plan shall have the status of general unsecured creditors of the Company or the Adopting Employer, as applicable. Each Participating Employer shall be solely responsible for payment of the benefits of its employees and their beneficiaries. The Plan is unfunded for Federal tax purposes and is intended to be an unfunded arrangement for eligible employees who are part of a select group of management or highly compensated employees of the Employer within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of ERISA. Any amounts set aside to defray the liabilities assumed by the Company or an Adopting Employer will remain the general assets of the Company or the Adopting Employer and shall remain subject to the claims of the Company's or the Adopting Employer's creditors until such amounts are distributed to the Participants.

ARTICLE II

Definitions

2.1 Account. Account means a bookkeeping account maintained by the Committee to record the payment obligation of a Participating Employer to a Participant as determined under the terms of the Plan. The Committee may maintain an Account to record the total

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Compensation Plan

obligation to a Participant and component Accounts to reflect amounts payable at different times and in different forms. Reference to an Account means any such Account established by the Committee, as the context requires. Accounts are intended to constitute unfunded obligations within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of ERISA.

2.2 Account Balance. Account Balance means, with respect to any Account, the total payment obligation owed to a Participant from such Account as of the most recent Valuation Date.

2.3 Adopting Employer. Adopting Employer means an Affiliate who, with the consent of the Committee, has adopted the Plan for the benefit of its eligible employees.

2.4 Affiliate. Affiliate means a corporation, trade or business that, together with the Company, is treated as a single employer under Code Section 414(b) or (c).

2.5 Beneficiary. Beneficiary means a natural person, estate, or trust designated by a Participant to receive payments to which a Beneficiary is entitled in accordance with provisions of the Plan. The Participant's spouse, if living, otherwise the Participant's estate, shall be the Beneficiary if: (i) the Participant has failed to properly designate a Beneficiary, or (ii) all designated Beneficiaries have predeceased the Participant.

A former spouse shall have no interest under the Plan, as Beneficiary or otherwise, unless the Participant designates such person as a Beneficiary after dissolution of the marriage.

2.6 Business Day. A Business Day is each day on which the New York Stock Exchange is open for business.

2.7 Change in Control. Change in Control, with respect to a Participating Employer that is organized as a corporation, occurs on the date on which any of the following events occur (i) a change in the ownership of the Participating Employer; (ii) a change in the effective control of the Participating Employer; (iii) a change in the ownership of a substantial portion of the assets of the Participating Employer.

For purposes of this Section, a change in the ownership of the Participating Employer occurs on the date on which any one person, or more than one person acting as a group, acquires ownership of stock of the Participating Employer that, together with stock held by such person or group constitutes more than 50% of the total fair market value or total voting power of the stock of the Participating Employer. A change in the effective control of the Participating Employer occurs on the date on which either (i) a person, or more than one person acting as a group, acquires ownership of stock of the Participating Employer possessing 35% or more of the total voting power of the stock of the Participating Employer, taking into account all such stock acquired during the 12-month period ending on the date of the most recent acquisition, or (ii) a majority of the members

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Compensation Plan

of the Participating Employer's Board of Directors is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of such Board of Directors prior to the date of the appointment or election, but only if no other corporation is a majority shareholder of the Participating Employer . A change in the ownership of a substantial portion of assets occurs on the date on which any one person, or more than one person acting as a group, other than a person or group of persons that is related to the Participating Employer, acquires assets from the Participating Employer that have a total gross fair market value equal to or more than 40% of the total gross fair market value of all of the assets of the Participating Employer immediately prior to such acquisition or acquisitions, taking into account all such assets acquired during the 12-month period ending on the date of the most recent acquisition.

An event constitutes a Change in Control with respect to a Participant only if the Participant performs services for the Participating Employer that has experienced the Change in Control, or the Participant's relationship to the affected Participating Employer otherwise satisfies the requirements of Treasury Regulation Section 1.409A-3(i)(5)(ii).

The determination as to the occurrence of a Change in Control shall be based on objective facts and in accordance with the requirements of Code Section 409A.

2.8 Claimant. Claimant means a Participant or Beneficiary filing a claim under Article XII of this Plan.

2.9 Code. Code means the Internal Revenue Code of 1986, as amended from time to time.

2.10 Code Section 409A. Code Section 409A means section 409A of the Code, and regulations and other guidance issued by the Treasury Department and Internal Revenue Service thereunder.

2.11 Committee. Committee means the committee appointed by the Board of Directors of the Company (or the appropriate committee of such board) to administer the Plan. If no designation is made, the Chief Executive Officer of the Company or his delegate shall have and exercise the powers of the Committee.

2.12 Company. Company means Chesapeake Energy Corporation.

2.13 Company Contribution. Company Contribution means a credit by a Participating Employer to a Participant's Account(s) in accordance with the provisions of Article V of the Plan. Company Contributions are credited at the sole discretion of the Participating Employer and the fact that a Company Contribution is credited in one year shall not obligate the Participating Employer to continue to make such Company Contribution in subsequent years. Unless the context clearly indicates otherwise, a reference to Company Contribution shall include Earnings attributable to such contribution.

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Compensation Plan

2.14 Company Stock. Company Stock means phantom shares of common stock issued by the Company.

2.15 Compensation. Compensation means a Participant's base salary, bonus, commission, Director fees, and such other cash or equity-based compensation (if any) identified by the Committee on Exhibit B attached hereto as Compensation that may be deferred under this Plan. Compensation shall not include any compensation that has been previously deferred under this Plan or any other arrangement subject to Code Section 409A. The types of deferrable Compensation identified on Exhibit B may be amended from time to time by the Committee without formal amendment of the Plan.

2.16 Compensation Deferral Agreement. Compensation Deferral Agreement means an agreement between a Participant and a Participating Employer that specifies (i) the amount of each component of Compensation that the Participant has elected to defer to the Plan in accordance with the provisions of Article IV, and (ii) the Payment Schedule applicable to one or more Accounts. The Committee may permit different deferral amounts for each component of Compensation and may establish a minimum or maximum deferral amount for each such component. Unless otherwise specified by the Committee in the Compensation Deferral Agreement, Participants may defer up to 75% of their base salary and up to 100% of other types of Compensation for a Plan Year. A Compensation Deferral Agreement may also specify the investment allocation described in Section 8.4.

2.17 Death Benefit. Death Benefit means the benefit payable under the Plan to a Participant's Beneficiary(ies) upon the Participant's death as provided in Section 6.1 of the Plan.

2.18 Deferral. Deferral means a credit to a Participant's Account(s) that records that portion of the Participant's Compensation that the Participant has elected to defer to the Plan in accordance with the provisions of Article IV. Unless the context of the Plan clearly indicates otherwise, a reference to Deferrals includes Earnings attributable to such Deferrals.

Deferrals shall be calculated with respect to the gross cash Compensation payable to the Participant prior to any deductions or withholdings, but shall be reduced by the Committee as necessary so that it does not exceed 100% of the cash Compensation of the Participant remaining after deduction of all required income and employment taxes, 401(k) and other employee benefit deductions, and other deductions required by law. Changes to payroll withholdings that affect the amount of Compensation being deferred to the Plan shall be allowed only to the extent permissible under Code Section 409A.

2.19 Director. Director means a member of the Board of Directors of the Company.

2.20 Disability Benefit. Disability Benefit means the benefit payable under the Plan to a Participant in the event such Participant is determined to be Disabled.

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Compensation Plan

2.21 Disabled. Disabled means that a Participant is, by reason of any medically-determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve months, (i) unable to engage in any substantial gainful activity, or (ii) receiving income replacement benefits for a period of not less than three months under an accident and health plan covering employees of the Participant's employer. The Committee shall determine whether a Participant is Disabled in accordance with Code Section 409A provided, however, that a Participant shall be deemed to be Disabled if determined to be totally disabled by the Social Security Administration or the Railroad Retirement Board. Notwithstanding anything to the contrary herein, Disability with respect to a Grandfathered Account means a physical or mental disability as a result of which, at least 180 days after commencement of such disability, the Participant is determined, by a physician selected by the Company and acceptable to the Participant or the Participant's legal representative, to be totally and permanently disabled.

2.22 Earnings. Earnings means a positive or negative adjustment to the value of an Account, based upon the allocation of the Account by the Participant among deemed investment options in accordance with Article VIII.

2.23 Effective Date. Effective Date means January 1, 2008.

2.24 Eligible Employee. Eligible Employee means, for a Plan Year, a member of a "select group of management or highly compensated employees" of a Participating Employer within the meaning of Sections 201(2), 30l(a)(3) and 401(a)(l) of ERISA, as determined by the Committee from time to time in its sole discretion, who has been designated by the Committee as eligible to participate in the Plan. The Committee may in its discretion establish criteria to use in determining which Employees are Eligible Employees, which criteria may include income level, period of employment, participation in other plans, or such other criteria as it may deem appropriate. Any criteria established may be described on an Exhibit A to the Plan, and such criteria can be amended from time to time without formal amendment of the Plan.

2.25 Employee. Employee means a common-law employee of an Employer.

2.26 Employer. Employer means, with respect to Employees it employs, the Company and each Affiliate.

2.27 ERISA. ERISA means the Employee Retirement Income Security Act of 1974, as amended from time to time.

2.28 Fiscal Year Compensation. Fiscal Year Compensation means Compensation earned during one or more consecutive fiscal years of a Participating Employer, all of which is paid after the last day of such fiscal year or years.

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Compensation Plan

2.29 Grandfathered Account. Grandfathered Account means amounts deferred under the Prior Plans prior to January 1, 2005 that were vested as of December 31, 2004.

2.30 Participant. Participant means an Eligible Employee or a Director who has received notification of his or her eligibility to defer Compensation under the Plan under Section 3.1 and any other person with an Account Balance greater than zero, regardless of whether such individual continues to be an Eligible Employee or a Director. A Participant's continued participation in the Plan shall be governed by Section 3.2 of the Plan.

2.31 Participating Employer. Participating Employer means the Company and each Adopting Employer.

2.32 Payment Schedule. Payment Schedule means the date as of which payment of an Account under the Plan will commence and the form in which payment of such Account will be made.

2.33 Performance-Based Compensation. Performance-Based Compensation means Compensation where the amount of, or entitlement to, the Compensation is contingent on the satisfaction of pre-established organizational or individual performance criteria relating to a performance period of at least twelve consecutive months. Organizational or individual performance criteria are considered pre-established if established in writing by not later than ninety (90) days after the commencement of the period of service to which the criteria relate, provided that the outcome is substantially uncertain at the time the criteria are established. The determination of whether Compensation qualifies as "Performance-Based Compensation" will be made in accordance with Treas. Reg. Section 1.409A-l(e) and subsequent guidance.

2.34 Plan. Generally, the term Plan means the "Chesapeake Energy Corporation Amended and Restated Deferred Compensation Plan" as documented herein and as may be amended from time to time hereafter. However, to the extent permitted or required under Code Section 409A, the term Plan may in the appropriate context also mean a portion of the Plan that is treated as a single plan under Treas. Reg. Section 1.409A-l(c), or the Plan or portion of the Plan and any other nonqualified deferred compensation plan or portion thereof that is treated as a single plan under such section.

2.35 Plan Year. Plan Year means January 1 through December 31.

2.36 Qualified Plan. Qualified Plan means the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan.

2.37 Retirement. Retirement means a Participant's Separation from Service after attainment of age fifty-five (55) and completion often (10) Years of Service.

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Compensation Plan

2.38 Retirement Benefit. Retirement Benefit means the benefit payable to a Participant under the Plan following the Retirement of the Participant.

2.39 Retirement/Termination Account. Retirement/Termination Account means an Account established by the Committee to record the amounts payable to a Participant that have not been allocated to a Specified Date Account. Unless the Participant has established a Specified Date Account, all Deferrals and Company Contributions shall be allocated to a Retirement/Termination Account on behalf of the Participant.

2.40 Separation from Service. An Employee incurs a Separation from Service upon termination of employment with the Employer. A Director incurs a Separation from Service upon the expiration of all contracts with the Employer, provided the contractual relationship has in good faith been completely terminated. Whether a Separation from Service has occurred shall be determined by the Committee in accordance with Code Section 409A.

Except in the case of an Employee on a bona fide leave of absence as provided below, an Employee is deemed to have incurred a Separation from Service if the Employer and the Employee reasonably anticipated that the level of services to be performed by the Employee after a date certain would be reduced to 20% or less of the average services rendered by the Employee during the immediately preceding 36-month period (or the total period of employment, if less than 36 months), disregarding periods during which the Employee was on a bona fide leave of absence.

An Employee who is absent from work due to military leave, sick leave, or other bona fide leave of absence shall incur a Separation from Service on the first date immediately following the later of (i) the six-month anniversary of the commencement of the leave or (ii) the expiration of the Employee's right, if any, to reemployment under statute or contract.

If a Participant is both a Director and an Employee, the services provided as a Director shall be disregarded in determining whether there has been a Separation from Service as an Employee, and the services provided as an Employee shall be disregarded in determining whether there has been a Separation from Service as a Director, provided the portion of the Plan in which the Participant participates as a Director is substantially similar to arrangements covering non-Employee Directors.

For purposes of determining whether a Separation from Service has occurred, the Employer means the Employer as defined in Section 2.26 of the Plan, except that in applying Code sections 1563(a)(1), (2) and (3) for purposes of determining whether another organization is an Affiliate of the Company under Code Section 414(b), and in applying Treasury Regulation Section 1.414(c)-2 for purposes of determining whether another organization is an Affiliate of the Company under Code Section 414(c), "at least

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Compensation Plan

50 percent" shall be used instead of "at least 80 percent" each place it appears in those sections.

The Committee specifically reserves the right to determine whether a sale or other disposition of substantial assets to an unrelated party constitutes a Separation from Service with respect to a Participant providing services to the seller immediately prior to the transaction and providing services to the buyer after the transaction. Such determination shall be made in accordance with the requirements of Code Section 409A.

2.41 Specified Date Account. A Specified Date Account means an Account established pursuant to Section 4.3 that will be paid (or that will commence to be paid) at a future date as specified in the Participant's Compensation Deferral Agreement. Unless otherwise determined by the Committee, a Participant may maintain no more than five (5) Specified Date Accounts. A Specified Date Account may be identified in enrollment materials as an "In-Service Account".

2.42 Specified Date Benefit. Specified Date Benefit means the benefit payable to a Participant under the Plan in accordance with Section 6.1(c).

2.43 Specified Employee. Specified Employee means an Employee who, as of the date of his Separation from Service, is a "key employee" of the Company or any Affiliate, any stock of which is actively traded on an established securities market or otherwise. An Employee is a key employee if he meets the requirements of Code Section 416(i)(l)(A)(i), (ii), or (iii) (applied in accordance with applicable regulations thereunder and without regard to Code Section 416(i)(5)) at any time during the 12-month period ending on the Specified Employee Identification Date. Such Employee shall be treated as a key employee for the entire 12-month period beginning on the Specified Employee Effective Date.

For purposes of determining whether an Employee is a Specified Employee, the compensation of the Employee shall be determined in accordance with the definition of compensation provided under Treas. Reg. Section 1.415(c)-2(d)(3) (wages within the meaning of Code section 3401(a) for purposes of income tax withholding at the source, plus amounts excludible from gross income under section 125(a), 132(t)(4), 402(e)(3), 402(h)(l)(B), 402(k) or 457(b), without regard to rules that limit the remuneration included in wages based on the nature or location of the employment or the services performed); provided, however, that, with respect to a nonresident alien who is not a Participant in the Plan, compensation shall not include compensation that is not includible in the gross income of the Employee under Code Sections 872, 893, 894, 911, 931 and 933, provided such compensation is not effectively connected with the conduct of a trade or business within the United States.

Notwithstanding anything in this paragraph to the contrary, (i) if a different definition of compensation has been designated by the Company with respect to another nonqualified

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Compensation Plan

deferred compensation plan in which a key employee participates, the definition of compensation shall be the definition provided in Treas. Reg. Section 1.409A-l(i)(2), and (ii) the Company may through action that is legally binding with respect to all nonqualified deferred compensation plans maintained by the Company, elect to use a different definition of compensation.

In the event of corporate transactions described in Treas. Reg. Section 1.409A-1(i)6), the identification of Specified Employees shall be determined in accordance with the default rules described therein, unless the Employer elects to utilize the available alternative methodology through designations made within the timeframes specified therein.

2.44 Specified Employee Identification Date. Specified Employee Identification Date means December 31, unless the Employer has elected a different date through action that is legally binding with respect to all nonqualified deferred compensation plans maintained by the Employer.

2.45 Specified Employee Effective Date. Specified Employee Effective Date means the first day of the fourth month following the Specified Employee Identification Date, or such earlier date as is selected by the Committee.

2.46 Substantial Risk of Forfeiture. Substantial Risk of Forfeiture shall have the meaning specified in Treas. Reg. Section 1.409A-l(d).

2.47 Termination Benefit. Termination Benefit means the benefit payable to a Participant under the Plan following the Participant's Separation from Service prior to Retirement.

2.48 Unforeseeable Emergency. An Unforeseeable Emergency means a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participant's spouse, the Participant's dependent (as defined in Code section 152, without regard to section 152(b)(l), (b)(2), and (d)(l)(B)), or a Beneficiary; loss of the Participant's property due to casualty (including the need to rebuild a home following damage to a home not otherwise covered by insurance, for example, as a result of a natural disaster); or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant. The types of events which may qualify as an Unforeseeable Emergency may be limited by the Committee.

2.49 Valuation Date. Valuation Date shall mean each Business Day.

2.50 Year of Service. A Year of Service shall mean each 12-month period of continuous service with the Employer.

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Compensation Plan

ARTICLE III

Eligibility and Participation

3.1 Eligibility and Participation. An Eligible Employee or a Director becomes a Participant upon the earlier to occur of (i) a credit of Company Contributions under Article V or (ii) receipt of notification of eligibility to participate.

3.2 Duration. A Participant shall be eligible to defer Compensation and receive allocations of Company Contributions, subject to the terms of the Plan, for as long as such Participant remains an Eligible Employee or a Director. A Participant who is no longer an Eligible Employee or a Director but has not Separated from Service may not defer Compensation under the Plan beyond the Plan Year in which he or she became ineligible but may otherwise exercise all of the rights of a Participant under the Plan with respect to his or her Account(s). On and after a Separation from Service, a Participant shall remain a Participant as long as his or her Account Balance is greater than zero and during such time may continue to make allocation elections as provided in Section 8.4. An individual shall cease being a Participant in the Plan when all benefits under the Plan to which he or she is entitled have been paid.

ARTICLE IV

Deferrals

4.1    Deferral Elections, Generally.

(a) A Participant shall submit a Compensation Deferral Agreement during the enrollment periods established by the Committee and in the manner specified by the Committee, but in any event, in accordance with Section 4.2. A Compensation Deferral Agreement that is not timely filed with respect to a service period or component of Compensation shall be considered void and shall have no effect with respect to such service period or Compensation. The Committee may modify any Compensation Deferral Agreement prior to the date the election becomes irrevocable under the rules of Section 4.2.

(b) The Participant may elect on the Compensation Deferral Agreement to defer (i) an amount of Compensation equal to the percentage of Compensation he has elected to defer to the Qualified Plan reduced by the maximum amount he is permitted to defer to such plan, and/or (ii) additional amounts of Compensation that are independent of his deferral election under the Qualified Plan. The deferral election under the Qualified Plan shall be irrevocable for a year to the extent the Participant makes an election of the type described in (i) above.

(c) The Participant shall specify on his or her Compensation Deferral Agreement whether to allocate Deferrals to a Retirement/Termination Account or to a

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Specified Date Account. If no designation is made, all Deferrals shall be allocated to the Retirement/Termination Account. A Participant may also specify in his or her Compensation Deferral Agreement the Payment Schedule applicable to his or her Plan Accounts. If the Payment Schedule is not specified in a Compensation Deferral Agreement, the Payment Schedule shall be the Payment Schedule specified in Section 6.2.

(d) Notwithstanding any other provision of this Plan, a Director may not establish a Specified Date Account or allocate Deferrals to an existing Specified Date Account. All Deferrals by a Director shall be allocated to such Director's Retirement/Termination Account.

4.2     Timing Requirements for Compensation Deferral Agreements.

(a) First Year of Eligibility. In the case of the first year in which an Eligible Employee or a Director becomes eligible to participate in the Plan, he has up to 30 days following his initial eligibility to submit a Compensation Deferral Agreement with respect to Compensation to be earned during such year. The Compensation Deferral Agreement described in this paragraph becomes irrevocable upon the end of such 30-day period. The determination of whether an Eligible Employee or a Director may file a Compensation Deferral Agreement under this paragraph shall be determined in accordance with the rules of Code Section 409A, including the provisions of Treas. Reg. Section 1.409A-2(a)(7).

A Compensation Deferral Agreement filed under this paragraph applies to Compensation earned on and after the date the Compensation Deferral Agreement becomes irrevocable.

(b) Prior Year Election. Except as otherwise provided in this Section 4.2, Participants may defer Compensation by filing a Compensation Deferral Agreement no later than December 31 of the year prior to the year in which the Compensation to be deferred is earned. A Compensation Deferral Agreement described in this paragraph shall become irrevocable with respect to such Compensation as of January 1 of the year in which such Compensation is earned.

(c) Performance-Based Compensation. Participants may file a Compensation Deferral Agreement with respect to Performance-Based Compensation no later than the date that is six months before the end of the performance period, provided that:

(i) the Participant performs services continuously from the later of the beginning of the performance period or the date the criteria are established through the date the Compensation Deferral Agreement is submitted; and

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(ii) the Compensation is not readily ascertainable as of the date the Compensation Deferral Agreement is filed.

A Compensation Deferral Agreement becomes irrevocable with respect to Performance-Based Compensation as of the day immediately following the latest date for filing such election. Any election to defer Performance-Based Compensation that is made in accordance with this paragraph and that becomes payable as a result of the Participant's death or disability (as defined in Treas. Reg. Section 1.409A-l(e)) or upon a Change in Control (as defined in Treas. Reg. Section 1.409A-3(i)(5)) prior to the satisfaction of the performance criteria, will be void.

(d) Fiscal Year Compensation. A Participant may defer Fiscal Year Compensation by filing a Compensation Deferral Agreement prior to the first day of the fiscal year or years in which such Fiscal Year Compensation is earned. The Compensation Deferral Agreement described in this paragraph becomes irrevocable on the first day of the fiscal year or years to which it applies.

(e) Short-Term Deferrals. Compensation that meets the definition of a "short-term deferral" described in Treas. Reg. Section 1.409A-l(b)(4) may be deferred in accordance with the rules of Article VII, applied as if the date the Substantial Risk of Forfeiture lapses is the date payments were originally scheduled to commence, provided, however, that the provisions of Section 7.3 shall not apply to payments attributable to a Change in Control (as defined in Treas. Reg. Section 1.409A-3(i)(5)).

(f) Certain Forfeitable Rights. With respect to a legally binding right to a payment in a subsequent year that is subject to a forfeiture condition requiring the Participant's continued services for a period of at least twelve months from the date the Participant obtains the legally binding right, an election to defer such Compensation may be made on or before the 30th day after the Participant obtains the legally binding right to the Compensation, provided that the election is made at least twelve months in advance of the earliest date at which the forfeiture condition could lapse. The Compensation Deferral Agreement described in this paragraph becomes irrevocable after such 30th day. If the forfeiture condition applicable to the payment lapses before the end of the required service period as a result of the Participant's death or disability (as defined in Treas. Reg. Section 1.409A-3(i)(4)) or upon a Change in Control (as defined in Treas. Reg. Section 1.409A-3(i)(5)), the Compensation Deferral Agreement will be void unless it would be considered timely under another rule described in this Section.

(g) Company Awards. Participating Employers may unilaterally provide for deferrals of Company awards prior to the date of such awards. Deferrals of Company awards (such as sign-on, retention, severance pay, etc.) may be negotiated with a

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Participant prior to the date the Participant has a legally binding right to such Compensation.

(h) "Evergreen" Deferral Elections. The Committee, in its discretion, may provide in the Compensation Deferral Agreement that such Compensation Deferral Agreement will continue in effect for each subsequent year or performance period. Such "evergreen" Compensation Deferral Agreements will become effective with respect to an item of Compensation on the date such election becomes irrevocable under this Section 4.2. An evergreen Compensation Deferral Agreement may be terminated or modified prospectively with respect to Compensation for which such election remains revocable under this Section 4.2. A Participant whose Compensation Deferral Agreement is cancelled in accordance with Section 4.6 will be required to file a new Compensation Deferral Agreement under this Article IV in order to recommence Deferrals under the Plan.

(i) Deferrals On Or Before March 15, 2005. Notwithstanding any other provisions of the Plan, the Committee is authorized to allow any Participant to file an initial deferral election on or before March 15, 2005 with respect to amounts earned on or before December 31, 2005 and which have not become payable as of the date such deferral election is filed.

4.3 Allocation of Deferrals. Except as provided in Section 4.1(c), a Compensation Deferral Agreement may allocate Deferrals to one or more Specified Date Accounts and/or to the Retirement/Termination Account. The Committee may, in its discretion, establish a minimum deferral period for Specified Date Accounts (for example, the third Plan Year following the year Compensation subject to the Compensation Deferral Agreement is earned).

4.4 Deductions from Pay. The Committee has the authority to determine the payroll practices under which any component of Compensation subject to a Compensation Deferral Agreement will be deducted from a Participant's Compensation.

4.5 Vesting. Participant Deferrals shall be 100% vested at all times.

4.6 Cancellation of Deferrals. The Committee may cancel a Participant's Deferrals (i) for the balance of the Plan Year in which an Unforeseeable Emergency payment occurs and for the following Plan Year, (ii) if the Participant receives a hardship distribution under the Employer's qualified 401(k) plan, through the end of the Plan Year in which the six­ month anniversary of the hardship distribution falls, and (iii) during periods in which the Participant is unable to perform the duties of his or her position or any substantially similar position due to a mental or physical impairment that can be expected to result in death or last for a continuous period of at least six months, provided cancellation occurs by the later of the end of the taxable year of the Participant or the 15th day of the third

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month following the date the Participant incurs the disability (as defined in this paragraph (iii)). Notwithstanding any other provisions of the Plan, the Committee is authorized to allow any Participant, at any time during the 2005 calendar year to (i) cancel existing deferral elections or (ii) terminate participation in the Plan.

ARTICLE V

Company Contributions

5.1 Company Make-Up Contribution. Provided the Participating Employer has made the maximum matching contribution to the Qualified Plan that is permissible under Section 401(m) of the Code, a Participating Employer will credit to the Retirement/Termination Account of each eligible Participant a Company Make-Up Contribution in an amount (if any) equal to (a) minus (b) below:

(a) 100% of a Participant's Deferrals into this Plan that do not exceed 15% of such Participant's base salary and bonus (or such other percentage as determined by the Committee in its discretion);

(b) The actual amount of any Company matching contributions to its qualified 401(k) plan for such Participant during the Plan Year.

To be an eligible Participant for purposes of this Section 5.1, the Participant must (i) be a Participant in the Qualified Plan, (b) have made the maximum contribution allowable under the Qualified Plan, (c) have experienced a reduction in the benefits he would have received from the Qualified Plan as a result of the limitations of Section 401(a)(17) of the Code, and (d) satisfy the criteria outlined in Exhibit A.

5.2 Discretionary Company Contributions. The Participating Employer may, from time to time in its sole and absolute discretion, credit Company Contributions to any Participant in any amount determined by the Participating Employer. Such contributions will be credited to a Participant's Retirement/Termination Account.

5.3 Vesting. Company Make-Up Contributions described in Section 5.1, above, and the Earnings thereon, shall vest in accordance with the following vesting schedule on a "rolling vesting" basis (each Company Make-Up Contribution has its own vesting schedule):

Years of Service Since the Date of the Company Make-Up Contribution	Percent Vested
Less than 1	0%
At least 1 but fewer than 2	25%

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At least 2 but fewer than 3	50%
At least 3 but fewer than 4	75%
4 or more	100%

Discretionary Company Contributions described in Section 5.2, above, and the Earnings thereon, shall vest in accordance with the vesting schedule(s) established by the Committee at the time that the Discretionary Company Contribution is made.

All Company Contributions shall become 100% vested upon the occurrence of a Change in Control. In addition, the Committee may at any time in its sole discretion increase a Participant's vested interest in a Company Contribution, for example, if the Participant dies while actively employed, becomes Disabled, or Retires. The portion of a Participant's Accounts that remains unvested upon his or her Separation from Service after the application of the terms of this Section 5.3 shall be forfeited.

Solely for purposes of this Section 5.3, Change in Control shall mean the occurrence of any of the following:

(i)     the acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act")) (a "Person") of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of20% or more of either (A) the then outstanding shares of common stock of the Company (the "Outstanding Company Common Stock") or (B) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the "Outstanding Company Voting Securities"); provided, however, that the following acquisitions by a Person will not constitute a Change of Control: (1) any acquisition directly from the Company; (2) any acquisition by the Company; (3) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company; or (4) any acquisition by any corporation pursuant to a transaction which complies with clauses (A), (B) and (C) of paragraph (iii);

(ii)     the individuals who, as of the date hereof, constitute the board of directors (the "Incumbent Board") cease for any reason to constitute at least a majority of the board of directors. Any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company's shareholders, is approved by a vote of at least a majority of the directors then comprising the Incumbent Board will be considered a member of the Incumbent Board as of the date hereof, but any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Incumbent Board will not be deemed a member of the Incumbent Board as of the date hereof;

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(iii)     the consummation of a reorganization, merger, consolidation or sale or other disposition of all or substantially all of the assets of the Company (a "Business Combination"), unless following such Business Combination: (A) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 60% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company's assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (B) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination and (C) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

(iv)     the approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.

ARTICLE VI

Benefits

6.1     Benefits, Generally. A Participant shall be entitled to the following benefits under the Plan:

(a) Retirement Benefit. Upon the Participant's Separation from Service due to Retirement, he or she shall be entitled to a Retirement Benefit. The Retirement Benefit shall be equal to the vested portion of the Retirement/Termination Account and (i) if the Retirement/Termination Account is payable in a lump sum, the unpaid balances of any Specified Date Accounts, or (ii) if the Retirement/Termination Account is payable in installments, the vested portion of any Specified Date Accounts with respect to which payments have not yet commenced. The Retirement Benefit shall be based on the value of that Account

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as of the end of the month in which Separation from Service occurs. Payment of the Retirement Benefit will be made or begin in the month following the month in which Separation from Service occurs, provided, however, that with respect to a Participant who is a Specified Employee as of the date such Participant incurs a Separation from Service, payment will be made or begin in the seventh month following the month in which such Separation from Service occurs. If the Retirement Benefit is to be paid in the form of installments, any subsequent installment payments to a Specified Employee will be paid on the anniversary of the date the initial installment was made.

(b) Termination Benefit. Upon the Participant's Separation from Service for reasons other than death, Disability or Retirement, he or she shall be entitled to a Termination Benefit. The Termination Benefit shall be equal to the vested portion of the Retirement/Termination Account and the vested portion of any unpaid balances in any Specified Date Accounts. The Termination Benefit shall be based on the value of the Retirement/Termination Account as of the end of the month in which Separation from Service occurs. Payment of the Termination Benefit will be made or begin in the month following the month in which Separation from Service occurs, provided, however, that with respect to a Participant who is a Specified Employee as of the date such Participant incurs a Separation from Service, payment will be made or begin in the seventh month following the month in which such Separation from Service occurs.

(c) Specified Date Benefit. If the Participant has established one or more Specified Date Accounts, he or she shall be entitled to a Specified Date Benefit with respect to each such Specified Date Account. The Specified Date Benefit shall be equal to the vested portion of the Specified Date Account, based on the value of that Account as of the end of the month designated by the Participant at the time the Account was established. Payment of the Specified Date Benefit will be made or begin in the month following the designated month.

(d) Disability Benefit. Upon a determination by the Committee that a Participant is Disabled, he or she shall be entitled to a Disability Benefit. The Disability Benefit shall be equal to the vested portion of the Retirement/Termination Account and (i) if the Retirement/Termination Account is payable in a lump sum, the unpaid balances of any Specified Date Accounts, or (ii) if the Retirement/Termination Account is payable in installments, the vested portion of any Specified Date Accounts with respect to which payments have not yet commenced. The Disability Benefit shall be based on the value of the Accounts as of the last day of the month in which Disability occurs and will be paid in the following month.

(e) Death Benefit. In the event of the Participant's death, his or her designated Beneficiary(ies) shall be entitled to a Death Benefit. The Death Benefit shall be equal to the vested portion of the Retirement/Termination Account and the vested

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portion of any unpaid balances in any Specified Date Accounts. The Death Benefit shall be based on the value of the Accounts as of the end of the month in which death occurred, with payment made in the following month.

(f) Unforeseeable Emergency Payments. A Participant who experiences an Unforeseeable Emergency may submit a written request to the Committee to receive payment of all or any portion of his or her Deferrals. The minimum withdrawal is the lesser of $25,000 or 100% of the Deferrals credited to the Participant's Account. Whether a Participant or Beneficiary is faced with an Unforeseeable Emergency permitting an emergency payment shall be determined by the Committee based on the relevant facts and circumstances of each case, but, in any case, a distribution on account of Unforeseeable Emergency may not be made to the extent that such emergency is or may be reimbursed through insurance or otherwise, by liquidation of the Participant's assets, to the extent the liquidation of such assets would not cause severe financial hardship, or by cessation of Deferrals under this Plan. If an emergency payment is approved by the Committee, the amount of the payment shall not exceed the amount reasonably necessary to satisfy the need, taking into account the additional compensation that is available to the Participant as the result of cancellation of deferrals to the Plan, including amounts necessary to pay any taxes or penalties that the Participant reasonably anticipates will result from the payment. The amount of the emergency payment shall be subtracted first from the vested portion of the Participant's Retirement/Termination Account until depleted and then from the vested Specified Date Accounts, beginning with the Specified Date Account with the latest payment commencement date. Emergency payments shall be paid in a single lump sum within the 90-day period following the date the payment is approved by the Committee.

(g) Voluntary Withdrawal of Grandfathered Amounts. A Participant may elect at any time to voluntarily withdraw not less than 25% of any Deferrals credited to his or her Grandfathered Account. If such a withdrawal is requested, the Participant (i) shall forfeit an amount equal to 10% of the amount requested, (ii) shall not be permitted to make Deferrals to the Plan in the Plan Year following the Plan Year in which the withdrawal is made, and (iii) shall forfeit any Company Discretionary Contributions (whether vested or unvested) attributable to the amounts so distributed.

6.2     Form of Payment.

(a) Retirement Benefit. A Participant who is entitled to receive a Retirement Benefit shall receive payment of such benefit in a single lump sum, unless the Participant elects on his or her initial Compensation Deferral Agreement to have such benefit paid in an alternative form of payment. Alternative forms of payment include (i) a lump sum payment between 0% and 100% of the balance in the

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Retirement/Termination Account; and (ii) any remaining Account Balance payable in a series of substantially equal annual installments from two to twenty years.

(b) Termination Benefit. A Participant who is entitled to receive a Termination Benefit shall receive payment of such benefit in a single lump sum.

(c) Specified Date Benefit. The Specified Date Benefit shall be paid in a single lump sum, unless the Participant elects on the Compensation Deferral Agreement with which the account was established to have the Specified Date Account paid in substantially equal annual installments over a period of two to five years, as elected by the Participant.

Notwithstanding any election of a form of payment by the Participant, upon a Separation from Service the unpaid balance of a Specified Date Account with respect to which payments have not commenced shall be paid in accordance with the form of payment applicable to the Retirement, Termination, Disability or Death Benefit, as applicable. If such benefit is payable in a single lump sum, the unpaid balance of all Specified Date Accounts (including those in pay status) will be paid in a lump sum.

Any Specified Date Accounts credited to a Grandfathered Account shall, upon an earlier termination or Disability, be paid in accordance with the Payment Schedule applicable to the Retirement Benefit, Termination Benefit or Disability Benefit that is payable from such Grandfathered Account.

(d) Disability Benefit. A Participant who becomes entitled to receive a Disability Benefit prior to eligibility for Retirement shall receive payment of such benefit in a single lump sum. A Participant who becomes entitled to receive a Disability Benefit after eligibility for Retirement shall receive payment of such benefit in a single lump sum, unless the Participant elects on his or her initial Compensation Deferral Agreement to have such benefit paid in an alternative form of payment. Alternative forms of payment include (i) a lump sum payment between 0% and 100% of the balance in the Retirement/Termination Account; and (ii) any remaining Account Balance payable in a series of substantially equal annual installments from two to twenty years.

(e) Death Benefit. A designated Beneficiary who is entitled to receive a Death Benefit shall receive payment of such benefit in a single lump sum.

(f) Change in Control. A Participant will receive a single lump sum payment equal to the unpaid balance of all of his or her Accounts if a Separation from Service occurs within 24 months following a Change in Control. In addition to the foregoing, upon a Change in Control, a Participant who has incurred a Separation

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from Service prior to the Change in Control, and any Beneficiary of such Participant who is receiving or is scheduled to receive payments, will receive the balance of all unpaid Accounts in a single lump sum. Accounts will be valued as of the last day of the month following the Change in Control and will be paid within 90 days of said Change in Control.

(g) Small Account Balances. The Committee shall pay the value of the Participant's Accounts upon a Separation from Service in a single lump sum if the balance of such Accounts is not greater than the applicable dollar amount under Code Section 402(g)(l)(B), provided the payment represents the complete liquidation of the Participant's interest in the Plan.

(h) Rules Applicable to Installment Payments. If a Payment Schedule specifies installment payments, annual payments will be made beginning as of the payment commencement date for such installments and shall continue on each anniversary thereof until the number of installment payments specified in the Payment Schedule has been paid. The amount of each installment payment shall be determined by dividing (a) by (b), where (a) equals the Account Balance as of the Valuation Date and (b) equals the remaining number of installment payments.

For purposes of Article VII, installment payments will be treated as a single form of payment. If a lump sum equal to less than 100% of the Retirement/Termination Account is paid, the payment commencement date for the installment form of payment will be the first anniversary of the payment of the lump sum.

(i) Payments from Grandfathered Accounts. Notwithstanding anything to the contrary in this Article VI, the portion of a Retirement Benefit or Disability Benefit credited to a Grandfathered Account (i) shall, if the applicable Account Balance is less than $50,000, be paid in a lump sum, and (ii) shall, if the applicable Account Balance is at least $50,000, be paid commencing within 30 days of the calendar quarter following the one-year anniversary of the Participant's date of termination or date of Disability or, if the Participant has elected a lump sum payment, shall be paid 13 months following the Participant's date of termination or date of Disability. Further, the portion of a Specified Date Benefit credited to a Grandfathered Account shall be paid in a lump sum if the applicable Account Balance is less than $25,000.

6.3 Acceleration of or Delay in Payments. The Committee, in its sole and absolute discretion, may elect to accelerate the time or form of payment of a benefit owed to the Participant hereunder, provided such acceleration is permitted under Treas. Reg. Section 1.409A-3G)(4). The Committee may also, in its sole and absolute discretion, delay the time for payment of a benefit owed to the Participant hereunder, to the extent permitted under Treas. Reg. Section 1.409A-2(b)(7). Notwithstanding anything to the contrary herein, no payments shall be made from the Plan pursuant to a domestic relations order.

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ARTICLE VII

Modifications to Payment Schedules

7.1 Participant's Right to Modify. A Participant may modify any or all of the alternative Payment Schedules with respect to an Account, consistent with the permissible Payment Schedules available under the Plan, provided such modification complies with the requirements of this Article VII. Notwithstanding the foregoing, prior to January 1, 2009, the Committee may permit a Participant to modify any or all of the alternative Payment Schedules with respect to an Account, consistent with the permissible Payment Schedules available under the Plan, and without regard to Sections 7.2, 7.3 and 7.4 hereof, provided such modification complies with the requirements of IRS Notice 2007-86.

7.2 Time of Election. The date on which a modification election is submitted to the Committee must be at least twelve months prior to the date on which payment is scheduled to commence under the Payment Schedule in effect prior to the modification.

7.3 Date of Payment under Modified Payment Schedule. Except with respect to modifications that relate to the payment of a Death Benefit or a Disability Benefit, the date payments are to commence under the modified Payment Schedule must be no earlier than five years after the date payment would have commenced under the original Payment Schedule. Under no circumstances may a modification election result in an acceleration of payments in violation of Code Section 409A.

7.4 Effective Date. A modification election submitted in accordance with this Article VII is irrevocable upon receipt by the Committee and becomes effective 12 months after such date.

7.5 Effect on Accounts. An election to modify a Payment Schedule is specific to the Account or payment event to which it applies, and shall not be construed to affect the Payment Schedules of any other Accounts.

7.6 Modifications to Grandfathered Accounts. Notwithstanding the preceding provisions of this Article VII, a Participant may modify the form of payment in which a Retirement Benefit or Disability Benefit applicable to a Grandfathered Account is payable only if the Committee, in its sole discretion, determines the Participant to be subject to special circumstances, and only if the change is submitted before the 12-month period prior to the date payment was scheduled to commence. A Participant may also postpone payment of a Specified Date Benefit applicable to a Grandfathered Account to a date at least one year later than the previously scheduled payment date if a request is filed with the Committee at least one year prior to the date payments are scheduled to begin.

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ARTICLE VIII

Valuation of Account Balances; Investments

8.1 Valuation. Deferrals shall be credited to appropriate Accounts on the date such Compensation would have been paid to the Participant absent the Compensation Deferral Agreement. Company Contributions shall be credited to the Retirement/Termination Account at the times determined by the Committee. Valuation of Accounts shall be performed under procedures approved by the Committee.

8.2 Adjustment for Earnings. Each Account will be adjusted to reflect Earnings on each Business Day. Adjustments shall reflect the net earnings, gains, losses, expenses, appreciation and depreciation associated with an investment option for each portion of the Account allocated to such option ("investment allocation").

8.3 Investment Options. Investment options will be determined by the Committee. The Committee, in its sole discretion, shall be permitted to add or remove investment options from the Plan menu from time to time, provided that any such additions or removals of investment options shall not be effective with respect to any period prior to the effective date of such change.

8.4 Investment Allocations. A Participant's investment allocation constitutes a deemed, not actual, investment among the investment options comprising the investment menu. At no time shall a Participant have any real or beneficial ownership in any investment option included in the investment menu, nor shall the Participating Employer or any trustee acting on its behalf have any obligation to purchase actual securities as a result of a Participant's investment allocation. A Participant's investment allocation shall be used solely for purposes of adjusting the value of a Participant's Account Balances.

A Participant shall specify an investment allocation for each of his Accounts in accordance with procedures established by the Committee. Allocation among the investment options must be designated in increments of 1%. The Participant's investment allocation will become effective on the same Business Day or, in the case of investment allocations received after a time specified by the Committee, the next Business Day.

A Participant may change an investment allocation on any Business Day, both with respect to future credits to the Plan and with respect to existing Account Balances, in accordance with procedures adopted by the Committee. Changes shall become effective on the same Business Day or, in the case of investment allocations received after a time specified by the Committee, the next Business Day, and shall be applied prospectively.

8.5 Unallocated Deferrals and Accounts. If the Participant fails to make an investment allocation with respect to an Account, such Account shall be invested in an investment option, the primary objective of which is the preservation of capital, as determined by the Committee.

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8.6 Company Stock. The Committee may include Company Stock as one of the investment options described in Section 8.3. The Committee may, in its sole discretion, limit the investment allocation of Company Contributions to Company Stock. The Committee may also require Deferrals consisting of equity-based Compensation to be allocated to Company Stock.

8.7 Diversification. A Participant may not re-allocate an investment in Company Stock into another investment option. The portion of an Account that is invested in Company Stock will be paid under Article VI in the form of whole shares of Company Stock.

8.8 Effect on Installment Payments. If an Account is to be paid in installments, the Committee will determine the portion of each payment that will be paid in the form of Company Stock.

8.9 Dividend Equivalents. Dividend equivalents with respect to Company Stock will be credited to the applicable Accounts in the form of additional shares or units of Company Stock.

ARTICLE IX

Administration

9.1 Plan Administration. This Plan shall be administered by the Committee which shall have discretionary authority to make, amend, interpret and enforce all appropriate rules and regulations for the administration of this Plan and to utilize its discretion to decide or resolve any and all questions, including but not limited to eligibility for benefits and interpretations of this Plan and its terms, as may arise in connection with the Plan. Claims for benefits shall be filed with the Committee and resolved in accordance with the claims procedures in Article XII.

9.2 Administration Upon Change in Control. Upon a Change in Control, the Committee, as constituted immediately prior to such Change in Control, shall continue to act as the Committee. The individual who was the Chief Executive Officer of the Company (or if such person is unable or unwilling to act, the next highest ranking officer) prior to the Change in Control shall have the authority (but shall not be obligated) to appoint an independent third party to act as the Committee.

Upon such Change in Control, the Company may not remove the Committee, unless 2/3rds of the members of the Board of Directors of the Company and a majority of Participants and Beneficiaries with Account Balances consent to the removal and replacement Committee. Notwithstanding the foregoing, neither the Committee nor the officer described above shall have authority to direct investment of trust assets under any rabbi trust described in Section 11.2.

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The Participating Employer shall, with respect to the Committee identified under this Section, (i) pay all reasonable expenses and fees of the Committee, (ii) indemnify the Committee (including individuals serving as Committee members) against any costs, expenses and liabilities including, without limitation, attorneys' fees and expenses arising in connection with the performance of the Committee hereunder, except with respect to matters resulting from the Committee's gross negligence or willful misconduct and (iii) supply full and timely information to the Committee on all matters related to the Plan, any rabbi trust, Participants, Beneficiaries and Accounts as the Committee may reasonably require.

9.3 Withholding. The Participating Employer shall have the right to withhold from any payment due under the Plan (or with respect to any amounts credited to the Plan) any taxes required by law to be withheld in respect of such payment (or credit). Withholdings with respect to amounts credited to the Plan shall be deducted from Compensation that has not been deferred to the Plan.

9.4 Indemnification. The Participating Employers shall indemnify and hold harmless each employee, officer, director, agent or organization, to whom or to which are delegated duties, responsibilities, and authority under the Plan or otherwise with respect to administration of the Plan, including, without limitation, the Committee and its agents, against all claims, liabilities, fines and penalties, and all expenses reasonably incurred by or imposed upon him or it (including but not limited to reasonable attorney fees) which arise as a result of his or its actions or failure to act in connection with the operation and administration of the Plan to the extent lawfully allowable and to the extent that such claim, liability, fine, penalty, or expense is not paid for by liability insurance purchased or paid for by the Participating Employer. Notwithstanding the foregoing, the Participating Employer shall not indemnify any person or organization if his or its actions or failure to act are due to gross negligence or willful misconduct or for any such amount incurred through any settlement or compromise of any action unless the Participating Employer consents in writing to such settlement or compromise.

9.5 Delegation of Authority. In the administration of this Plan, the Committee may, from time to time, employ agents and delegate to them such administrative duties as it sees fit, and may from time to time consult with legal counsel who shall be legal counsel to the Company.

9.6 Binding Decisions or Actions. The decision or action of the Committee in respect of any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations thereunder shall be final and conclusive and binding upon all persons having any interest in the Plan.

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ARTICLE X

Amendment and Termination

10.1 Amendment and Termination. The Company may at any time and from time to time amend the Plan or may terminate the Plan as provided in this Article X. Each Participating Employer may also terminate its participation in the Plan.

10.2 Amendments. The Company, by action taken by its Board of Directors, may amend the Plan at any time and for any reason, provided that any such amendment shall not reduce the vested Account Balances of any Participant accrued as of the date of any such amendment or restatement (as if the Participant had incurred a voluntary Separation from Service on such date) or reduce any rights of a Participant under the Plan or other Plan features with respect to Deferrals made prior to the date of any such amendment or restatement without the consent of the Participant. The Board of Directors of the Company may delegate to the Committee the authority to amend the Plan without the consent of the Board of Directors for the purpose of (i) conforming the Plan to the requirements of law, (ii) facilitating the administration of the Plan, (iii) clarifying provisions based on the Committee's interpretation of the document and (iv) making such other amendments as the Board of Directors may authorize.

10.3 Termination. The Company, by action taken by its Board of Directors, may terminate the Plan and pay Participants and Beneficiaries their Account Balances in a single lump sum at any time, to the extent and in accordance with Treas. Reg. Section 1.409A-3G)(4)(ix). If a Participating Employer terminates its participation in the Plan, the benefits of affected Employees shall be paid at the time provided in Article VI.

10.4 Accounts Taxable Under Code Section 409A. The Plan is intended to constitute a plan of deferred compensation that meets the requirements for deferral of income taxation under Code Section 409A. The Committee, pursuant to its authority to interpret the Plan, may sever from the Plan or any Compensation Deferral Agreement any provision or exercise of a right that otherwise would result in a violation of Code Section 409A.

ARTICLE XI

Informal Funding

11.1 General Assets. Obligations established under the terms of the Plan may be satisfied from the general funds of the Participating Employers, or a trust described in this Article XI. No Participant, spouse or Beneficiary shall have any right, title or interest whatever in assets of the Participating Employers. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind, or a fiduciary relationship, between the Participating Employers and any Employee, spouse, or Beneficiary. To the extent that any person acquires a right to receive payments hereunder, such rights are no greater than the right of an unsecured general creditor of the Participating Employer.

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11.2 Rabbi Trust. A Participating Employer may, in its sole discretion, establish a grantor trust, commonly known as a rabbi trust, as a vehicle for accumulating assets to pay benefits under the Plan. Payments under the Plan may be paid from the general assets of the Participating Employer or from the assets of any such rabbi trust. Payment from any such source shall reduce the obligation owed to the Participant or Beneficiary under the Plan.

ARTICLE XII

Claims

12.1 Filing a Claim. Any controversy or claim arising out of or relating to the Plan shall be filed in writing with the Committee which shall make all determinations concerning such claim. Any claim filed with the Committee and any decision by the Committee denying such claim shall be in writing and shall be delivered to the Participant or Beneficiary filing the claim (the "Claimant").

(a) In General. Notice of a denial of benefits (other than Disability benefits) will be provided within ninety (90) days of the Committee's receipt of the Claimant's claim for benefits. If the Committee determines that it needs additional time to review the claim, the Committee will provide the Claimant with a notice of the extension before the end of the initial ninety (90) day period. The extension will not be more than ninety (90) days from the end of the initial ninety (90) day period and the notice of extension will explain the special circumstances that require the extension and the date by which the Committee expects to make a decision.

(b) Disability Benefits. Notice of denial of Disability benefits will be provided within forty-five (45) days of the Committee's receipt of the Claimant's claim for Disability benefits. If the Committee determines that it needs additional time to review the Disability claim, the Committee will provide the Claimant with a notice of the extension before the end of the initial forty-five (45) day period. If the Committee determines that a decision cannot be made within the first extension period due to matters beyond the control of the Committee, the time period for making a determination may be further extended for an additional thirty (30) days. If such an additional extension is necessary, the Committee shall notify the Claimant prior to the expiration of the initial thirty (30) day extension. Any notice of extension shall indicate the circumstances necessitating the extension of time, the date by which the Committee expects to furnish a notice of decision, the specific standards on which such entitlement to a benefit is based, the unresolved issues that prevent a decision on the claim and any additional information needed to resolve those issues. A Claimant will be provided a minimum of forty-five (45) days to submit any necessary additional information to the Committee. In the

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event that a thirty (30) day extension is necessary due to a Claimant's failure to submit information necessary to decide a claim, the period for furnishing a notice of decision shall be tolled from the date on which the notice of the extension is sent to the Claimant until the earlier of the date the Claimant responds to the request for additional information or the response deadline.

(c) Contents of Notice. If a claim for benefits is completely or partially denied, notice of such denial shall be in writing and shall set forth the reasons for denial in plain language. The notice shall (i) cite the pertinent provisions of the Plan document and (ii) explain, where appropriate, how the Claimant can perfect the claim, including a description of any additional material or information necessary to complete the claim and why such material or information is necessary. The claim denial also shall include an explanation of the claims review procedures and the time limits applicable to such procedures, including a statement of the Claimant's right to bring a civil action under Section 502(a) of ERISA following an adverse decision on review. In the case of a complete or partial denial of a Disability benefit claim, the notice shall provide a statement that the Committee will provide to the Claimant, upon request and free of charge, a copy of any internal rule, guideline, protocol, or other similar criterion that was relied upon in making the decision.

12.2 Appeal of Denied Claims. A Claimant whose claim has been completely or partially denied shall be entitled to appeal the claim denial by filing a written appeal with a committee designated to hear such appeals (the "Appeals Committee"). A Claimant who timely requests a review of the denied claim (or his or her authorized representative) may review, upon request and free of charge, copies of all documents, records and other information relevant to the denial and may submit written comments, documents, records and other information relevant to the claim to the Appeals Committee. All written comments, documents, records, and other information shall be considered "relevant" if the information (i) was relied upon in making a benefits determination,(ii) was submitted, considered or generated in the course of making a benefits decision regardless of whether it was relied upon to make the decision, or (iii) demonstrates compliance with administrative processes and safeguards established for making benefit decisions. The Appeals Committee may, in its sole discretion and if it deems appropriate or necessary, decide to hold a hearing with respect to the claim appeal.

(a) In General. Appeal of a denied benefits claim (other than a Disability benefits claim) must be filed in writing with the Appeals Committee no later than sixty (60) days after receipt of the written notification of such claim denial. The Appeals Committee shall make its decision regarding the merits of the denied claim within sixty (60) days following receipt of the appeal (or within one hundred and twenty (120) days after such receipt, in a case where there are special circumstances requiring extension of time for reviewing the appealed claim). If an extension of time for reviewing the appeal is required because of special

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circumstances, written notice of the extension shall be furnished to the Claimant prior to the commencement of the extension. The notice will indicate the special circumstances requiring the extension of time and the date by which the Appeals Committee expects to render the determination on review. The review will take into account comments, documents, records and other information submitted by the Claimant relating to the claim without regard to whether such information was submitted or considered in the initial benefit determination.

(b) Disability Benefits. Appeal of a denied Disability benefits claim must be filed in writing with the Appeals Committee no later than one hundred eighty (180) days after receipt of the written notification of such claim denial. The review shall be conducted by the Appeals Committee (exclusive of the person who made the initial adverse decision or such person's subordinate). In reviewing the appeal, the Appeals Committee shall (i) not afford deference to the initial denial of the claim, (ii) consult a medical professional who has appropriate training and experience in the field of medicine relating to the Claimant's disability and who was neither consulted as part of the initial denial nor is the subordinate of such individual and (iii) identify the medical or vocational experts whose advice was obtained with respect to the initial benefit denial, without regard to whether the advice was relied upon in making the decision. The Appeals Committee shall make its decision regarding the merits of the denied claim within forty-five (45) days following receipt of the appeal (or within ninety (90) days after such receipt, in a case where there are special circumstances requiring extension of time for reviewing the appealed claim). If an extension of time for reviewing the appeal is required because of special circumstances, written notice of the extension shall be furnished to the Claimant prior to the commencement of the extension. The notice will indicate the special circumstances requiring the extension of time and the date by which the Appeals Committee expects to render the determination on review. Following its review of any additional information submitted by the Claimant, the Appeals Committee shall render a decision on its review of the denied claim.

(c) Contents of Notice. If a benefits claim is completely or partially denied on review, notice of such denial shall be in writing and shall set forth the reasons for denial in plain language.

The decision on review shall set forth (i) the specific reason or reasons for the denial, (ii) specific references to the pertinent Plan provisions on which the denial is based, (iii) a statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to and copies of all documents, records, or other information relevant (as defined above) to the Claimant's claim, and (iv) a statement describing any voluntary appeal procedures offered by the plan and a statement of the Claimant's right to bring an action under Section 502(a) of ERISA.

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(d) For the denial of a Disability benefit, the notice will also include a statement that the Appeals Committee will provide, upon request and free of charge, (i) any internal rule, guideline, protocol or other similar criterion relied upon in making the decision, (ii) any medical opinion relied upon to make the decision and (iii) the required statement under Section 2560.503-1(j)(5)(iii) of the Department of Labor regulations.

12.3 Claims Appeals Upon Change in Control. Upon a Change in Control, the Appeals Committee, as constituted immediately prior to such Change in Control, shall continue to act as the Appeals Committee. Upon such Change in Control, the Company may not remove any member of the Appeals Committee, but may replace resigning members if 2/3rds of the members of the Board of Directors of the Company and a majority of Participants and Beneficiaries with Account Balances consent to the replacement.

The Appeals Committee shall have the exclusive authority at the appeals stage to interpret the terms of the Plan and resolve appeals under the Claims Procedure.

Each Participating Employer shall, with respect to the Committee identified under this Section, (i) pay its proportionate share of all reasonable expenses and fees of the Appeals Committee, (ii) indemnify the Appeals Committee (including individual committee members) against any costs, expenses and liabilities including, without limitation, attorneys' fees and expenses arising in connection with the performance of the Appeals Committee hereunder, except with respect to matters resulting from the Appeals Committee's gross negligence or willful misconduct and (iii) supply full and timely information to the Appeals Committee on all matters related to the Plan, any rabbi trust, Participants, Beneficiaries and Accounts as the Appeals Committee may reasonably require.

12.4 Legal Action. A Claimant may not bring any legal action, including commencement of any arbitration, relating to a claim for benefits under the Plan unless and until the Claimant has followed the claims procedures under the Plan and exhausted his or her administrative remedies under such claims procedures.

If a Participant or Beneficiary prevails in a legal proceeding brought under the Plan to enforce the rights of such Participant or any other similarly situated Participant or Beneficiary, in whole or in part, the Participating Employer shall reimburse such Participant or Beneficiary for all legal costs, expenses, attorneys' fees and such other liabilities incurred as a result of such proceedings. If the legal proceeding is brought in connection with a Change in Control, or a "change in control" as defined in a rabbi trust described in Section 11.2, the Participant or Beneficiary may file a claim directly with the trustee for reimbursement of such costs, expenses and fees. For purposes of the preceding sentence, the amount of the claim shall be treated as if it were an addition to the Participant's or Beneficiary's Account Balance.

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12.5 Discretion of Appeals Committee. All interpretations, determinations and decisions of the Appeals Committee with respect to any claim shall be made in its sole discretion, and shall be final and conclusive.

12.6 Arbitration.

(a) Prior to Change in Control. If, prior to a Change in Control, any claim or controversy between a Participating Employer and a Participant or Beneficiary is not resolved through the claims procedure set forth in Article XII, such claim shall be submitted to and resolved exclusively by expedited binding arbitration by a single arbitrator. Arbitration shall be conducted in accordance with the following procedures:

The complaining party shall promptly send written notice to the other party identifying the matter in dispute and the proposed remedy. Following the giving of such notice, the parties shall meet and attempt in good faith to resolve the matter. In the event the parties are unable to resolve the matter within twenty one (21) days, the parties shall meet and attempt in good faith to select a single arbitrator acceptable to both parties. If a single arbitrator is not selected by mutual consent within ten (I0) Business Days following the giving of the written notice of dispute, an arbitrator shall be selected from a list of nine persons each of whom shall be an attorney who is either engaged in the active practice of law or recognized arbitrator and who, in either event, is experienced in serving as an arbitrator in disputes between employers and employees, which list shall be provided by the main office of either JAMS, the American Arbitration Associate ("AAA") or the Federal Mediation and Conciliation Service. If, within three Business Days of the parties' receipt of such list, the parties are unable to agree on an arbitrator from the list, then the parties shall each strike names alternatively from the list, with the first to strike being determined by the flip of a coin. After each party has had four strikes, the remaining name on the list shall be the arbitrator. If such person is unable to serve for any reason, the parties shall repeat this process until an arbitrator is selected.

Unless the parties agree otherwise, within sixty (60) days of the selection of the arbitrator, a hearing shall be conducted before such arbitrator at a time and a place agreed upon by the parties. In the event the parties are unable to agree upon the time or place of the arbitration, the time and place shall be designated by the arbitrator after consultation with the parties. Within thirty (30) days of the conclusion of the arbitration hearing, the arbitrator shall issue an award, accompanied by a written decision explaining the basis for the arbitrator's award.

In any arbitration hereunder, the Participating Employer shall pay all administrative fees of the arbitration and all fees of the arbitrator, except that the

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Participant or Beneficiary may, if he/she/it wishes, pay up to one-half of those amounts. Each party shall pay its own attorneys' fees, costs, and expenses, unless the arbitrator orders otherwise. The prevailing party in such arbitration, as determined by the arbitrator, and in any enforcement or other court proceedings, shall be entitled, to the extent permitted by law, to reimbursement from the other party for all of the prevailing party's costs (including but not limited to the arbitrator's compensation), expenses, and attorneys' fees. The arbitrator shall have no authority to add to or to modify this Plan, shall apply all applicable law, and shall have no lesser and no greater remedial authority than would a court of law resolving the same claim or controversy. The arbitrator shall have no authority to add to or to modify this Plan, shall apply all applicable law, and shall have no lesser and no greater remedial authority than would a court of law resolving the same claim or controversy. The arbitrator shall, upon an appropriate motion, dismiss any claim without an evidentiary hearing if the party bringing the motion establishes that it would be entitled to summary judgment if the matter had been pursued in court litigation.

The parties shall be entitled to discovery as follows: Each party may take no more than three depositions. The Participating Employer may depose the Participant or Beneficiary plus two other witnesses, and the Participant or Beneficiary may depose the Participating Employer, pursuant to Rule 30(b)(6) of the Federal Rules of Civil Procedure, plus two other witnesses. Each party may make such reasonable document discovery requests as are allowed in the discretion of the arbitrator.

The decision of the arbitrator shall be final, binding, and non-appealable, and may be enforced as a final judgment in any court of competent jurisdiction.

This arbitration provision of the Plan shall extend to claims against any parent, subsidiary, or affiliate of each party, and, when acting within such capacity, any officer, director, shareholder, Participant, Beneficiary, or agent of any party, or of any of the above, and shall apply as well to claims arising out of state and federal statutes and local ordinances as well as to claims arising under the common law or under this Plan.

Notwithstanding the foregoing, and unless otherwise agreed between the parties, either party may apply to a court for provisional relief, including a temporary restraining order or preliminary injunction, on the ground that the arbitration award to which the applicant may be entitled may be rendered ineffectual without provisional relief.

Any arbitration hereunder shall be conducted in accordance with the Federal Arbitration Act: provided, however, that, in the event of any inconsistency

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between the rules and procedures of the Act and the terms of this Plan, the terms of this Plan shall prevail.

If any of the provisions of this Section 12.6(a) are determined to be unlawful or otherwise unenforceable, in the whole part, such determination shall not affect the validity of the remainder of this section and this section shall be reformed to the extent necessary to carry out its provisions to the greatest extent possible and to insure that the resolution of all conflicts between the parties, including those arising out of statutory claims, shall be resolved by neutral, binding arbitration. If a court should find that the provisions of this Section 12.6(a) are not absolutely binding, then the parties intend any arbitration decision and award to be fully admissible in evidence in any subsequent action, given great weight by any finder of fact and treated as determinative to the maximum extent permitted by law.

The parties do not agree to arbitrate any putative class action or any other representative action. The parties agree to arbitrate only the claims(s) of a single Participant or Beneficiary.

(b) Upon Change in Control. If, upon the occurrence of a Change in Control, any dispute, controversy or claim arises between a Participant or Beneficiary and the Participating Employer out of or relating to or concerning the provisions of the Plan, such dispute, controversy or claim shall be finally settled by a court of competent jurisdiction which, notwithstanding any other provision of the Plan, shall apply a de novo standard of review to any determination made by the Company or its Board of Directors, a Participating Employer, the Committee, or the Appeals Committee.

ARTICLE XIII

General Provisions

13.1 Assignment. No interest of any Participant, spouse or Beneficiary under this Plan and no benefit payable hereunder shall be assigned as security for a loan, and any such purported assignment shall be null, void and of no effect, nor shall any such interest or any such benefit be subject in any manner, either voluntarily or involuntarily, to anticipation, sale, transfer, assignment or encumbrance by or through any Participant, spouse or Beneficiary.

The Company may assign any or all of its liabilities under this Plan in connection with any restructuring, recapitalization, sale of assets or other similar transactions affecting a Participating Employer without the consent of the Participant.

13.2 No Legal or Equitable Rights or Interest. No Participant or other person shall have any legal or equitable rights or interest in this Plan that are not expressly granted in this Plan. Participation in this Plan does not give any person any right to be retained in the service

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of the Participating Employer. The right and power of a Participating Employer to dismiss or discharge an Employee is expressly reserved. The Participating Employers make no representations or warranties as to the tax consequences to a Participant or a Participant's beneficiaries resulting from a deferral of income pursuant to the Plan.

13.3 No Employment Contract. Nothing contained herein shall be construed to constitute a contract of employment between an Employee and a Participating Employer.

13.4 Notice. Any notice or filing required or permitted to be delivered to the Committee under this Plan shall be delivered in writing, in person, or through such electronic means as is established by the Committee. Notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification. Written transmission shall be sent by certified mail to:

CHESAPEAKE ENERGY CORPORATION
ATTN: VICE PRESIDENT OF HUMAN RESOURCES
6100 N. WESTERN AVENUE
OKLAHOMA CITY, OKLAHOMA 73118

Any notice or filing required or permitted to be given to a Participant under this Plan shall be sufficient if in writing or hand-delivered, or sent by mail to the last known address of the Participant.

13.5 Headings. The headings of Sections are included solely for convenience of reference, and if there is any conflict between such headings and the text of this Plan, the text shall control.

13.6 Invalid or Unenforceable Provisions. If any provision of this Plan shall be held invalid or unenforceable, such invalidity or unenforceability shall not affect any other provisions hereof and the Committee may elect in its sole discretion to construe such invalid or unenforceable provisions in a manner that conforms to applicable law or as if such provisions, to the extent invalid or unenforceable, had not been included.

13.7 Lost Participants or Beneficiaries. Any Participant or Beneficiary who is entitled to a benefit from the Plan has the duty to keep the Committee advised of his or her current mailing address. If benefit payments are returned to the Plan or are not presented for payment after a reasonable amount of time, the Committee shall presume that the payee is missing. The Committee, after making such efforts as in its discretion it deems reasonable and appropriate to locate the payee, shall stop payment on any uncashed checks and may discontinue making future payments until contact with the payee is restored.

13.8 Facility of Payment to a Minor. If a distribution is to be made to a minor, or to a person who is otherwise incompetent, then the Committee may, in its discretion, make such

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distribution (i) to the legal guardian, or if none, to a parent of a minor payee with whom the payee maintains his or her residence, or (ii) to the conservator or committee or, if none, to the person having custody of an incompetent payee. Any such distribution shall fully discharge the Committee, the Company, and the Plan from further liability on account thereof.

13.9 Governing Law. To the extent not preempted by ERISA, the laws of the State of Oklahoma shall govern the construction and administration of the Plan.

IN WITNESS WHEREOF, the undersigned executed this Plan as of the 30^th day of December, 2008, to be effective as of the Effective Date.

Chesapeake Energy Corporation

By:	Lisa M. Phelps	(Print Name)
Its:	Vice President of HR	(Title)
	/s/ Lisa M. Phelps	(Signature)

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EXHIBIT A TO THE

CHESAPEAKE ENERGY CORPORATION

AMENDED AND RESTATED DEFERRED COMPENSATION PLAN

Criteria for purposes of Sections 4.1(b)(i) and 5.1

• Receive a base salary of at least $150,000 during the 12-month period immediately preceding the Plan Year, and

•    Be employed by an Employer on December 31 immediately preceding the Plan Year, and

• Have completed at least three Years of Service as of the December 31 immediately preceding the Plan Year, and

•    Must have an Employment Agreement with the Company; or

•    Be designated by the Committee as eligible to participate.

Criteria for purposes of Sections 4.1(b)(ii)

• Receive a base salary of at least $150,000 during the 12-month period immediately preceding the Plan Year, and

•    Be employed by an Employer on December 31 immediately preceding the Plan Year, and

• Have completed at least one Year of Service as of the December 31 immediately preceding the Plan Year, and

•    Must have an Employment Agreement with the Company; or

•    Be designated by the Committee as eligible to participate.

EXHIBIT B TO THE

CHESAPEAKE ENERGY CORPORATION

AMENDED AND RESTATED DEFERRED COMPENSATION PLAN

Until such time as this Exhibit B is modified by the Committee pursuant to Section 2.15 of the Plan, the types of Compensation that may be deferred to the Plan are as follows:

•    Base Salary

•    Performance Bonuses

•    Director Fees

Chesapeake Energy Corporation Amended and Restated Deferred

Compensation Plan

THIRD AMENDMENT* TO THE

CHESAPEAKE ENERGY CORPORATION

AMENDED AND RESTATED DEFERRED COMPENSATION PLAN

WHEREAS, Chesapeake Energy Corporation (the "Company") established the Chesapeake Energy Corporation Amended and Restated Deferred Compensation Plan (the "Plan"), effective as of January 1, 2008, and as thereafter amended; and

WHEREAS, Section 10.2 of the Plan permits the Company to amend the Plan at any time, subject to the limitations specified therein; and

WHEREAS, the Company desires to amend the Plan to make certain changes thereto.

NOW, THEREFORE, the Company does hereby amend the Plan, effective January 1, 2015, as described herein.

1.     Section 2.24 of the Plan is hereby amended to read as follows:

2.24 Eligible Employee. Eligible Employee means, for a Plan Year, a member of a 'select group of management or highly compensated employees' of a Participating Employer within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of ERISA, as determined by the Committee from time to time in its sole discretion, who has been designated by the Committee as eligible to participate in the Plan.

2.     The first paragraph of Section 5.3 of the Plan is hereby deleted and replaced with the following language:

5.3 Vesting. Company Make-Up Contributions described in Section 5.1 above that were made during or after the Plan Year beginning January 2, 2015, and the Earnings thereon, shall vest in accordance with the following vesting schedule:

Years of Service	Percent Vested
Less than 1	0%
At least 1 but fewer than 2	20%
At least 2 but fewer than 3	40%
At least 3 but fewer than 4	60%
At least 4 but fewer than 5	80%
5 or more	100%

Company Make-Up Contributions described in Section 5.1 above that were made prior to January 1, 2015, and the Earnings thereon, shall vest in accordance with the following vesting schedule on a "rolling vesting" basis (each Company Make-Up Contribution has its own vesting schedule):

Years of Service Since the Date of the Company Make-Up Contribution	Percent Vested
Less than 1	0%
At least 1 but fewer than 2	25%
At least 2 but fewer than 3	50%
At least 3 but fewer than 4	75%
4 or more	100%

* Note: The First and Second Amendments to the Deferred Compensation Plan, dated October 20, 2003 and June 2, 2006, respectively, were previously incorporated into the Amended and Restated Deferred Compensation Plan (above) on January 1, 2008.

Chesapeake Energy Corporation Amended and Restated Deferred

Compensation Plan

3.     Exhibit A of the Plan is hereby deleted in its entirety.

Except as otherwise provided in this Third Amendment to the Chesapeake Energy Corporation Amended and Restate Deferred Compensation Plan (the "Third Amendment"), the Plan is hereby Ratified and confirmed in all respects.

IN WITNESS WHEREOF, the undersigned executed this Third Amendment as of the 17^th Day of December, 2014, to be effective on the dates specified above.

CHESAPEAKE ENERGY CORPORATION

By:	Jay Hawkins
Its:	VP-Human Resources
	/s/ Jay Hawkins
	Signature

EX-10.8

Exhibit 10.8

EMPLOYMENT AGREEMENT

between

CHESAPEAKE ENERGY CORPORATION

and

JAMES R. WEBB

Effective January 1, 2013

EMPLOYMENT AGREEMENT

THIS AGREEMENT is made effective January 1, 2013, between CHESAPEAKE ENERGY CORPORATION, an Oklahoma corporation (the "Company") and JAMES R. WEBB, an individual (the "Executive").

W I T N E S S E T H:

WHEREAS, the Company desires to retain the services of the Executive and the Executive desires to make the Executive's services available to the Company.

NOW, THEREFORE, in consideration of the mutual promises herein contained, the Company and the Executive agree as follows:

1. Employment. The Company hereby employs the Executive and the Executive hereby accepts such employment subject to the terms and conditions contained in this Agreement. The Executive is engaged as an Executive of the Company, and the Executive and the Company do not intend to create a joint venture, partnership or other relationship which might impose a fiduciary obligation on the Executive or the Company in the performance of this Agreement.

2. Executive's Duties. The Executive is employed on a full-time basis. Throughout the term of this Agreement, the Executive will use the Executive's best efforts and due diligence to assist the Company in achieving the most profitable operation of the Company and the Company's affiliated entities consistent with developing and maintaining a quality business operation. The Executive shall also devote all of Executive's working time, attention and energies to the performance of Executive's duties and responsibilities under this Agreement.

2.1 Specific Duties. The Executive will serve as Senior Vice President – Legal and General Counsel for the Company, and in such other positions as might be mutually agreed upon by the parties. The Executive shall perform all of the duties required to fully and faithfully execute the office and position to which the Executive is appointed,and such other duties as may be reasonably requested by the Executive's supervisor. During the term of this Agreement, the Executive may be nominated for election or appointed to serve as a director or officer of any of the Company's affiliated entities as determined in such affiliates' Board of Directors' sole discretion. The services of the Executive will be requested and directed by the Company's Chief Executive Officer, Mr. Aubrey K. McClendon.

2.2 Rules and Regulations. The Company has issued various policies and procedures applicable to employees and the Executive including an Employment Policies Manual which sets forth the general human

resources policies of the Company and addresses frequently asked questions regarding the Company. The Executive agrees to comply with such policies and procedures except to the extent inconsistent with this Agreement. Such policies and procedures may be changed or adopted in the sole discretion of the Company without advance notice. 

3. Other Activities. Except as provided in this Agreement or approved by the Compensation Committee, or its designee, as applicable, in writing, the Executive agrees not to: (a) engage in other operating business activities independent of the Company; (b) serve as a general partner, officer, executive, director or member of any corporation, partnership, company or firm; or (c) directly or indirectly invest, participate or engage in the Oil and Gas Business. For purposes of this Agreement the term "Oil and Gas Business" means: (i) producing oil and gas; (ii) drilling, owning or operating an interest in oil and gas leases or wells; (iii) providing material or services to the Oil and Gas Business; (iv) refining, processing, gathering, compressing, transporting or marketing oil or gas; or (v) owning an interest in or assisting any corporation, partnership, company, entity or person in any of the foregoing. The foregoing will not prohibit: (v) ownership of publicly traded securities; (w) ownership of royalty interests where the Executive owns or previously owned the surface of the land covered in whole or in part by the royalty interest and the ownership of the royalty interest is incidental to the ownership of such surface estate; (x) ownership of royalty interests, overriding royalty interests, working interests or other interests in oil and gas owned prior to the Executive's date of first employment with the Company and disclosed to the Company in writing; (y) ownership of royalty interests, overriding royalty interests, working interests or other interests in oil and gas acquired by the Executive through a bona fide gift or inheritance subject to disclosure by Executive to the Company in writing; or (z) service as an officer or director of a not-for-profit organization so long as such activity does not materially interfere with Executive’s obligations under this Agreement. If the Executive serves as a director or officer of a not-for-profit organization, the Executive shall disclose the name of the organization and their involvement in an annual disclosure statement, the form of which shall be provided by the Company.

 4. Executive's Compensation. The Company agrees to compensate the Executive as follows: 

4.1 Base Salary. A base salary (the "Base Salary"), at the initial annual rate of not less than Four Hundred Fifty Thousand Dollars ($450,000.00) will be paid to the Executive in regular installments in accordance with the Company's designated payroll schedule increasing to not less than Four Hundred Seventy-Five Thousand Dollars ($475,000.00) not later than July 31, 2013, and increasing to not less than Five Hundred Thousand Dollars ($500,000.00) not later than July 31, 2014, assuming the Executive’s continued employment with the Company at the time of any salary increase.

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4.2 Bonus. In addition to the Base Salary described in paragraph 4.1 of this Agreement, the Executive shall be eligible for an annual bonus for each fiscal year during the Term on the same basis as other executive officers under the Company’s then current annual incentive plan which shall be payable in accordance with the terms of such plan.

4.3 Equity Compensation. In addition to the compensation set forth in paragraphs 4.1 and 4.2 of this Agreement, the Executive may periodically receive grants of Chesapeake Energy Corporation restricted stock or other awards from the Company's various equity compensation plans (generally referred to as “Equity Compensation Plans”), subject to the terms and conditions thereof.

4.4 Benefits. The Company will provide the Executive such retirement benefits, and such other benefits as are customarily provided to similarly situated executives of the Company and as are set forth in and governed by the Company's Employment Policies Manual. The Executive will be entitled to take one hundred seventy-six (176) hours of Paid Time Off (“PTO”) annually, calculated from the Executive's anniversary date, during the term of this Agreement. No additional compensation will be paid for failure to take PTO. The Company will also provide the Executive the opportunity to apply for coverage under the Company's medical, life and disability plans, if any. If the Executive is accepted for coverage under such plans, the Company will make such coverage available to the Executive on the same terms as is customarily provided by the Company to the plan participants as modified from time to time. The Executive is subject to all of the terms and provisions of the Company's benefit plans or policies. Executive will be entitled to receive reimbursement for all reasonable business expenses incurred by Executive in accordance with the Company’s expense reimbursement policy. All payments for reimbursement under this Section 4.4 shall be paid promptly but in no event later than the last day of Executive’s taxable year following the taxable year in which Executive incurred such expenses.

5. Term. The term of Executive’s employment under the provisions of this Agreement shall be for a period commencing on the Effective Date and ending on December 31, 2015 (the "Term"); provided, however, if during the Term of this Agreement a Change of Control occurs, the Term of this Agreement shall be extended to the later of the original expiration date of the Term or the expiration of the Change of Control Period. For purposes of this Agreement, a "Change of Control" means the occurrence of any of the following:

(a) the acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act")) (a "Person") of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of thirty percent (30%) or more of either (i) the then outstanding shares of Chesapeake Energy Corporation

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common stock (the "Outstanding CHK Common Stock") or (ii) the combined voting power of the then outstanding voting securities of Chesapeake Energy Corporation entitled to vote generally in the election of directors (the "Outstanding CHK Voting Securities"). For purposes of this paragraph, the following acquisitions by a Person will not constitute a Change of Control: (i) any acquisition by Chesapeake Energy Corporation; (ii) any redemption, share acquisition or other purchase of shares directly or indirectly by Chesapeake Energy Corporation; (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by Chesapeake Energy Corporation or any corporation controlled by Chesapeake Energy Corporation; or (iv) any acquisition by any corporation pursuant to a transaction which complies with clauses (i), (ii) and (iii) of paragraph (c) below;

(b) during any period of not more than twenty-four (24) months, the individuals who constitute the Board of Directors (the "Incumbent Board") of Chesapeake Energy Corporation as of the beginning of the period cease for any reason to constitute at least a majority of the Board of Directors. Any individual becoming a director whose election, or nomination for election by Chesapeake Energy Corporation's shareholders, is approved by a vote of at least a majority of the directors then comprising the Incumbent Board will be considered a member of the Incumbent Board, but any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Incumbent Board will not be deemed a member of the Incumbent Board.

(c) the consummation of a reorganization, merger, consolidation or sale or other disposition of all or substantially all of the assets of Chesapeake Energy Corporation (a "Business Combination"), unless following such Business Combination: (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding CHK Common Stock and Outstanding CHK Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than sixty percent (60%) of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns Chesapeake Energy Corporation or all or substantially all of Chesapeake Energy Corporation's assets either directly or through

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one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination of the Outstanding CHK Common Stock and Outstanding CHK Voting Securities, as the case may be, (ii) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of Chesapeake Energy Corporation or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, thirty percent (30%) or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination and (iii) at least a majority of the members of the Board of Directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Incumbent Board, providing for such Business Combination; or,

(d) the approval by the shareholders of Chesapeake Energy Corporation of a complete liquidation or dissolution of Chesapeake Energy Corporation.

For purposes of this Agreement, “Change of Control Period” means the twenty‑four (24) month period commencing on the effective date of a Change of Control.

6. Termination. This Agreement will continue in effect until the expiration of the term stated in Section 5 of this Agreement unless earlier terminated pursuant to this Section 6. For purposes of this Agreement, “Termination Date” shall mean (a) if Executive’s employment is terminated by death, the date of death; (b) if Executive’s employment is terminated pursuant to Section 6.4 due to a disability, thirty (30) days after notice of termination is provided to Executive in accordance with Section 6.4; (c) if Executive’s employment is terminated by Company without Cause or by Executive for Good Reason pursuant to Section 6.1.1 or 6.1.2, on the effective date of termination specified in the notice required by Section 6.1.1 or 6.1.2 respectively; (d) if Executive’s employment is terminated by Company for Cause pursuant to Section 6.1.3, the date on which the notice of termination required by Section 6.1.3 is given; or (e) if Executive’s employment is terminated by Executive pursuant to Section 6.2, on the effective date of termination specified by Executive in the notice of termination required by Section 6.2 unless the Company rejects such date as allowed by Section 6.2, in which case it would be the date specified by the Company.

6.1 Termination by Company. The Executive’s employment under this Agreement may be terminated prior to the expiration of the Term under the following circumstances:

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6.1.1 Termination without Cause or for Good Reason Outside of a Change of Control Period.

(a) Termination by the Company without Cause. The Company may terminate the Executive’s employment without Cause at any time by the service of written notice of termination to the Executive specifying an effective date of such termination not sooner than thirty (30) business days after the date of such notice.

(b) Termination by the Executive for Good Reason. Executive may terminate employment with the Company for “Good Reason” and such termination will not be a breach of this Agreement by Executive. For purposes of this paragraph 6.1.1(b), Good Reason shall mean the occurrence of one of the events set forth below:

(i) elimination of the Executive's job position or material reduction in duties and/or reassignment of the Executive to a new position of materially less authority; or

(ii) a material reduction in the Executive’s Base Salary.

Notwithstanding the foregoing, the Executive will not be deemed to have terminated for Good Reason unless (A) the Executive provides written notice to the Company of the existence of one of the conditions described above within ninety (90) days after the Executive has knowledge of the initial existence of the condition, (B) the Company fails to remedy the condition so identified within thirty (30) days after receipt of such notice (if capable of correction), (C) the Executive provides a notice of termination to the Company within thirty (30) days of the expiration of the Company’s period to remedy the condition specifying an effective date for the Executive’s termination, and (D) the effective date of the Executive’s termination of employment is within ninety (90) days after the Executive provides written notice to the Company of the existence of the condition referred to in clause (A).

(c) Obligations of the Company. In the event the Executive is Terminated without Cause or terminates employment for Good Reason outside of a Change of Control Period, the Executive will receive as termination compensation within thirty (30) days of the Termination Date: (a) a payment of one (1) times the sum of Base Salary and Annual Bonus in a lump sum payment; (b) all unvested awards granted to Executive prior to January 1, 2013 under the Equity

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Compensation Plans shall be immediately vested (provided performance share units shall only be payable subject to the attainment of the performance measures for the applicable performance period as provided under the terms of the applicable award agreement); (c) pro rata vesting through the last day of the month in which the Termination Date occurs of all unvested awards granted to Executive on or after January 1, 2013 under the Equity Compensation Plans (provided performance share units shall only be payable subject to the attainment of the performance measures for the applicable performance period as provided under the terms of the applicable award agreement); (d) any Supplemental Matching Contributions to the Chesapeake Energy Corporation Amended and Restated Deferred Compensation Plan (the “401(k) Make-Up Plan”) shall be immediately vested; and (e) a lump sum payment of any PTO pay accrued but unused through the Termination Date. For purposes of this Agreement “Annual Bonus” shall be defined as the average of the annual bonus payments the Executive has received during the immediately preceding three (3) calendar years unless the Executive has been employed by the Company or held the position listed in section 2.1 for less than fifteen (15) months prior to the Termination Date, in which case, “Annual Bonus” shall be defined as the greater of (i) the Executive’s target bonus for the year in which the Termination Date occurs or (ii) the average of the annual bonus payments the Executive has received during the immediately preceding three (3) calendar years. The right to the foregoing termination compensation described under clauses (a), (b) and (c) above is subject to the Executive's execution of the Company's severance agreement which will operate as a release of all legally waivable claims against the Company and the Executive's compliance with all of the provisions of this Agreement, including all post-employment obligations.

6.1.2 Termination without Cause or for Good Reason During a Change of Control Period.

(a) Termination by the Company without Cause. The Company may terminate the Executive’s employment without Cause during a Change of Control Period at any time by the service of written notice of termination to the Executive specifying an effective date of such termination

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not sooner than thirty (30) business days after the date of such notice.

(b) Termination by the Executive for Good Reason. Executive may terminate employment with the Company for “Good Reason” and such termination will not be a breach of this Agreement by Executive. For purposes of this paragraph 6.1.2(b), Good Reason during a Change of Control Period shall mean the occurrence of one of the events set forth below:

(i) elimination of the Executive's job position or material reduction in duties and/or reassignment of the Executive to a new position of materially less authority;

(ii) a material reduction in Executive’s Base Salary; or

(iii) a requirement that the Executive relocate to a location outside of a fifty (50) mile radius of the location of his/her office or principal base of operation immediately prior to the effective date of a Change of Control.

Notwithstanding the foregoing, Executive will not be deemed to have terminated for Good Reason unless (A) Executive provides written notice to the Company of the existence of one of the conditions described above within ninety (90) days after Executive has knowledge of the initial existence of the condition, (B) the Company fails to remedy the condition so identified within thirty (30) days after receipt of such notice (if capable of correction), (C) Executive provides a Notice of Termination to the Company within thirty (30) days of the expiration of the Company’s period to remedy the condition specifying an effective date for the Executive’s termination, and (D) the effective date of the Executive’s termination of employment is within ninety (90) days after Executive provides written notice to the Company of the existence of the condition referred to in clause (A).

(c) Obligations of the Company. In the event the Executive is Terminated without Cause or terminates employment for Good Reason during a Change of Control Period, the Executive will receive as termination compensation within thirty (30) days of the Termination Date: (a) a payment of two (2) times the sum of Base Salary and Annual Bonus in a lump sum payment; (b) all unvested awards granted under the Equity Compensation Plans shall be immediately vested (provided performance share units

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shall only be payable subject to the attainment of the performance measures for the applicable performance period as provided under the terms of the applicable award agreement); (c) any Supplemental Matching Contributions to the Chesapeake Energy Corporation Amended and Restated Deferred Compensation Plan (the “401(k) Make-Up Plan”) shall be immediately vested; and (d) a lump sum payment of any PTO pay accrued but unused through the Termination Date. The right to the foregoing termination compensation described under clauses (a), (b) and (c) above is subject to the Executive's execution of the Company's severance agreement which will operate as a release of all legally waivable claims against the Company and the Executive's compliance with all of the provisions of this Agreement, including all post-employment obligations.

6.1.3 Termination for Cause. The Company may terminate the employment of the Executive hereunder at any time for Cause (as hereinafter defined) (such a termination being referred to in this Agreement as a "Termination For Cause") by giving the Executive written notice of such termination. As used in this Agreement, "Cause" means:

(i) the willful and continued failure of the Executive to perform substantially the Executive’s duties with the Company or one of its affiliates (other than any such failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Executive by the Board or the Chief Executive Officer of the Company which specifically identifies the manner in which the Board or Chief Executive Officer believes that the Executive has not substantially performed the Executive’s duties, or

(ii) the willful engaging by the Executive in illegal conduct or gross misconduct which is materially and demonstrably injurious to the Company. For purposes of this provision, no act, or failure to act, on the part of the Executive shall be considered “willful” unless it is done, or omitted to be done, by the Executive in bad faith or without reasonable belief that the Executive’s action or omission was in the best interests of the Company. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board or upon the instructions of the Chief Executive Officer or based upon the advice of counsel for the Company shall be conclusively presumed

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to be done, or omitted to be done, by the Executive in good faith and in the best interests of the Company.

In the event this Agreement is terminated for Cause, the Company will not have any obligation to provide any further payments or benefits to the Executive after the Termination Date other than a lump sum payment within thirty (30) days of the Termination Date of any PTO pay accrued but unused through the Termination Date. 

6.2 Termination by Executive. The Executive may voluntarily terminate employment under this Agreement for any reason by the service of written notice of such termination to the Company specifying an effective date of termination no sooner than thirty (30) days and no later than sixty (60) days after the date of such notice; provided, however, if less than thirty (30) days remain in the Term, the minimum notice required from Executive under this Section 6.2 shall be reduced from thirty (30) to seven (7) days. The Company reserves the right to end the employment relationship at any time after the date such notice is given to the Company and to pay Executive through the Termination Date.

6.3 Retirement by Executive. In the event the Executive is fifty-five (55) years or older and the Executive’s employment is terminated under Sections 6.1.1 or 6.2 of this Agreement, the Executive will be (a) eligible for accelerated vesting of the unvested awards granted to the Executive prior to January 1, 2013 under the Equity Compensation Plans (provided performance share units shall only be payable subject to the attainment of the performance measures for the applicable performance period as provided under the terms of the applicable award agreement); (b) eligible for continued post-retirement vesting of the unvested awards granted to the Executive on or after January 1, 2013 under the Equity Compensation Plans (provided performance share units shall only be payable subject to the attainment of the performance measures for the applicable performance period as provided under the terms of the applicable award agreement); and (c) eligible for accelerated vesting of the unvested Supplemental Matching Contributions to the Chesapeake Energy Corporation Amended and Restated Deferred Compensation Plan (the "401(k) Make-Up Plan"). The vesting under clauses (a), (b) and (c) of this Section 6.3 will be in accordance with the retirement matrix (the "Retirement Matrix") attached to this Agreement. The right to acceleration and continued vesting is subject to the Executive’s execution of the Company’s severance agreement which will include a release of all legally waivable claims between the parties as of the effective date of the release except for the Company’s obligation to pay the foregoing severance compensation and the Executive’s obligation to comply with all post-employment obligations under this Agreement.

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6.4 Disability. If the Executive suffers from a physical or mental condition which in the reasonable judgment of the Company's management prevents the Executive from being able to perform the duties specified herein for a period of twelve (12) consecutive weeks, the Executive may be terminated by the Company. In the event the Executive is terminated due to Disability (a) all unvested awards granted to the Executive under the Equity Compensation Plans shall be immediately vested (provided performance share units shall only be payable subject to the attainment of the performance measures for the applicable performance period as provided under the terms of the applicable award agreement); and (b) any Supplemental Matching Contributions to the Chesapeake Energy 401(k) Make-Up Plan shall be immediately vested. Executive shall also receive a lump sum payment within thirty (30) days of the Termination Date of any PTO pay accrued but unused through the Termination Date. The right to the foregoing compensation due under clauses (a) and (b) above is subject to the execution by the Executive or the Executive's legal representative of the Company's severance agreement which will operate as a release of all legally waivable claims against the Company. In applying this Section 6.4, the Company will comply with any applicable legal requirements, including the Americans with Disabilities Act.

6.5 Death of Executive. If the Executive dies during the term of this Agreement, the Company may thereafter terminate this Agreement without compensation. In the event of the Executive’s death the Company will (a) immediately vest all unvested awards granted to the Executive under the Equity Compensation Plans (provided performance share units shall only be payable subject to the attainment of the performance measures for the applicable performance period as provided under the terms of the applicable award agreement); and (b) immediately vest any Supplemental Matching Contributions to the Chesapeake Energy 401(k) Make-Up Plan. Executive’s beneficiaries/estate shall also receive a lump sum payment within thirty (30) days of death of any PTO pay accrued but unused through the Termination Date. Amounts payable under this Section 6.5 shall be paid to the beneficiary designated on the Company's universal beneficiary designation form in effect on the date of the Executive's death. If the Executive fails to designate a beneficiary or if such designation is ineffective, in whole or in part, any payment that would otherwise have been paid under this Section 6.5 shall be paid to the Executive's estate. The right to the foregoing compensation due under clauses (a) and (b) above is subject to the execution by the beneficiary, or as applicable, the administrator of the Executive's estate of the Company's severance agreement which will operate as a release of all legally waivable claims against the Company.

6.6 Effect of Termination. The termination of this Agreement, when accompanied by the termination of Executive’s employment with the

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Company, will terminate all obligations of the Executive to render services on behalf of the Company from and after the Termination Date, provided that upon termination of this Agreement and termination of employment for any reason (other than by reason of Executive’s death), the Executive will maintain the confidentiality of all information acquired by the Executive during the term of Executive's employment in accordance with the terms and provisions of the Company’s Confidentiality Agreement and the Executive shall comply with all other post employment requirements including Section 6.6 and Sections 7, 8, 9, 10, 11, 12 and 13. Except as otherwise provided in Sections 4.5 and 6 of this Agreement and payment of any PTO pay accrued but unused through the Termination Date, no accrued bonus, severance pay or other form of compensation will be payable by the Company to the Executive by reason of the termination of this Agreement. All keys, entry cards, credit cards, files, records, financial information, Confidential Information, research, results, test data, instructions, drawings, sketches, specifications, product data sheets, products, books, DVDs, disks, memory devices, business plans, marketing plans, documents, correspondence, furniture, furnishings, equipment, supplies and other items relating to the Company in the Executive's possession will remain the property of the Company. Upon termination of employment, the Executive will have the right to retain and remove all personal property and effects which are owned by the Executive and located in the offices of the Company at a time determined by the Company. All such personal items will be removed from such offices no later than two (2) days after the Termination Date, and the Company is hereby authorized to discard any items remaining and to reassign the Executive's office space after such date. Prior to the Termination Date, the Executive will render such services to the Company as might be reasonably required to provide for the orderly termination of the Executive's employment. Notwithstanding the foregoing and without discharging any obligations to pay compensation to the Executive under this Agreement, after notice of the termination, the Company may request that the Executive not provide any other services to the Company and not enter the Company's premises before or after the Termination Date. In the event that the Executive separates employment with the Company, Executive hereby grants consent to notification by the Company to Executive's new employer about Executive's rights and obligations under this Agreement. Upon such termination of employment, the Executive further agrees to acknowledge compliance with this Agreement in a form reasonably provided by the Company.

If this Agreement is not terminated pursuant to any of the preceding provisions of Section 6 or extended by mutual written agreement of the parties prior to the expiration of the Term, this Agreement and Executive’s employment under this Agreement will end and Company will have no further obligation to provide any further payments or benefits to Executive under this Agreement after the expiration of the

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Term other than any PTO pay accrued but unused through the expiration of the Term. Upon expiration of this Agreement, Executive will continue to be employed with Company on an at will basis until such employment is terminated by either party, with or without any reason.

7. Non-Competition. For a period of one (1) year after the Executive is no longer employed by the Company for any reason, the Executive will not knowingly acquire, attempt to acquire or aid another in the acquisition or attempted acquisition of an interest in oil and gas assets, oil and gas production, oil and gas leases, mineral interests, oil and gas wells or other such oil and gas exploration, development or production activities within any spacing unit in which the Company owns an oil and gas interest on the date of the resignation or termination of the Executive.

8. Non-Solicitation. The Executive agrees that during his/her employment hereunder, and for the one (1) year period immediately following the termination of employment for any reason, the Executive shall not solicit or contact any established client or customer of the Company with a view to inducing or encouraging such established client or customer to discontinue or curtail any business relationship with the Company. The Executive further agrees that the Executive will not request or advise any established clients, customers or suppliers of the Company to withdraw, curtail or cancel its business with the Company.

9. Non-Solicitation of Employees. The Executive covenants that during the term of employment and for the one (1) year period immediately following the termination of employment for any reason, Executive will neither directly nor indirectly induce nor attempt to induce any executive or employee of the Company to terminate his or her employment with the Company to go to work for any other company.

10. Reasonableness. The Company and the Executive have attempted to specify a reasonable period of time and reasonable restrictions to which this Agreement shall apply. The Company and Executive agree that if a court or administrative body should subsequently determine that the terms of this Agreement are greater than reasonably necessary to protect the Company's interest, the Company agrees to waive those terms which are found by a court or administrative body to be greater than reasonably necessary to protect the Company's interest and to request that the court or administrative body reform this Agreement specifying a reasonable period of time and such other reasonable restrictions as the court or administrative body deems necessary.

11. Equitable Relief. The Executive acknowledges that the services to be rendered by Executive are of a special, unique, unusual, extraordinary, and intellectual character, which gives them a peculiar value, and the loss of which cannot reasonably or adequately be compensated in damages in an action at law; and that a breach by the Executive of any of the provisions contained in this Agreement will cause the Company irreparable injury and damage. The Executive further acknowledges that the Executive possesses unique skills, knowledge and ability

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and that any material breach of the provisions of this Agreement would be extremely detrimental to the Company. By reason thereof, the Executive agrees that the Company shall be entitled, in addition to any other remedies it may have under this Agreement or otherwise, to injunctive and other equitable relief to prevent or curtail any breach of this Agreement by him/her.

12. Continued Litigation Assistance. The Executive will cooperate with and assist the Company and its representatives and attorneys as requested, during and after the Term, with respect to any litigation, arbitration or other dispute resolutions by being available for interviews, depositions and/or testimony in regard to any matters in which the Executive is or has been involved or with respect to which the Executive has relevant information. The Company will reimburse the Executive for any reasonable business expenses the Executive may have incurred in connection with this obligation.

13. Arbitration. Any disputes, claims or controversies between the Company and Executive including, but not limited to those arising out of or related to this Agreement or out of the parties' employment relationship (together, “Employment Matter”), shall be settled by arbitration as provided herein. This agreement shall survive the termination or rescission of this Agreement. All arbitration shall be in accordance with Rules of the American Arbitration Association, including discovery, and shall be undertaken pursuant to the Federal Arbitration Act. Arbitration will be held in Oklahoma City, Oklahoma unless the parties mutually agree to another location. The decision of the arbitrator will be enforceable in any court of competent jurisdiction. The parties, however, agree that the Company shall be entitled to obtain injunctive or other equitable relief to enforce the provisions of this Agreement in a court of competent jurisdiction. The parties further agree that this arbitration provision is not only applicable to the Company but its affiliates, officers, directors, employees and related parties. Executive agrees that he/she shall have no right or authority for any dispute to be brought, heard or arbitrated as a class or collective action, or in a representative or a private attorney general capacity on behalf of a class of persons or the general public. No class, collective or representative actions are thus allowed to be arbitrated and Executive agrees that he/she must pursue any claims that he/she may have solely on an individual basis through arbitration. The Company will reimburse the Executive for all legal fees and expenses reasonably incurred (provided such legal fees are calculated on an hourly, and not on a contingency fee basis), as well as costs and expenses reasonably incurred in connection with an Employment Matter. Reimbursement by the Company shall be made as soon as practicable following final resolution of the Employment Matter to the extent the Company receives appropriate documentation of such attorney’s fees, costs and expenses which shall be provided no later than December 31 of the year in which the Employment Matter is resolved, provided, however, the Executive will only be entitled to reimbursement if the Executive is successful in respect of one or more material claims or defenses brought, raised or pursued in connection with such Employment Matter. Payment of reimbursement for such fees and expenses

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shall be made no later than December 31 of the year immediately following the year of resolution.

14 Miscellaneous. The parties further agree as follows:

14.1 Time. Time is of the essence of each provision of this Agreement.

14.2 Notices. Any notice, payment, demand or communication required or permitted to be given by any provision of this Agreement will be in writing and will be deemed to have been given when delivered personally or by express mail to the party designated to receive such notice, or on the date following the day sent by overnight courier, or on the third business day after the same is sent by certified mail, postage and charges prepaid, directed to the following address or to such other or additional addresses as any party might designate by written notice to the other party:

To the Company:	Chesapeake Energy Corporation
	6100 N. Western Ave.
	Oklahoma City, OK 73118
	Attn: Lisa M. Phelps
To the Executive:	James R. Webb
	516 Meadow Run Court
	Yukon, OK 73099

14.3 Assignment. Neither this Agreement nor any of the parties' rights or obligations hereunder can be transferred or assigned without the prior written consent of the other parties to this Agreement; provided, however, the Company may assign this Agreement to any wholly owned affiliate or subsidiary of Chesapeake Energy Corporation without Executive's consent as well as to any purchaser of the Company.

14.4 Construction. If any provision of this Agreement or the application thereof to any person or circumstances is determined, to any extent, to be invalid or unenforceable, the remainder of this Agreement, or the application of such provision to persons or circumstances other than those as to which the same is held invalid or unenforceable, will not be affected thereby, and each term and provision of this Agreement will be valid and enforceable to the fullest extent permitted by law. Except as provided for in Section 13, this Agreement is intended to be interpreted, construed and enforced in accordance with the laws of the State of Oklahoma.

14.5 Entire Agreement. This Agreement, any documents executed in connection with this Agreement, any documents specifically referred to in this Agreement and the Employment Policies Manual constitute the entire agreement between the parties hereto with respect to the subject matter

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herein contained, and no modification hereof will be effective unless made by a supplemental written agreement executed by all of the parties hereto.

14.6 Binding Effect. This Agreement will be binding on the parties and their respective successors, legal representatives and permitted assigns. In the event of a merger, consolidation, combination, dissolution or liquidation of the Company, the performance of this Agreement will be assumed by any entity which succeeds to or is transferred the business of the Company as a result thereof, and the Executive waives the consent requirement of Section 14.3 to effect such assumption.

14.7 Supersession. On execution of this Agreement by the Company and the Executive, the relationship between the Company and the Executive will be bound by the terms of this Agreement, any documents executed in connection with this Agreement, any documents specifically referred to in this Agreement and the Employment Policies Manual. In the event of a conflict between the Employment Policies Manual and this Agreement, this Agreement will control in all respects.

14.8 Third-Party Beneficiary. The Company's affiliated entities and partnerships are beneficiaries of all terms and provisions of this Agreement and entitled to all rights hereunder.

14.9 Section 409A. This Agreement is intended to be exempt from Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), and related U.S. Treasury regulations or official pronouncements (“Section 409A”) and any ambiguous provision will be construed in a manner that is compliant with such exemption; provided, however, if and to the extent that any compensation payable pursuant to this Agreement is determined to be subject to Section 409A, this Agreement will be construed in a manner that will comply with Section 409A. Notwithstanding any provision to the contrary in this Agreement, if the Executive is deemed on his/her Termination Date to be a “specified employee” within the meaning of that term under Section 409A, then any payments and benefits under this Agreement that are subject to Section 409A and paid by reason of a termination of employment shall be made or provided on the later of (a) the payment date set forth in this Agreement or (b) the date that is the earliest of (i) the expiration of the six-month period measured from the date of the Executive’s termination of employment or (ii) the date of the Executive’s death (the “Delay Period”). Payments and benefits subject to the Delay Period shall be paid or provided to the Executive without interest for such delay. Termination of employment as used throughout this Agreement shall refer to a separation from service within the meaning of Section 409A. To the extent required to comply with Section 409A, references to a “resignation,” “termination,” “termination of employment” or like terms

-16-

throughout this Agreement shall be interpreted consistent with the meaning of “separation from service” as defined in Section 409A.

14.10 Dodd-Frank Act. Notwithstanding anything in this Agreement or any other agreement between the Company and/or its related entities and Executive to the contrary, Executive acknowledges that the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Act”) may have the effect of requiring certain executives of the Company and/or its related entities to repay the Company, and for the Company to recoup from such executives, erroneously awarded amounts of incentive-based compensation. If, and only to the extent, the Act, any rules and regulations promulgated by thereunder by the Securities and Exchange Commission or any similar federal or state law requires the Company to recoup any erroneously awarded incentive-based compensation that the Company has paid or granted to Executive, Executive hereby agrees, even if Executive has terminated his employment with the Company, to promptly repay such erroneously awarded incentive compensation to the Company upon its written request. This Section shall survive the termination of this Agreement.

14.11 Maximum Payments by the Company.

(a) It is the objective of this Agreement to maximize Executive’s Net After-Tax Benefit (as defined herein) if payments or benefits provided under this Agreement are subject to excise tax under Section 4999 of the Code. Notwithstanding any other provisions of this Agreement, in the event that any payment or benefit by the Company or otherwise to or for the benefit of Executive, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise, including, by example and not by way of limitation, acceleration by the Company or otherwise of the date of vesting or payment or rate of payment under any plan, program, arrangement or agreement of the Company (all such payments and benefits, including the payments and benefits under Section 6 hereof, being hereinafter referred to as the “Total Payments”), would be subject (in whole or in part) to the excise tax imposed by Section 4999 of the Code (the “Excise Tax”), then the cash severance payments shall first be reduced, and the non-cash severance payments shall thereafter be reduced, to the extent necessary so that no portion of the Total Payments shall be subject to the Excise Tax, but only if (i) the net amount of such Total Payments, as so reduced (and after subtracting the net amount of federal, state and local income taxes on such reduced Total Payments and after taking into account the phase out of itemized deductions and personal exemptions attributable to such reduced Total Payments), is greater than or equal to (ii) the net amount of such Total Payments without such reduction (but after subtracting the net amount of federal, state and local income taxes on such Total Payments and the amount of Excise Tax

-17-

to which Executive would be subject in respect of such unreduced Total Payments and after taking into account the phase out of itemized deductions and personal exemptions attributable to such unreduced Total Payments).

(b) The Total Payments shall be reduced by the Company in the following order: (i) reduction of any cash severance payments otherwise payable to Executive that are exempt from Section 409A of the Code, (ii) reduction of any other cash payments or benefits otherwise payable to Executive that are exempt from Section 409A of the Code, but excluding any payments attributable to the acceleration of vesting or payments with respect to any equity award with respect to the Company’s common stock that is exempt from Section 409A of the Code, (iii) reduction of any other payments or benefits otherwise payable to Executive on a pro-rata basis or such other manner that complies with Section 409A of the Code, but excluding any payments attributable to the acceleration of vesting and payments with respect to any equity award with respect to the Company’s common stock that are exempt from Section 409A of the Code, and (iv) reduction of any payments attributable to the acceleration of vesting or payments with respect to any other equity award with respect to the Company’s common stock that are exempt from Section 409A of the Code.

(c) For purposes of determining whether and the extent to which the Total Payments will be subject to the Excise Tax, (i) no portion of the Total Payments the receipt or enjoyment of which Executive shall have waived at such time and in such manner as not to constitute a “payment” within the meaning of Section 280G(b) of the Code shall be taken into account, (ii) no portion of the Total Payments shall be taken into account which, in the written opinion of independent auditors of nationally recognized standing (“Independent Advisors”) selected by the Company, does not constitute a “parachute payment” within the meaning of Section 280G(b)(2) of the Code (including by reason of Section 280G(b)(4)(A) of the Code) and, in calculating the Excise Tax, no portion of such Total Payments shall be taken into account which, in the opinion of Independent Advisors, constitutes reasonable compensation for services actually rendered, within the meaning of Section 280G(b)(4)(B) of the Code, in excess of the “base amount” (as defined in Section 280G(b)(3) of the Code) allocable to such reasonable compensation, and (iii) the value of any non-cash benefit or any deferred payment or benefit included in the Total Payments shall be determined by the Independent Advisors in accordance with the principles of Sections 280G(d)(3) and (4) of the Code. The costs of obtaining such determination shall be borne by the Company.

-18-

IN WITNESS WHEREOF, the undersigned have executed this Agreement effective the date first above written.

	CHESAPEAKE ENERGY CORPORATION, an
	Oklahoma corporation
By:	/s/ Aubrey K. McClendon
	Aubrey K. McClendon, Chief Executive Officer
	(the "Company")
By:	/s/ James R. Webb
	James R. Webb, Individually
	(the "Executive")

-19-

RETIREMENT MATRIX

Executive Vice President
Service Yrs	<55	55-59	60-64	>=65
0-5	0%	0%	0%	0%
5-10	0%	60%	80%	100%
10-15	0%	80%	100%	100%
15-20	0%	100%	100%	100%
20+	0%	100%	100%	100%

EX-12

EXHIBIT 12

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

RATIOS OF EARNINGS TO FIXED CHARGES AND COMBINED FIXED CHARGES

AND PREFERRED DIVIDENDS

	Years Ended December 31,
	2010			2011			2012			2013		2014
	($ in millions)
EARNINGS:
Income (loss) before income taxes and cumulative effect of accounting change	$	2,884		$	2,880		$	(974	)	$	1,442	$	3,200
Interest expense(a)	122			94			142			207		172
(Gain)/loss on investment in equity investees in excess of distributed earnings	(232		)	(154		)	108			219		75
Amortization of capitalized interest	212			297			402			440		438
Loan cost amortization	25			28			43			37		32
Earnings	$	3,011		$	3,145		$	(279	)	$	2,345	$	3,917
FIXED CHARGES:
Interest Expense	$	122		$	94		$	142		$	207	$	172
Capitalized interest	711			727			976			815		604
Loan cost amortization	25			28			43			37		32
Fixed Charges	$	858		$	849		$	1,161		$	1,059	$	808
PREFERRED STOCK DIVIDENDS:
Preferred dividend requirements	$	111		$	172		$	171		$	171	$	171
Ratio of income (loss) before provision for taxes to net income (loss)(b)	1.63			1.65			1.64			1.61		1.56
Preferred Dividends	$	181		$	284		$	280		$	275	$	266
COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS	$	1,039		$	1,131		$	1,441		$	1,334	$	1,074
RATIO OF EARNINGS TO FIXED CHARGES	3.5			3.7			(0.2		)	2.2		4.8
INSUFFICIENT COVERAGE	$	—		$	—		$	1,440		$	—	$	—
RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS	2.9			2.8			(0.2		)	1.8		3.6
INSUFFICIENT COVERAGE	$	—		$	—		$	1,720		$	—	$	—

(a) Excludes the effect of unrealized gains or losses on interest rate derivatives and includes amortization of bond discount.

(b) Amounts of income (loss) before provision for taxes and of net income (loss) exclude the cumulative effect of accounting change.

EX-21

Exhibit 21

CHESAPEAKE ENERGY CORPORATION

Oklahoma Corporation

SIGNIFICANT SUBSIDIARIES*

Corporations	State of Organization
Chesapeake E&P Holding Corporation	Oklahoma
Chesapeake Energy Louisiana Corporation	Oklahoma
Limited Liability Companies	State of Organization
Chesapeake Appalachia, L.L.C.	Oklahoma
Chesapeake Energy Marketing, L.L.C.	Oklahoma
Chesapeake Exploration, L.L.C.	Oklahoma
Chesapeake Land Development Company, L.L.C.	Oklahoma
Chesapeake Operating, L.L.C.	Oklahoma
CHK Utica, L.L.C.	Delaware
MidCon Compression, L.L.C.	Oklahoma
Partnerships	State of Organization
Chesapeake Lousiana, L.P.	Oklahoma
* In accordance with Regulation S-K Item 601(b)(21), the names of particular subsidiaries that, considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary (as that term is defined in Rule 1-02(w) of Regulation S-X) as of the end of the year covered by this report have been omitted.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 333-109162, 333-126191, 333-135949, 333‑143990, 333-151762, 333-157504, 333-160350, 333-171468, 333-178067, 333-187018, 333-189651, 333-192175 and 333-196977) and Form S-3 (File No. 333-190457) of Chesapeake Energy Corporation of our report dated February 27, 2015 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10‑K.

/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma

February 27, 2015

EX-23.2

Exhibit 23.2

CONSENT OF PETROTECHNICAL SERVICES

DIVISION OF SCHLUMBERGER TECHNOLOGY CORPORATION

As independent oil and gas consultants, PetroTechnical Services, Division of Schlumberger Technology Corporation hereby consents to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 333-109162, 333‑126191, 333-135949, 333-143990, 333‑151762, 333-157504, 333-160350, 333-171468, 333‑178067, 333-187018, 333-189651, 333-192175 and 333-196977) and Form S-3 (File No. 333-190457) of Chesapeake Energy Corporation of all references to our firm and information from our reserves report dated 6 January 2015, included in or made a part of the Chesapeake Energy Corporation Annual Report on Form 10-K for the year ended December 31, 2014 to be filed with the Securities and Exchange Commission on or about February 25, 2015, and our summary report attached as Exhibit 99.1 to such Annual Report on Form 10-K.

PETROTECHNICAL SERVICES,

DIVISION OF SCHLUMBERGER

TECHNOLOGY CORPORATION

By: /s/ Charles M. Boyer II, PG, CPG

Charles M. Boyer II, PG, CPG

Consulting Services Manager – NE Basin

Adviser – Unconventional Reservoirs

Pittsburgh, Pennsylvania

25 February, 2015

EX-23.3

Exhibit 23.3

CONSENT OF RYDER SCOTT COMPANY, L.P.

As independent oil and gas consultants, Ryder Scott Company, L.P. hereby consents to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 333-109162, 333 126191, 333-135949, 333-143990, 333 151762, 333-157504, 333-160350, 333-171468, 333‑178067, 333-187018, 333-189651, 333-192175 and 333-196977) and Form S-3 (File No. 333-190457) of Chesapeake Energy Corporation of all references to our firm and information from our reserves report dated January 15, 2015, entitled “Chesapeake Energy Corporation Northern and Southern Divisions Estimated Future Reserves and Income Attributable to Certain Leasehold and Royalty Interests as of December 31, 2014”, included in or made a part of the Chesapeake Energy Corporation Annual Report on Form 10-K for the year ended December 31, 2014 to be filed with the Securities and Exchange Commission on or about February 25, 2015, and our summary report attached as Exhibit 99.2 to such Annual Report on Form 10-K.

By: /s/ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Registration No. F-1580

Houston, Texas

February 25, 2015

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Robert D. Lawler, certify that:

1. I have reviewed this annual report on Form 10-K of Chesapeake Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made know to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 27, 2015	By:	/s/ ROBERT D. LAWLER
		Robert D. Lawler
		President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Domenic J. Dell’Osso, Jr., certify that:

1. I have reviewed this annual report on Form 10-K of Chesapeake Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made know to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 27, 2015	By:	/s/ DOMENIC J. DELL’OSSO, JR.
		Domenic J. Dell’Osso, Jr.
		Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Chesapeake Energy Corporation (the “Company”) on Form 10-K for the period ended December 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert D. Lawler, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 27, 2015	By:	/s/ ROBERT D. LAWLER
		Robert D. Lawler        President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Chesapeake Energy Corporation (the “Company”) on Form 10-K for the period ended December 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 27, 2015	By:	/s/ DOMENIC J. DELL’OSSO, JR.
		Domenic J. Dell’Osso, Jr.
		Executive Vice President and Chief Financial Officer

EX-99.1

Exhibit 99.1

PetroTechnical Services
Division of Schlumberger Technology Corporation
4600 J. Barry Court
Suite 200
Canonsburg, PA 15317 USA
Tel: 724-416-9700
Fax: 724-416-9705

6 January 2015

Chesapeake Energy Corporation

6100 N. Western Avenue

Oklahoma City, OK 73118

Dear Gentlemen:

At the request of Chesapeake Energy Corporation (Chesapeake), through their letter of engagement, PetroTechnical Services (PTS) Division of Schlumberger Technology Corporation has evaluated the proved reserves of certain Chesapeake oil and gas interests located in their Northern Division United States (U.S.) properties as of 31 December 2014. The evaluated properties are located in Kentucky, Ohio, Pennsylvania, West Virginia, and Wyoming. This report was completed as of the date of this letter and has been prepared using constant prices and costs and conforms to our understanding of the U.S. Securities and Exchange Commission (SEC) guidelines and applicable financial accounting rules. All prices, costs, and cash flow estimates are expressed in U.S. dollars (US$). It is our understanding that the properties evaluated by PTS comprise approximately 24.7% of Chesapeake’s total proved reserves. We prepared this report for Chesapeake’s use in filing with the SEC. We believe that the assumptions, data, methods, and procedures used in preparing this report are appropriate for the purpose of this report and that we have used all methods and procedures that we consider necessary and appropriate under the circumstances to prepare this report. The Lead Evaluator for this evaluation was Charles M. Boyer II, PG, CPG, and his qualifications, independence, objectivity, and confidentiality meet the requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

The results of the Proved reserve evaluation are summarized in Table 1 and Table 2. The values contained in this report do not include existing Chesapeake financial instruments or hedges.

Table 1

Estimated Net Reserves And Income

Certain Northern Division Oil And Gas Interests

Chesapeake Energy Corporation

As Of 31 December 2014

Proved Developed And Undeveloped Reserves

	Proved Developed Reserves	Proved Undeveloped Reserves	Total Proved Reserves
Remaining Net Reserves Oil – Mbbls NGL - Mbbls Gas – MMscf Oil Equiv. – Mbbls	22,998.21 51,444.93 2,354,869.75 466,921.44	6,845.29 13,097.82 737,364.06 142,837.12	29,843.50 64,542.75 3,092,233.50 609,758.44
Income Data (M$) Future Net Revenue Deductions   Operating Expense   Production Taxes   Investment Future Net Cashflow (FNC)	10,378,187.24 1,591,295.00 371,640.77 439,202.97 7,976,046.50	3,125,823.94 210,932.09 61,352.54 667,938.69 2,185,600.50	13,504,011.00 1,802,227.00 432,993.28 1,107,141.75 10,161,648.00
Discounted PV @ 10% (M$)	4,479,868.50	1,107,491.50	5,587,357.00

PetroTechnical Services
Division of Schlumberger Technology Corporation
January 26, 2015
Page 2

Table 2

Estimated Net Reserves And Income

Certain Northern Division Oil And Gas Interests

Summarized By Reserve Category

Chesapeake Energy Corporation

As Of 31 December 2014

	Proved Producing Reserves	Proved Behind Pipe Reserves	Proved Non-producing Reserves	Proved Shut-In Reserves	Proved Undeveloped Reserves	Total Proved Reserves
Remaining Net Reserves Oil – Mbbls NGL - Mbbls Gas – MMscf Oil Equiv. – Mbbls	20,485.49 49,472.07 2,165,803.00 430,924.75	0.00 0.00 10,980.09 1,830.02	2,512.72 1,972.85 178,086.36 34,166.63	0.00 0.00 0.00 0.00	6,845.29 13,097.82 737,364.06 142,837.12	29,843.50 64,542.75 3,092,233.50 609,758.44
Income Data (M$) Future Net Revenue Deductions   Operating Expense   Production Taxes   Investment Future Net Cashflow (FNC)	9,571,083.50 1,507,111.88 336,494.03 351,209.88 7,376,266.00	34,002.66 4,811.43 787.61 8,221.17 20,182.45	773,100.65 78,730.56 34,359.07 75,482.80 584,528.12	0.00 640.96 0.00 4,289.14    (4,930.10)	3,125,823.94 210,932.09 61,352.54 667,938.69 2,185,600.50	13,504,011.00 1,802,227.00 432,993.28 1,107,141.75 10,161,648.00
Discounted PV @ 10% (M$)	4,107,597.75	8,519.94	368,291.69	(4,541.670)	1,107,491.50	5,587,357.00

The values in the tables above may not add up arithmetically due to rounding procedures in the computer software program used to prepare the economic projections. All hydrocarbon liquids are reported as 42 gallon barrels. Gas volumes are reported at the standard pressure and temperature bases of the area where the gas is sold.

We are independent with respect to Chesapeake as provided in the SEC regulations. Neither the employment of nor the compensation received by PTS was contingent upon the values estimated for the properties included in this report.

Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into: developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories: producing and non-producing. Non-producing reserves include shut-in and behind-pipe reserves. The reserves included in this report include only proved reserves and do not include probable or possible reserves. Chesapeake has an active exploration and development program to develop their interests in certain tracts not classified as proved at this time. Future drilling may result in the reclassification of additional volumes to the proved reserve category. However, changes in the regulatory requirements for oil and gas operations may impact future development plans and the ability of the company to recover the estimated proved undeveloped reserves. The reserves and income attributable to the various reserve categories included in this report have not been adjusted to reflect the varying degrees of risk associated with them.

Reserve estimates are strictly technical judgments. The accuracy of any reserve estimate is a function of the quality and quantity of data available and of the engineering and geological interpretations. The reserve estimates presented in this report are believed reasonable; however, they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision. A portion of these reserves are for undeveloped locations and producing or non-producing wells that lack sufficient production history to utilize conventional performance-based reserve estimates. In these cases, the reserves are based on volumetric estimates and recovery efficiencies along with analogies to similar producing areas. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. As additional production and

PetroTechnical Services
Division of Schlumberger Technology Corporation
January 26, 2015
Page 3

pressure data becomes available, these estimates may be revised up or down. Actual future prices may vary significantly from the prices used in this evaluation; therefore, future hydrocarbon volumes recovered and the income received from these volumes may vary significantly from those estimated in this report. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

Standard geological and engineering methods generally accepted by the petroleum industry were used in the estimation of Chesapeake’s reserves. Deterministic methods were used for all reserves included in this report. The appropriate combination of conventional decline curve analysis (DCA), production data analysis, volumetrics, reservoir simulation, and type curves were used to estimate the remaining reserves in the various producing areas. Volumetric calculations were based on data and maps provided by Chesapeake. Comparisons were made to similar properties for which more complete data were available for areas of new development.

All prices used in preparation of this report were based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December 2014. The resulting Henry Hub reference gas price used was $4.350/MMBtu and the resulting West Texas Intermediate reference oil price used was $94.984/Bbl. Henry Hub gas price and West Texas Intermediate oil price are common reference prices for natural gas and oil production in the U.S. The prices were adjusted forlocal differentials, gravity and Btu where applicable. As required by SEC guidelines, all pricing was held constant for the life of the projects (no escalation). Table 3 summarizes the 2013 reference prices and the resulting average prices used in this reserves evaluation. The average prices were calculated using the total future revenue by product prior to taxes and expenses divided by the total net reserves by product.

Table 3

Chesapeake Energy Corporation - Northern Division

Oil, Gas And NGL Prices

Year End 2014 Reserves Evaluation

Product	Reference Point	Year End 2014 Reference Price	Average Price
Oil	West Texas Intermediate	$94.984/Bbl	$82.320/Bbl
NGL	West Texas Intermediate	$94.984/Bbl	$23.191/Bbl
Natural Gas	Henry Hub	$4.350/MMBtu	$3.089/Mscf

Operating costs used in this report were based on values reported by Chesapake and reviewed by PTS. Chesapeake’s estimates for capital costs for all non-producing and undeveloped wells are included in the evaluation. Chesapeake has indicated to us that they have the ability and intent to implement their capital expenditure program as scheduled. Operating costs and capital costs were held constant for the life of the projects (no escalation).

Net revenue (sales) is defined as the total proceeds from the sale of oil, condensate, natural gas liquids (NGL), and gas adjusted for commodity price basis differential and gathering/ transportation expense. Future net income (cashflow) is future net revenue less net lease operating expenses, state severance or production taxes, certain allowed corporate general administrative and overhead costs, operating/development capital expenses and net salvage. Future plugging, abandonment, and salvage costs are included at the economic life of each well or unit. No provisions for State or Federal income taxes have been made in this evaluation. The present worth (discounted cashflow) at various discount rates is calculated on a monthly basis.

In the conduct of our evaluation, we have not independently verified the accuracy and completeness of information and data furnished by Chesapeake with respect to ownership interests, historical oil and gas production, costs of operation and development, product prices, payout balances, and agreements relating

PetroTechnical Services
Division of Schlumberger Technology Corporation
January 26, 2015
Page 4

to current and future operations and sales of production. If in the course of our examination something came to our attention which brought into question the validity or sufficiency of any of the information or data provided by Chesapeake, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information or data.

In our opinion the above-described estimates of Chesapeake’s proved reserves and supporting data are, in the aggregate, reasonable. It is also our opinion that the above-described estimates of Chesapeake’s proved reserves conform to the definitions of proved oil and gas reserves promulgated by the Securities and Exchange Commission. These reserves definitions are provided at the conclusion of this letter.

All data used in this study were obtained from Chesapeake, public industry information sources, or the non-confidential files of PTS. A field inspection of the properties was not made in connection with the preparation of this report. The potential environmental liabilities attendant to ownership and/or operation of the properties have not been addressed in this report. Abandonment and clean-up costs and possible salvage value of the equipment were considered in this report.

In evaluating the information at our disposal related to this report, we have excluded from our consideration all matters which require a legal or accounting interpretation, or any interpretation other than those of an engineering or geological nature. In assessing the conclusions expressed in this report pertaining to all aspects of oil and gas evaluations, especially pertaining to reserve evaluations, there are uncertainties inherent in the interpretation of engineering data, and such conclusions represent only informed professional judgments.

Data and worksheets used in the preparation of this evaluation will be maintained in our files in Canonsburg and will be available for inspection by anyone having proper authorization from Chesapeake.

Sincerely yours,
/s/ Denise L. Delozier	/s/ Charles M. Boyer II
Denise L. Delozier	Charles M. Boyer II, PG, CPG
Senior Engineer	Northeast Basin Business Manager
	Advisor - Unconventional Reservoirs
/s/ Walker K. Sawyer
Walker K. Sawyer, PE
Principal Consultant

SECURITIES AND EXCHANGE COMMISION

REGULATION S-X, RULE 210.4-10 (a)

RESERVES DEFINITIONS

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2):Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbonsmeans hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions

of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(21) Proved area.The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties.Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

(27) Reservoir.A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties.Properties with no proved reserves.

EX-99.2

Exhibit 99.2

Chesapeake Energy Corporation

SOUTHERN DIVISION

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

Executive Summary

SEC Parameters

As of

December 31, 2014

\s\ Don P. Griffin

Don P. Griffin, P.E.

TBPE License No. 64150

Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPE REGISTERED ENGINEERING FIRM F-1580        FAX (713) 651-0849

1100 LOUISIANA STREET SUITE 4600    HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

January 15, 2015

Chesapeake Energy Corporation

6100 North Western Avenue

Oklahoma City, Oklahoma 73118

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of proved reserves, future production, and income attributable to certain leasehold and royalty interests of Chesapeake Energy Corporation Southern Division (Chesapeake) as of December 31, 2014. The subject properties are located in the states of Arkansas, Kansas, Louisiana, Mississippi, Oklahoma and Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 15, 2015 and presented herein, was prepared for public disclosure by Chesapeake in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of Chesapeake’s total net proved reserves as of December 31, 2014. Based on information provided by Chesapeake, the third party estimate conducted by Ryder Scott addresses 58 percent of the total net proved developed reserves and 44 percent of the undeveloped reserves, based on the respective gas equivalent basis; assuming liquid hydrocarbons are converted to gas equivalent using a factor of one barrel of oil per 6,000 cubic feet of gas equivalent.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2014, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized on the following page.

SUITE 600, 1015 4TH STREET, S.W.    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790

621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501    TEL (303) 623-9147    FAX (303) 623-4258

Chesapeake Energy Corporation

January 15, 2015

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

Chesapeake Energy Corporation

Southern Division

As of December 31, 2014

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Remaining Reserves
Oil/Condensate – MBarrels	158,446		5,790		124,673		288,909
Plant Products – MBarrels	116,071		5,367		31,855		153,293
Gas – MMCF	4,541,273		193,396		648,225		5,382,894
MBOE	1,031,396		43,389		264,566		1,339,351
Income Data (M$)
Future Gross Revenue		$27,358,076		$1,186,093		$12,206,031		$40,750,200
Deductions	6,154,879		328,982		4,965,463		11,449,324
Future Net Income (FNI)		$21,203,197	$	857,111	$	7,240,568		$29,300,876
Discounted FNI @ 10%		$10,680,345	$	428,357	$	2,488,373		$13,597,075

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousands barrels of oil equivalent. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used at the request of Chesapeake. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, certain abandonment costs net of salvage, and certain allowed corporate general administrative and overhead costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately69.3 percent and gas reserves account for the remaining 30.7 percent of total future gross revenue from proved reserves.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Chesapeake Energy Corporation

January 15, 2015

Page 3

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income (M$)
	As of December 31, 2014
Discount Rate		Total
Percent		Proved
5		$18,418,128
8		$15,156,650
12		$12,353,876
14		$11,338,637

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The provedgas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. AtChesapeake’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic and probabilistic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” A portion of the proved reserves in the Eagle Ford shale areas included herein were estimated using probabilistic methods which assess the uncertainty in the estimated quantities of reserves based on the probability that the quantities actually recovered will equal or exceed the estimate. For proved reserves, there should be at

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Chesapeake Energy Corporation

January 15, 2015

Page 4

least a 90 percent probability (P90) that the actual quantities recovered will equal or exceed the estimate. The reserves determined by probabilistic methods represent 19 percent of the proved reserves presented in this report on a gas equivalent basis.

Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Chesapeake’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Chesapeake ownsan interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.”

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Chesapeake Energy Corporation

January 15, 2015

Page 5

The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 95 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. The performance methods, such as decline curve analysis, utilized extrapolations of historical production and pressure data available through November 2014 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Chesapeake or obtained from public data sources and were considered sufficient for the purpose thereof. Methods other than performance were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

All proved developed non-producing and undeveloped reserves included herein were estimated by the volumetric method, analogy, or a combination of methods. The volumetric analysis utilized pertinent well data furnished to Ryder Scott by Chesapeake that were available through November 2014. The data utilized from theanalogues in conjunction with well data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Chesapeake has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Chesapeake with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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January 15, 2015

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verification of the data furnished by Chesapeake. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Chesapeake. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Chesapeakefurnished us with the above mentioned average prices in effect on December 31, 2014. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Chesapeake Energy Corporation

January 15, 2015

Page 7

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Chesapeake. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Chesapeake to determine these differentials

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices*	Average Realized Prices
United States	Oil/Condensate	WTI Cushing	$94.98/Bbl	$89.91/Bbl
	NGLs	WTI Cushing	$94.98/Bbl	$24.76/Bbl
	Gas	Henry Hub	$4.35/MMBTU	$2.45/MCF

* Benchmark prices were provided by Chesapeake.

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by Chesapeake and are based on the operating expense reports of Chesapeake and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs shown as “Other Costs.” The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by Chesapeake were reviewed by us for their reasonableness using information furnished by Chesapeakefor this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Chesapeake and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs.The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. All development costs shown after 2019 are related to either workover expenses or abandonment charges. The estimates of the net abandonment costs furnished by Chesapeake were accepted without independent verification.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Chesapeake’s plans to develop these reserves as of December 31, 2014. The implementation of Chesapeake’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Chesapeake’s management. As the result of our inquires during the course of preparing this report,Chesapeake has informed us that the development activities included herein have been subjected to and received the internal approvals required by Chesapeake’s

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Chesapeake Energy Corporation

January 15, 2015

Page 8

management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Chesapeake. Additionally,Chesapeake has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2014, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Chesapeake. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Chesapeake Energy Corporation

January 15, 2015

Page 9

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Chesapeake.

Chesapeake makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Chesapeake has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Chesapeake of the references to our name as well as to the references to our third party report for Chesapeake, which appears in the December 31, 2014 annual report on Form 10-K of Chesapeake. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Chesapeake.

We have provided Chesapeake with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Chesapeake and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ Don P. Griffin

Don P. Griffin, P.E.

TBPE License No. 64150

Senior Vice President

[SEAL]

DPG (DCR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Don P. Griffin was the primary technical person responsible for overseeing the estimate of the reserves, future production and income presented herein.

Mr. Griffin, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Griffin served in a number of engineering positions with Amoco Production Company. For more information regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Griffin fulfills. Mr. Griffin attended an additional 15 hours of training during 2014 covering such topics as reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Griffin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

XML

Commitments - Undiscounted Gathering Processing and Transportation Agreements Commitments Table (Details) (Gathering and Processing Equipment [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Gathering and Processing Equipment [Member]
Other Commitments [Line Items]
Gathering, Processing and Transportation Commitment, Due in Next Twelve Months	$ 1,855
Gathering, Processing and Transportation Commitment, Due in Second Year	1,987
Gathering, Processing and Transportation Commitment, Due in Third Year	2,003
Gathering, Processing and Transportation Commitment, Due in Fourth Year	1,802
Gathering, Processing and TransportationCommitment, Due in Fifth Year	1,516
Gathering, Processing and Transportation Commitment, Due after Fifth Year	6,880
Gathering, Processing and Transportation Commitment	$ 16,043

XML

Fair Value Measurements - Assets and Liabilities Table (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	$ (1)	$ (2)
Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	57	80
Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	(58)	(82)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	(1)	(2)
Fair Value, Inputs, Level 1 [Member] | Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	57	80
Fair Value, Inputs, Level 1 [Member] | Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	(58)	(82)
Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	0	0
Fair Value, Inputs, Level 2 [Member] | Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 2 [Member] | Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	0	0
Fair Value, Inputs, Level 3 [Member] | Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 3 [Member] | Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	$ 0	$ 0

XML

Basis of Presentation and Summary of Significant Accounting Policies - Receivables Table (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Accounts, Notes, Loans and Financing Receivable [Line Items]
Other Receivables	$ 226	$ 150
Oil and Gas Joint Interest Billing Receivables, Current	691	417
Accounts Receivable, Related Parties	0	62
Allowance for Doubtful Accounts Receivable	(21)	(18)
Accounts receivable, net	2,236	2,222
Oil And Gas Exploration And Production [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Other Receivables	1,340	1,548
Oilfield Services [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Other Receivables	$ 0	$ 63

XML

Income Taxes - Deferred Tax Assets and Liabilities Table (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Deferred Tax Liabilities, Other Finite-Lived Assets	$ (3,950)	$ (2,631)
Deferred Tax Liabilities, Property, Plant and Equipment	(14)	(371)
Deferred Tax Liabilities, Deferred Expense, Other Capitalized Costs	(920)	(1,216)
Deferred Tax Liabilities, Deferred Expense, Deferred Financing Costs	(443)	(439)
Deferred Tax Liabilities, Tax Deferred Income	(102)	0
Deferred Tax Liabilities, Derivatives	(428)	0
Deferred Tax Liabilities, Gross	(5,857)	(4,657)
Deferred Tax Assets, Operating Loss Carryforwards	945	535
Deferred Tax Assets, Derivative Instruments	0	108
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Asset Retirement Obligations	165	153
Deferred Tax Assets, Investments	88	130
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	50	66
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	214	120
Deferred Tax Assets, Investment in Subsidiaries	135	152
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	34	317
Deferred Tax Assets, Other	56	40
Deferred Tax Assets, Gross	1,687	1,621
Deferred Tax Assets, Valuation Allowance	(222)	(148)
Deferred Tax Assets, Net of Valuation Allowance	1,465	1,473
Deferred income tax asset	0	223
Deferred Tax Liabilities, Net, Current	(207)	0
Deferred Tax Liabilities, Net, Noncurrent	(4,185)	(3,407)
Deferred Tax Liabilities, Net	$ 4,392	$ 3,184

XML

Derivative and Hedging Activities - Fair Value of Recurring Assets and Liabilities Table (Details) (Fair Value, Measurements, Recurring [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	$ (17)	$ (98)
Foreign Currency Contracts, Liability, Fair Value Disclosure	(53)
Foreign Currency Contracts, Asset, Fair Value Disclosure		2
Derivative Assets (Liabilities), at Fair Value, Net	652	(649)
Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	990	40
Derivative Liability	(268)	(593)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	0	0
Foreign Currency Contracts, Liability, Fair Value Disclosure	0
Foreign Currency Contracts, Asset, Fair Value Disclosure		0
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Fair Value, Inputs, Level 1 [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	(17)	(98)
Foreign Currency Contracts, Liability, Fair Value Disclosure	(53)
Foreign Currency Contracts, Asset, Fair Value Disclosure		2
Derivative Assets (Liabilities), at Fair Value, Net	706	(171)
Fair Value, Inputs, Level 2 [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	785	25
Derivative Liability	(9)	(100)
Fair Value, Inputs, Level 3 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	0	0
Foreign Currency Contracts, Liability, Fair Value Disclosure	0
Foreign Currency Contracts, Asset, Fair Value Disclosure		0
Derivative Assets (Liabilities), at Fair Value, Net	(54)	(478)
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	205	15
Derivative Liability	$ (259)	$ (493)

XML

Natural Gas and Oil Property Transactions (Tables)

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

VPP Transactions [Table Text Block]

As of December 31, 2014, our outstanding VPPs consisted of the following:

					Volume Sold
VPP #	Date of VPP	Location	Proceeds		Oil	Natural Gas	NGL	Total
			($ in millions)		(mmbbl)	(bcf)	(mmbbl)	(bcfe)
10	March 2012	Anadarko Basin Granite Wash	$	744	3.0	87	9.2	160
9	May 2011	Mid-Continent	853		1.7	138	4.8	177
8	September 2010	Barnett Shale	1,150		—	390	—	390
4	December 2008	Anadarko and Arkoma Basins	412		0.5	95	—	98
3	August 2008	Anadarko Basin	600		—	93	—	93
2	May 2008	Texas, Oklahoma and Kansas	622		—	94	—	94
1	December 2007	Kentucky and West Virginia	1,100		—	208	—	208
			$	5,481	5.2	1,105	14.0	1,220

VPP Volumes Produced During Period [Table Text Block]

The volumes produced on behalf of our VPP buyers during 2014, 2013 and 2012 were as follows:

	Year Ended December 31, 2014
VPP #	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)
10	403.0	10.6	1,296.5	20.7
9	187.5	15.4	411.0	19.0
8	—	60.1	—	60.1
6(a)	23.1	4.2	—	4.3
5(a)	16.5	4.6	—	4.7
4	48.1	9.0	—	9.2
3	—	7.2	—	7.2
2	—	6.2	—	6.2
1	—	13.8	—	13.8
	678.2	131.1	1,707.5	145.2
	Year Ended December 31, 2013
VPP #	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)
10	547.0	13.5	1,509.0	25.8
9	213.2	17.0	455.7	21.0
8	—	68.1	—	68.1
6	24.0	4.8	—	4.9
5	25.4	7.5	—	7.7
4	54.7	10.2	—	10.5
3	—	8.1	—	8.1
2	—	10.3	—	10.3
1	—	14.5	—	14.5
	864.3	154.0	1,964.7	170.9
	Year Ended December 31, 2012
VPP #	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)
10	727.0	18.1	1,729.1	32.8
9	249.3	18.4	643.6	23.7
8	—	79.7	—	79.7
7(b)	490.3	0.4	—	3.4
6	24.0	5.3	—	5.5
5	27.4	8.8	—	9.0
4	62.8	11.7	—	12.2
3	—	9.3	—	9.3
2	—	11.4	—	11.3
1	—	15.3	—	15.3
	1,580.8	178.4	2,372.7	202.2

____________________________________________

(a) In 2014, we divested the properties associated with VPP #5 and VPP #6.

(b) In 2012, to facilitate the sales process associated with our Permian Basin divestiture packages, we purchased the remaining reserves from our Permian Basin VPP (VPP #7). The reserves purchased were subsequently sold to the buyers of our Permian Basin assets.

The v

VPP Volumes Remaining to be Delivered [Table Text Block]

The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2014 were as follows:

		Volume Remaining as of December 31, 2014
VPP #	Term Remaining	Oil	Natural Gas	NGL	Total
	(in months)	(mmbbl)	(bcf)	(mmbbl)	(bcfe)
10	86	1.3	38.0	4.7	74.0
9	74	0.8	73.2	1.9	89.9
8	8	—	36.6	—	36.6
4	24	0.1	15.3	—	15.8
3	55	—	23.9	—	23.9
2	52	—	13.8	—	13.8
1	96	—	91.5	—	91.5
		2.2	292.3	6.6	345.5

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Basis of Presentation and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

Basis of Presentation

The accompanying consolidated financial statements of Chesapeake were prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated.

Use of Estimates, Policy [Policy Text Block]

Accounting Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in actual results differing significantly from our estimates.

Consolidation, Policy [Policy Text Block]

Consolidation

Chesapeake consolidates entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake has the ability to exercise significant influence through its investment. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Investments in securities not accounted for under the equity method have been designated as available-for-sale and, as such, are carried at fair value whenever this value is readily determinable. Otherwise, the investment is carried at cost. See Note 14 for further discussion of our investments. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis.

Noncontrolling Interests

Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests.

Consolidation, Variable Interest Entity, Policy [Policy Text Block]

Variable Interest Entities

VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

Along with a VIE that we consolidate, we also hold a variable interest in another VIE that is not consolidated because we are not the primary beneficiary. We continually monitor both our consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs.

We consolidate the activities of VIEs for which we are the primary beneficiary. In order to determine whether we own a variable interest in a VIE, we perform qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.

Cash and Cash Equivalents, Policy [Policy Text Block]

Accounts Payable

Included in accounts payable as of December 31, 2014 and 2013 are liabilities of approximately $333 million and $397 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts.

Cash and Cash Equivalents and Restricted Cash

For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. Restricted cash consists of the balance required to be maintained by the terms of the agreement governing the activities of CHK Cleveland Tonkawa, L.L.C. (CHK C-T) and, prior to our repurchase of all of the outstanding preferred shares of CHK Utica, L.L.C. (CHK Utica) in 2014, also consisted of a balance required to be maintained by the terms of the agreement governing the activities of CHK Utica. The repurchase of outstanding preferred shares of CHK Utica eliminated the restricted cash maintenance requirement related to this entity. See Note 8 for further discussion of these entities.

Receivables, Policy [Policy Text Block]

Accounts Receivable

Our accounts receivable are primarily from purchasers of oil, natural gas and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables we believe may be uncollectible. During 2014, 2013 and 2012, we recognized $2 million, $2 million and a nominal amount of bad debt expense related to potentially uncollectible receivables, and we reduced our allowance by $3 million in 2013 as we wrote off specific receivables against our allowance. Accounts receivable as of December 31, 2014 and 2013 are detailed below.

	December 31,
	2014			2013
	($ in millions)
Oil, natural gas and NGL sales	$	1,340		$	1,548
Joint interest	691			417
Oilfield services(a)	—			63
Related parties(b)	—			62
Other	226			150
Allowance for doubtful accounts	(21		)	(18		)
Total accounts receivable, net	$	2,236		$	2,222

___________________________________________

(a) In 2014, in connection with the spin-off of our oilfield services business, accounts receivable related to oilfield services were removed from our consolidated balance sheet.

(b) See Note 7 for discussion of related party transactions.

Oil and Gas Properties Policy [Policy Text Block]

Oil and Natural Gas Properties

Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with these activities and do not capitalize any costs related to production, general corporate overhead or similar activities (see Supplementary Information - Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. Estimates of our proved reserves as of December 31, 2014 were prepared by independent engineering firms and Chesapeake's internal staff. Approximately 79% of these proved reserves estimates (by volume) as of December 31, 2014 were prepared by independent engineering firms. In addition, our internal engineers review and update our reserves on a quarterly basis.

Proceeds from the sale of oil and natural gas properties are accounted for as reductions of capitalized costs unless these sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized.

The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unproved properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unproved properties are grouped by major prospect area where individual property costs are not significant. In addition, we analyze our unproved leasehold and transfer to proved properties leasehold that can be associated with proved reserves, leasehold that expired in the quarter or leasehold that is not a part of our development strategy and will be abandoned.

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2014 and the year in which the associated costs were incurred.

	Year of Acquisition
	2014		2013		2012		Prior		Total
	($ in millions)
Leasehold acquisition cost	$	577	$	199	$	1,462	$	5,149	$	7,387
Exploration cost	340		90		244		42		716
Capitalized interest	492		421		325		447		1,685
Total	$	1,409	$	710	$	2,031	$	5,638	$	9,788

We also review, on a quarterly basis, the carrying value of our oil and natural gas properties under the full cost accounting rules of the Securities and Exchange Commission (SEC). This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for oil and natural gas derivatives designated as cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The ceiling test calculation uses costs as of the end of the applicable quarterly period and the unweighted arithmetic average of oil, natural gas and NGL prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. As of December 31, 2014, none of our open derivative instruments were designated as cash flow hedges. Our oil and natural gas hedging activities are discussed in Note 11.

Two primary factors impacting the ceiling test are reserves levels and oil, natural gas and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an extended increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value over the ceiling is written off as an expense.

We account for seismic costs as part of our oil and natural gas properties. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. These costs are capitalized as incurred. The Company reviews its unproved properties and associated seismic costs quarterly to determine whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unproved properties, they are included in the amortization base as incurred.

Property, Plant and Equipment, Policy [Policy Text Block]

Other Property and Equipment

Other property and equipment consists primarily of natural gas compressors, buildings and improvements, land, vehicles, computer and office equipment, oil and natural gas gathering systems and treating plants. We have no remaining oilfield services equipment as a result of the spin-off of our oilfield services business in 2014 as discussed in Note 13, and substantially all of our natural gas gathering systems and treating plants were sold in 2013 and 2012 as discussed in Note 16. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating costs. See Note 16 for further discussion of our gains and losses on the sales of other property and equipment and a summary of our other property and equipment held for sale as of December 31, 2014 and 2013. Other property and equipment costs, excluding land, are depreciated on a straight-line basis.

Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. During 2014, 2013 and 2012, we determined that certain of our property and equipment was being carried at values that were not recoverable and in excess of fair value. See Note 17 for further discussion of these impairments.

Interest Capitalization, Policy [Policy Text Block]

Capitalized Interest

Interest from external borrowings is capitalized on significant projects until the asset is ready for service using the weighted average cost of outstanding borrowings. Capitalized interest is determined by multiplying our weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.

Goodwill and Intangible Assets, Policy [Policy Text Block]

Goodwill

Goodwill represents the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment at least annually. This test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. When the qualitative assessment indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, the quantitative assessment is then performed. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense.

Our goodwill, which is included in other long-term assets on our consolidated balance sheets, was $15 million and $43 million, respectively, as of December 31, 2014 and 2013. The 2014 amount consists of $15 million of excess consideration over the fair value of assets acquired in our Horizon Drilling Services acquisition in 2011. The 2013 amount also included $28 million of excess consideration over the fair value of assets acquired in our Bronco Drilling Company acquisition in 2011. We no longer have the goodwill balance related to Bronco Drilling Company as a result of the spin-off of our oilfield services business in June 2014. We performed annual impairment tests of goodwill in the fourth quarters of 2014 and 2013. Based on these assessments, no impairment of goodwill was required. Goodwill was included in our exploration and production segment as of December 31, 2014 and as of December 31, 2013 was included in our former oilfield services segment.

Cash and Cash Equivalents, Accounts Payable, Policy [Policy Text Block]

Accounts Payable

Included in accounts payable as of December 31, 2014 and 2013 are liabilities of approximately $333 million and $397 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts.

Cash and Cash Equivalents and Restricted Cash

For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. Restricted cash consists of the balance required to be maintained by the terms of the agreement governing the activities of CHK Cleveland Tonkawa, L.L.C. (CHK C-T) and, prior to our repurchase of all of the outstanding preferred shares of CHK Utica, L.L.C. (CHK Utica) in 2014, also consisted of a balance required to be maintained by the terms of the agreement governing the activities of CHK Utica. The repurchase of outstanding preferred shares of CHK Utica eliminated the restricted cash maintenance requirement related to this entity. See Note 8 for further discussion of these entities.

Debt, Policy [Policy Text Block]

Debt Issuance and Hedging Facility Costs

Included in other long-term assets are costs associated with the issuance of our senior notes, revolving credit facility, hedging facility and, as of December 31, 2013, costs associated with our former term loan and former oilfield services credit facility. The remaining unamortized issuance costs as of December 31, 2014 and 2013 totaled $130 million and $145 million, respectively, and are being amortized over the life of the applicable debt or facility using the effective interest method.

Environmental Costs, Policy [Policy Text Block]

Environmental Remediation Costs

Chesapeake records environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

Asset Retirement Obligations, Policy [Policy Text Block]

Asset Retirement Obligations

We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. See Note 20 for further discussion of asset retirement obligations.

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

Oil, Natural Gas and NGL Sales. Revenue from the sale of oil, natural gas and NGL is recognized when title passes, net of royalties due to third parties and gathering and transportation charges.

Natural Gas Imbalances. We follow the "sales method" of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of the remaining natural gas reserves on the underlying properties. The natural gas imbalance net liability position as of December 31, 2014 and 2013 was $12 million and $11 million, respectively.

Marketing, Gathering and Compression Sales. Chesapeake takes title to the oil, natural gas and NGL it purchases from other interest owners in operated wells at defined delivery points and delivers the product to third parties, at which time revenues are recorded. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments. In circumstances where we act as a principal rather than an agent, Chesapeake's results of operations related to its oil, natural gas and NGL marketing activities are presented on a "gross" basis. Gathering and compression revenues consist of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated.

Oilfield Services Revenue. Prior to the spin-off of our oilfield services business in June 2014, we reported oilfield services revenue. Our former oilfield services operating segment was responsible for contract drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Our oilfield services revenues prior to the spin-off were as follows:

• Drilling. Revenues were generated by drilling oil and natural gas wells for our customers under daywork contracts and recognized for the days completed based on the dayrate specified in each contract. Revenue generated and costs incurred for mobilization services were recognized over the days of actual mobilization.

• Hydraulic Fracturing. Revenue was recognized upon the completion of each fracturing stage. Typically, one or more fracturing stages per day per active crew was completed during the course of a job. A stage was considered complete when the customer requested or the job design dictated that pumping discontinue for that stage. Invoices typically included a lump sum equipment charge determined by the rate per stage specified in each contract and product charges for sand, chemicals and other products actually consumed during the course of providing fracturing services.

• Oilfield Rentals. Oilfield equipment rentals included drill pipe, drill collars, tubing, blowout preventers, and frac and mud tanks, and services included air drilling services and services associated with the transfer of fresh water to the wellsite. Rentals and services were priced by the day or hour based on the type of equipment rented and the service job performed. Revenue was recognized ratably over the term of the rental.

• Oilfield Trucking. Oilfield trucking provided rig relocation and logistics services as well as fluid handling services. Trucks moved drilling rigs, crude oil, other fluids and construction materials to and from the wellsites and also transported produced water from the wellsites. These services were priced on a per barrel basis based on mileage and revenue was recognized as services were performed.

• Other Operations. A manufacturing subsidiary designed, engineered and fabricated natural gas compressor packages that were purchased primarily by Chesapeake. Compression units were priced based on certain specifications such as horsepower, stages and additional options. Revenue was recognized upon completion and transfer of ownership of the natural gas compression unit.

Fair Value Measurement, Policy [Policy Text Block]

Fair Value Measurements

Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

The carrying values of financial instruments comprising cash and cash equivalents, restricted cash, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments.

Derivatives, Policy [Policy Text Block]

Derivatives

Derivative instruments are recorded on our consolidated balance sheets as derivative assets or derivative liabilities at fair value, and changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. For qualifying commodity derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Locked-in gains and losses of settled cash flow hedges are recorded in accumulated other comprehensive income and are transferred to earnings in the month of production. Changes in the fair value of interest rate derivative instruments designated as fair value hedges are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent hedge ineffectiveness and are recognized currently in earnings. Locked-in gains and losses related to settled fair value hedges are amortized as an adjustment to interest expense over the remaining term of the related senior notes. We have elected not to designate any of our qualifying commodity and interest rate derivatives as cash flow or fair value hedges. Therefore, changes in fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in our consolidated statements of operations within oil, natural gas and NGL sales and interest expense, respectively.

Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our derivative instruments are subject to master netting arrangements by contract type (i.e., commodity, interest rate and cross currency contracts) which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets.

We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. See Note 11 for further discussion of our derivative instruments.

Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]

Share-Based Compensation

Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize in our financial statements the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three or four years from the grant date. For directors, although restricted stock grants vest over three years, this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units can only be settled in cash, they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as compensation expense in the consolidated statements of operations.

To the extent compensation cost relates to employees directly involved in the acquisition of oil and natural gas leasehold and exploration and development activities, these amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses, oil, natural gas and NGL production expenses, or marketing, gathering and compression expenses, based on the employees involved in those activities.

Cash inflows resulting from tax deductions in excess of compensation expense recognized for stock options and restricted stock are classified as financing cash inflows, while reductions in tax benefits are classified as operating cash outflows in our consolidated statements of cash flows. See Note 9 for further discussion of share-based compensation.

Reclassification, Policy [Policy Text Block]

Reclassifications

Certain reclassifications have been made to the consolidated financial statements for 2012 and 2013 to conform to the presentation used for the 2014 consolidated financial statements.

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Income Taxes - Unrecognized Tax Benefits Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Period Start	$ 644	$ 599	$ 369
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	13	15	134
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	0	30	96
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions	(354)	0	0
Unrecognized Tax Benefits, Period End	$ 303	$ 644	$ 599

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Other Property and Equipment - Assets Held For Sale Table (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Long Lived Assets Held-for-sale [Line Items]
Assets Held for Sale	$ 93	$ 730
Land and Building [Member]
Long Lived Assets Held-for-sale [Line Items]
Assets Held for Sale	93	405
Compressor [Member]
Long Lived Assets Held-for-sale [Line Items]
Assets Held for Sale	0	285
Exploration and Production Equipment [Member]
Long Lived Assets Held-for-sale [Line Items]
Assets Held for Sale	0	29
Gathering and Processing Equipment [Member]
Long Lived Assets Held-for-sale [Line Items]
Assets Held for Sale	$ 0	$ 11

XML

Major Customers and Segment Information - Narrative (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014 Segment	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Segment Reporting, Disclosure of Major Customers		no
Concentration Risk, Percentage		10.00%
Number of reportable segments	2
Total Revenues	$ 20,951	$ 17,506	$ 12,316
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0
Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	12,225	9,559	5,431
Marketing, Gathering And Compression [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	8,565	7,570	5,464
Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	516	879	602
Oilfield Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	$ 544	$ 1,309	$ 1,315
ExxonMobil [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	12.00%		11.00%

XML

Commitments - Narrative (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 20, 2011
Long-term Purchase Commitment [Line Items]
Operating Leases, Rent Expense	$ 33	$ 158	$ 185
Gathering Fee Escalation Rate	15.00%
Investments	265	477
Sundrop Fuels Inc [Member]
Long-term Purchase Commitment [Line Items]
Marketable Securities, Equity Securities	25
Investments	155			155
Net Acreage Maintenance Commitment [Member]
Long-term Purchase Commitment [Line Items]
Cash Payment for Shortfall	$ 50
Net Acreage Shortfall [Member]
Long-term Purchase Commitment [Line Items]
Number Of Net Acres	20,800
Drilling Rig Leases [Member] | Minimum [Member]
Long-term Purchase Commitment [Line Items]
Lease Term	3 months
Drilling Rig Leases [Member] | Maximum [Member]
Long-term Purchase Commitment [Line Items]
Lease Term	3 years
Drilling Rig Leases [Member] | Seven Seven Energy Inc. [Member] | Minimum [Member]
Long-term Purchase Commitment [Line Items]
Lease Term	3 months
Drilling Rig Leases [Member] | Seven Seven Energy Inc. [Member] | Maximum [Member]
Long-term Purchase Commitment [Line Items]
Lease Term	3 years
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Percent of Total	50.00%
Pressure Pumping Leases [Member] | Pressure Pumping Crew Year One of Agreement [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews	7
Year of Service Agreement	1 year
Pressure Pumping Leases [Member] | Pressure Pumping Crew Year Two of Agreement [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews	5
Year of Service Agreement	2 years
Pressure Pumping Leases [Member] | Pressure Pumping Crew Year Three of Agreement [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews	3
Year of Service Agreement	3 years

XML

Equity - Noncontrolling Interests Distribution Table (Details) (Noncontrolling Interest, Chesapeake Granite Wash Trust [Member], USD $)	3 Months Ended
	Aug. 31, 2014	May 31, 2014	Feb. 28, 2014	Nov. 30, 2013	Aug. 31, 2013	May 31, 2013	Feb. 28, 2013	Nov. 30, 2012	Aug. 31, 2012	May 31, 2012	Feb. 29, 2012	Nov. 30, 2011
Noncontrolling Interest [Line Items]
Distribution Made to Limited Partner, Distribution Date	Dec. 01, 2014	Aug. 29, 2014	May 30, 2014	Mar. 03, 2014	Nov. 29, 2013	Aug. 29, 2013	May 31, 2013	Mar. 01, 2013	Nov. 29, 2012	Aug. 30, 2012	May 31, 2012	Mar. 01, 2012
Common Unit [Member]
Noncontrolling Interest [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared, Per Unit	0.5079	0.5796	0.6454	0.6624	0.6671	0.6900	0.6900	0.6700	0.6300	0.6100	0.6588	0.7277
Subordinated Units [Member]
Noncontrolling Interest [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared, Per Unit	0.0000	0.0000	0.0000	0.0000	0.0000	0.1432	0.3010	0.3772	0.2208	0.4819	0.6588	0.7277

XML

Basis of Presentation and Summary of Significant Accounting Policies - Narrative (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Summary of Significant Accounting Policies Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	50.00%
Provision for Doubtful Accounts	$ 2	$ 2	$ 0
Premiums Receivable, Allowance for Doubtful Accounts, Write Offs Against Allowance		3
Percentage of Reserve Estimates (by Volume) Prepared by Independent Engineering Firm	79.00%
Goodwill	15	43
Bank Overdrafts	333	397
Unamortized Debt Issuance Expense	130	145
Gas Balancing Asset (Liability)	12	11
Director [Member]
Summary of Significant Accounting Policies Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Minimum [Member] | Employee [Member]
Summary of Significant Accounting Policies Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Maximum [Member] | Employee [Member]
Summary of Significant Accounting Policies Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	4 years
Horizon Drilling Services [Member]
Summary of Significant Accounting Policies Line Items]
Goodwill	15
Bronco Drilling Company Incorporated [Member]
Summary of Significant Accounting Policies Line Items]
Goodwill		$ 28

XML

Natural Gas and Oil Property Transactions - VPP Volumes Produced During Period Table (Details)	12 Months Ended
	Dec. 31, 2014 Mcfe	Dec. 31, 2013 Mcfe	Dec. 31, 2012 Mcfe
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	145,200,000,000	170,900,000,000	202,200,000,000
Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	678,200	864,300	1,580,800
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	131,100,000,000	154,000,000,000	178,400,000,000
NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	1,707,500	1,964,700	2,372,700
VPP 10 Anadarko Basin Granite Wash [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	20,700,000,000	25,800,000,000	32,800,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	403,000	547,000	727,000
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	10,600,000,000	13,500,000,000	18,100,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	1,296,500	1,509,000	1,729,100
VPP 9 Mid-Continent [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	19,000,000,000	21,000,000,000	23,700,000,000
VPP 9 Mid-Continent [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	187,500	213,200	249,300
VPP 9 Mid-Continent [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	15,400,000,000	17,000,000,000	18,400,000,000
VPP 9 Mid-Continent [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	411,000	455,700	643,600
VPP 8 Barnett Shale [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	60,100,000,000	68,100,000,000	79,700,000,000
VPP 8 Barnett Shale [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 8 Barnett Shale [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	60,100,000,000	68,100,000,000	79,700,000,000
VPP 8 Barnett Shale [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 7 Permian Basin [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)			3,400,000,000
VPP 7 Permian Basin [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production			490,300
VPP 7 Permian Basin [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production			400,000,000
VPP 7 Permian Basin [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production			0
VPP 6 East Texas and Texas Gulf Coast [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	4,300,000,000	4,900,000,000	5,500,000,000
VPP 6 East Texas and Texas Gulf Coast [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	23,100	24,000	24,000
VPP 6 East Texas and Texas Gulf Coast [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	4,200,000,000	4,800,000,000	5,300,000,000
VPP 6 East Texas and Texas Gulf Coast [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 5 South Texas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	4,700,000,000	7,700,000,000	9,000,000,000
VPP 5 South Texas [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	16,500	25,400	27,400
VPP 5 South Texas [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	4,600,000,000	7,500,000,000	8,800,000,000
VPP 5 South Texas [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 4 Anadarko and Arkoma Basins [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	9,200,000,000	10,500,000,000	12,200,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	48,100	54,700	62,800
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	9,000,000,000	10,200,000,000	11,700,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 3 Anadarko Basin [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	7,200,000,000	8,100,000,000	9,300,000,000
VPP 3 Anadarko Basin [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	7,200,000,000	8,100,000,000	9,300,000,000
VPP 3 Anadarko Basin [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 2 Texas, Oklahoma and Kansas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	6,200,000,000	10,300,000,000	11,300,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	6,200,000,000	10,300,000,000	11,400,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 1 Kentucky and West Virginia [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	13,800,000,000	14,500,000,000	15,300,000,000
VPP 1 Kentucky and West Virginia [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	13,800,000,000	14,500,000,000	15,300,000,000
VPP 1 Kentucky and West Virginia [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0

XML

Income Taxes - Income Tax Expense Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Current Federal Tax Expense (Benefit)	$ 0	$ 0	$ 0
Current State and Local Tax Expense (Benefit)	47	22	47
Current income taxes	47	22	47
Deferred Federal Income Tax Expense (Benefit)	1,115	502	(358)
Deferred State and Local Income Tax Expense (Benefit)	(18)	24	(69)
Deferred income taxes	1,097	526	(427)
INCOME TAX EXPENSE (BENEFIT)	$ 1,144	$ 548	$ (380)

XML

Equity - AOCI Reclassifications Table (Details) (Accumulated Other Comprehensive Income (Loss) [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$ 18	$ 24
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	23	20
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(5)	4
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Impairment of Investment [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		6
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Sale of Investment [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$ (5)	$ (2)

XML

Related Party Transactions - Equity Method Investees Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	$ 0	$ 47	$ 67
Related Party Transaction, Due from (to) Related Party	0	1	42
FTS International, Inc. [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	0	0	73
Payment For Transaction with Related Party	220	397	480
Twin Eagle Resource Management Llc [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	$ 0	$ 666	$ 392
Equity Method Investment, Ownership Percentage		30.00%

XML

Equity - Narrative (Details)	12 Months Ended
	Dec. 31, 2014
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.00%
4.50% Cumulative Convertible Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage	4.50%
5.75% Cumulative Convertible Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.75%

XML

Income Taxes - Effective Income Tax Rate Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount	$ 1,120	$ 505	$ (341)
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	68	88	(38)
Effective Income Tax Rate Reconciliation, Deferred Remeasurement	(114)	(38)	(19)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	74	(12)	0
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount	(4)	5	18
INCOME TAX EXPENSE (BENEFIT)	$ 1,144	$ 548	$ (380)

XML

Commitments - Undiscounted Drilling Contracts Commitments Table (Details) (Drilling Rig Leases [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Drilling Rig Leases [Member]
Drilling Contracts [Line Items]
Drilling Contracts Obligation, Due in Next Twelve Months	$ 232
Drilling Contracts Obligation, Due in Second Year	179
Drilling Contracts Obligation, Due in Third Year	91
Drilling Contracts Obligation	$ 502

XML

Other Property and Equipment (Note)

12 Months Ended

Dec. 31, 2014

Gain (Loss) on Disposition of Property Plant Equipment [Abstract]

Other Property and Equipment Disclosure [Text Block]

Other Property and Equipment

Other Property and Equipment

A summary of other property and equipment held for use and the estimated useful lives thereof is as follows:

	December 31,						Estimated Useful Life
	2014			2013
	($ in millions)						(in years)
Buildings and improvements	$	1,242		$	1,433		10 - 39
Natural gas compressors	551			368			3 - 20
Land	296			212			—
Gathering systems and treating plants	218			292			20
Oilfield services equipment	—			2,192			3 - 15
Other	776			898			2 - 20
Total other property and equipment, at cost	3,083			5,395
Less: accumulated depreciation	(804		)	(1,584		)
Total other property and equipment, net	$	2,279		$	3,811

Net Gains on Sales of Fixed Assets

A summary by asset class of (gains) or losses on sales of fixed assets for the years ended December 31, 2014, 2013 and 2012 is as follows:

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Natural gas compressors	$	(195	)	$	—		$	—
Gathering systems and treating plants	8			(326		)	(286		)
Oilfield services equipment	(7		)	2			10
Buildings and land	(2		)	27			7
Other	(3		)	(5		)	2
Total net gains on sales of fixed assets	$	(199	)	$	(302	)	$	(267	)

Natural Gas Compressors. In 2014, as part of a divestiture of noncore oil and natural gas properties in South Texas, we sold 61 compressors and related equipment to Hilcorp Energy Company for $19 million. We recorded a $6 million gain associated with the compressors sold. Also in 2014, we sold 499 compressors and related equipment to Exterran Partners, L.P. for approximately $495 million. We recorded a $161 million gain associated with the compressors sold. In 2014, we also sold 102 compressors and related equipment to Access Midstream Partners, L.P. (ACMP) for proceeds of approximately $159 million. We recorded a $24 million gain associated with the transaction.

Gathering Systems and Treating Plants. In 2013, we sold our wholly owned midstream subsidiary Mid-America Midstream Gas Services, L.L.C. to SemGas, L.P., a wholly owned subsidiary of SemGroup Corporation, for net proceeds of approximately $306 million. We recorded a $141 million gain associated with the transaction. In 2013, we also sold our wholly owned subsidiary Granite Wash Midstream Gas Services, L.L.C. to MarkWest Oklahoma Gas Company, L.L.C. (MW), a wholly owned subsidiary of MarkWest Energy Partners, L.P., for net proceeds of approximately $252 million. We recorded a $105 million gain associated with this transaction. The transaction with MW included long-term fixed fee arrangements for gas gathering, compression, treating and processing services in the Anadarko Basin. In 2013, we also sold our interest in certain gathering system assets in Pennsylvania to Western Gas Partners, LP for proceeds of approximately $134 million. We recorded a $55 million gain associated with this transaction.

In 2012, CMD sold its wholly owned subsidiary, CMO, which held a majority of our midstream business, to ACMP for total consideration of $2.16 billion in cash.In connection with the sale, Chesapeake entered into new long-term agreements in which ACMP agreed to perform certain natural gas gathering and related services for us within specified acreage dedication areas in exchange for (i) cost-of-service based fees redetermined annually beginning January 2014 in the Niobrara and Marcellus Shale plays, (ii) cost-of-service based fees redetermined annually beginning October 2013 for the wet gas gathering systems and January 2014 for the dry gas gathering systems in the Utica Shale play, (iii) tiered fees based on volumes delivered relative to scheduled volumes through 2015 and thereafter cost-of-service based fees redetermined annually in the Eagle Ford Shale play, and (iv) annual minimum volume commitments and a fixed fee per mmbtu of natural gas gathered, subject to an annual 2.5% rate escalation, through 2017 and thereafter tiered fees based on volumes delivered relative to scheduled volumes in the Haynesville Shale play. We recorded a $289 million gain associated with this transaction.

In 2012, we sold our oil gathering business and related assets in the Eagle Ford Shale to Plains Pipeline, L.P. for cash proceeds of approximately $115 million. Subsequent to December 31, 2012, we received an additional $10 million of proceeds upon satisfaction of a certain closing contingency. We recorded a $3 million gain associated with this transaction. In connection with the sale, we entered into new gathering and transportation agreements covering acreage dedication areas.

Oilfield Services Equipment. In 2014, we sold substantially all of our crude oil hauling assets for approximately $44 million. We recorded a $23 million gain associated with the transaction. Also, in 2014, we sold 14 rigs for approximately $14 million and recorded a $14 million loss.

Buildings and Land. The net gains in 2014 and the net losses in 2013 on sales of buildings and land were mainly from the sale of certain buildings and land located primarily in our Oklahoma City and Barnett Shale operating area.

Assets Held for Sale

In 2013, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. In addition, as of December 31, 2014, we were continuing to pursue the sale of land located in the Fort Worth, Texas area. Land and buildings are recorded within our other segment. These Oklahoma City and Fort Worth assets are being actively marketed, and we believe it is probable they will be sold over the next 12 months. As a result, these assets are reflected as held for sale as of December 31, 2014. Oil and natural gas properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and gas properties. A summary of the assets held for sale on our consolidated balance sheets as of December 31, 2014 and 2013 is detailed below.

	December 31,
	2014		2013
	($ in millions)
Buildings and land, net of accumulated depreciation	$	93	$	405
Compressors, net of accumulated depreciation	—		285
Oilfield services equipment, net of accumulated depreciation	—		29
Gathering systems and treating plants, net of accumulated depreciation	—		11
Property and equipment held for sale, net	$	93	$	730

In 2014, management determined that certain properties in the Fort Worth area of the Barnett Shale, previously classified as held for sale as of December 31, 2013, would be reclassified as held for use. As of December 31, 2013, management’s development plan for the Barnett Shale did not contemplate the need for the underlying properties (for pad drilling in certain urban locations around Fort Worth) and the properties were marketed for sale. Management modified its development plan and consequently these properties no longer met the criteria to be classified as held for sale. The properties were measured at the lesser of their fair value at the date of the decision not to sell or their carrying amount before being classified as held for sale. During 2014, we reclassified $120 million of these properties to held for use classification. There was no impact to the statement of operations related to this reclassification.

During 2014, we sold compressors previously classified as held for sale to Hilcorp Energy Company and Exterran Partners, L.P. The oilfield services equipment was included in the spin-off of our oilfield services business. See Note 13 for further discussion of the spin-off.

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Restructuring and other Termination Benefits (Tables)

12 Months Ended

Dec. 31, 2014

Restructuring and Related Activities [Abstract]

Restructuring and Related Costs [Table Text Block]

Below is a summary of our restructuring and other termination costs for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014			2013		2012
	($ in millions)
Oilfield services spin-off costs:
Transaction costs	$	17		$	—	$	—
Stock-based compensation adjustments for Chesapeake employees	5			—		—
Stock-based compensation forfeitures for SSE employees	(10		)	—		—
Debt extinguishment costs	3			—		—
Total oilfield services spin-off costs	15			—		—
Restructuring charges under workforce reduction plan:
Salary expense	—			20		—
Acceleration of stock-based compensation	—			45		—
Other termination benefits	—			1		—
Total restructuring changes under workforce reduction plan	—			66		—
Termination benefits provided to Mr. McClendon:
Salary and bonus expense	—			11		—
Acceleration of 2008 performance bonus clawback	—			11		—
Acceleration of stock-based compensation	—			22		—
Acceleration of performance share unit awards(a)	(8		)	18		—
Estimated aircraft usage benefits	—			7		—
Total termination benefits provided to Mr. McClendon	(8		)	69		—
Termination benefits provided to VSP participants:
Salary and bonus expense	—			33		1
Acceleration of stock-based compensation	—			29		1
Other termination benefits	—			1		—
Total termination benefits provided to VSP participants	—			63		2
Other termination benefits(a)	—			50		5
Total restructuring and other termination costs	$	7		$	248	$	7

____________________________________________

(a) Amounts for the year ended December 31, 2014 are primarily related to negative fair value adjustments to PSUs granted to former executives of the Company. For further discussion of our PSUs, see Note 9.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2014

Related Party Transactions [Abstract]

Schedule of Related Party Transactions [Table Text Block]

During 2014, 2013 and 2012, we had the following transactions with our equity method investees:

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
Purchases(a)	$	—	$	—	$	73
Sales(b)	$	—	$	666	$	392
Services(c)	$	220	$	397	$	480

___________________________________________

(a) Purchase of equipment from FTS International, Inc. (FTS).

(b) In 2013 and 2012, Chesapeake sold produced gas to our 30%-owned investee, Twin Eagle Resource Management LLC (Twin Eagle). We sold our investment in Twin Eagle in 2014.

(c) Hydraulic fracturing and other services provided to us by FTS in the ordinary course of business. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs.

The table below shows the total amounts due from and due to our equity method investees.

	December 31,
	2014		2013		2012
	($ in millions)
Amounts due from equity method investees	$	—	$	47	$	67
Amounts due to equity method investees	$	—	$	1	$	42

XML

Other Liabilities - Long-Term Table (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Long-Term Liabilities [Line Items]
Financing obligations	$ 30	$ 31
Unrecognized Tax Benefits	303	644	599	369
Other	249	237
Other Liabilities, Current	3,061	3,511
Total other long-term liabilities	679	984
Other Noncurrent Liabilities [Member]
Other Long-Term Liabilities [Line Items]
Unrecognized Tax Benefits	45	317
Noncontrolling Interest, Chesapeake Utica L L C [Member]
Other Long-Term Liabilities [Line Items]
Conveyance Obligation Noncurrent	220	250
Other Liabilities, Current	14	13
Total other long-term liabilities	234	263
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]
Other Long-Term Liabilities [Line Items]
Conveyance Obligation Noncurrent	135	149
Other Liabilities, Current	23	12
Total other long-term liabilities	$ 158	$ 161

XML

Share-Based Compensation - Narrative (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Shares Authorized	1,000,000,000	1,000,000,000
Common Stock, Shares, Issued	664,944,232	666,192,371	666,468,000	660,888,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures	994,000	5,264,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value	130
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	135
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	2 years 8 days
Restricted Stock [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	2 years 8 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used	Black-Scholes option pricing model
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options	11
TSR [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used	Monte Carlo simulation
Employee [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Employee [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	4 years
Management [Member] | Retention Based Stock Option Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	33.00%
Management [Member] | Incentive Based Stock Option Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Management [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	10 years
Stock Option Award Three Year Anniversary [Member] | Management [Member] | Retention Based Stock Option Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Stock Optioin Award Four Year Anniversary [Member] | Management [Member] | Retention Based Stock Option Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	4 years
Stock option Award Five Year Anniversary [Member] | Management [Member] | Retention Based Stock Option Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	5 years
Paid-In Capital [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase (decrease) in tax benefit from stock-based compensation	15	(13)	(30)
Paid-In Capital [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Adjustments to Additional Paid in Capital, Income Tax Deficiency from Share-based Compensation		14	32
Increase (decrease) in tax benefit from stock-based compensation	12
Paid-In Capital [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase (decrease) in tax benefit from stock-based compensation	3	1	$ 2
Year of 2012 [Member] | Share-Based Comp Award One Year Anniversary [Member] | Management [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	1 year
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights	first
Year of 2012 [Member] | Share-Based Comp Award Two Year Anniversary [Member] | Management [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	2 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights	second
Year of 2012 [Member] | Share-Based Comp Award Three Year Anniversary [Member] | Management [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights	third
Years of 2013 and 2014 [Member] | Share-Based Comp Award Three Year Anniversary [Member] | Management [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights		third
2014 Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Reduction due to issuance of stock option or SAR	1.0
Reduction due to award other than stock option or SAR	2.12
Remaining Shares Available For Issuance	36,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	10 years
2014 Long Term Incentive Plan [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Shares Authorized	36,600,000
2014 Long Term Incentive Plan [Member] | Employee [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation, Option to Purchase, Shares	272,289
2014 Long Term Incentive Plan [Member] | Non-Employee Director [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period		50,771
2005 Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	10 years
2005 Long Term Incentive Plan [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Shares Authorized	59,300,000
2005 Long Term Incentive Plan [Member] | Employee [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	1,300,000	2,500,000	5,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures	993,730	5,300,000	0
2005 Long Term Incentive Plan [Member] | Non-Employee Director [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	48,083	147,108	170,151
2003 Stock Award Plan for Non-Employee Directors [Member] | Non-Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining Shares Available For Issuance	120,000
2003 Stock Award Plan for Non-Employee Directors [Member] | Non-Employee Director [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Shares Authorized	250,000
Common Stock, Shares, Issued	10,000
2003 Stock Award Plan for Non-Employee Directors [Member] | Common Stock [Member] | Non-Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	10,000	20,000	30,000
Long-Term Incentive Plan [Member] | Year of 2012 [Member] | Management [Member] | Performance Shares [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
Long-Term Incentive Plan [Member] | Year of 2012 [Member] | Management [Member] | Performance Shares [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	125.00%
Long-Term Incentive Plan [Member] | Year of 2012 [Member] | Management [Member] | Performance Shares and Operational Components [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	250.00%
Long-Term Incentive Plan [Member] | Year of 2013 [Member] | Management [Member] | Performance Shares [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	200.00%
Long-Term Incentive Plan [Member] | Year of 2013 [Member] | Management [Member] | TSR [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
Long-Term Incentive Plan [Member] | Year of 2013 [Member] | Management [Member] | TSR [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	125.00%
Long-Term Incentive Plan [Member] | Year of 2013 [Member] | Management [Member] | Operational Component [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
Long-Term Incentive Plan [Member] | Year of 2013 [Member] | Management [Member] | Operational Component [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	62.50%
Long-Term Incentive Plan [Member] | Year of 2014 [Member] | Performance Shares [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		100.00%
Long-Term Incentive Plan [Member] | Year of 2014 [Member] | Management [Member] | TSR [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
Long-Term Incentive Plan [Member] | Year of 2014 [Member] | Management [Member] | TSR [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	200.00%

XML

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2014

Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]

Antidilutive Securities Excluded From Computation Of Earnings Per Share [Table Text Block]

For the years ended December 31, 2014, 2013 and 2012, shares of the following securities and associated adjustments to net income, representing dividends on preferred stock and allocated earnings on participating securities, were excluded from the calculation of diluted EPS as the effect was antidilutive. The impact of our stock options was immaterial in the calculation of diluted EPS for these periods.

	Net Income Adjustments		Shares
	($ in millions)		(in millions)
Year Ended December 31, 2014
Participating securities	$	22	3
Year Ended December 31, 2013
Common stock equivalent of our preferred stock outstanding:
5.75% cumulative convertible preferred stock	$	86	56
5.75% cumulative convertible preferred stock (series A)	$	63	40
5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
4.50% cumulative convertible preferred stock	$	12	6
Participating securities	$	10	5
Year Ended December 31, 2012
Common stock equivalent of our preferred stock outstanding:
5.75% cumulative convertible preferred stock	$	86	56
5.75% cumulative convertible preferred stock (series A)	$	63	39
5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
4.50% cumulative convertible preferred stock	$	12	6
Participating securities	$	—	5

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

A reconciliation of basic EPS and diluted EPS for the year ended December 31, 2014 is as follows: 

	Income (Numerator)		Weighted Average Shares (Denominator)	Per Share Amount
	(in millions, except per share data)
For the Year Ended December 31, 2014:
Basic EPS	$	1,273	659	$	1.93
Effect of Dilutive Securities:
Assumed conversion as of the beginning of the period     of preferred shares outstanding during the period:
Common shares assumed issued for 5.75% cumulative convertible preferred stock	86		59
Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)	63		42
Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)	10		6
Common shares assumed issued for 4.50% cumulative convertible preferred stock	12		6
Diluted EPS	$	1,444	772	$	1.87

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Asset Retirement Obligation (Tables)

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The components of the change in our asset retirement obligations are shown below.

	Years Ended December 31,
	2014			2013
	($ in millions)
Asset retirement obligations, beginning of period	$	405		$	375
Additions	29			20
Revisions(a)	101			8
Settlements and disposals	(92		)	(20		)
Accretion expense	22			22
Asset retirement obligations, end of period	465			405
Less current portion (b)	18			—
Asset retirement obligation, long-term	$	447		$	405

_________________________________________

(a) Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settlement.

XML

Debt - Fair Value of Other Financial Instruments (Table) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt, net	$ 11,535	$ 12,886
Reported Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt, net	11,525	10,501
Reported Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt, net	0	2,372
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt, net	12,052	11,557
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt, net	$ 0	$ 2,369

XML

Natural Gas and Oil Property Transactions - Narrative (Details) (USD $)	12 Months Ended			1 Months Ended	0 Months Ended
	Dec. 31, 2014 Mcfe	Dec. 31, 2013 Mcfe	Dec. 31, 2012 Mcfe	Jul. 31, 2008	Oct. 15, 2014 acre	Oct. 14, 2014
Business Acquisition [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	145,200,000,000	170,900,000,000	202,200,000,000
Proceeds from divestitures of proved and unproved properties	$ 5,813,000,000	$ 3,467,000,000	$ 5,884,000,000
Total Drilling Carries	9,000,000,000
Minimum [Member]
Business Acquisition [Line Items]
Interest Sold				20.00%
Maximum [Member]
Business Acquisition [Line Items]
Interest Sold				50.00%
VPP 6 East Texas and Texas Gulf Coast [Member]
Business Acquisition [Line Items]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds						63,000,000
Proved Developed and Undeveloped Reserve, Production (Energy)	4,300,000,000	4,900,000,000	5,500,000,000
Corporate Joint Venture [Member]
Business Acquisition [Line Items]
Number Of Net Acres		850,000
Proceeds from divestitures of proved and unproved properties	379,000,000
Number of Joint Ventures	8
Number of Resource Plays	8
Proceeds from Divestiture of Interest in Joint Venture	8,000,000,000
Oil And Gas Benefit From Drilling Carries	679,000,000	884,000,000	784,000,000
JV Mississippian Lime [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Interest in Joint Venture		1,110,000,000
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners		50.00%
JV Utica [Member]
Business Acquisition [Line Items]
Drilling Carries Remaining	51,000,000
Percentage of Total Payment by Joint Venture Partner	60.00%
JV Marcellus, Barnett, Utica, Eagle Ford, Mid-Continent [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Interest in Joint Venture	33,000,000	58,000,000	272,000,000
Corporate VPP [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Other Assets	0
Payment Remaining [Member] | JV Mississippian Lime [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Interest in Joint Venture		71,000,000
Closing adjustments between the effective date and the closing date transaction [Member] | JV Mississippian Lime [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Interest in Joint Venture		90,000,000
Payment Received [Member] | JV Mississippian Lime [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Interest in Joint Venture		64,000,000
Southwestern [Member]
Business Acquisition [Line Items]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds						4,975,000,000
Number Of Net Acres					413,000
Southwestern [Member] | North Western Virginia and Southern Pennsylvania [Member]
Business Acquisition [Line Items]
Number of Wells, Gross					1,500
Southwestern [Member] | Marcellus and Utica Formations [Member]
Business Acquisition [Line Items]
Number of Wells, Gross					435
RKI Exploration & Production, LLC [Member]
Business Acquisition [Line Items]
Number Of Gross Acres	440,000
RKI Exploration & Production, LLC [Member] | RKI Obligation [Member]
Business Acquisition [Line Items]
Number Of Net Acres	203,000
Number of Wells, Gross	186
Interest Sold	48.00%
RKI Exploration & Production, LLC [Member] | Chesapeake Obligation [Member]
Business Acquisition [Line Items]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	450,000,000
Number Of Net Acres	137,000
Number of Wells, Gross	67
Interest Sold	22.00%
Rice Drilling [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties	233,000,000
Hilcorp Energy [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties	133,000,000
Haynesville Shale [Member]
Business Acquisition [Line Items]
Number Of Net Acres		9,600
Haynesville Shale [Member] | Payment at Closing [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties		257,000,000
Haynesville Shale [Member] | Subsequent Payment [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties		47,000,000
Northern Eagle Ford Shale [Member]
Business Acquisition [Line Items]
Number Of Net Acres		55,000
Northern Eagle Ford Shale [Member] | Payment at Closing [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties		617,000,000
Northern Eagle Ford Shale [Member] | Subsequent Payment [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties	57,000,000	32,000,000
MKR Holdings LLC [Member] | Payment at Closing [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties		490,000,000
Permian Basin [Member]
Business Acquisition [Line Items]
Percentage Of Estimated Proved Reserves			6.00%
Permian Basin [Member] | Cash Payment [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties			3,091,000,000
Permian Basin [Member] | Amount allocated to midstream and other fixed assets [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties		42,000,000
Permian Basin [Member] | Subsequent Payment [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties			466,000,000
Chitwood Knox [Member]
Business Acquisition [Line Items]
Number Of Net Acres			40,000
Proceeds from divestitures of proved and unproved properties			540,000,000
Utica [Member]
Business Acquisition [Line Items]
Number Of Net Acres			72,000
Proceeds from divestitures of proved and unproved properties			358,000,000
XTO Energy Inc. [Member]
Business Acquisition [Line Items]
Number Of Net Acres			60,000
Proceeds from divestitures of proved and unproved properties			$ 572,000,000
Compressor [Member] | Hilcorp Energy [Member]
Business Acquisition [Line Items]
Equipment, Number of Units	61

XML

Debt - Long Term Debt Table (Phantom) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Senior Unsecured Term Loan Due 2017 [Member] | Unsecured Debt [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument Maturity Date	Dec. 02, 2017
9.5% Senior Notes Due 2015 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	9.50%
Debt Instrument Maturity Date	Feb. 15, 2015
3.25% Senior Notes due 2016 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.25%	3.25%
Debt Instrument Maturity Date	Mar. 15, 2016
6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member] | Cross Currency Interest Rate Contract [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Debt Instrument Maturity Date	Jan. 15, 2017
6.5% Senior Notes Due 2017 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument Maturity Date	Aug. 15, 2017
6.875% Senior Notes Due 2018 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.875%	6.875%
Debt Instrument Maturity Date	Aug. 18, 2018
7.25% Senior Notes Due 2018 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.25%
Debt Instrument Maturity Date	Dec. 15, 2018
Floating Rate Senior Notes due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument Maturity Date	Apr. 15, 2019
6.625% Senior Notes Due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.625%
Debt Instrument Maturity Date	Nov. 15, 2019
6.625% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.625%
Debt Instrument Maturity Date	Aug. 15, 2020
6.875% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.875%
Debt Instrument Maturity Date	Nov. 15, 2020
5.375% Senior Notes due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.375%	5.375%
Debt Instrument Maturity Date	Jun. 15, 2021
6.125% Senior Notes Due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.125%
Debt Instrument Maturity Date	Feb. 15, 2021
4.875% Senior Notes due 2022 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.875%
Debt Instrument Maturity Date	Apr. 15, 2022
5.75% Senior Notes due 2023 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.75%	5.75%
Debt Instrument Maturity Date	Mar. 15, 2023
2.75% Contingent Convertible Senior Notes Due 2035 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instruments Convertible Optional Repurchase Dates	November 15, 2015, 2020, 2025, 2030
2.75% Contingent Convertible Senior Notes Due 2035 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.75%
Debt Instrument Maturity Date	Nov. 15, 2035
2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instruments Convertible Optional Repurchase Dates	May 15, 2017, 2022, 2027, 2032
2.5% Contingent Convertible Senior Notes due 2037 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Debt Instrument Maturity Date	May 17, 2037
2.25% Contingent Convertible Senior Notes Due 2038 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instruments Convertible Optional Repurchase Dates	December 15, 2018, 2023, 2028, 2033
2.25% Contingent Convertible Senior Notes Due 2038 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.25%
Debt Instrument Maturity Date	Dec. 15, 2038

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Investments (Tables)

12 Months Ended

Dec. 31, 2014

Investments [Abstract]

Equity Method Investments [Table Text Block]

A summary of our investments, including our approximate ownership percentage and carrying value as of December 31, 2014 and 2013, is presented below.

		Approximate Ownership %		Carrying Value
	Accounting	December 31,		December 31,
	Method	2014	2013	2014		2013
				($ in millions)
FTS International, Inc.	Equity	30%	30%	$	116	$	138
Sundrop Fuels, Inc.	Equity	56%	56%	130		135
Chaparral Energy, Inc.	Equity	—%	20%	—		143
Other	—	—%	—%	19		61
Total investments				$	265	$	477

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) (Treasury Stock - Common [Member])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Treasury Stock - Common [Member]
Purchase of shares for company benefit plans, shares	34,678	251,403	652,443
Release of shares from company benefit plans, shares	422,395	397,098	57,252

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Other Property and Equipment - Held for Use and Useful Lives Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 3,083	$ 3,203
Oilfield services equipment	0	2,192
Property and equipment, other	3,083	5,395
Accumulated Depreciation And Amortization Of Other Property And Equipment	(804)	(1,584)
Other property and equipment, net	2,279	3,811
Building and Building Improvements [Member]
Property, Plant and Equipment [Line Items]
Buildings and Improvements, Gross	1,242	1,433
Property, Plant and Equipment, Estimated Useful Lives	10 - 39
Natural Gas Compressors [Member]
Property, Plant and Equipment [Line Items]
Machinery and Equipment, Gross	551	368
Property, Plant and Equipment, Estimated Useful Lives	3 - 20
Land [Member]
Property, Plant and Equipment [Line Items]
Land	296	212
Property, Plant and Equipment, Estimated Useful Lives	0
Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	218	292
Property, Plant and Equipment, Estimated Useful Lives	20
Exploration and Production Equipment [Member]
Property, Plant and Equipment [Line Items]
Oilfield services equipment	0	2,192
Property, Plant and Equipment, Estimated Useful Lives	3 - 15
Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Line Items]
Property and Equipment Other Miscellaneous	$ 776	$ 898
Property, Plant and Equipment, Estimated Useful Lives	2 - 20

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Debt - Schedule of Debt Maturities Table (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 396
Long-term Debt, Maturities, Repayments of Principal in Year Two	500
Long-term Debt, Maturities, Repayments of Principal in Year Three	2,244
Long-term Debt, Maturities, Repayments of Principal in Year Four	1,016
Long-term Debt, Maturities, Repayments of Principal in Year Five	1,500
Long-term Debt, Maturities, Repayments of Principal after Year Five	6,100
Long-term Debt, Gross	$ 11,756

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Condensed Consolidating Financial Information - Balance Sheet Table (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CURRENT ASSETS:
Cash and cash equivalents	$ 4,108	$ 837	$ 287	$ 351
Restricted cash	38	75
Other current assets	207	299
Intercompany receivable, net	0	0
Total Current Assets	7,468	3,656
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	30,143	32,593
Other property and equipment, net	2,279	3,811
Property and equipment held for sale, net	93	730
Total Property and Equipment, Net	32,515	37,134
LONG-TERM ASSETS:
Other long-term assets	497	511
Investments in subsidiaries and intercompany advances	0	0
Total Assets	40,751	41,782	41,611
CURRENT LIABILITIES:
Other Liabilities, Current	3,061	3,511
Intercompany payable, net	0	0
Current Liabilities	5,863	5,515
LONG-TERM LIABILITIES:
Long-term debt, net	11,154	12,886
Deferred income tax liabilities	4,185	3,407
Other long-term liabilities	679	984
Total Long-Term Liabilities	16,683	18,127
EQUITY:
Chesapeake stockholders’ equity	16,903	15,995
Noncontrolling interests	1,302	2,145
Total Equity	18,205	18,140	17,896
TOTAL LIABILITIES AND EQUITY	40,751	41,782
Parent Company Member]
CURRENT ASSETS:
Cash and cash equivalents	4,100	799	228	2
Restricted cash	0	0
Other current assets	55	103
Intercompany receivable, net	24,527	25,549
Total Current Assets	28,682	26,451
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	0	0
Other property and equipment, net	0	0
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	0	0
LONG-TERM ASSETS:
Other long-term assets	153	111
Investments in subsidiaries and intercompany advances	126	2,169
Total Assets	28,961	28,731
CURRENT LIABILITIES:
Other Liabilities, Current	792	300
Intercompany payable, net	0	0
Current Liabilities	792	300
LONG-TERM LIABILITIES:
Long-term debt, net	11,154	11,831
Deferred income tax liabilities	0	209
Other long-term liabilities	112	396
Total Long-Term Liabilities	11,266	12,436
EQUITY:
Chesapeake stockholders’ equity	16,903	15,995
Noncontrolling interests	0	0
Total Equity	16,903	15,995
TOTAL LIABILITIES AND EQUITY	28,961	28,731
Guarantor Subsidiaries [Member]
CURRENT ASSETS:
Cash and cash equivalents	2	8	0	0
Restricted cash	0	37
Other current assets	3,174	2,465
Intercompany receivable, net	0	0
Total Current Assets	3,176	2,510
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	28,358	30,933
Other property and equipment, net	2,276	2,360
Property and equipment held for sale, net	93	701
Total Property and Equipment, Net	30,727	33,994
LONG-TERM ASSETS:
Other long-term assets	618	1,161
Investments in subsidiaries and intercompany advances	467	(209)
Total Assets	34,988	37,456
CURRENT LIABILITIES:
Other Liabilities, Current	5,084	5,262
Intercompany payable, net	24,937	26,409
Current Liabilities	30,021	31,671
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities	3,751	2,338
Other long-term liabilities	1,090	1,278
Total Long-Term Liabilities	4,841	3,616
EQUITY:
Chesapeake stockholders’ equity	126	2,169
Noncontrolling interests	0	0
Total Equity	126	2,169
TOTAL LIABILITIES AND EQUITY	34,988	37,456
Non-Guarantor Subsidiaries [Member]
CURRENT ASSETS:
Cash and cash equivalents	84	38	59	349
Restricted cash	38	38
Other current assets	93	524
Intercompany receivable, net	341	860
Total Current Assets	556	1,460
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	1,112	1,471
Other property and equipment, net	3	1,452
Property and equipment held for sale, net	0	29
Total Property and Equipment, Net	1,115	2,952
LONG-TERM ASSETS:
Other long-term assets	26	96
Investments in subsidiaries and intercompany advances	0	0
Total Assets	1,697	4,508
CURRENT LIABILITIES:
Other Liabilities, Current	68	309
Intercompany payable, net	0	0
Current Liabilities	68	309
LONG-TERM LIABILITIES:
Long-term debt, net	0	1,055
Deferred income tax liabilities	234	773
Other long-term liabilities	142	504
Total Long-Term Liabilities	376	2,332
EQUITY:
Chesapeake stockholders’ equity	1,253	1,867
Noncontrolling interests	0	0
Total Equity	1,253	1,867
TOTAL LIABILITIES AND EQUITY	1,697	4,508
Eliminations [Member]
CURRENT ASSETS:
Cash and cash equivalents	(78)	(8)	0	0
Restricted cash	0	0
Other current assets	0	(348)
Intercompany receivable, net	(24,868)	(26,409)
Total Current Assets	(24,946)	(26,765)
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	673	189
Other property and equipment, net	0	(1)
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	673	188
LONG-TERM ASSETS:
Other long-term assets	(29)	(376)
Investments in subsidiaries and intercompany advances	(593)	(1,960)
Total Assets	(24,895)	(28,913)
CURRENT LIABILITIES:
Other Liabilities, Current	(81)	(356)
Intercompany payable, net	(24,937)	(26,409)
Current Liabilities	(25,018)	(26,765)
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities	200	87
Other long-term liabilities	0	(344)
Total Long-Term Liabilities	200	(257)
EQUITY:
Chesapeake stockholders’ equity	(1,379)	(4,036)
Noncontrolling interests	1,302	2,145
Total Equity	(77)	(1,891)
TOTAL LIABILITIES AND EQUITY	(24,895)	(28,913)
Consolidated Entities [Member]
CURRENT ASSETS:
Other current assets	3,322	2,744
LONG-TERM ASSETS:
Other long-term assets	768	992
CURRENT LIABILITIES:
Other Liabilities, Current	5,863	5,515
LONG-TERM LIABILITIES:
Other long-term liabilities	$ 1,344	$ 1,834

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Equity (Tables)

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Common Stock [Table Text Block]

The following is a summary of the changes in our common shares issued for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014		2013		2012
	(in thousands)
Shares issued as of January 1	666,192		666,468		660,888
Restricted stock issuances (net of forfeitures and cancellations)(a)	(2,529	)	(599	)	5,038
Stock option exercises	1,281		323		542
Shares issued as of December 31	664,944		666,192		666,468

___________________________________________

(a) In the second quarter of 2013, we began granting restricted stock units (RSUs) in lieu of restricted stock awards (RSAs) to non-employee directors and employees. Shares of common stock underlying RSUs are issued when the units vest, whereas shares of common stock are issued on the date the RSAs are granted. We refer to RSAs and RSUs collectively as restricted stock.

Schedule of Preferred Stock Summary and Conversion Terms [Table Text Block]

Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2014:

Preferred Stock Series	Issue Date	Liquidation Preference per Share		Holder's Conversion Right	Conversion Rate	Conversion Price		Company's Conversion Right From	Company's Market Conversion Trigger(a)
5.75% cumulative convertible non-voting	May and June 2010	$	1,000	Any time	39.5856	$	25.2617	May 17, 2015	$	32.8402
5.75% (series A) cumulative convertible non-voting	May 2010	$	1,000	Any time	38.2538	$	26.1412	May 17, 2015	$	33.9836
4.50% cumulative convertible	September 2005	$	100	Any time	2.4468	$	40.8693	September 15, 2010	$	53.1301
5.00% cumulative convertible (series 2005B)	November 2005	$	100	Any time	2.7669	$	36.1415	November 15, 2010	$	46.9840

___________________________________________

(a) Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding.

Schedule of Stock by Class [Table Text Block]

The following reflects the shares outstanding of our preferred stock for the years ended December 31, 2014, 2013 and 2012:

	5.75%	5.75% (A)	4.50%	5.00% (2005B)
	(in thousands)
Shares outstanding as of January 1, 2014, 2013 and 2012 and shares outstanding as of December 31, 2014, 2013 and 2012	1,497	1,100	2,559	2,096

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

For the years ended December 31, 2014 and 2013, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below.

	Net Gains (Losses) on Cash Flow Hedges			Net Gains (Losses) on Investments			Total
	($ in millions)
Balance, December 31, 2013	$	(167	)	$	5		$	(162	)
Other comprehensive income before reclassifications	1			—			1
Amounts reclassified from accumulated other comprehensive income	23			(5		)	18
Net other comprehensive income	24			(5		)	19
Balance, December 31, 2014	$	(143	)	$	—		$	(143	)
Balance, December 31, 2012	$	(189	)	$	7		$	(182	)
Other comprehensive income before reclassifications	2			(6		)	(4		)
Amounts reclassified from accumulated other comprehensive income	20			4			24
Net other comprehensive income	22			(2		)	20
Balance, December 31, 2013	$	(167	)	$	5		$	(162	)

A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.

	Years Ended December 31,
	2014						2013						2012
	Before  Tax			After  Tax			Before  Tax			After  Tax			Before  Tax			After  Tax
	($ in millions)
Balance, beginning of period	$	(269	)	$	(167	)	$	(304	)	$	(189	)	$	(287	)	$	(178	)
Net change in fair value	1			1			3			2			10			6
Gains (losses) reclassified to income	37			23			32			20			(27		)	(17		)
Balance, end of period	$	(231	)	$	(143	)	$	(269	)	$	(167	)	$	(304	)	$	(189	)

Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]

For the years ended December 31, 2014 and 2013, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the consolidated statements of operations are detailed below.

Details About Accumulated Other Comprehensive Income (Loss) Components	Affected Line Item in the Statement Where Net Income is Presented	Year Ended December 31, 2014
		($ in millions)
Year Ended December 31, 2014:
Net losses on cash flow hedges:
Commodity contracts	Oil, natural gas and NGL revenues	$	23
Investments:
Sale of investment	Net gain on sale of investment	(5		)
Total reclassifications for the period, net of tax		$	18
Year Ended December 31, 2013:
Net losses on cash flow hedges:
Commodity contracts	Oil, natural gas and NGL revenues	$	20
Investments:
Impairment of investment	Losses on investments	6
Sale of investment	Net gain on sale of investment	(2		)
Total reclassifications for the period, net of tax		$	24

Distributions Made to Limited Partner, by Distribution [Table Text Block]

For the years ended December 31, 2014, 2013 and 2012, the Trust declared and paid the following distributions:

Production Period	Distribution Date	Cash Distribution per Common Unit		Cash Distribution per Subordinated Unit
June 2014 - August 2014	December 1, 2014	$	0.5079	$	—
March 2014 - May 2014	August 29, 2014	$	0.5796	$	—
December 2013 - February 2014	May 30, 2014	$	0.6454	$	—
September 2013 - November 2013	March 3, 2014	$	0.6624	$	—
June 2013 - August 2013	November 29, 2013	$	0.6671	$	—
March 2013 - May 2013	August 29, 2013	$	0.6900	$	0.1432
December 2012 - February 2013	May 31, 2013	$	0.6900	$	0.3010
September 2012 - November 2012	March 1, 2013	$	0.6700	$	0.3772
June 2012 - August 2012	November 29, 2012	$	0.6300	$	0.2208
March 2012 - May 2012	August 30, 2012	$	0.6100	$	0.4819
December 2011 - February 2012	May 31, 2012	$	0.6588	$	0.6588
September 2011 - November 2011	March 1, 2012	$	0.7277	$	0.7277

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Asset Retirement Obligation (Note)

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

Asset Retirement Obligations

The components of the change in our asset retirement obligations are shown below.

	Years Ended December 31,
	2014			2013
	($ in millions)
Asset retirement obligations, beginning of period	$	405		$	375
Additions	29			20
Revisions(a)	101			8
Settlements and disposals	(92		)	(20		)
Accretion expense	22			22
Asset retirement obligations, end of period	465			405
Less current portion (b)	18			—
Asset retirement obligation, long-term	$	447		$	405

_________________________________________

(a) Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settlement.

(b) Balance is included in other current liabilities on the consolidated balance sheet.

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Fair Value Measurements (Note)

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements Disclosure [Text Block]

Fair Value Measurements

Recurring Fair Value Measurements

Other Current Assets. Assets related to Company matches of employee contributions to Chesapeake’s employee benefit plans are included in other current assets. The fair value of these assets is determined using quoted market prices as they consist of exchange-traded securities.

Other Current Liabilities. Liabilities related to Chesapeake’s deferred compensation plan are included in other current liabilities. The fair values of these liabilities are determined using quoted market prices as the plan consists of exchange-traded mutual funds.

Financial Assets (Liabilities). The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:

	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value
				($ in millions)
As of December 31, 2014
Financial Assets (Liabilities):
Other current assets	$	57		$	—	$	—	$	57
Other current liabilities	(58		)	—		—		(58		)
Total	$	(1	)	$	—	$	—	$	(1	)
As of December 31, 2013
Financial Assets (Liabilities):
Other current assets	$	80		$	—	$	—	$	80
Other current liabilities	(82		)	—		—		(82		)
Total	$	(2	)	$	—	$	—	$	(2	)

See Note 3 for information regarding fair value of other financial instruments. See Note 11 for information regarding fair value measurement of derivatives.

Nonrecurring Fair Value Measurements

See Note 17 regarding nonrecurring fair value measurements.

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Derivative and Hedging Activities - Derivative Instruments in Balance Sheet Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 652
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value	(17)
Derivative liability, gross liability		(649)
Foreign Currency Fair Value Hedge Asset at Fair Value		2
Derivative, Gain (Loss) on Derivative, Net	0	0
Derivative, Fair Value, Net	652	(649)
Interest Rate Derivative Instruments Not Designated as Hedging Instruments at Fair Value, Net	(17)	(98)
Foreign Currency Fair Value Hedge Derivative at Fair Value, Net	(53)	2
Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	722
Derivative liability, gross liability		(553)
Derivative, Gain (Loss) on Derivative, Net	0	0
Derivative, Fair Value, Net	722	(553)
Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value		(98)
Derivative, Gain (Loss) on Derivative, Net	0	0
Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	974	29
Derivative, Gain (Loss) on Derivative, Net	(95)	(29)
Derivative, Fair Value, Net	879	0
Other Noncurrent Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	16	11
Derivative, Gain (Loss) on Derivative, Net	(10)	(9)
Derivative, Fair Value, Net	6	2
Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value	(5)	(6)
Interest Rate Derivative Instruments Not Designated as Hedging Instruments at Fair Value, Net	(5)	(6)
Other Current Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative liability, gross liability	(105)	(231)
Derivative, Gain (Loss) on Derivative, Net	95	29
Derivative, Fair Value, Net	(10)	(202)
Other Current Liabilities [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value	(12)	(92)
Foreign Currency Fair Value Hedge Asset at Fair Value		2
Foreign Currency Fair Value Hedge Liability at Fair Value	53
Interest Rate Derivative Instruments Not Designated as Hedging Instruments at Fair Value, Net	(12)	(92)
Foreign Currency Fair Value Hedge Derivative at Fair Value, Net	(53)	2
Other Noncurrent Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative liability, gross liability	(163)	(362)
Derivative, Gain (Loss) on Derivative, Net	10	9
Derivative, Fair Value, Net	(153)	(353)
Other Noncurrent Liabilities [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Other Noncurrent Liabilities [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 0	$ 0

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Basis of Presentation and Summary of Significant Accounting Policies - Unproved Properties Excluded From Amortization Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended			170 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]
Acquisition Costs, Period Cost	$ 577	$ 199	$ 1,462	$ 5,149
Acquisition Costs, Cumulative	7,387
Exploration Costs, Period Cost	340	90	244	42
Exploration Costs, Cumulative	716
Capitalized Interest of Unproved Properties Excluded from Amortization	492	421	325	447
Capitalized Interest Of Unproved Properties Excluded From Amortization Cumulative	1,685
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	1,409	710	2,031	5,638
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative	$ 9,788	$ 12,013

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Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Unvested Restricted Stock Units Roll Forward [Table Text Block]

A summary of the changes in unvested restricted stock during 2014, 2013 and 2012 is presented below.

	Shares of Unvested Restricted Stock		Weighted Average Grant Date Fair Value
	(in thousands)
Unvested restricted stock as of January 1, 2014	13,400		$	23.38
Granted	5,049		$	25.92
Vested	(4,803	)	$	27.17
Forfeited	(3,555	)	$	28.09
Unvested restricted stock as of December 31, 2014	10,091		$	21.20
Unvested restricted stock as of January 1, 2013	18,899		$	23.72
Granted	9,189		$	19.68
Vested	(12,897	)	$	21.32
Forfeited	(1,791	)	$	22.86
Unvested restricted stock as of December 31, 2013	13,400		$	23.38
Unvested restricted stock as of January 1, 2012	19,544		$	26.97
Granted	9,480		$	21.13
Vested	(8,620	)	$	28.08
Forfeited	(1,505	)	$	24.57
Unvested restricted stock as of December 31, 2012	18,899		$	23.72

Equity-Classified Share-Based Payment Award Valuation Assumptions [Table Text Block]

The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2014:

Expected option life - years	5.9
Volatility	48.63	%
Risk-free interest rate	1.93	%
Dividend yield	1.33	%

For the 2014 awards, the Company utilized the Monte Carlo simulation for the TSR performance measure, and the following assumptions to determine the grant date fair value of the PSUs:

Volatility	41.37	%
Risk-free interest rate	0.76	%
Dividend yield for value of awards	1.36	%

Schedule of Share-Based Compensation, Stock Options, Activity [Table Text Block]

The following table provides information related to stock option activity for 2014, 2013 and 2012: 

	Number of Shares Underlying   Options		Weighted Average Exercise Price Per Share		Weighted   Average Contract Life in Years	Aggregate   Intrinsic Value(a)
	(in thousands)					($ in millions)
Outstanding at January 1, 2014	5,268		$	19.28	6.66	$	41
Granted	994		$	24.43
Exercised	(1,322	)	$	18.71		$	11
Expired	(28	)	$	18.97
Forfeited	(313	)	$	21.05
Outstanding at December 31, 2014	4,599		$	19.55	7.03	$	5
Exercisable at December 31, 2014	1,304		$	18.71	5.70	$	1
Outstanding at January 1, 2013	481		$	12.69	0.96	$	2
Granted	5,264		$	19.32
Exercised	(346	)	$	10.82		$	3
Expired	(131	)	$	19.31
Outstanding at December 31, 2013	5,268		$	19.28	6.66	$	41
Exercisable at December 31, 2013	1,552		$	18.82	1.97	$	13
Outstanding at January 1, 2012	1,051		$	9.84	1.41	$	13
Exercised	(570	)	$	7.45		$	7
Outstanding and exercisable at December 31, 2012	481		$	12.69	0.96	$	2

___________________________________________

(a) The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.

Equity-Classified Stock-Based Compensation [Table Text Block]

We recognized the following compensation costs related to PSUs for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014			2013		2012
	($ in millions)
General and administrative expenses	$	(4	)	$	34	$	8
Oil and natural gas properties	3			9		4
Oil, natural gas and NGL production expenses	—			2		1
Marketing, gathering and compression expenses	—			2		1
Oilfield services expenses	—			1		—
Total	$	(1	)	$	48	$	14

We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
General and administrative expenses	$	46	$	60	$	71
Oil and natural gas properties	29		52		71
Oil, natural gas and NGL production expenses	18		21		24
Marketing, gathering and compression expenses	6		7		15
Oilfield services expenses	5		10		10
Total	$	104	$	150	$	191

Liability-Classified Share-Based Payment Award Valuation Assumptions [Table Text Block]

The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2014:

Expected option life - years	5.9
Volatility	48.63	%
Risk-free interest rate	1.93	%
Dividend yield	1.33	%

For the 2014 awards, the Company utilized the Monte Carlo simulation for the TSR performance measure, and the following assumptions to determine the grant date fair value of the PSUs:

Volatility	41.37	%
Risk-free interest rate	0.76	%
Dividend yield for value of awards	1.36	%

Schedule of Nonvested Performance-based Units Activity [Table Text Block]

The following table presents a summary of our PSU awards:

	Units	Fair Value as of Grant Date		Fair Value(a)		Liability for Vested Amount
		($ in millions)
2012 Awards (b)
Payable 2015	884,507	$	23	$	12	$	12
2013 Awards
Payable 2016	1,701,941	$	35	$	42	$	39
2014 Awards
Payable 2017	609,637	$	16	$	10	$	7

___________________________________________

(a) As of December 31, 2014.

(b) In 2014 and 2013, we paid $11 million and $2 million, respectively, related to 2012 PSU awards.

Liability-Classified Stock-Based Compensation [Table Text Block]

We recognized the following compensation costs related to PSUs for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014			2013		2012
	($ in millions)
General and administrative expenses	$	(4	)	$	34	$	8
Oil and natural gas properties	3			9		4
Oil, natural gas and NGL production expenses	—			2		1
Marketing, gathering and compression expenses	—			2		1
Oilfield services expenses	—			1		—
Total	$	(1	)	$	48	$	14

We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
General and administrative expenses	$	46	$	60	$	71
Oil and natural gas properties	29		52		71
Oil, natural gas and NGL production expenses	18		21		24
Marketing, gathering and compression expenses	6		7		15
Oilfield services expenses	5		10		10
Total	$	104	$	150	$	191

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Major Customers and Segment Information (Note)

12 Months Ended

Dec. 31, 2014

Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]

Segment Information Disclosure [Text Block]

Major Customers and Segment Information

Sales to ExxonMobil Corporation and Plains Marketing, L.P. constituted approximately 12% and 11%, respectively, of our total revenues (before the effects of hedging) for the years ended December 31, 2014 and 2012, respectively. There were no sales to individual customers constituting 10% or more of total revenues (before the effects of hedging) for the year ended December 31, 2013.

As of December 31, 2014, we have two reportable operating segments, each of which is managed separately because of the nature of its operations. The exploration and production operating segment is responsible for finding and producing oil, natural gas and NGL. The marketing, gathering and compression operating segment is responsible for marketing, gathering and compression of oil, natural gas and NGL. In addition, prior to the spin-off described in Note 13, our former oilfield services operating segment was responsible for drilling, oilfield trucking, oilfield rentals, hydraulic fracturing and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations, as reflected in the table below.

Management evaluates the performance of our segments based upon income (loss) before income taxes. Revenues from the sale of oil, natural gas and NGL related to Chesapeake’s ownership interests by our marketing, gathering and compression operating segment are reflected as revenues within our exploration and production operating segment. These amounts totaled $8.565 billion, $7.570 billion and $5.464 billion for the years ended December 31, 2014, 2013 and 2012, respectively. Revenues generated by our former oilfield services operating segment for work performed for Chesapeake’s exploration and production operating segment were reclassified to the full cost pool based on Chesapeake’s ownership interest. Revenues reclassified totaled $544 million, $1.309 billion and $1.315 billion for the years ended December 31, 2014, 2013 and 2012, respectively. No income was recognized in our consolidated statements of operations related to oilfield services performed for Chesapeake-operated wells.

The following tables present selected financial information for Chesapeake’s operating segments:

	Exploration and Production			Marketing, Gathering and Compression			Former Oilfield Services			Other			Intercompany Eliminations			Consolidated  Total
	($ in millions)
Year Ended December 31, 2014:
Revenues	$	8,180		$	20,790		$	1,060		$	30		$	(9,109	)	$	20,951
Intersegment revenues	—			(8,565		)	(544		)	—			9,109			—
Total revenues	$	8,180		$	12,225		$	516		$	30		$	—		$	20,951
Unrealized gains on commodity derivatives	$	(1,394	)	$	—		$	—		$	—		$	—		$	(1,394	)
Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,756		$	38		$	145		$	42		$	(66	)	$	2,915
Impairments of fixed assets and other	$	22		$	24		$	23		$	19		$	—		$	88
Net gains on sales of fixed assets	$	(2	)	$	(187	)	$	(8	)	$	(2	)	$	—		$	(199	)
Interest expense	$	(709	)	$	(21	)	$	(42	)	$	3		$	680		$	(89	)
Earnings (losses) on investments	$	2		$	—		$	(6	)	$	(76	)	$	—		$	(80	)
Net gain (loss) on sales of investments	$	(6	)	$	—		$	—		$	73		$	—		$	67
Losses on purchases of debt	$	(197	)	$	—		$	—		$	—		$	—		$	(197	)
Income (Loss) Before Income Taxes	$	2,874		$	326		$	(16	)	$	(30	)	$	46		$	3,200
Total Assets	$	35,381		$	1,978		$	—		$	4,283		$	(891	)	$	40,751
Capital Expenditures	$	6,173		$	298		$	158		$	38		$	—		$	6,667

	Exploration and Production			Marketing, Gathering and Compression			Former Oilfield Services			Other			Intercompany Eliminations			Consolidated  Total
	($ in millions)
Year Ended December 31, 2013:
Revenues	$	7,052		$	17,129		$	2,188		$	29		$	(8,892	)	$	17,506
Intersegment revenues	—			(7,570		)	(1,309		)	(13		)	8,892			—
Total revenues	$	7,052		$	9,559		$	879		$	16		$	—		$	17,506
Unrealized gains on commodity derivatives	$	(228	)	$	—		$	—		$	—		$	—		$	(228	)
Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,674		$	46		$	289		$	49		$	(155	)	$	2,903
Impairments of fixed assets and other	$	27		$	50		$	75		$	394		$	—		$	546
Net (gains) losses on sales of fixed assets	$	2		$	(329	)	$	(1	)	$	26		$	—		$	(302	)
Interest expense	$	(918	)	$	(24	)	$	(82	)	$	(74	)	$	871		$	(227	)
Earnings (losses) on investments	$	3		$	—		$	(1	)	$	(229	)	$	1		$	(226	)
Net gain (loss) on sales of investments	$	—		$	—		$	—		$	(7	)	$	—		$	(7	)
Losses on purchases of debt	$	(193	)	$	—		$	—		$	—		$	—		$	(193	)
Income (Loss) Before Income Taxes	$	2,997		$	511		$	(51	)	$	(727	)	$	(1,288	)	$	1,442
Total Assets	$	35,341		$	2,430		$	2,018		$	5,750		$	(3,757	)	$	41,782
Capital Expenditures	$	6,198		$	299		$	272		$	421		$	—		$	7,190

	Exploration and Production			Marketing, Gathering and Compression			Former Oilfield Services			Other			Intercompany Eliminations			Consolidated  Total
	($ in millions)
Year Ended December 31, 2012:
Revenues	$	6,278		$	10,895		$	1,917		$	21		$	(6,795	)	$	12,316
Intersegment revenues	—			(5,464		)	(1,315		)	(16		)	6,795			—
Total revenues	$	6,278		$	5,431		$	602		$	5		$	—		$	12,316
Unrealized losses on commodity derivatives	$	(561	)	$	—		$	—		$	—		$	—		$	(561	)
Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,624		$	54		$	232		$	46		$	(145	)	$	2,811
Impairment of oil and natural gas properties	$	3,315		$	—		$	—		$	—		$	—		$	3,315
Impairments of fixed assets and other	$	28		$	6		$	60		$	246		$	—		$	340
Net (gains) losses on sales of fixed assets	$	14		$	(298	)	$	10		$	7		$	—		$	(267	)
Interest expense	$	(47	)	$	(20	)	$	(76	)	$	(364	)	$	430		$	(77	)
Earnings (losses) on investments	$	—		$	49		$	—		$	(152	)	$	—		$	(103	)
Net gain (loss) on sales of investments	$	(2	)	$	1,094		$	—		$	—		$	—		$	1,092
Losses on purchases of debt	$	(200	)	$	—		$	—		$	—		$	—		$	(200	)
Income (Loss) Before Income Taxes	$	(1,798	)	$	1,665		$	112		$	(478	)	$	(475	)	$	(974	)
Total Assets	$	37,004		$	2,291		$	2,115		$	2,529		$	(2,328	)	$	41,611
Capital Expenditures	$	12,044		$	852		$	658		$	554		$	—		$	14,108

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Condensed Consolidating Financial Information (Note)

12 Months Ended

Dec. 31, 2014

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

Condensed Consolidating Financial Information

Chesapeake Energy Corporation is a holding company, owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding senior notes and contingent convertible senior notes listed in Note 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries are non-guarantors. Our former oilfield services subsidiaries were separately capitalized and were not guarantors of our debt obligations.

The tables below are condensed consolidating financial statements for Chesapeake Energy Corporation (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012. This financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2014

($ in millions)

	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	4,100	$	2	$	84	$	(78	)	$	4,108
Restricted cash	—		—		38		—			38
Other	55		3,174		93		—			3,322
Intercompany receivable, net	24,527		—		341		(24,868		)	—
Total Current Assets	28,682		3,176		556		(24,946		)	7,468
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	—		28,358		1,112		673			30,143
Other property and equipment, net	—		2,276		3		—			2,279
Property and equipment held for sale, net	—		93		—		—			93
Total Property and Equipment, Net	—		30,727		1,115		673			32,515
LONG-TERM ASSETS:
Other assets	153		618		26		(29		)	768
Investments in subsidiaries and intercompany advances	126		467		—		(593		)	—
TOTAL ASSETS	$	28,961	$	34,988	$	1,697	$	(24,895	)	$	40,751
CURRENT LIABILITIES:
Current liabilities	$	792	$	5,084	$	68	$	(81	)	$	5,863
Intercompany payable, net	—		24,937		—		(24,937		)	—
Total Current Liabilities	792		30,021		68		(25,018		)	5,863
LONG-TERM LIABILITIES:
Long-term debt, net	11,154		—		—		—			11,154
Deferred income tax liabilities	—		3,751		234		200			4,185
Other long-term liabilities	112		1,090		142		—			1,344
Total Long-Term Liabilities	11,266		4,841		376		200			16,683
EQUITY:
Chesapeake stockholders’ equity	16,903		126		1,253		(1,379		)	16,903
Noncontrolling interests	—		—		—		1,302			1,302
Total Equity	16,903		126		1,253		(77		)	18,205
TOTAL LIABILITIES AND EQUITY	$	28,961	$	34,988	$	1,697	$	(24,895	)	$	40,751

CONDENSED CONSOLIDATING BALANCE SHEET

YEAR ENDED DECEMBER 31, 2013

($ in millions)

	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	799	$	8		$	38	$	(8	)	$	837
Restricted cash	—		37			38		—			75
Other	103		2,465			524		(348		)	2,744
Intercompany receivable, net	25,549		—			860		(26,409		)	—
Total Current Assets	26,451		2,510			1,460		(26,765		)	3,656
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	—		30,933			1,471		189			32,593
Other property and equipment, net	—		2,360			1,452		(1		)	3,811
Property and equipment held for sale, net	—		701			29		—			730
Total Property and Equipment, Net	—		33,994			2,952		188			37,134
LONG-TERM ASSETS:
Other assets	111		1,161			96		(376		)	992
Investments in subsidiaries and intercompany advances	2,169		(209		)	—		(1,960		)	—
TOTAL ASSETS	$	28,731	$	37,456		$	4,508	$	(28,913	)	$	41,782
CURRENT LIABILITIES:
Current liabilities	$	300	$	5,262		$	309	$	(356	)	$	5,515
Intercompany payable, net	—		26,409			—		(26,409		)	—
Total Current Liabilities	300		31,671			309		(26,765		)	5,515
LONG-TERM LIABILITIES:
Long-term debt, net	11,831		—			1,055		—			12,886
Deferred income tax liabilities	209		2,338			773		87			3,407
Other long-term liabilities	396		1,278			504		(344		)	1,834
Total Long-Term Liabilities	12,436		3,616			2,332		(257		)	18,127
EQUITY:
Chesapeake stockholders’ equity	15,995		2,169			1,867		(4,036		)	15,995
Noncontrolling interests	—		—			—		2,145			2,145
Total Equity	15,995		2,169			1,867		(1,891		)	18,140
TOTAL LIABILITIES AND EQUITY	$	28,731	$	37,456		$	4,508	$	(28,913	)	$	41,782

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2014

($ in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	7,765		$	418		$	(3	)	$	8,180
Marketing, gathering and compression	—			12,220			5			—			12,225
Oilfield services	—			41			983			(478		)	546
Total Revenues	—			20,026			1,406			(481		)	20,951
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			1,166			42			—			1,208
Production taxes	—			227			5			—			232
Marketing, gathering and compression	—			12,232			4			—			12,236
Oilfield services	—			53			769			(391		)	431
General and administrative	—			273			49			—			322
Restructuring and other termination costs	—			4			3			—			7
Provision for legal contingencies	100			134			—			—			234
Oil, natural gas and NGL depreciation, depletion and amortization	—			2,523			162			(2		)	2,683
Depreciation and amortization of other assets	—			153			143			(64		)	232
Impairment of oil and natural gas properties	—			—			349			(349		)	—
Impairments of fixed assets and other	—			65			23			—			88
Net gains on sales of fixed assets	—			(192		)	(7		)	—			(199		)
Total Operating Expenses	100			16,638			1,542			(806		)	17,474
INCOME (LOSS) FROM OPERATIONS	(100		)	3,388			(136		)	325			3,477
OTHER INCOME (EXPENSE):
Interest expense	(657		)	(37		)	(42		)	647			(89		)
Losses on investments	—			(77		)	(5		)	2			(80		)
Net gain on sales of investments	—			67			—			—			67
Losses on purchases of debt	(195		)	(2		)	—			—			(197		)
Other income (expense)	502			198			(2		)	(676		)	22
Equity in net earnings (losses) of subsidiary	2,206			(258		)	—			(1,948		)	—
Total Other Income (Expense)	1,856			(109		)	(49		)	(1,975		)	(277		)
INCOME (LOSS) BEFORE INCOME TAXES	1,756			3,279			(185		)	(1,650		)	3,200
INCOME TAX EXPENSE (BENEFIT)	(161		)	1,264			(66		)	107			1,144
NET INCOME (LOSS)	1,917			2,015			(119		)	(1,757		)	2,056
Net income attributable to noncontrolling interests	—			—			—			(139		)	(139		)
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	1,917			2,015			(119		)	(1,896		)	1,917
Other comprehensive income	1			18			—			—			19
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	1,918		$	2,033		$	(119	)	$	(1,896	)	$	1,936

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2013

($ in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	6,439		$	553		$	60		$	7,052
Marketing, gathering and compression	—			9,547			12			—			9,559
Oilfield services	—			221			1,836			(1,162		)	895
Total Revenues	—			16,207			2,401			(1,102		)	17,506
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			1,112			47			—			1,159
Production taxes	—			222			7			—			229
Marketing, gathering and compression	—			9,455			6			—			9,461
Oilfield services	—			239			1,434			(937		)	736
General and administrative	—			375			83			(1		)	457
Restructuring and other termination costs	—			244			4			—			248
Oil, natural gas and NGL depreciation, depletion and amortization	—			2,336			253			—			2,589
Depreciation and amortization of other assets	—			180			281			(147		)	314
Impairment of oil and natural gas properties	—			(2		)	313			(311		)	—
Impairments of fixed assets and other	—			417			129			—			546
Net gains on sales of fixed assets	—			(301		)	(1		)	—			(302		)
Total Operating Expenses	—			14,277			2,556			(1,396		)	15,437
INCOME (LOSS) FROM OPERATIONS	—			1,930			(155		)	294			2,069
OTHER INCOME (EXPENSE):
Interest expense	(921		)	(4		)	(85		)	783			(227		)
Losses on investments	—			(225		)	(1		)	—			(226		)
Net loss on sales of investments	—			(7		)	—			—			(7		)
Losses on purchases of debt	(70		)	(123		)	—			—			(193		)
Other income	3,979			(603		)	13			(3,363		)	26
Equity in net earnings (losses) of subsidiary	(1,129		)	(383		)	—			1,512			—
Total Other Income (Expense)	1,859			(1,345		)	(73		)	(1,068		)	(627		)
INCOME (LOSS) BEFORE INCOME TAXES	1,859			585			(228		)	(774		)	1,442
INCOME TAX EXPENSE (BENEFIT)	1,135			370			(87		)	(870		)	548
NET INCOME (LOSS)	724			215			(141		)	96			894
Net income attributable to noncontrolling interests	—			—			—			(170		)	(170		)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	724			215			(141		)	(74		)	724
Other comprehensive income (loss)	3			19			(2		)	—			20
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	727		$	234		$	(143	)	$	(74	)	$	744

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2012

($ in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Oil, natural gas and NGL	$	—		$	5,920		$	351		$	7		$	6,278
Marketing, gathering and compression	—			5,218			212			1			5,431
Oilfield services	—			154			1,553			(1,100		)	607
Total Revenues	—			11,292			2,116			(1,092		)	12,316
OPERATING EXPENSES:
Oil, natural gas and NGL production	—			1,278			26			—			1,304
Production taxes	—			182			6			—			188
Marketing, gathering and compression	—			5,197			115			—			5,312
Oilfield services	—			301			1,096			(932		)	465
General and administrative	—			431			105			(1		)	535
Restructuring and other termination costs	—			5			2			—			7
Oil, natural gas and NGL depreciation, depletion and amortization	—			2,353			154			—			2,507
Depreciation and amortization of other assets	—			187			266			(149		)	304
Impairment of oil and natural gas properties	—			3,192			123			—			3,315
Impairments of fixed assets and other	—			275			65			—			340
Net gains (losses) on sales of fixed assets	—			(269		)	2			—			(267		)
Total Operating Expenses	—			13,132			1,960			(1,082		)	14,010
INCOME (LOSS) FROM OPERATIONS	—			(1,840		)	156			(10		)	(1,694		)
OTHER INCOME (EXPENSE):
Interest expense	(879		)	45			(84		)	841			(77		)
Losses on investments	—			(167		)	55			9			(103		)
Net gain on sales of investments	—			29			1,063			—			1,092
Losses on purchases of debt	(200		)	—			—			—			(200		)
Other income (loss)	819			203			14			(1,028		)	8
Equity in net earnings (losses) of subsidiary	(610		)	436			—			174			—
Total Other Income (Expense)	(870		)	546			1,048			(4		)	720
INCOME (LOSS) BEFORE INCOME TAXES	(870		)	(1,294		)	1,204			(14		)	(974		)
INCOME TAX EXPENSE (BENEFIT)	(101		)	(675		)	470			(74		)	(380		)
NET INCOME (LOSS)	(769		)	(619		)	734			60			(594		)
Net income attributable to noncontrolling interests	—			—			—			(175		)	(175		)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(769		)	(619		)	734			(115		)	(769		)
Other comprehensive income (loss)	6			(22		)	—			—			(16		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	(763	)	$	(641	)	$	734		$	(115	)	$	(785	)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2014

($ in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	4,201		$	462		$	(29	)	$	4,634
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(4,445		)	(136		)	—			(4,581		)
Acquisitions of proved and unproved properties	—			(1,306		)	(5		)	—			(1,311		)
Proceeds from divestitures of proved and unproved properties	—			5,812			1			—			5,813
Additions to other property and equipment	—			(480		)	(246		)	—			(726		)
Other investing activities	—			1,199			60			—			1,259
Net Cash Provided By (Used In) Investing Activities	—			780			(326		)	—			454
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	—			6,689			717			—			7,406
Payments on credit facilities borrowings	—			(6,689		)	(1,099		)	—			(7,788		)
Proceeds from issuance of senior notes, net of discount and offering costs	2,966			—			494			—			3,460
Proceeds from issuance of term loans, net of discount and offering costs	—			—			394			—			394
Cash paid to purchase debt	(3,362		)	—			—			—			(3,362		)
Other financing activities	(439		)	(1,278		)	(169		)	(41		)	(1,927		)
Intercompany advances, net	4,136			(3,709		)	(427		)	—			—
Net Cash Provided By (Used In) Financing Activities	3,301			(4,987		)	(90		)	(41		)	(1,817		)
Net increase (decrease) in cash and cash equivalents	3,301			(6		)	46			(70		)	3,271
Cash and cash equivalents, beginning of period	799			8			38			(8		)	837
Cash and cash equivalents, end of period	$	4,100		$	2		$	84		$	(78	)	$	4,108

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2013

($ in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	4,218		$	439		$	(43	)	$	4,614
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(4,838		)	(766		)	—			(5,604		)
Acquisitions of proved and unproved properties	—			(1,378		)	346			—			(1,032		)
Proceeds from divestitures of proved and unproved properties	—			3,466			1			—			3,467
Additions to other property and equipment	—			(271		)	(701		)	—			(972		)
Other investing activities	—			246			765			163			1,174
Net Cash Provided By (Used In) Investing Activities	—			(2,775		)	(355		)	163			(2,967		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	—			6,452			1,217			—			7,669
Payments on credit facilities borrowings	—			(6,452		)	(1,230		)	—			(7,682		)
Proceeds from issuance of senior notes, net of discount and offering costs	2,274			—			—			—			2,274
Cash paid to purchase debt	(2,141		)	—			—			—			(2,141		)
Proceeds from sales of noncontrolling interests	—			—			6			—			6
Other financing activities	1,819			(2,897		)	(17		)	(128		)	(1,223		)
Intercompany advances, net	(1,381		)	1,462			(81		)	—			—
Net Cash Provided By (Used In) Financing Activities	571			(1,435		)	(105		)	(128		)	(1,097		)
Net increase (decrease) in cash and cash equivalents	571			8			(21		)	(8		)	550
Cash and cash equivalents, beginning of period	228			—			59			—			287
Cash and cash equivalents, end of period	$	799		$	8		$	38		$	(8	)	$	837

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2012

($ in millions)

	Parent(a)			Guarantor Subsidiaries(a)			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	1,711		$	1,182		$	(56	)	$	2,837
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	—			(8,605		)	(325		)	—			(8,930		)
Acquisitions of proved and unproved properties	—			(3,622		)	461			—			(3,161		)
Proceeds from divestitures of proved and unproved properties	—			5,884			—			—			5,884
Additions to other property and equipment	—			(1,736		)	(915		)	—			(2,651		)
Other investing activities	—			5,083			(316		)	(893		)	3,874
Net Cash Used In Investing Activities	—			(2,996		)	(1,095		)	(893		)	(4,984		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	—			18,930			1,388			—			20,318
Payments on credit facilities borrowings	—			(20,651		)	(999		)	—			(21,650		)
Proceeds from issuance of senior notes, net of discount and offering costs	1,263			—			—			—			1,263
Proceeds from issuance of term loans, net of discount and offering costs	5,722			—			—			—			5,722
Cash paid to purchase debt	(4,000		)	—			—			—			(4,000		)
Proceeds from sales of noncontrolling interests	—			63			1,014			—			1,077
Other financing activities	(477		)	(299		)	(820		)	949			(647		)
Intercompany advances, net	(2,282		)	3,242			(960		)	—			—
Net Cash Provided By (Used In) Financing Activities	226			1,285			(377		)	949			2,083
Net increase (decrease) in cash and cash equivalents	226			—			(290		)	—			(64		)
Cash and cash equivalents, beginning of period	2			—			349			—			351
Cash and cash equivalents, end of period	$	228		$	—		$	59		$	—		$	287

___________________________________________

(a) We have revised the amounts presented as cash and cash equivalents in the Guarantor Subsidiaries and Parent columns to properly reflect the cash of the Parent. As of December 31, 2012, $228 million was incorrectly presented in the Guarantor Subsidiaries column. The impact of this error was not material to any previously issued financial statements.

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (USD $) In Millions, unless otherwise specified	Total	Preferred Stock [Member]	Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Stock - Common [Member]	Parent [Member]	Noncontrolling Interest [Member]
Stockholders' Equity Attributable to Noncontrolling Interest, Period Start at Dec. 31, 2011									$ 1,337
Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2011				12,146	1,608	(166)	(33)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation				174
Exercise of stock options				3
Increase (decrease) in tax benefit from stock-based compensation				(30)
Net income (loss) attributable to Chesapeake	(769)
Dividends on common stock	(231)
Dividends on preferred stock	(171)
Spin-off of oilfield services business (Note 13)	0
Redemption of preferred shares of a subsidiary	0
Hedging activity						(11)
Investment activity						(5)
Purchase of 34,678, 251,403 and 652,443 shares for company benefit plans							(16)
Release of 422,395, 397,098 and 57,252 shares from company benefit plans							1
Sales of noncontrolling interests									1,077
Net income attributable to noncontrolling interests	175								175
Distributions to noncontrolling interest owners									(218)
Redemption of preferred shares of a subsidiary									0
Deconsolidation of investments, net									(44)
Total Equity	17,896
Stockholders' Equity Attributable to Noncontrolling Interest, Period End at Dec. 31, 2012									2,327
Chesapeake stockholders’ equity, end of period at Dec. 31, 2012		3,062	7	12,293	437	(182)	(48)	15,569
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation				162
Exercise of stock options				4
Increase (decrease) in tax benefit from stock-based compensation				(13)
Net income (loss) attributable to Chesapeake	724
Dividends on common stock	(233)
Dividends on preferred stock	(171)
Spin-off of oilfield services business (Note 13)	0
Redemption of preferred shares of a subsidiary	(69)
Hedging activity						22
Investment activity						(2)
Purchase of 34,678, 251,403 and 652,443 shares for company benefit plans							(6)
Release of 422,395, 397,098 and 57,252 shares from company benefit plans							8
Sales of noncontrolling interests									6
Net income attributable to noncontrolling interests	170								170
Distributions to noncontrolling interest owners									(215)
Redemption of preferred shares of a subsidiary									(143)
Deconsolidation of investments, net									0
Total Equity	18,140
Stockholders' Equity Attributable to Noncontrolling Interest, Period End at Dec. 31, 2013	2,145								2,145
Chesapeake stockholders’ equity, end of period at Dec. 31, 2013	15,995	3,062	7	12,446	688	(162)	(46)	15,995
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation				47
Exercise of stock options				23
Increase (decrease) in tax benefit from stock-based compensation				15
Net income (loss) attributable to Chesapeake	1,917
Dividends on common stock	(234)
Dividends on preferred stock	(171)
Spin-off of oilfield services business (Note 13)	(270)
Redemption of preferred shares of a subsidiary	(447)
Hedging activity						24
Investment activity						(5)
Purchase of 34,678, 251,403 and 652,443 shares for company benefit plans							(1)
Release of 422,395, 397,098 and 57,252 shares from company benefit plans							10
Sales of noncontrolling interests									0
Net income attributable to noncontrolling interests	139								139
Distributions to noncontrolling interest owners									(169)
Redemption of preferred shares of a subsidiary									(807)
Deconsolidation of investments, net									(6)
Total Equity	18,205
Stockholders' Equity Attributable to Noncontrolling Interest, Period End at Dec. 31, 2014	1,302								1,302
Chesapeake stockholders’ equity, end of period at Dec. 31, 2014	$ 16,903	$ 3,062	$ 7	$ 12,531	$ 1,483	$ (143)	$ (37)	$ 16,903

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Recently Issued Accounting Standards (Note)

12 Months Ended

Dec. 31, 2014

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements and Changes in Accounting Principles [Text Block]

Recently Issued Accounting Standards

In April 2014, the FASB issued an accounting standards update that raises the threshold for a disposal or classification as held for sale to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. This accounting standards update is effective for us beginning on January 1, 2015, and it is not expected to have a material impact on our consolidated financial statements.

In May 2014, the FASB issued updated revenue recognition guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and international financial reporting standards. The new standard requires the recognition of revenue to depict the transfer of promised goods to customers in an amount reflecting the consideration the company expects to receive in the exchange. The accounting standards update is effective for us beginning January 1, 2017, including retrospective application to comparative periods, and we are evaluating the impact on our consolidated financial statements.

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Equity - Preferred Stock Conversion Terms Table (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
5.75% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Preferred Stock, Liquidation Preference Per Share	$ 1,000,000	$ 1,000,000
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Preferred Stock, Liquidation Preference Per Share	$ 1,000,000	$ 1,000,000
4.50% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Preferred Stock, Liquidation Preference Per Share	$ 100,000	$ 100,000
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Preferred Stock, Liquidation Preference Per Share	$ 100,000	$ 100,000
Preferred Stock [Member] | 5.75% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Conversion of Stock, Stock Issue Date	May and June 2010
Preferred Stock, Liquidation Preference Per Share	$ 1,000
Conversion of Stock, Holders Conversion Right	Any time
Preferred Stock Conversion Rate	39.5856%
Conversion of Stock, Conversion Price	$ 25.2617
Conversion of Stock, Company Conversion Right, Date	May 17, 2015
Trigger Price For Time Period	$ 32.8402
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Preferred Stock [Member] | 5.75% Cumulative Convertible Preferred Stock Series A [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Conversion of Stock, Stock Issue Date	May 2010
Preferred Stock, Liquidation Preference Per Share	$ 1,000
Conversion of Stock, Holders Conversion Right	Any time
Preferred Stock Conversion Rate	38.2538%
Conversion of Stock, Conversion Price	$ 26.1412
Conversion of Stock, Company Conversion Right, Date	May 17, 2015
Trigger Price For Time Period	33.9836
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Preferred Stock [Member] | 4.50% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Conversion of Stock, Stock Issue Date	September 2005
Preferred Stock, Liquidation Preference Per Share	$ 100
Conversion of Stock, Holders Conversion Right	Any time
Preferred Stock Conversion Rate	2.4468%
Conversion of Stock, Conversion Price	$ 40.8693
Conversion of Stock, Company Conversion Right, Date	September 15, 2010
Trigger Price For Time Period	53.1301
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Preferred Stock [Member] | 5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Conversion of Stock, Stock Issue Date	November 2005
Preferred Stock, Liquidation Preference Per Share	$ 100
Conversion of Stock, Holders Conversion Right	Any time
Preferred Stock Conversion Rate	2.7669%
Conversion of Stock, Conversion Price	$ 36.1415
Conversion of Stock, Company Conversion Right, Date	November 15, 2010
Trigger Price For Time Period	$ 46.9840
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Minimum [Member] | Preferred Stock [Member] | 5.75% Cumulative Convertible Preferred Stock Series A [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Conversion of Stock, Company Market Trigger	25,000
Minimum [Member] | Preferred Stock [Member] | 4.50% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Conversion of Stock, Company Market Trigger	250,000

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Investments - Narrative (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments	$ 239	$ 115	$ 2,000
Investments	265	477
FTS International, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Investment Adjustments	32
Equity method accretion adjustments	10
Excess carrying value of investment over underlying equity in net assets	44
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity Attributable to Goodwill	14
Investments	116	138
Equity Method Investment, Ownership Percentage	30.00%	30.00%
Sundrop Fuels Inc [Member]
Schedule of Equity Method Investments [Line Items]
Equity Investment Adjustments	21
Excess carrying value of investment over underlying equity in net assets	78
Interest Costs Capitalized	16
Investments	130	135
Equity Method Investment, Ownership Percentage	56.00%	56.00%
Chaparral Energy, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Net Sales Proceeds	209
Equity Method Investment, Realized Gain (Loss) on Disposal	73
Investments	0	143
Equity Method Investment, Ownership Percentage	0.00%	20.00%
Clean Energy Fuels Corp [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Realized Gain (Loss) on Disposal		3
Cost Method Investments		100
Proceeds from Cost Method Investment		85
Other than Temporary Impairment Losses, Investments		15
Proceeds from sales of investments		13
Other Commitment		50
Gastar Exploration Ltd [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Net Sales Proceeds		10
Chesapeake Midstream Partners Lp [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Realized Gain (Loss) on Disposal			1,032
Proceeds from sales of investments			2,000
Glass Mountain Pipeline Limited Liability Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Realized Gain (Loss) on Disposal			62
Proceeds from sales of investments			99
Additional Assets Pipeline Length			210
Equity Method Investment, Ownership Percentage			50.00%
Other Investments [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Realized Gain (Loss) on Disposal	(6)	5
Proceeds from sales of investments	$ 30	$ 6

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Other Liabilities (Tables)

12 Months Ended

Dec. 31, 2014

Other Liabilities Disclosure [Abstract]

Other Current Liabilities [Table Text Block]

Other current liabilities as of December 31, 2014 and 2013 are detailed below.

	December 31,
	2014		2013
	($ in millions)
Revenues and royalties due others	$	1,176	$	1,409
Accrued oil, natural gas and NGL drilling and production costs	385		457
Joint interest prepayments received	189		464
Accrued compensation and benefits	344		320
Other accrued taxes	55		161
Accrued dividends	101		101
Other	811		599
Total other current liabilities	$	3,061	$	3,511

Other Long-Term Liabilities [Table Text Block]

Other long-term liabilities as of December 31, 2014 and 2013 are detailed below.

	December 31,
	2014		2013
	($ in millions)
CHK Utica ORRI conveyance obligation(a)	$	220	$	250
CHK C-T ORRI conveyance obligation(b)	135		149
Financing obligations	30		31
Unrecognized tax benefits	45		317
Other	249		237
Total other long-term liabilities	$	679	$	984

____________________________________________

(a) $14 million and $13 million of the total $234 million and $263 million obligations are recorded in other current liabilities as of December 31, 2014 and 2013, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction.

(b) $23 million and $12 million of the total $158 million and $161 million obligations are recorded in other current liabilities as of December 31, 2014 and 2013, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction.

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Major Customers and Segment Information (Tables)

12 Months Ended

Dec. 31, 2014

Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

The following tables present selected financial information for Chesapeake’s operating segments:

	Exploration and Production			Marketing, Gathering and Compression			Former Oilfield Services			Other			Intercompany Eliminations			Consolidated  Total
	($ in millions)
Year Ended December 31, 2014:
Revenues	$	8,180		$	20,790		$	1,060		$	30		$	(9,109	)	$	20,951
Intersegment revenues	—			(8,565		)	(544		)	—			9,109			—
Total revenues	$	8,180		$	12,225		$	516		$	30		$	—		$	20,951
Unrealized gains on commodity derivatives	$	(1,394	)	$	—		$	—		$	—		$	—		$	(1,394	)
Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,756		$	38		$	145		$	42		$	(66	)	$	2,915
Impairments of fixed assets and other	$	22		$	24		$	23		$	19		$	—		$	88
Net gains on sales of fixed assets	$	(2	)	$	(187	)	$	(8	)	$	(2	)	$	—		$	(199	)
Interest expense	$	(709	)	$	(21	)	$	(42	)	$	3		$	680		$	(89	)
Earnings (losses) on investments	$	2		$	—		$	(6	)	$	(76	)	$	—		$	(80	)
Net gain (loss) on sales of investments	$	(6	)	$	—		$	—		$	73		$	—		$	67
Losses on purchases of debt	$	(197	)	$	—		$	—		$	—		$	—		$	(197	)
Income (Loss) Before Income Taxes	$	2,874		$	326		$	(16	)	$	(30	)	$	46		$	3,200
Total Assets	$	35,381		$	1,978		$	—		$	4,283		$	(891	)	$	40,751
Capital Expenditures	$	6,173		$	298		$	158		$	38		$	—		$	6,667

	Exploration and Production			Marketing, Gathering and Compression			Former Oilfield Services			Other			Intercompany Eliminations			Consolidated  Total
	($ in millions)
Year Ended December 31, 2013:
Revenues	$	7,052		$	17,129		$	2,188		$	29		$	(8,892	)	$	17,506
Intersegment revenues	—			(7,570		)	(1,309		)	(13		)	8,892			—
Total revenues	$	7,052		$	9,559		$	879		$	16		$	—		$	17,506
Unrealized gains on commodity derivatives	$	(228	)	$	—		$	—		$	—		$	—		$	(228	)
Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,674		$	46		$	289		$	49		$	(155	)	$	2,903
Impairments of fixed assets and other	$	27		$	50		$	75		$	394		$	—		$	546
Net (gains) losses on sales of fixed assets	$	2		$	(329	)	$	(1	)	$	26		$	—		$	(302	)
Interest expense	$	(918	)	$	(24	)	$	(82	)	$	(74	)	$	871		$	(227	)
Earnings (losses) on investments	$	3		$	—		$	(1	)	$	(229	)	$	1		$	(226	)
Net gain (loss) on sales of investments	$	—		$	—		$	—		$	(7	)	$	—		$	(7	)
Losses on purchases of debt	$	(193	)	$	—		$	—		$	—		$	—		$	(193	)
Income (Loss) Before Income Taxes	$	2,997		$	511		$	(51	)	$	(727	)	$	(1,288	)	$	1,442
Total Assets	$	35,341		$	2,430		$	2,018		$	5,750		$	(3,757	)	$	41,782
Capital Expenditures	$	6,198		$	299		$	272		$	421		$	—		$	7,190

	Exploration and Production			Marketing, Gathering and Compression			Former Oilfield Services			Other			Intercompany Eliminations			Consolidated  Total
	($ in millions)
Year Ended December 31, 2012:
Revenues	$	6,278		$	10,895		$	1,917		$	21		$	(6,795	)	$	12,316
Intersegment revenues	—			(5,464		)	(1,315		)	(16		)	6,795			—
Total revenues	$	6,278		$	5,431		$	602		$	5		$	—		$	12,316
Unrealized losses on commodity derivatives	$	(561	)	$	—		$	—		$	—		$	—		$	(561	)
Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,624		$	54		$	232		$	46		$	(145	)	$	2,811
Impairment of oil and natural gas properties	$	3,315		$	—		$	—		$	—		$	—		$	3,315
Impairments of fixed assets and other	$	28		$	6		$	60		$	246		$	—		$	340
Net (gains) losses on sales of fixed assets	$	14		$	(298	)	$	10		$	7		$	—		$	(267	)
Interest expense	$	(47	)	$	(20	)	$	(76	)	$	(364	)	$	430		$	(77	)
Earnings (losses) on investments	$	—		$	49		$	—		$	(152	)	$	—		$	(103	)
Net gain (loss) on sales of investments	$	(2	)	$	1,094		$	—		$	—		$	—		$	1,092
Losses on purchases of debt	$	(200	)	$	—		$	—		$	—		$	—		$	(200	)
Income (Loss) Before Income Taxes	$	(1,798	)	$	1,665		$	112		$	(478	)	$	(475	)	$	(974	)
Total Assets	$	37,004		$	2,291		$	2,115		$	2,529		$	(2,328	)	$	41,611
Capital Expenditures	$	12,044		$	852		$	658		$	554		$	—		$	14,108

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Commitments - Undiscounted Pressure Pumping Contracts Commitments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Other Commitments [Line Items]
Pressure Pumping Contracts, Future Minimum Payments Due, Next Twelve Months	$ 5
Pressure Pumping Contracts, Future Minimum Payments, Due in Two Years	4
Pressure Pumping Contracts, Future Minimum Payments, Due in Three Years	1
Future Minimum Payments Due	11
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member]
Other Commitments [Line Items]
Pressure Pumping Contracts, Future Minimum Payments Due, Next Twelve Months	245
Pressure Pumping Contracts, Future Minimum Payments, Due in Two Years	162
Pressure Pumping Contracts, Future Minimum Payments, Due in Three Years	59
Future Minimum Payments Due	$ 466

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CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
CURRENT ASSETS:
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$ 4,108	$ 837
Restricted cash	38	75
Accounts receivable, net	2,236	2,222
Short-term derivative assets ($16 and $0 attributable to our VIE)	879	0
Deferred income tax asset	0	223
Other current assets	207	299
Total Current Assets	7,468	3,656
Oil and natural gas properties, at cost based on full cost accounting:
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	58,594	56,157
Unproved properties	9,788	12,013
Oilfield services equipment	0	2,192
Other property and equipment	3,083	3,203
Total Property and Equipment, at Cost	71,465	73,565
Less: accumulated depreciation, depletion and amortization (($251) and ($168) attributable to our VIE)	(39,043)	(37,161)
Property and equipment held for sale, net	93	730
Total Property and Equipment, Net	32,515	37,134
LONG-TERM ASSETS:
Investments	265	477
Long-term derivative assets	6	4
Other long-term assets	497	511
TOTAL ASSETS	40,751	41,782
CURRENT LIABILITIES:
Accounts payable	2,049	1,596
Current maturities of long-term debt, net	381	0
Accrued interest	150	200
Deferred income tax liabilities	207	0
Short-term derivative liabilities ($0 and $5 attributable to our VIE)	15	208
Other current liabilities ($15 and $22 attributable to our VIE)	3,061	3,511
Total Current Liabilities	5,863	5,515
LONG-TERM LIABILITIES:
Long-term debt, net	11,154	12,886
Deferred income tax liabilities	4,185	3,407
Long-term derivative liabilities	218	445
Asset retirement obligations, net of current portion	447	405
Other long-term liabilities	679	984
Total Long-Term Liabilities	16,683	18,127
Chesapeake Stockholders’ Equity:
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 7,251,515 shares outstanding	3,062	3,062
Common stock, $0.01 par value, 1,000,000,000 shares authorized: 664,944,232 and 666,192,371 shares issued	7	7
Paid-in capital	12,531	12,446
Retained earnings	1,483	688
Accumulated other comprehensive loss	(143)	(162)
Less: treasury stock, at cost; 1,614,312 and 2,002,029 common shares	(37)	(46)
Total Chesapeake Stockholders’ Equity	16,903	15,995
Noncontrolling interests	1,302	2,145
Total Equity	18,205	18,140
TOTAL LIABILITIES AND EQUITY	$ 40,751	$ 41,782

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Derivative and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments Included in Trading Activities [Table Text Block]

The estimated fair values of our oil and natural gas derivative instrument assets (liabilities) as of December 31, 2014 and 2013 are provided below. 

	December 31, 2014				December 31, 2013
	Volume	Fair Value			Volume	Fair Value
		($ in millions)				($ in millions)
Oil (mmbbl):
Fixed-price swaps	12.5	471			25.3	(50		)
Three-way collars	4.4	40			—	—
Call options	35.8	(89		)	42.5	(265		)
Basis protection swaps	—	—			0.4	1
Total oil	52.7	422			68.2	(314		)
Natural gas (tbtu):
Fixed-price swaps	275	$	281		448	$	(23	)
Three-way collars	207	165			288	(7		)
Call options	193	(170		)	193	(210		)
Call swaptions	—	—			12	—
Basis protection swaps	60	23			68	3
Total natural gas	735	299			1,009	(237		)
Total estimated fair value		$	721			$	(551	)

Schedule Of Derivative Instruments In Condensed Consolidated Balance Sheets [Table Text Block]

The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2014 and 2013 on a gross basis and after same-counterparty netting: 

Balance Sheet Classification	Gross Fair Value			Amounts Netted in Consolidated Balance Sheet			Net Fair Value Presented in Consolidated Balance Sheet
	($ in millions)
As of December 31, 2014
Commodity Contracts
Short-term derivative asset	$	974		$	(95	)	$	879
Long-term derivative asset	16			(10		)	6
Short-term derivative liability	(105		)	95			(10		)
Long-term derivative liability	(163		)	10			(153		)
Total commodity contracts	722			—			722
Interest Rate Contracts
Short-term derivative liability	(5		)	—			(5		)
Long-term derivative liability	(12		)	—			(12		)
Total interest rate contracts	(17		)	—			(17		)
Foreign Currency Contracts(a)
Long-term derivative liability	(53		)	—			(53		)
Total foreign currency contracts	(53		)	—			(53		)
Total Derivatives	$	652		$	—		$	652
As of December 31, 2013
Commodity Contracts
Short-term derivative asset	$	29		$	(29	)	$	—
Long-term derivative asset	11			(9		)	2
Short-term derivative liability	(231		)	29			(202		)
Long-term derivative liability	(362		)	9			(353		)
Total commodity contracts	(553		)	—			(553		)
Interest Rate Contracts
Short-term derivative liability	(6		)	—			(6		)
Long-term derivative liability	(92		)	—			(92		)
Total interest rate contracts	(98		)	—			(98		)
Foreign Currency Contracts(a)
Long-term derivative asset	2			—			2
Total foreign currency contracts	2			—			2
Total Derivatives	$	(649	)	$	—		$	(649	)

____________________________________________

(a) Designated as cash flow hedging instruments.

Schedule of Derivative Instruments [Table Text Block]

The components of oil, natural gas and NGL sales for the years ended December 31, 2014, 2013 and 2012 are presented below. 

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Oil, natural gas and NGL sales	$	7,162		$	6,923		$	5,359
Gains on undesignated oil and natural gas derivatives	1,055			443			857
Gains (losses) on terminated cash flow hedges	(37		)	(314		)	62
Total oil, natural gas and NGL sales	$	8,180		$	7,052		$	6,278

Interest Income And Interest Expense Disclosure [Table Text Block]

The components of interest expense for the years ended December 31, 2014, 2013 and 2012 are presented below. 

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Interest expense on senior notes	$	704		$	740		$	732
Interest expense on term loans	36			116			173
Amortization of loan discount, issuance costs and other	42			91			89
Interest expense on credit facilities	28			38			70
Gains on terminated fair value hedges	(3		)	(5		)	(8		)
(Gains) losses on undesignated interest rate derivatives	(81		)	63			1
Capitalized interest	(637		)	(816		)	(980		)
Total interest expense	$	89		$	227		$	77

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

For the years ended December 31, 2014 and 2013, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below.

	Net Gains (Losses) on Cash Flow Hedges			Net Gains (Losses) on Investments			Total
	($ in millions)
Balance, December 31, 2013	$	(167	)	$	5		$	(162	)
Other comprehensive income before reclassifications	1			—			1
Amounts reclassified from accumulated other comprehensive income	23			(5		)	18
Net other comprehensive income	24			(5		)	19
Balance, December 31, 2014	$	(143	)	$	—		$	(143	)
Balance, December 31, 2012	$	(189	)	$	7		$	(182	)
Other comprehensive income before reclassifications	2			(6		)	(4		)
Amounts reclassified from accumulated other comprehensive income	20			4			24
Net other comprehensive income	22			(2		)	20
Balance, December 31, 2013	$	(167	)	$	5		$	(162	)

A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.

	Years Ended December 31,
	2014						2013						2012
	Before  Tax			After  Tax			Before  Tax			After  Tax			Before  Tax			After  Tax
	($ in millions)
Balance, beginning of period	$	(269	)	$	(167	)	$	(304	)	$	(189	)	$	(287	)	$	(178	)
Net change in fair value	1			1			3			2			10			6
Gains (losses) reclassified to income	37			23			32			20			(27		)	(17		)
Balance, end of period	$	(231	)	$	(143	)	$	(269	)	$	(167	)	$	(304	)	$	(189	)

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:

	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Fair Value
			($ in millions)
As of December 31, 2014
Derivative Assets (Liabilities):
Commodity assets	$	—	$	785		$	205		$	990
Commodity liabilities	—		(9		)	(259		)	(268		)
Interest rate liabilities	—		(17		)	—			(17		)
Foreign currency liabilities	—		(53		)	—			(53		)
Total derivatives	$	—	$	706		$	(54	)	$	652
As of December 31, 2013
Derivative Assets (Liabilities):
Commodity assets	$	—	$	25		$	15		$	40
Commodity liabilities	—		(100		)	(493		)	(593		)
Interest rate liabilities	—		(98		)	—			(98		)
Foreign currency assets	—		2			—			2
Total derivatives	$	—	$	(171	)	$	(478	)	$	(649	)

The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:

	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value
				($ in millions)
As of December 31, 2014
Financial Assets (Liabilities):
Other current assets	$	57		$	—	$	—	$	57
Other current liabilities	(58		)	—		—		(58		)
Total	$	(1	)	$	—	$	—	$	(1	)
As of December 31, 2013
Financial Assets (Liabilities):
Other current assets	$	80		$	—	$	—	$	80
Other current liabilities	(82		)	—		—		(82		)
Total	$	(2	)	$	—	$	—	$	(2	)

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2014 and 2013 is presented below.

	Derivatives
	Commodity			Interest Rate
	($ in millions)
Beginning Balance as of January 1, 2014	$	(478	)	$	—
Total gains (losses) (realized/unrealized):
Included in earnings(a)	292			—
Total purchases, issuances, sales and settlements:
Settlements	136			—
Transfers(b)	(4		)	—
Ending Balance as of December 31, 2014	$	(54	)	$	—
Beginning Balance as of January 1, 2013	$	(1,016	)	$	—
Total gains (losses) (realized/unrealized):
Included in earnings(a)	410			(1		)
Total purchases, issuances, sales and settlements:
Sales	—			1
Settlements	128			—
Ending Balance as of December 31, 2013	$	(478	)	$	—

___________________________________________

(a)	Oil, Natural Gas and NGL Sales				Interest Expense
	2014		2013		2014		2013
	($ in millions)
Total gains (losses) included in earnings for the period	$	292	$	410	$	—	$	(1	)
Change in unrealized gains (losses) related to assets still held at reporting date	$	262	$	382	$	—	$	—

(b) The values related to basis swaps were transferred from Level 3 to Level 2 as a result of our ability to begin using data readily available in the public market to corroborate our estimated fair values.

Fair Value Inputs, Assets, Quantitative Information [Table Text Block]

The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of December 31, 2014:

Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value December 31, 2014(a)
				($ in millions)
Oil trades	Oil price volatility curves	27.33% - 43.56%	34.09%	$	(49	)
Natural gas trades	Natural gas price volatility curves	18.71% - 63.70%	34.38%	$	(5	)

___________________________________________

(a) Fair value is based on an estimate derived from option models.

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Share-Based Compensation - Liability-Classified Compensation Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 104	$ 150	$ 191
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	46	60	71
Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	29	52	71
Operating Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	18	21	24
Cost of Sales [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	6	7	15
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	(1)	48	14
Performance Shares [Member] | General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	(4)	34	8
Performance Shares [Member] | Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	3	9	4
Performance Shares [Member] | Operating Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	0	2	1
Performance Shares [Member] | Cost of Sales [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	0	2	1
Performance Shares [Member] | Oilfield Services [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 0	$ 1	$ 0

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Investments - Schedule of Investments Table (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
Investments	$ 265	$ 477
FTS International, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	30.00%	30.00%
Investments	116	138
Sundrop Fuels Inc [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	56.00%	56.00%
Investments	130	135
Chaparral Energy, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	0.00%	20.00%
Investments	0	143
Other Investment Companies [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	0.00%	0.00%
Investments	$ 19	$ 61

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Unrealized gain on derivative instruments, net of income tax expense of $0, $1 and $4	$ 0	$ 1	$ 4
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $12 million, ($10) million and ($139) million	14	12	(10)
Unrealized loss on investments, net of income tax benefit of $0, ($4) and ($4)	0	(4)	(4)
Reclassification of (gain) loss on investment, net of income tax expense (benefit) of $3 million, $0 and $0	$ (3)	$ 3	$ 0

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Share-Based Compensation - Liability Classified Valuation Table (Details) (Performance Shares [Member])	12 Months Ended
	Dec. 31, 2014
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	41.37%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	0.76%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	1.36%

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Earnings Per Share Earnings Per Share - Reconciliation of Basic and Diluted EPS Table (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	$ 1,273	$ 474	$ (940)
Weighted Average Number of Shares Outstanding, Basic	659	653	643
Earnings Per Share, Basic	$ 1.93	$ 0.73	$ (1.46)
Net Income (Loss) Available to Common Stockholders, Diluted	1,444
Weighted Average Number of Shares Outstanding, Diluted	772	653	643
Earnings Per Share, Diluted	$ 1.87	$ 0.73	$ (1.46)
Convertible Debt Securities [Member] | 5.75% Cumulative Convertible Preferred Stock [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities	86
Weighted Average Number Diluted Shares Outstanding Adjustment	59
Convertible Debt Securities [Member] | 5.75% Cumulative Convertible Preferred Stock Series A [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities	63
Weighted Average Number Diluted Shares Outstanding Adjustment	42
Convertible Debt Securities [Member] | 5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities	10
Weighted Average Number Diluted Shares Outstanding Adjustment	6
Convertible Debt Securities [Member] | 4.50% Cumulative Convertible Preferred Stock [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities	$ 12
Weighted Average Number Diluted Shares Outstanding Adjustment	6

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Derivative and Hedging Activities - Derivative Instruments Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014 MMBbls	Dec. 31, 2013 MMBbls
Derivative [Line Items]
Fair Value	$ 721	$ (551)
Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	52,700,000	68,200,000
Fair Value	422	(314)
Crude Oil [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	12,500,000	25,300,000
Fair Value	471	(50)
Crude Oil [Member] | Three Way Collar [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	4,400,000	0
Fair Value	40	0
Crude Oil [Member] | Call Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	35,800,000	42,500,000
Fair Value	(89)	(265)
Crude Oil [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0	400,000
Fair Value	0	1
Natural Gas [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	735,000,000,000,000	1,009,000,000,000,000
Fair Value	299	(237)
Natural Gas [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	275,000,000,000,000	448,000,000,000,000
Fair Value	281	(23)
Natural Gas [Member] | Three Way Collar [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	207,000,000,000,000	288,000,000,000,000
Fair Value	165	(7)
Natural Gas [Member] | Call Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	193,000,000,000,000	193,000,000,000,000
Fair Value	(170)	(210)
Natural Gas [Member] | Swaption [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	0	12,000,000,000,000
Fair Value	0	0
Natural Gas [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	60,000,000,000,000	68,000,000,000,000
Fair Value	$ 23	$ 3

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Impairments (Policies)

12 Months Ended

Dec. 31, 2014

Asset Impairment Charges [Abstract]

Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]

Our oil and natural gas properties are subject to quarterly full cost ceiling tests.

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Condensed Consolidating Financial Information Condensed Consolidating Financial Information Narrative (Details)	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	50.00%
Senior Notes [Member]
Condensed Financial Statements, Captions [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	100.00%

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Debt - Revolving Credit Facility Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014 extension	Dec. 31, 2015
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 11,756,000,000
Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Borrowing capacity	4,000,000,000
Line of Credit Facility, Increase (Decrease), Net	1,000,000,000
Line of Credit Facility, Number of Expiration Period Options	2
Line of Credit Facility, Expiration Period Option	1 year
Long-term Debt, Gross	0
Commitment Period	5 years
Letters of Credit Outstanding, Amount	$ 15,000,000
Interest Rate In Addition To Federal Funds Rate	0.50%
Loans Receivable, Basis Spread on Variable Rate	1.00%
Debt Instrument, Covenant Description	4.0 to 1.0
Line of Credit Facility, Guarantee Event One	cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $125 million or more
Line of Credit Facility, Guarantee Event Two	bankruptcy; judgments involving liability of $125 million or more that are not paid
Line of Credit Facility, Guarantee Event Three	ERISA events
Revolving Credit Facility [Member] | Alternatiove Base Rate (ABR) [Member]
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End	0.625%
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End	1.625%
Revolving Credit Facility [Member] | Maximum [Member]
Long-Term Debt Instrument [Line Items]
Ratio of Indebtedness to Net Capital	65
Revolving Credit Facility [Member] | Scenario, Forecast [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument Maturity Date		Dec. 15, 2019
Revolving Credit Facility [Member] | Moody's, Ba3 Rating [Member] | Minimum [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Credit Rating	Ba3
Revolving Credit Facility [Member] | Standard & Poor's, BB- Rating [Member] | Minimum [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Credit Rating	BB-

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Spin-Off of Oilfield Services Business (Note)

12 Months Ended

Dec. 31, 2014

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

Spin-Off of Oilfield Services Business

On June 30, 2014, we completed the spin-off of our oilfield services business, which we previously conducted through our indirect, wholly owned subsidiary COO, into an independent, publicly traded company called SSE. Following the close of business on June 30, 2014, we distributed to Chesapeake shareholders one share of SSE common stock and cash in lieu of fractional shares for every 14 shares of Chesapeake common stock held on June 19, 2014, the record date for the distribution.

Prior to the completion of the spin-off, we and COO and its affiliates engaged in the following series of transactions:

• COO and certain of its subsidiaries entered into a $275 million senior secured revolving credit facility and a $400 million secured term loan, the proceeds of which were used to repay in full and terminate COO’s existing credit facility.

• COO distributed to us its compression unit manufacturing business, its geosteering business and the proceeds from the sale of substantially all of its crude oil hauling business. See Note 16 for further discussion of the sale.

• We transferred to a subsidiary of COO, at carrying value, certain of our buildings and land, most of which COO had been leasing from us prior to the spin-off.

• COO issued $500 million of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility and for general corporate purposes.

• COO converted from a limited liability company into a corporation named Seventy Seven Energy Inc.

• We distributed all of SSE’s outstanding shares to our shareholders, which resulted in SSE becoming an independent, publicly traded company.

Following the spin-off, we have no ownership interest in SSE. Therefore, we ceased to consolidate SSE’s assets and liabilities as of the spin-off date. Because we expect to have significant continued involvement associated with SSE’s future operations through the various agreements described below, our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations. For segment disclosures, we have labeled our oilfield services segment as “former oilfield services”. See Note 21 for additional information regarding our segments.

In connection with the spin-off, we entered into several agreements to define the terms and conditions of the spin-off and our ongoing relationship with SSE after the spin-off, including a master separation agreement, a tax sharing agreement, an employee matters agreement, a transition services agreement, a services agreement and certain commercial agreements. These agreements, among other things, allocate responsibility for obligations arising before and after the distribution date, including obligations relating to taxes, employees, various transition services and oilfield services.

• The master separation agreement sets forth the agreements between SSE and Chesapeake regarding the principal transactions that were necessary to effect the spin-off and also sets forth other agreements that govern certain aspects of SSE’s relationship with Chesapeake after completion of the spin-off.

• The tax sharing agreement governs the respective rights, responsibilities and obligations of SSE and Chesapeake with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings, and certain other matters regarding taxes.

• The employee matters agreement addresses employee compensation and benefit plans and programs, and other related matters in connection with the spin-off, including the treatment of holders of Chesapeake common stock options, restricted stock and performance share units, and the cooperation between SSE and Chesapeake in the sharing of employee information and maintenance of confidentiality. See Note 9 for additional information regarding the effect of the spin-off on outstanding equity compensation.

• The transition services agreement sets forth the terms on which we provide SSE certain services. Transition services include marketing and corporate communication, human resources, information technology, security, legal, risk management, tax, environmental health and safety, maintenance, internal audit, accounting, treasury and certain other services specified in the agreement. SSE pays Chesapeake a negotiated fee for providing those services.

• The services agreement requires us to utilize, at market-based pricing, certain SSE pressure pumping services. See Note 4 for a summary of the terms of the services agreement.

• We have also entered into drilling agreements that are rig-specific daywork drilling contracts with terms ranging from three months to three years and at market-based rates. We have the right to terminate a drilling agreement in certain circumstances. As of December 31, 2014, the aggregate undiscounted minimum future payments under these drilling agreements were approximately $410 million.

In 2014, our stockholders’ equity decreased by $270 million, net of $151 million of associated deferred tax liabilities, as the result of the spin-off, and we recognized $15 million of charges associated with the spin-off that are included in restructuring and other termination costs on our consolidated statement of operations. See Note 18 for further details regarding these charges.

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Basis of Presentation and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]

Accounts receivable as of December 31, 2014 and 2013 are detailed below.

	December 31,
	2014			2013
	($ in millions)
Oil, natural gas and NGL sales	$	1,340		$	1,548
Joint interest	691			417
Oilfield services(a)	—			63
Related parties(b)	—			62
Other	226			150
Allowance for doubtful accounts	(21		)	(18		)
Total accounts receivable, net	$	2,236		$	2,222

___________________________________________

(a) In 2014, in connection with the spin-off of our oilfield services business, accounts receivable related to oilfield services were removed from our consolidated balance sheet.

(b) See Note 7 for discussion of related party transactions.

Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization [Table Text Block]

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2014 and the year in which the associated costs were incurred.

	Year of Acquisition
	2014		2013		2012		Prior		Total
	($ in millions)
Leasehold acquisition cost	$	577	$	199	$	1,462	$	5,149	$	7,387
Exploration cost	340		90		244		42		716
Capitalized interest	492		421		325		447		1,685
Total	$	1,409	$	710	$	2,031	$	5,638	$	9,788

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Employee Benefit Plans Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	15.00%
Defined Benefit Plan, Contributions by Employer	$ 61,000,000	$ 81,000,000	$ 91,000,000
Defined Benefit Plans, General Information	55
Defined Benefit Pension Plan, Liabilities	3,000,000
Deferred Compensation, Excluding Share-based Payments and Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	75.00%
Deferred Bonus [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	100.00%
Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Annual Compensation Received	150,000
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, General Information	10%
DC Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	15.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	100.00%
Deferred Compensation Arrangement with Individual, Employer Contribution	$ 7,000,000	$ 14,000,000	$ 16,000,000
Director DC Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	100.00%

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Restructuring and Other Termination Benefits - Narrative (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended	12 Months Ended
	Dec. 30, 2012 Employee	Feb. 28, 2013 Employee	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Restructuring and other termination costs			$ 7	$ 248	$ 7
Restructuring and Related Cost, Number of Positions Eliminated				900
Severance Costs				50
Former CEO [Member]
Defined Benefit Plan Disclosure [Line Items]
Restructuring and other termination costs			(8)	69	0
Severance Costs				69
Workforce Reduction Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Restructuring and other termination costs			0	66	0
Restructuring and Related Cost, Incurred Cost				66
VSP Program [Member]
Defined Benefit Plan Disclosure [Line Items]
Restructuring and other termination costs			0	63	2
Restructuring and Related Cost, Number of Positions Eliminated	275	211
Severance Costs				63
Seven Seven Energy Inc. [Member] | Spinoff [Member]
Defined Benefit Plan Disclosure [Line Items]
Restructuring and other termination costs			$ 15	$ 0	$ 0

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Variable Interest Entities (Note)

12 Months Ended

Dec. 31, 2014

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

Variable Interest Entities Disclosure [Text Block]

Variable Interest Entities

We consolidate the activities of VIEs for which we are the primary beneficiary. In order to determine whether we own a variable interest in a VIE, we perform qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.

Consolidated VIE

Chesapeake Granite Wash Trust. For a discussion of the formation, operations and presentation of the Trust, see Noncontrolling Interests in Note 8. The Trust is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Trust. Our ownership in the Trust and our obligations under the development agreement and related drilling support lien constitute variable interests. We have determined that we are the primary beneficiary of the Trust because (i) we have the power to direct the activities that most significantly impact the economic performance of the Trust via our obligations to perform under the development agreement, and (ii) as a result of the subordination and incentive thresholds applicable to the subordinated units we hold in the Trust, we have the obligation to absorb losses and the right to receive residual returns that could potentially be significant to the Trust. As a result, we consolidate the Trust in our financial statements, and the common units of the Trust owned by third parties are reflected as a noncontrolling interest.

The Trust is a consolidated entity whose legal existence is separate from Chesapeake and our other consolidated subsidiaries, and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake; however, we have certain obligations to the Trust through the development agreement that are secured by a drilling support lien on our retained interest in the development wells up to a specified maximum amount recoverable by the Trust, which could result in the Trust acquiring all or a portion of our retained interest in the undeveloped portion of an area of mutual interest, if we do not meet our drilling commitment. In consolidation, as of December 31, 2014, $1 million of cash and cash equivalents, $16 million of short-term derivative assets, $488 million of proved oil and natural gas properties, $251 million of accumulated depreciation, depletion and amortization and $15 million of other current liabilities were attributable to the Trust. We have presented parenthetically on the face of the consolidated balance sheets the assets of the Trust that can be used only to settle obligations of the Trust and the liabilities of the Trust for which creditors do not have recourse to the general credit of Chesapeake.

Unconsolidated VIE

Mineral Acquisition Company I, L.P. In 2012, MAC-LP, L.L.C., a wholly owned non-guarantor unrestricted subsidiary of Chesapeake, entered into a partnership agreement with KKR Royalty Aggregator LLC (KKR) to form Mineral Acquisition Company I, L.P. The purpose of the partnership is to acquire mineral interests, or royalty interests carved out of mineral interests, in oil and natural gas basins in the continental United States. We are committed to acquire for our own account (outside the partnership) 10% of any acquisition agreed upon by the partnership up to a maximum of $25 million, and the partnership will acquire the remaining 90% up to a maximum of $225 million, funded entirely by KKR, making KKR the sole equity investor. We have significant influence over the decisions made by the partnership, as we hold two of five seats on the board of directors. We will receive proportionate distributions from the partnership of any cash received from royalties in excess of expenses paid, ranging from 7% to 22.5%. The partnership is considered a VIE because KKR’s control over the partnership is disproportionate to its economic interest. This VIE remains unconsolidated as the power to direct the activities of the partnership is shared between the Company and KKR. We are using the equity method to account for this investment. The carrying value of our investment was $9 million as of December 31, 2014.

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Contingencies - Narrative (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Loss Contingencies [Line Items]
Provision for legal contingencies	$ 234	$ 0	$ 0
Redemption of 2019 Notes [Member]
Loss Contingencies [Line Items]
Provision for legal contingencies	100
Redemption of 2019 Notes [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Provision for legal contingencies	100
Redemption of 2019 Notes [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Provision for legal contingencies	380
Settled Litigation [Member]
Loss Contingencies [Line Items]
Provision for legal contingencies	$ 119
Senior Notes [Member] | 6.775% Senior Notes Due 2019 [Member]
Loss Contingencies [Line Items]
Prejudgment Interest Statutory Rate	9.00%

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Natural Gas and Oil Property Transactions - VPP Transactions Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended	3 Months Ended
	Dec. 31, 2014 Mcfe	Mar. 31, 2012 Mcfe	Jun. 30, 2011	Sep. 30, 2010 Mcfe	Dec. 31, 2008 Mcfe	Sep. 30, 2008	Jun. 30, 2008	Dec. 31, 2007 Mcfe	May 31, 2011 Mcfe	Aug. 31, 2008 Mcfe	May 31, 2008 Mcfe
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)	$ 5,481
Proved Developed Reserves (Energy)	1,220,000,000,000
Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)	5,200,000
Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)	1,105,000,000,000
NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)	14,000,000
VPP 10 Aradarko Basin Granite Wash [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)		744
Proved Developed Reserves (Energy)		160,000,000,000
VPP 10 Aradarko Basin Granite Wash [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)		3,000,000
VPP 10 Aradarko Basin Granite Wash [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)		87,000,000,000
VPP 10 Aradarko Basin Granite Wash [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)		9,200,000
VPP 9 Mid-Continent [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)			853
Proved Developed Reserves (Energy)									177,000,000,000
VPP 9 Mid-Continent [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)									1,700,000
VPP 9 Mid-Continent [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)									138,000,000,000
VPP 9 Mid-Continent [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)									4,800,000
VPP 8 Barnett Shale [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)				1,150
Proved Developed Reserves (Energy)				390,000,000,000
VPP 8 Barnett Shale [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)				0
VPP 8 Barnett Shale [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)				390,000,000,000
VPP 8 Barnett Shale [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)				0
VPP 4 Anadarko and Arkoma Basins [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)					412
Proved Developed Reserves (Energy)					98,000,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)					500,000
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)					95,000,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)					0
VPP 3 Anadarko Basin [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)						600
Proved Developed Reserves (Energy)										93,000,000,000
VPP 3 Anadarko Basin [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)										0
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)										93,000,000,000
VPP 3 Anadarko Basin [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)										0
VPP 2 Texas, Oklahoma and Kansas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)							622
Proved Developed Reserves (Energy)											94,000,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)											0
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)											94,000,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)											0
VPP 1 Kentucky and West Virginia [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)								$ 1,100
Proved Developed Reserves (Energy)								208,000,000,000
VPP 1 Kentucky and West Virginia [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)								0
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)								208,000,000,000
VPP 1 Kentucky and West Virginia [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)								0

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$ 2,056	$ 894	$ (594)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	2,915	2,903	2,811
Deferred income tax expense (benefit)	1,097	526	(427)
Derivative gains, net	(1,102)	(71)	(926)
Cash (payments) receipts on derivative settlements, net	(253)	(104)	226
Stock-based compensation	59	98	120
Impairment of oil and natural gas properties	0	0	3,315
Net gains on sales of fixed assets	(199)	(302)	(267)
Impairment of fixed assets and other	58	483	316
Losses on investments	80	229	164
Net (gains) losses on sales of investments	(67)	7	(1,092)
Restructuring and other termination costs	(15)	175	2
Provision for legal contingencies	234	0	0
Losses on purchases of debt	63	40	200
Other	100	80	72
(Increase) decrease in accounts receivable and other assets	(21)	5	(68)
Decrease in accounts payable, accrued liabilities and other	(371)	(349)	(1,015)
Net Cash Provided By Operating Activities	4,634	4,614	2,837
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(4,581)	(5,604)	(8,930)
Acquisitions of proved and unproved properties	(1,311)	(1,032)	(3,161)
Proceeds from divestitures of proved and unproved properties	5,813	3,467	5,884
Additions to other property and equipment	(726)	(972)	(2,651)
Proceeds from sales of other property and equipment	1,003	922	2,492
Additions to investments	(17)	(44)	(395)
Proceeds from sales of investments	239	115	2,000
Decrease (increase) in restricted cash	37	177	(222)
Other	(3)	4	(1)
Net Cash Provided By (Used In) Investing Activities	454	(2,967)	(4,984)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	7,406	7,669	20,318
Payments on credit facilities borrowings	(7,788)	(7,682)	(21,650)
Proceeds from issuance of senior notes, net of discount and offering costs	3,460
Proceeds from issuance of oilfield services senior notes, net of discount and offering costs	3,460
Proceeds from issuance of term loan, net of issuance costs	394
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	394
Cash paid to purchase debt	(3,362)	(2,141)	(4,000)
Cash paid for common stock dividends	(234)	(233)	(227)
Cash paid for preferred stock dividends	(171)	(171)	(171)
Cash paid to extinguish other financing	0	(141)	0
Cash paid on financing derivatives	(53)	(91)	(37)
Cash paid for prepayment of mortgage	0	(55)	0
Proceeds from sales of noncontrolling interests	0	6	1,077
Proceeds from other financings	0	0	257
Cash paid to purchase preferred shares of a subsidiary	(1,254)	(212)	0
Cash held and retained by SSE at spin-off	(8)	0	0
Distributions to noncontrolling interest owners	(173)	(215)	(218)
Other	(34)	(105)	(251)
Net Cash Provided By (Used In) Financing Activities	(1,817)	(1,097)	2,083
Net increase (decrease) in cash and cash equivalents	3,271	550	(64)
Cash and cash equivalents, beginning of period	837	287	351
Cash and cash equivalents, end of period	4,108	837	287
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest	96	43	0
Income taxes paid, net of refunds received	10	26	44
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in accrued drilling and completion costs	(84)	(63)	(75)
Change in accrued acquisitions of proved and unproved properties	(74)	(1)	242
Change in accrued additions to other property and equipment	(11)	(81)	(25)
Chesapeake Energy [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of senior notes, net of discount and offering costs	2,966	2,274	1,263
Proceeds from issuance of oilfield services senior notes, net of discount and offering costs	2,966	2,274	1,263
Proceeds from issuance of term loan, net of issuance costs			5,722
Proceeds from issuance of oilfield services term loan, net of discount and offering costs			5,722
Chesapeake Oilfield Operating [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of senior notes, net of discount and offering costs	494	0	0
Proceeds from issuance of oilfield services senior notes, net of discount and offering costs	494	0	0
Proceeds from issuance of term loan, net of issuance costs	394	0	0
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	$ 394	$ 0	$ 0

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Preferred stock, par value (usd per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (shares)	20,000,000	20,000,000
Preferred stock, shares outstanding (shares)	7,251,515	7,251,515
Common stock, par value (usd per share)	$ 0.01	$ 0.01
Common Stock, Shares Authorized	1,000,000,000	1,000,000,000
Common Stock, Shares, Issued	664,944,232	666,192,371
Treasury stock, shares	1,614,312	2,002,029
Cash and cash equivalents	$ 4,108	$ 837
Short-term derivative assets ($16 and $0 attributable to our VIE)	879	0
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	58,594	56,157
Less: accumulated depreciation, depletion and amortization (($251) and ($168) attributable to our VIE)	(39,043)	(37,161)
Short-term derivative liabilities ($0 and $5 attributable to our VIE)	15	208
Other current liabilities ($15 and $22 attributable to our VIE)	3,061	3,511
Variable Interest Entities, Primary Beneficiary [Member]
Cash and cash equivalents	1	1
Short-term derivative assets ($16 and $0 attributable to our VIE)	16	0
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	488	488
Less: accumulated depreciation, depletion and amortization (($251) and ($168) attributable to our VIE)	(251)	(168)
Short-term derivative liabilities ($0 and $5 attributable to our VIE)	0	5
Other current liabilities ($15 and $22 attributable to our VIE)	$ 15	$ 22

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Equity (Note)

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Stockholders' Equity Note Disclosure [Text Block]

Equity

Common Stock

The following is a summary of the changes in our common shares issued for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014		2013		2012
	(in thousands)
Shares issued as of January 1	666,192		666,468		660,888
Restricted stock issuances (net of forfeitures and cancellations)(a)	(2,529	)	(599	)	5,038
Stock option exercises	1,281		323		542
Shares issued as of December 31	664,944		666,192		666,468

___________________________________________

(a) In the second quarter of 2013, we began granting restricted stock units (RSUs) in lieu of restricted stock awards (RSAs) to non-employee directors and employees. Shares of common stock underlying RSUs are issued when the units vest, whereas shares of common stock are issued on the date the RSAs are granted. We refer to RSAs and RSUs collectively as restricted stock.

Preferred Stock

Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2014:

Preferred Stock Series	Issue Date	Liquidation Preference per Share		Holder's Conversion Right	Conversion Rate	Conversion Price		Company's Conversion Right From	Company's Market Conversion Trigger(a)
5.75% cumulative convertible non-voting	May and June 2010	$	1,000	Any time	39.5856	$	25.2617	May 17, 2015	$	32.8402
5.75% (series A) cumulative convertible non-voting	May 2010	$	1,000	Any time	38.2538	$	26.1412	May 17, 2015	$	33.9836
4.50% cumulative convertible	September 2005	$	100	Any time	2.4468	$	40.8693	September 15, 2010	$	53.1301
5.00% cumulative convertible (series 2005B)	November 2005	$	100	Any time	2.7669	$	36.1415	November 15, 2010	$	46.9840

___________________________________________

(a) Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding.

The following reflects the shares outstanding of our preferred stock for the years ended December 31, 2014, 2013 and 2012:

	5.75%	5.75% (A)	4.50%	5.00% (2005B)
	(in thousands)
Shares outstanding as of January 1, 2014, 2013 and 2012 and shares outstanding as of December 31, 2014, 2013 and 2012	1,497	1,100	2,559	2,096

Dividends

Dividends declared on our common stock and preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings exists after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, payments constitute a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital.

Dividends on our outstanding preferred stock are payable quarterly. We may pay dividends on our 5.00% Cumulative Convertible Preferred Stock (Series 2005B) and our 4.50% Cumulative Convertible Preferred Stock in cash, common stock or a combination thereof, at our option. Dividends on both series of our 5.75% Cumulative Convertible Non-Voting Preferred Stock are payable only in cash.

Accumulated Other Comprehensive Income (Loss)

For the years ended December 31, 2014 and 2013, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below.

	Net Gains (Losses) on Cash Flow Hedges			Net Gains (Losses) on Investments			Total
	($ in millions)
Balance, December 31, 2013	$	(167	)	$	5		$	(162	)
Other comprehensive income before reclassifications	1			—			1
Amounts reclassified from accumulated other comprehensive income	23			(5		)	18
Net other comprehensive income	24			(5		)	19
Balance, December 31, 2014	$	(143	)	$	—		$	(143	)
Balance, December 31, 2012	$	(189	)	$	7		$	(182	)
Other comprehensive income before reclassifications	2			(6		)	(4		)
Amounts reclassified from accumulated other comprehensive income	20			4			24
Net other comprehensive income	22			(2		)	20
Balance, December 31, 2013	$	(167	)	$	5		$	(162	)

For the years ended December 31, 2014 and 2013, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the consolidated statements of operations are detailed below.

Details About Accumulated Other Comprehensive Income (Loss) Components	Affected Line Item in the Statement Where Net Income is Presented	Year Ended December 31, 2014
		($ in millions)
Year Ended December 31, 2014:
Net losses on cash flow hedges:
Commodity contracts	Oil, natural gas and NGL revenues	$	23
Investments:
Sale of investment	Net gain on sale of investment	(5		)
Total reclassifications for the period, net of tax		$	18
Year Ended December 31, 2013:
Net losses on cash flow hedges:
Commodity contracts	Oil, natural gas and NGL revenues	$	20
Investments:
Impairment of investment	Losses on investments	6
Sale of investment	Net gain on sale of investment	(2		)
Total reclassifications for the period, net of tax		$	24

Noncontrolling Interests

Cleveland Tonkawa Financial Transaction. We formed CHK Cleveland Tonkawa, L.L.C. (CHK C-T) in March 2012 to continue development of a portion of our oil and natural gas assets in our Cleveland and Tonkawa plays. CHK C-T is an unrestricted subsidiary under our revolving credit facility agreement and is not a guarantor of, or otherwise liable for, any of our indebtedness or other liabilities, including indebtedness under our indentures. In exchange for all of the common shares of CHK C-T, we contributed to CHK C-T approximately 245,000 net acres of leasehold and the existing wells within an area of mutual interest in the plays between the top of the Tonkawa and the top of the Big Lime formations covering Ellis and Roger Mills counties in western Oklahoma. In March 2012, in a private placement, third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in the existing wells and up to 1,000 future net wells to be drilled on the contributed play leasehold. Subject to customary minority interest protections afforded the investors by the terms of the CHK C-T limited liability company agreement (the CHK C-T LLC Agreement), as the holder of all the common shares and the sole managing member of CHK C-T, we maintain voting and managerial control of CHK C-T and therefore include it in our consolidated financial statements. Of the $1.25 billion of investment proceeds, we allocated $225 million to the ORRI obligation and $1.025 billion to the preferred shares based on estimates of fair values. The remaining ORRI obligation is included in other current and long-term liabilities and the preferred shares are included in noncontrolling interests on our consolidated balance sheets. Pursuant to the CHK C-T LLC Agreement, CHK C-T is required to retain an amount of cash equal to the next two quarters of preferred dividend payments. The amount reserved, approximately $38 million as of December 31, 2014 and 2013, was reflected as restricted cash on our consolidated balance sheets.

Dividends on the preferred shares are payable on a quarterly basis at a rate of 6% per annum based on $1,000 per share. This dividend rate is subject to increase in limited circumstances in the event that, and only for so long as, any dividend amount is not paid in full for any quarter. As the managing member of CHK C-T, we may, at our sole discretion and election at any time after March 31, 2014, distribute certain excess cash of CHK C-T, as determined in accordance with the CHK C-T LLC Agreement and the development agreement, as amended. The optional distribution of excess cash is allocated 75% to the preferred shares (which is applied toward redemption of the preferred shares) and 25% to the common shares; provided, however, that in certain circumstances, as set forth in the CHK C-T L.L.C. Agreement and the development agreement, as amended, the optional distribution would be allocated 100% to the preferred shares (and applied toward redemption thereof). We may also, at our sole discretion and election, in accordance with the CHK C-T LLC Agreement, cause CHK C-T to redeem all or a portion of the CHK C-T preferred shares for cash. The preferred shares may be redeemed at a valuation equal to the greater of a 9% internal rate of return or a return on investment of 1.35x, in each case inclusive of dividends paid through redemption at the rate of 6% per annum and optional distributions made through the applicable redemption date. In the event that redemption does not occur on or prior to March 31, 2019, the optional redemption valuation will increase to provide a 15% internal rate of return to the investors. The preferred shares can be redeemed on a pro-rata basis in accordance with the then-applicable redemption valuation formula. As of December 31, 2014 and 2013, the redemption price and the liquidation preference were approximately $1,185 and $1,245, respectively, per preferred share.

We initially committed to drill and complete, for the benefit of CHK C-T in the area of mutual interest, a minimum of 37.5 net wells per six-month period through 2013, inclusive of wells drilled in 2012, and 25 net wells per six-month period in 2014 through 2016, up to a minimum cumulative total of 300 net wells. In April 2014, the drilling commitment was amended to require us to drill and complete a minimum cumulative total of (i) 162.5 net wells by June 30, 2014 and (ii) 175 net wells by December 31, 2014. In January 2015, the drilling commitment was suspended. We are not required or allowed to drill any wells with respect to the CHK C-T properties unless we receive written notice from the owners of a majority of the preferred shares electing to lift the drilling prohibition. If we receive written notice at least 45 days prior to June 30, 2015, we will be required to drill and complete a minimum cumulative total of 225 net wells by June 30, 2016, and thereafter the minimum cumulative total will be increased by 25 net wells in each of the subsequent six-month periods ending December 31, 2017. If notice is not received by that time, future drilling commitment dates will be extended, as provided in the January 2015 amendment to the drilling commitment. If we fail to meet the then-current cumulative drilling commitment in any six-month period, any optional cash distributions will be distributed 100% to the investors. If we fail to meet the then-current cumulative drilling commitment in two consecutive six-month periods, the then-applicable internal rate of return to investors at redemption will increase by 3% per annum. In addition, if we fail to meet the then-current cumulative drilling commitment in four consecutive six-month periods, the then-applicable internal rate of return to investors at redemption will be increased by an additional 3% per annum. Any increase in the internal rate of return would be effective only until the end of the first succeeding six-month period in which we have met our then-current cumulative drilling commitment. CHK C-T is responsible for all capital and operating costs of the wells drilled for the benefit of the entity. Under the development agreement, approximately 17, 77 and 84 qualified net wells were added in 2014, 2013 and 2012, respectively. Through December 31, 2014, we had met all current drilling commitments associated with the CHK C-T transaction.

The CHK C-T investors’ right to receive, proportionately, a 3.75% ORRI in the contributed wells and up to 1,000 future net wells on our contributed leasehold is subject to an increase to 5% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation, which runs from 2012 through the first quarter of 2025. However, in no event are we required to deliver to investors more than a total ORRI of 3.75% in existing wells and 1,000 future net wells. If at any time CHK C-T holds fewer net acres than would enable us to drill all then-remaining net wells on 160-acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs. CHK C-T retains the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs once we have drilled a minimum of 867 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our oil and natural gas properties. We had met our ORRI conveyance commitment as of December 31, 2013, but we did not meet the 2014 ORRI conveyance commitment as of December 31, 2014.

As of December 31, 2014 and 2013, $1.015 billion of noncontrolling interests on our consolidated balance sheets were attributable to CHK C-T. For 2014, 2013 and 2012, income of $75 million, $75 million and $57 million, respectively, was attributable to the noncontrolling interests of CHK C-T.

Utica Financial Transaction. We formed CHK Utica, L.L.C. (CHK Utica) in October 2011 to develop a portion of our Utica Shale oil and natural gas assets. In exchange for all of the common shares of CHK Utica, we contributed to CHK Utica approximately 700,000 net acres of leasehold and the existing wells within an area of mutual interest in the Utica Shale play covering 13 counties located primarily in eastern Ohio. During November and December 2011, in private placements, third-party investors contributed $1.25 billion in cash to CHK Utica in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3% ORRI in 1,500 net wells to be drilled on certain of our Utica Shale leasehold.

In 2014, we repurchased all of the outstanding preferred shares of CHK Utica from third-party preferred shareholders for approximately $1.254 billion, or approximately $1,189 per share including accrued dividends. The $447 million difference between the cash paid for the preferred shares and the carrying value of the noncontrolling interest acquired is reflected in retained earnings and as a reduction to net income available to common stockholders for purposes of our EPS computations. Pursuant to the transaction, our obligation to pay quarterly dividends to third-party preferred shareholders was eliminated. In addition, the development agreement was terminated pursuant to the transaction, which eliminated our obligation to drill and complete a minimum number of wells within a specified period for the benefit of CHK Utica. Our repurchase of the outstanding preferred shares in CHK Utica did not affect our obligation to deliver a 3% ORRI in 1,500 net wells on certain Utica Shale leasehold.

The CHK Utica investors’ right to receive, proportionately, a 3% ORRI in the first 1,500 net wells drilled on our Utica Shale leasehold is subject to an increase to 4% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation, which runs from 2012 through 2023. However, in no event are we required to deliver to investors more than a total ORRI of 3% in 1,500 net wells. If at any time we hold fewer net acres than would enable us to drill all then-remaining net wells on 150-acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs. We retain the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs once we have drilled a minimum of 1,300 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the future conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our oil and natural gas properties. Because we did not meet our ORRI commitment in 2012, the ORRI increased to 4% for wells earned in 2013, and the ultimate number of wells in which we must assign an interest will be reduced accordingly. We met the 2013 ORRI conveyance commitment as of December 31, 2013 and met the 2014 ORRI conveyance commitment as of December 31, 2014 associated with the CHK Utica transaction.

As of December 31, 2014 and 2013, $0 and $807 million, respectively, of noncontrolling interests on our consolidated balance sheets were attributable to CHK Utica. In 2014, 2013 and 2012, income of approximately $43 million, $79 million and $88 million, respectively, was attributable to the noncontrolling interests of CHK Utica.

Chesapeake Granite Wash Trust. In November 2011, Chesapeake Granite Wash Trust (the Trust) sold 23,000,000 common units representing beneficial interests in the Trust at a price of $19.00 per common unit in its initial public offering. The common units are listed on the New York Stock Exchange and trade under the symbol “CHKR”. We own 12,062,500 common units and 11,687,500 subordinated units, which in the aggregate represent an approximate 51% beneficial interest in the Trust. The Trust has a total of 46,750,000 units outstanding.

In connection with the initial public offering of the Trust, we conveyed royalty interests to the Trust that entitle the Trust to receive (i) 90% of the proceeds (after deducting certain post-production expenses and any applicable taxes) that we receive from the production of hydrocarbons from 69 producing wells, and (ii) 50% of the proceeds (after deducting certain post-production expenses and any applicable taxes) in 118 development wells that have been or will be drilled on approximately 45,400 gross acres (29,000 net acres) in the Colony Granite Wash play in Washita County in the Anadarko Basin of western Oklahoma. Pursuant to the terms of a development agreement with the Trust, we are obligated to drill, or cause to be drilled, the development wells at our own expense prior to June 30, 2016, and the Trust is not responsible for any costs related to the drilling of the development wells or any other operating or capital costs of the Trust properties. In addition, we granted to the Trust a lien on our remaining interests in the undeveloped properties that are subject to the development agreement in order to secure our drilling obligation to the Trust, although the maximum amount that may be recovered by the Trust under the lien cannot exceed $263 million initially and will be proportionately reduced as we fulfill our drilling obligation over time. As of December 31, 2014 and 2013, we had drilled or caused to be drilled approximately 102 and 82 development wells, respectively, as calculated under the development agreement, and the maximum amount recoverable under the drilling support lien was approximately $36 million and $79 million, respectively.

The subordinated units we hold in the Trust are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is not less than the applicable subordination threshold for the quarter. If there is not sufficient cash to fund a distribution on all of the Trust units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for the quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. The distribution made with respect to the subordinated units to Chesapeake was either reduced or eliminated for each of the most recent ten quarters of distributions paid. In exchange for agreeing to subordinate a portion of our Trust units, and in order to provide additional financial incentive to us to satisfy our drilling obligation and perform operations on the underlying properties in an efficient and cost-effective manner, Chesapeake is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on the Trust units in any quarter exceeds the applicable incentive threshold for the quarter. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold will be paid to Trust unitholders, including Chesapeake, on a pro rata basis. Through December 31, 2014, no incentive distributions had been made. At the end of the fourth full calendar quarter following our satisfaction of our drilling obligation with respect to the development wells, the subordinated units will automatically convert into common units on a one-for-one basis and our right to receive incentive distributions will terminate. After such time, the common units will no longer have the protection of the subordination threshold, and all Trust unitholders will share in the Trust’s distributions on a pro rata basis.

For the years ended December 31, 2014, 2013 and 2012, the Trust declared and paid the following distributions:

Production Period	Distribution Date	Cash Distribution per Common Unit		Cash Distribution per Subordinated Unit
June 2014 - August 2014	December 1, 2014	$	0.5079	$	—
March 2014 - May 2014	August 29, 2014	$	0.5796	$	—
December 2013 - February 2014	May 30, 2014	$	0.6454	$	—
September 2013 - November 2013	March 3, 2014	$	0.6624	$	—
June 2013 - August 2013	November 29, 2013	$	0.6671	$	—
March 2013 - May 2013	August 29, 2013	$	0.6900	$	0.1432
December 2012 - February 2013	May 31, 2013	$	0.6900	$	0.3010
September 2012 - November 2012	March 1, 2013	$	0.6700	$	0.3772
June 2012 - August 2012	November 29, 2012	$	0.6300	$	0.2208
March 2012 - May 2012	August 30, 2012	$	0.6100	$	0.4819
December 2011 - February 2012	May 31, 2012	$	0.6588	$	0.6588
September 2011 - November 2011	March 1, 2012	$	0.7277	$	0.7277

We have determined that the Trust is a variable interest entity (VIE) and that Chesapeake is the primary beneficiary. As a result, the Trust is included in our consolidated financial statements. As of December 31, 2014 and 2013, $287 million and $314 million, respectively, of noncontrolling interests on our consolidated balance sheets were attributable to the Trust. In 2014, 2013 and 2012, income of approximately $24 million, $20 million and $35 million, respectively, was attributable to the Trust’s noncontrolling interests in our consolidated statements of operations. See Note 15 for further discussion of VIEs.

Wireless Seismic, Inc. As of December 31, 2014, we no longer consolidated Wireless Seismic, Inc. (Wireless), a privately owned company engaged in research, development and production of wireless seismic systems and related technology that delivers seismic information obtained from standard geophones in real time to personal computers. Because we no longer have a controlling equity interest in Wireless, our interest is included in investments in our consolidated balance sheet and within other in the table in Note 14.

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Derivative and Hedging Activities - Cash Flow Hedges Components of AOCI Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Effect of Derivative Instruments AOCI Reconcile [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	$ (143)	$ (162)
Accumulated Other Comprehensive Income (Loss) [Member]
Effect of Derivative Instruments AOCI Reconcile [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(143)	(162)	(182)
Cash Flow Hedging [Member] | Accumulated Other Comprehensive Income (Loss) [Member]
Effect of Derivative Instruments AOCI Reconcile [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Before Tax, Period Start	(269)	(304)	(287)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	(167)	(189)	(178)
Other Comprehensive Income (Loss), Before Reclassifications, Before Tax	1	3	10
Other Comprehensive Income (Loss), Before Reclassifications, Net of Tax	1	2	6
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	37	32
Derivative Instruments, Loss Reclassified from Accumulated OCI into Income, Effective Portion, Before Tax			27
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	23	20	(17)
Accumulated Other Comprehensive Income (Loss), Before Tax, Period End	(231)	(269)	(304)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	$ (143)	$ (167)	$ (189)

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Share-Based Compensation - Equity-Classified Compensation Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 104	$ 150	$ 191
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	46	60	71
Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	29	52	71
Operating Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	18	21	24
Cost of Sales [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	6	7	15
Other Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 5	$ 10	$ 10

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Share-Based Compensation - Equity-Classified Valuation Table (Details) (Employee Stock Option [Member])	12 Months Ended
	Dec. 31, 2014
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	5 years 10 months 20 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	48.63%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.93%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	1.33%

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Restructuring and Other Termination Benefits - Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Cash paid to purchase debt	$ 3,362	$ 2,141	$ 4,000
Severance Costs		50
Restructuring and other termination costs	7	248	7
Other, Including PSU's [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Restructuring and other termination costs	0	50	5
Seven Seven Energy Inc. [Member] | Spinoff [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Business Exit Costs	17	0	0
Adjustments to Additional Paid in Capital, Share-based Compensation and Exercise of Stock Options	5	0	0
Stock Granted, Value, Share-Based Compensation, Forfeited	(10)	0	0
Cash paid to purchase debt	3	0	0
Restructuring and other termination costs	15	0	0
Workforce Reduction Plan [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Restructuring and Related Cost, Incurred Cost		66
Restructuring and other termination costs	0	66	0
Workforce Reduction Plan [Member] | Other Costs Associated with Retirement [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Restructuring and Related Cost, Incurred Cost	0	1	0
Workforce Reduction Plan [Member] | Salary Expense [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Restructuring and Related Cost, Incurred Cost	0	20	0
Workforce Reduction Plan [Member] | Acceleration of Stock-Based Compensation Awards [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Restructuring and Related Cost, Incurred Cost	0	45	0
VSP Program [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs		63
Restructuring and other termination costs	0	63	2
VSP Program [Member] | Cash Salary and Bonus Costs [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	0	33	1
VSP Program [Member] | Acceleration of Restricted Stock Awards [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	0	29	1
VSP Program [Member] | Other Costs Associated with Retirement [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	0	1	0
Former CEO [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs		69
Restructuring and other termination costs	(8)	69	0
Former CEO [Member] | Cash Salary and Bonus Costs [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	0	11	0
Former CEO [Member] | Claw-Back Bonus [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	0	11	0
Former CEO [Member] | Acceleration of Restricted Stock Awards [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	0	22	0
Former CEO [Member] | Acceleration of Performance Shares [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	(8)	18	0
Former CEO [Member] | Other Costs Associated with Retirement [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	$ 0	$ 7	$ 0

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Other Property and Equipment - Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	$ 199,000,000	$ 302,000,000	$ 267,000,000
Gathering Fee Escalation Rate	15.00%
Reclassification from held for sale to held for use	120,000,000
Chesapeake Midstream Operating [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment			289,000,000
Proceeds from Divestiture of Businesses and Interests in Affiliates			2,160,000,000
Gathering Fee Escalation Rate			2.50%
Midstream Eagle Ford Oil Gathering Assets [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment			115,000,000
Gain (Loss) on Disposition of Property Plant Equipment			3,000,000
Midstream Eagle Ford Oil Gathering Assets [Member] | Scenario, Adjustment [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment			10,000,000
Compressor [Member] | Hilcorp Energy [Member]
Property, Plant and Equipment [Line Items]
Equipment, Number of Units	61
Proceeds from Sale of Property, Plant, and Equipment	19,000,000
Gain (Loss) on Disposition of Property Plant Equipment	6,000,000
Compressor [Member] | Exterran Partners L.P. [Member]
Property, Plant and Equipment [Line Items]
Equipment, Number of Units	499
Proceeds from Sale of Property, Plant, and Equipment	495,000,000
Gain (Loss) on Disposition of Property Plant Equipment	161,000,000
Compressor [Member] | Access Midstream Partners, L.P. [Member]
Property, Plant and Equipment [Line Items]
Equipment, Number of Units	102
Proceeds from Sale of Property, Plant, and Equipment	159,000,000
Gain (Loss) on Disposition of Property Plant Equipment	24,000,000
Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	(8,000,000)	326,000,000	286,000,000
Gathering and Processing Equipment [Member] | SemGroup Corporation [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment		306,000,000
Gain (Loss) on Disposition of Property Plant Equipment	141,000,000
Gathering and Processing Equipment [Member] | Granite Wash Midstream Gas Services, L.L.C. [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment		252,000,000
Gain (Loss) on Disposition of Property Plant Equipment		105,000,000
Gathering and Processing Equipment [Member] | Sale to Western Gas Partners, LP [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment		134,000,000
Gain (Loss) on Disposition of Property Plant Equipment		55,000,000
Exploration and Production Equipment [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	44,000,000
Gain (Loss) on Disposition of Property Plant Equipment	7,000,000	(2,000,000)	(10,000,000)
Crude Oil Hauling Equipment [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	23,000,000
Drilling Rigs [Member]
Property, Plant and Equipment [Line Items]
Equipment, Number of Units	14	23
Proceeds from Sale of Property, Plant, and Equipment	14,000,000
Gain (Loss) on Disposition of Property Plant Equipment	$ (14,000,000)

XML

Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Feb. 09, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	CHK
Entity Registrant Name	CHESAPEAKE ENERGY CORP
Entity Central Index Key	0000895126
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		665,038,368
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 20.5

XML

Asset Retirement Obligation Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation Beginning of Period	$ 465	$ 405	$ 375
Asset Retirement Obligation, Liabilities Incurred	29	20
Asset Retirement Obligation, Revision of Estimate	101	8
Asset Retirement Obligation, Liabilities Settled	(92)	(20)
Asset Retirement Obligation, Accretion Expense	22	22
Asset Retirement Obligation End of Period	465	405	375
Asset Retirement Obligation, Current	18	0
Asset retirement obligations, net of current portion	$ 447	$ 405

XML

Share-Based Compensation (Note)

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

Share-Based Compensation

Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units (PSUs) granted to employees and common stock and restricted stock granted to non-employee directors under our long term incentive plans. The restricted stock and stock options are equity-classified awards and the PSUs are liability-classified awards. In connection with the spin-off of our oilfield services business on June 30, 2014, and pursuant to the terms of our share-based compensation plans and the employee matters agreement between Chesapeake and Seventy Seven Energy Inc., unexercised stock options and unvested restricted stock were modified as of the date of the spin-off. The modifications were designed to ensure that the value of each award of unexercised stock options and unvested restricted stock did not change as a result of the spin-off. The number of stock options and number of shares of restricted stock reported below have been adjusted to reflect modifications on the spin-off date.

Share-Based Compensation Plans

2014 Long Term Incentive Plan. Our 2014 Long Term Incentive Plan (2014 LTIP), which is administered by the Compensation Committee of our Board of Directors, became effective on June 13, 2014 after it was approved by shareholders at our 2014 Annual Meeting. The 2014 LTIP replaced our Amended and Restated Long Term Incentive Plan (2005 LTIP) which was adopted in 2005. The 2014 LTIP provides for up to 36,600,000 shares of common stock that may be issued as long-term incentive compensation to our employees and non-employee directors; provided, however, that the 2014 LTIP uses a fungible share pool under which (i) each share issued pursuant to a stock option or stock appreciation right (SAR) reduces the number of shares available under the 2014 LTIP by 1.0 share; (ii) each share issued pursuant to awards other than options and SARs reduces the number of shares available by 2.12 shares; and (iii) PSUs and other performance awards which are payable solely in cash are not counted against the aggregate number of shares issuable. In addition, the 2014 LTIP prohibits the reuse of shares withheld or delivered to satisfy the exercise price of, or to satisfy tax withholding requirements for, an option or SAR. The 2014 LTIP also prohibits “net share counting” upon the exercise of options or SARs.

The 2014 LTIP authorizes the issuance of the following types of awards: (i) nonqualified and incentive stock options; (ii) SARs; (iii) restricted stock; (iv) performance awards, including PSUs; and (v) other stock-based awards. For both stock options and SARs, the exercise price may not be less than the fair market value of our common stock on the date of grant and the maximum exercise period may not exceed ten years from the date of grant. Awards granted under the plan vest at specified dates and/or upon the satisfaction of certain performance or other criteria, as determined by the Compensation Committee. In 2014, we issued 50,771 and 272,289 shares of restricted stock, net of forfeitures, to non-employee directors and employees, respectively, under the 2014 LTIP. As of December 31, 2014, 36 million shares of common stock remained issuable under the 2014 LTIP.

2005 Long Term Incentive Plan. Chesapeake’s 2005 LTIP, which terminated upon shareholder approval of the 2014 LTIP on June 13, 2014, provided for the issuance of restricted stock, stock options and PSUs to employees, directors and consultants of Chesapeake. Subject to any adjustments as provided by the plan, the aggregate number of shares of common stock available for awards under the plan was limited to 59,300,000 shares. The maximum period for exercise of an option or SAR was not more than ten years from the date of grant, and the exercise price was not less than the fair market value of the shares underlying the option or SAR on the date of grant. Awards granted under the plan became vested at specified dates or upon the satisfaction of certain performance or other criteria determined by a committee of the Board of Directors. The plan was approved by our shareholders. We issued 48,083, 147,108 and 170,151 shares of restricted stock to non-employee directors under the 2005 LTIP in 2014, 2013 and 2012, respectively. We issued options to purchase 993,730, 5.3 million and no shares of common stock to employees and consultants under the 2005 LTIP in 2014, 2013 and 2012, respectively. Additionally, we issued 1.3 million, 2.5 million and 5.0 million shares of restricted stock, net of forfeitures, to employees and consultants under the 2005 LTIP in 2014, 2013 and 2012, respectively.

2003 Stock Award Plan for Non-Employee Directors. Under Chesapeake's 2003 Stock Award Plan for Non-Employee Directors (2003 Non-Employee Director Plan), a maximum of 10,000 shares of Chesapeake's common stock is awarded to each newly appointed non-employee director on his or her first day of service. Subject to any adjustments as provided by the plan, the aggregate number of shares issued may not exceed 250,000 shares. The plan was approved by our shareholders. We issued 10,000, 20,000 and 30,000 shares of common stock to newly appointed non-employee directors under the 2003 Non-Employee Director Plan in 2014, 2013 and 2012, respectively. As of December 31, 2014, there were 120,000 shares remaining available for issuance under the 2003 Non-Employee Director Plan.

Equity-Classified Awards

Restricted Stock. We grant restricted stock to employees and non-employee directors. Restricted stock vests over a minimum of three years and the holder receives dividends on unvested shares. A summary of the changes in unvested restricted stock during 2014, 2013 and 2012 is presented below.

	Shares of Unvested Restricted Stock		Weighted Average Grant Date Fair Value
	(in thousands)
Unvested restricted stock as of January 1, 2014	13,400		$	23.38
Granted	5,049		$	25.92
Vested	(4,803	)	$	27.17
Forfeited	(3,555	)	$	28.09
Unvested restricted stock as of December 31, 2014	10,091		$	21.20
Unvested restricted stock as of January 1, 2013	18,899		$	23.72
Granted	9,189		$	19.68
Vested	(12,897	)	$	21.32
Forfeited	(1,791	)	$	22.86
Unvested restricted stock as of December 31, 2013	13,400		$	23.38
Unvested restricted stock as of January 1, 2012	19,544		$	26.97
Granted	9,480		$	21.13
Vested	(8,620	)	$	28.08
Forfeited	(1,505	)	$	24.57
Unvested restricted stock as of December 31, 2012	18,899		$	23.72

The aggregate intrinsic value of restricted stock that vested during 2014 was approximately $130 million based on the stock price at the time of vesting.

As of December 31, 2014, there was approximately $135 million of total unrecognized compensation expense related to unvested restricted stock. The expense is expected to be recognized over a weighted average period of approximately 2.02 years.

The vesting of certain restricted stock grants may result in state and federal income tax benefits, or reductions in these benefits, related to the difference between the market price of the common stock at the date of vesting and the date of grant. During 2014, we recognized an excess tax benefit related to restricted stock of $12 million. During 2013 and 2012, we recognized reductions in tax benefits related to restricted stock of $14 million and $32 million, respectively. Each adjustment was recorded to additional paid-in capital and deferred income taxes.

Stock Options. In 2014 and 2013, we granted members of senior management stock options that vest ratably over a three-year period. In January 2013, we also granted retention awards to certain officers of stock options that vest one-third on each of the third, fourth and fifth anniversaries of the grant date. Each stock option award has an exercise price equal to the closing price of the Company’s common stock on the grant date. Outstanding options generally expire ten years from the date of grant.

We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method, as there is no adequate historical exercise behavior available. Volatility assumptions are estimated based on an average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account the Company's current dividend policy, over the expected life of the option. The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2014:

Expected option life - years	5.9
Volatility	48.63	%
Risk-free interest rate	1.93	%
Dividend yield	1.33	%

The following table provides information related to stock option activity for 2014, 2013 and 2012: 

	Number of Shares Underlying   Options		Weighted Average Exercise Price Per Share		Weighted   Average Contract Life in Years	Aggregate   Intrinsic Value(a)
	(in thousands)					($ in millions)
Outstanding at January 1, 2014	5,268		$	19.28	6.66	$	41
Granted	994		$	24.43
Exercised	(1,322	)	$	18.71		$	11
Expired	(28	)	$	18.97
Forfeited	(313	)	$	21.05
Outstanding at December 31, 2014	4,599		$	19.55	7.03	$	5
Exercisable at December 31, 2014	1,304		$	18.71	5.70	$	1
Outstanding at January 1, 2013	481		$	12.69	0.96	$	2
Granted	5,264		$	19.32
Exercised	(346	)	$	10.82		$	3
Expired	(131	)	$	19.31
Outstanding at December 31, 2013	5,268		$	19.28	6.66	$	41
Exercisable at December 31, 2013	1,552		$	18.82	1.97	$	13
Outstanding at January 1, 2012	1,051		$	9.84	1.41	$	13
Exercised	(570	)	$	7.45		$	7
Outstanding and exercisable at December 31, 2012	481		$	12.69	0.96	$	2

___________________________________________

(a) The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.

As of December 31, 2014, there was $11 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 2.02 years.

The vesting of certain stock option grants may result in state and federal income tax benefits, or reductions in these benefits, related to the difference between the market price of the common stock at the date of vesting and the date of grant.During 2014, 2013 and 2012, we recognized excess tax benefits related to stock options of $3 million, $1 million and $2 million, respectively. Each adjustment was recorded to additional paid-in capital and deferred income taxes.

Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
General and administrative expenses	$	46	$	60	$	71
Oil and natural gas properties	29		52		71
Oil, natural gas and NGL production expenses	18		21		24
Marketing, gathering and compression expenses	6		7		15
Oilfield services expenses	5		10		10
Total	$	104	$	150	$	191

Liability-Classified Awards

Performance Share Units. In 2012, 2013 and 2014, we granted PSUs to senior management that settle in cash at the end of their respective performance periods and vest ratably over their respective terms. The 2012 awards were granted in one-, two- and three-year tranches and are settled in cash on the first, second and third anniversary dates of the awards, and the 2013 and 2014 awards are settled in cash on the third anniversary of the awards. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors, which include total shareholder return (TSR) and, for certain of the awards, the achievement of operational performance goals such as production and proved reserve growth.

For PSUs granted in 2012, each of the TSR and operational payout components can range from 0% to 125% resulting in a maximum total payout of 250%. For PSUs granted in 2013, the TSR component can range from 0% to 125% and each of the two operational components can range from 0% to 62.5%; however, the maximum total payout is capped at 200%. For PSUs granted in 2014, the TSR component can range from 0% to 200%, with no operational components. For the 2013 and 2014 PSUs, the payout percentage is capped at 100% if the Company’s absolute TSR is less than zero. Compensation expense associated with the PSU grants is recognized over the service period. The number of units settled is dependent upon the Company’s estimates of the underlying performance measures. For the 2014 awards, the Company utilized the Monte Carlo simulation for the TSR performance measure, and the following assumptions to determine the grant date fair value of the PSUs:

Volatility	41.37	%
Risk-free interest rate	0.76	%
Dividend yield for value of awards	1.36	%

The following table presents a summary of our PSU awards:

	Units	Fair Value as of Grant Date		Fair Value(a)		Liability for Vested Amount
		($ in millions)
2012 Awards (b)
Payable 2015	884,507	$	23	$	12	$	12
2013 Awards
Payable 2016	1,701,941	$	35	$	42	$	39
2014 Awards
Payable 2017	609,637	$	16	$	10	$	7

___________________________________________

(a) As of December 31, 2014.

(b) In 2014 and 2013, we paid $11 million and $2 million, respectively, related to 2012 PSU awards.

PSU Compensation. We recognized the following compensation costs related to PSUs for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014			2013		2012
	($ in millions)
General and administrative expenses	$	(4	)	$	34	$	8
Oil and natural gas properties	3			9		4
Oil, natural gas and NGL production expenses	—			2		1
Marketing, gathering and compression expenses	—			2		1
Oilfield services expenses	—			1		—
Total	$	(1	)	$	48	$	14

Effect of the Spin-off on Share-Based Compensation

The employee matters agreement entered into in connection with the spin-off of our oilfield services business (see Note 13) addresses the treatment of holders of Chesapeake stock options, restricted stock and PSUs. Unvested equity-based compensation awards held by COO employees were canceled and replaced with new awards of SSE, and unvested equity-based compensation awards held by Chesapeake employees were adjusted to account for the spin-off, each as of the spin-off date. The employee matters agreement provides that employees of SSE ceased to participate in benefit plans sponsored or maintained by Chesapeake as of the spin-off date. In addition, the employee matters agreement provides that as of the spin-off date, each party is responsible for the compensation of its current employees and for all liabilities relating to its former employees, as determined by their respective employer on the date of termination.

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Income Taxes - Narrative (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes Summary [Line Items]
Effective Income Tax Rate Reconciliation, Deferred Remeasurement	$ (114)	$ (38)	$ (19)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	74	(12)	0
Deferred income tax asset	0	223
Deferred income tax liabilities	4,185	3,407
Deferred Tax Assets, Gross	1,687	1,621
Deferred Tax Assets, Valuation Allowance	222	148
Treasury Regulations Purchase of Stock	5.00%
Percentage Of Beneficial Interest Owned	50.00%
Unrecognized Tax Benefits	303	644	599	369
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	5	13
Federal Jurisdiction [Member]
Income Taxes Summary [Line Items]
Tax Credit Carryforward, Amount	1,600
State and Local Jurisdiction [Member]
Income Taxes Summary [Line Items]
Tax Credit Carryforward, Amount	8,300
Tax Credit Carryforward, Deferred Tax Asset	551	394
Unrecognized Tax Benefits	17	4
Alternative Minimum Tax [Member]
Income Taxes Summary [Line Items]
Tax Credit Carryforward, Amount	76
Unrecognized Tax Benefits	23
Windfall [Member]
Income Taxes Summary [Line Items]
Tax Credit Carryforward, Amount	$ 18

XML

Share-Based Compensation - Restricted Stock Table (Details) (Restricted Stock [Member], USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Shares, Period Start	13,400	18,899	19,544
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	5,049	9,189	9,480
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(4,803)	(12,897)	(8,620)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(3,555)	(1,791)	(1,505)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Shares, Period End	10,091	13,400	18,899
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period Start	$ 23.38	$ 23.72	$ 26.97
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 25.92	$ 19.68	$ 21.13
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 27.17	$ 21.32	$ 28.08
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$ 28.09	$ 22.86	$ 24.57
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End	$ 21.20	$ 23.38	$ 23.72

XML

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES:
Oil, natural gas and NGL	$ 8,180	$ 7,052	$ 6,278
Marketing, gathering and compression	12,225	9,559	5,431
Oilfield services	546	895	607
Total Revenues	20,951	17,506	12,316
OPERATING EXPENSES:
Oil, natural gas and NGL production	1,208	1,159	1,304
Production taxes	232	229	188
Marketing, gathering and compression	12,236	9,461	5,312
Oilfield services	431	736	465
General and administrative	322	457	535
Restructuring and other termination costs	7	248	7
Provision for legal contingencies	234	0	0
Oil, natural gas and NGL depreciation, depletion and amortization	2,683	2,589	2,507
Depreciation and amortization of other assets	232	314	304
Impairment of oil and natural gas properties	0	0	3,315
Impairments of fixed assets and other	88	546	340
Net gains on sales of fixed assets	(199)	(302)	(267)
Total Operating Expenses	17,474	15,437	14,010
INCOME (LOSS) FROM OPERATIONS	3,477	2,069	(1,694)
OTHER INCOME (EXPENSE):
Interest expense	(89)	(227)	(77)
Losses on investments	80	226	103
Net gain (loss) on sales of investments	67	(7)	1,092
Losses on purchases of debt	(197)	(193)	(200)
Other income	22	26	8
Total Other Income (Expense)	(277)	(627)	720
INCOME (LOSS) BEFORE INCOME TAXES	3,200	1,442	(974)
INCOME TAX EXPENSE (BENEFIT):
Current income taxes	47	22	47
Deferred income taxes	1,097	526	(427)
Total Income Tax Expense (Benefit)	1,144	548	(380)
NET INCOME (LOSS)	2,056	894	(594)
Net income attributable to noncontrolling interests	(139)	(170)	(175)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	1,917	724	(769)
Preferred stock dividends	(171)	(171)	(171)
Redemption of preferred shares of a subsidiary	(447)	(69)	0
Earnings allocated to participating securities	(26)	(10)	0
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$ 1,273	$ 474	$ (940)
EARNINGS (LOSS) PER COMMON SHARE:
Earnings Per Share, Basic	$ 1.93	$ 0.73	$ (1.46)
Earnings Per Share, Diluted	$ 1.87	$ 0.73	$ (1.46)
CASH DIVIDEND DECLARED PER COMMON SHARE	$ 0.35	$ 0.35	$ 0.35
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Weighted Average Number of Shares Outstanding, Basic	659	653	643
Weighted Average Number of Shares Outstanding, Diluted	772	653	643

XML

Debt (Note)

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Debt Disclosure [Text Block]

Debt

Our long-term debt consisted of the following as of December 31, 2014 and 2013:

	December 31,
	2014			2013
	($ in millions)
Term loan due 2017(a)	$	—		$	2,000
9.5% senior notes due 2015(b)	—			1,265
3.25% senior notes due 2016	500			500
6.25% euro-denominated senior notes due 2017(c)	416			473
6.5% senior notes due 2017	660			660
6.875% senior notes due 2018(d)	—			97
7.25% senior notes due 2018	669			669
Floating rate senior notes due 2019	1,500			—
6.625% senior notes due 2019(e)	—			650
6.625% senior notes due 2020	1,300			1,300
6.875% senior notes due 2020	500			500
6.125% senior notes due 2021	1,000			1,000
5.375% senior notes due 2021	700			700
4.875% senior notes due 2022	1,500			—
5.75% senior notes due 2023	1,100			1,100
2.75% contingent convertible senior notes due 2035(f)	396			396
2.5% contingent convertible senior notes due 2037(f)	1,168			1,168
2.25% contingent convertible senior notes due 2038(f)	347			347
Revolving credit facility	—			—
Oilfield services revolving credit facility(g)	—			405
Discount on senior notes and term loan(h)	(231		)	(357		)
Interest rate derivatives(i)	10			13
Total debt, net	11,535			12,886
Less current maturities of long-term debt, net(j)	(381		)	—
Total long-term debt, net	$	11,154		$	12,886

___________________________________________

(a) In 2014, we repaid the borrowings outstanding under and terminated the term loan due 2017.

(b) In 2014, we completed a tender offer for a portion of the 9.5% Senior Notes due 2015, and we redeemed the remaining balance of the notes.

(c) The principal amount shown is based on the exchange rate of $1.2098 to €1.00 and $1.3743 to €1.00 as of December 31, 2014 and 2013, respectively. See Note 11 for information on our related foreign currency derivatives.

(d) In 2014, we redeemed all outstanding 6.875% Senior Notes due 2018.

(e) Initial issuers were Chesapeake Oilfield Operating, L.L.C. (COO) and Chesapeake Oilfield Finance, Inc., a wholly owned subsidiary of COO. Chesapeake Energy Corporation is the issuer of all other senior notes and the contingent convertible senior notes. In 2014, in connection with the spin-off of our oilfield services business, the obligations with respect to the COO senior notes were removed from our consolidated balance sheet. See Note 13 for further discussion of the spin-off.

(f) The repurchase, conversion, contingent interest and redemption provisions of our contingent convertible senior notes are as follows:

Holders’ Demand Repurchase Rights. The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date.

Optional Conversion by Holders. At the holder’s option, prior to maturity under certain circumstances, the notes are convertible into cash and, if applicable, shares of our common stock using a net share settlement process. One such triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the specified period in the fourth quarter of 2014, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash and common stock in the first quarter of 2015 under this provision.

The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. The notes were not convertible under this provision in 2014, 2013 or 2012. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note’s conversion value in excess of the principal amount.

Contingent Interest. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years during certain periods if the average trading price of the notes exceeds the threshold defined in the indenture.

The holders’ demand repurchase dates, the common stock price conversion threshold amounts (as adjusted to give effect to the dividend of SSE common stock paid in the spin-off of our oilfield services business and cash dividends on our common stock) and the ending date of the first six-month period in which contingent interest may be payable for the contingent convertible senior notes are as follows:

Contingent       Convertible       Senior  Notes	Holders' Demand Repurchase Dates	Common Stock  Price Conversion  Thresholds		Contingent Interest First Payable (if applicable)
2.75% due 2035	November 15, 2015, 2020, 2025, 2030	$	45.14	May 14, 2016
2.5% due 2037	May 15, 2017, 2022, 2027, 2032	$	59.71	November 14, 2017
2.25% due 2038	December 15, 2018, 2023, 2028, 2033	$	100.35	June 14, 2019

Optional Redemption by the Company. We may redeem the contingent convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of the notes, payable in cash.

(g) In 2014, in connection with the spin-off of our oilfield services business, we terminated our oilfield services credit facility. See Note 13 for further discussion of the spin-off.

(h) Discount as of December 31, 2014 and 2013 included $224 million and $303 million, respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. Discount also included $33 million as of December 31, 2013 associated with our term loan due 2017 discussed below.

(i) See Note 11 for further discussion related to these instruments.

(j) As of December 31, 2014, there was $15 million of discount associated with the equity component of the 2.75% Contingent Convertible Senior Notes due 2035. As discussed in footnote (f) above, the holders of our 2.75% Contingent Convertible Senior Notes due 2035 could exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the principal amount of the notes.

Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes, for the five years ended after December 31, 2014 and thereafter are as follows:

	Principal Amount of Debt Securities
	($ in millions)
2015	$	396
2016	500
2017	2,244
2018	1,016
2019	1,500
2020 and thereafter	6,100
Total	$	11,756

Term Loan

In November 2012, we established an unsecured five-year term loan credit facility in an aggregate principal amount of $2.0 billion for net proceeds of $1.935 billion. The term loan provided that it could be voluntarily repaid before November 9, 2015 at par plus a specified premium and at any time thereafter at par. The maturity date of the term loan was December 2, 2017. In 2014, we used a portion of the net proceeds from our offering of $3.0 billion in aggregate principal amount of senior notes to repay the borrowings under, and terminate, the term loan. We recorded a loss of $90 million, consisting of $40 million in premiums, $30 million of unamortized discount and $20 million of unamortized deferred charges, in connection with the termination.

Chesapeake Senior Notes and Contingent Convertible Senior Notes

The Chesapeake senior notes and the contingent convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Chesapeake is a holding company, owns no operating assets and has no significant operations independent of its subsidiaries. Chesapeake’s obligations under the senior notes and the contingent convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect 100% owned subsidiaries. See Note 22 for consolidating financial information regarding our guarantor and non-guarantor subsidiaries.

We may redeem the senior notes, other than the contingent convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale-leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the senior notes and the contingent convertible senior notes do not have any financial or restricted payment covenants. The senior notes and contingent convertible senior notes indentures have cross default provisions that apply to other indebtedness the Company or any guarantor subsidiary may have from time to time with an outstanding principal amount of at least $50 million or $75 million, depending on the indenture.

We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense at the interest rate of similar nonconvertible debt at the time of issuance. The applicable rates for our 2.75% Contingent Convertible Senior Notes due 2035, our 2.5% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038 are 6.86%, 8.0% and 8.0%, respectively.

During 2014, we issued $3.0 billion in aggregate principal amount of senior notes at par. The offering included two series of notes: $1.5 billion in aggregate principal amount of Floating Rate Senior Notes due 2019 and $1.5 billion in aggregate principal amount of 4.875% Senior Notes due 2022. We used a portion of the net proceeds of $2.966 billion to repay the borrowings under, and terminate, our term loan credit facility. We used the remaining proceeds along with cash on hand to redeem the remaining $97 million principal amount of the 6.875% Senior Notes due 2018 and to purchase and redeem the remaining $1.265 billion principal amount of the 9.5% Senior Notes due 2015 for $1.454 billion. We recorded a loss of approximately $6 million associated with the redemption of the 6.875% Senior Notes due 2018, which consisted of $5 million in premiums and $1 million of unamortized deferred charges. We recorded a loss of approximately $99 million associated with the purchase and redemption of the 9.5% Senior Notes due 2015, which consisted of $87 million in premiums, $9 million of unamortized discount and $3 million of unamortized deferred charges.

During 2013, we issued $2.3 billion in aggregate principal amount of senior notes at par. The offering included three series of notes: $500 million in aggregate principal amount of 3.25% Senior Notes due 2016; $700 million in aggregate principal amount of 5.375% Senior Notes due 2021; and $1.1 billion in aggregate principal amount of 5.75% Senior Notes due 2023. We used a portion of the net proceeds of $2.274 billion to repay outstanding indebtedness under our revolving credit facility and purchase certain senior notes. We purchased $217 million in aggregate principal amount of our 7.625% Senior Notes due 2013 for $221 million and $377 million in aggregate principal amount of our 6.875% Senior Notes due 2018 for $405 million pursuant to tender offers during 2013. We recorded a loss of approximately $37 million associated with the tender offers, including $32 million in premiums and $5 million of unamortized deferred charges. During 2013, we also redeemed $1.3 billion in aggregate principal amount of our 6.775% Senior Notes due 2019 (the 2019 Notes) at par pursuant to notice of special early redemption. We recorded a loss of approximately $33 million associated with the redemption, including $19 million of unamortized deferred charges and $14 million of discount. As described in the following paragraph, our redemption of the 2019 Notes has been the subject of litigation. On July 15, 2013, we retired at maturity the remaining $247 million aggregate principal amount outstanding of our 7.625% Senior Notes due 2013.

In March 2013, the Company brought suit in the U.S. District Court for the Southern District of New York against The Bank of New York Mellon Trust Company, N.A., the indenture trustee for the 2019 Notes. The Company sought and ultimately obtained a judgment declaring that the notice it issued on March 15, 2013 to redeem all of the 2019 Notes at par (plus accrued interest through the redemption date) was timely and effective for that redemption pursuant to the special early redemption provision of the supplemental indenture governing the 2019 Notes. In May 2013, as a result of that ruling, the 2019 Notes were redeemed at par. In November 2014, the U.S. Court of Appeals for the Second Circuit, on appeal by the indenture trustee, reversed the District Court’s declaratory judgment and held that the notice was not effective to redeem the 2019 Notes at par because it was not timely for that purpose. The Court of Appeals remanded the case to the District Court for a determination whether the redemption notice triggered a redemption at the make-whole price specified in the indenture, instead of at par. The Company sought a rehearing by the Court of Appeals en banc in December 2014, and that petition was denied on February 6, 2015. On February 13, 2015, the indenture trustee filed a motion in the District Court for entry of a judgment requiring the Company to pay the make-whole price, as defined in the indenture, less the par amount paid in the 2013 redemption plus prejudgment interest at the statutory 9% rate from the redemption date. The Company intends to oppose the trustee’s motion vigorously.

On December 30, 2014, six former holders of the 2019 Notes filed a putative class action against the Company on behalf of all former holders who sold the 2019 Notes after the Company issued the notice of early redemption in March 2013 but before the notes were redeemed at par in May 2013. These former holders allege that the Company breached the indenture by issuing a wrongful notice of special early redemption, and that this breach caused the market value of the notes to decline, injuring them when they sold their 2019 Notes. This suit has been assigned to the same District Court judge as the suit described above. The Company intends to defend itself against this claim vigorously.

No scheduled principal payments are required on our senior notes until 2016 unless the holders of our 2.75% Contingent Convertible Senior Notes due 2035 exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the $396 million principal amount of notes.

Revolving Credit Facility

In December 2014, we entered into a new five-year $4.0 billion senior unsecured revolving credit facility to use for general corporate purposes. The new credit facility replaced our then-existing $4.0 billion senior secured revolving credit facility that was scheduled to mature in December 2015. The aggregate commitments under the facility may be increased up to an additional $1.0 billion, and the December 2019 maturity date may be extended for twoone-year periods at our request and with the consent of the participating lenders. As of December 31, 2014, we had no outstanding borrowings under the facility and utilized $15 million of the facility for various letters of credit. Borrowings under the facility are currently unsecured; however, we will be required to provide collateral and the facility will be subject to a borrowing base if our credit rating declines to Ba3 (Moody’s Investors Services, Inc.) or BB- (Standard & Poor’s Ratings Services) or lower.

Revolving loans under the revolving credit facility bear interest at a fluctuating rate per annum equal to the highest of (i) the federal funds effective rate plus 0.5%, (ii) the administrative agent’s prime rate or (iii) the London interbank offer rate (LIBOR) for a one-month interest period plus 1.0% (alternative base rate (ABR) loans), and/or LIBOR rates (LIBOR loans), at our election, plus an applicable margin rate depending on our credit rating (currently 0.625% per annum for ABR loans and 1.625% per annum for LIBOR loans). The terms of the credit facility include covenants limiting, among other things, the ability of the Company and its restricted subsidiaries to incur additional indebtedness, make investments or loans, create liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates. In addition, the credit facility requires us to maintain, as of the last day of each fiscal quarter, (i) a net debt to capitalization ratio (as defined in the credit agreement) that does not exceed 65%; and (ii) a leverage ratio (net debt to consolidated EBITDA, as defined in the credit agreement) that does not exceed 4.0 to 1.0; provided, however, that the leverage ratio will not apply during any period in which our credit rating, as determined by either Moody’s Investors Services, Inc. or Standard & Poor’s Rating Services, meet and continue to meet certain investment grade thresholds, as defined in the credit agreement.

Our credit facility is fully and unconditionally guaranteed, on a joint and several basis, by certain of our material subsidiaries. The credit agreement includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $125 million or more; bankruptcy; judgments involving liability of $125 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods.

Spin-Off Debt Transactions

Prior to the spin-off of our oilfield services business, COO or its subsidiaries completed the following debt transactions:

• Entered into a five-year senior secured revolving credit facility with total commitments of $275 million and incurred approximately $3 million in financing costs related to entering into the facility.

• Entered into a $400 millionseven-year secured term loan and used the net proceeds of approximately $394 million and borrowings under the new revolving credit facility to repay and terminate COO’s existing credit facility.

• Issued $500 million in aggregate principal amount of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds of approximately $494 million to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility discussed above and for general corporate purposes.

All deferred charges and debt balances related to these transactions were removed from our consolidated balance sheet as of June 30, 2014. See Note 13 for further discussion of the spin-off.

Fair Value of Debt

We estimate the fair value of our exchange-traded debt using quoted market prices (Level 1). The fair value of all other debt, which currently consists of our revolving credit facility and as of December 31, 2013 also consisted of our former oilfield services credit facility and term loan, is estimated using our credit default swap rate (Level 2). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.

	December 31, 2014				December 31, 2013
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
			($ in millions)
Long-term debt (Level 1)	$	11,525	$	12,052	$	10,501	$	11,557
Long-term debt (Level 2)	$	—	$	—	$	2,372	$	2,369

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Earnings Per Share (Note)

12 Months Ended

Dec. 31, 2014

Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]

Earnings Per Share Disclosure [Text Block]

Earnings Per Share

Basic earnings per share (EPS) is calculated using the weighted average number of common shares outstanding during the period and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide dividend rights.

Diluted EPS is calculated assuming the issuance of common shares for all potentially dilutive securities, provided the effect is not antidilutive. For the years ended December 31, 2014, 2013 and 2012, our contingent convertible senior notes did not have a dilutive effect and therefore were excluded from the calculation of diluted EPS. See Note 3 for further discussion of our contingent convertible senior notes.

For the years ended December 31, 2014, 2013 and 2012, shares of the following securities and associated adjustments to net income, representing dividends on preferred stock and allocated earnings on participating securities, were excluded from the calculation of diluted EPS as the effect was antidilutive. The impact of our stock options was immaterial in the calculation of diluted EPS for these periods.

	Net Income Adjustments		Shares
	($ in millions)		(in millions)
Year Ended December 31, 2014
Participating securities	$	22	3
Year Ended December 31, 2013
Common stock equivalent of our preferred stock outstanding:
5.75% cumulative convertible preferred stock	$	86	56
5.75% cumulative convertible preferred stock (series A)	$	63	40
5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
4.50% cumulative convertible preferred stock	$	12	6
Participating securities	$	10	5
Year Ended December 31, 2012
Common stock equivalent of our preferred stock outstanding:
5.75% cumulative convertible preferred stock	$	86	56
5.75% cumulative convertible preferred stock (series A)	$	63	39
5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
4.50% cumulative convertible preferred stock	$	12	6
Participating securities	$	—	5

For the year ended December 31, 2014, all outstanding equity securities convertible into common stock were included in the calculation of diluted EPS. A reconciliation of basic EPS and diluted EPS for the year ended December 31, 2014 is as follows: 

	Income (Numerator)		Weighted Average Shares (Denominator)	Per Share Amount
	(in millions, except per share data)
For the Year Ended December 31, 2014:
Basic EPS	$	1,273	659	$	1.93
Effect of Dilutive Securities:
Assumed conversion as of the beginning of the period     of preferred shares outstanding during the period:
Common shares assumed issued for 5.75% cumulative convertible preferred stock	86		59
Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)	63		42
Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)	10		6
Common shares assumed issued for 4.50% cumulative convertible preferred stock	12		6
Diluted EPS	$	1,444	772	$	1.87

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Investments (Note)

12 Months Ended

Dec. 31, 2014

Investments [Abstract]

Investments Disclosure [Text Block]

Investments

A summary of our investments, including our approximate ownership percentage and carrying value as of December 31, 2014 and 2013, is presented below.

		Approximate Ownership %		Carrying Value
	Accounting	December 31,		December 31,
	Method	2014	2013	2014		2013
				($ in millions)
FTS International, Inc.	Equity	30%	30%	$	116	$	138
Sundrop Fuels, Inc.	Equity	56%	56%	130		135
Chaparral Energy, Inc.	Equity	—%	20%	—		143
Other	—	—%	—%	19		61
Total investments				$	265	$	477

FTS International, Inc. FTS, based in Fort Worth, Texas, is a privately held company that, through its subsidiaries, provides hydraulic fracturing and other services to oil and gas companies. In 2014, we recorded negative equity method and other adjustments of $32 million for our share of FTS’s net loss and recorded an accretion adjustment of $10 million related to the excess of our underlying equity in net assets of FTS over our carrying value.

As of December 31, 2014, the carrying value of our investment in FTS was less than our underlying equity in net assets by approximately $44 million, of which $14 million was attributed to non-depreciable assets. The value attributed to depreciable assets is being accreted over the estimated useful lives of the underlying assets.

Sundrop Fuels, Inc. Sundrop Fuels, Inc. (Sundrop), based in Longmont, Colorado, is a privately held cellulosic biofuels company that is constructing a nonfood biomass-based “green gasoline” plant. In 2014, we recorded a $21 million charge related to our share of Sundrop's net loss and $16 million of capitalized interest associated with the construction of Sundrop’s plant. The carrying value of our investment in Sundrop was in excess of our underlying equity in net assets by approximately $78 million as of December 31, 2014 and will be amortized over the life of the plant once it is placed into service.

Sold Investments

Chaparral Energy, Inc. Chaparral Energy, Inc. (Chaparral), based in Oklahoma City, Oklahoma, is a private independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties. In 2014, we sold all of our interest in Chaparral for net cash proceeds of $209 million. We recorded a $73 million gain related to the sale.

Clean Energy Fuels Corp. In 2013, we sold all of our shares of Clean Energy Fuels Corp. (Clean Energy) common stock for cash proceeds of approximately $13 million. We recorded a $3 million gain related to the sale. In 2013, we sold our $100 million investment in convertible notes of Clean Energy for cash proceeds of $85 million. The buyer also assumed our commitment to purchase the third and final $50 million tranche of Clean Energy convertible notes. We recorded a $15 million loss related to this sale.

Gastar Exploration Ltd. In 2013, we sold our investment in Gastar Exploration Ltd. for cash proceeds of $10 million.

Chesapeake Midstream Partners, L.P. In 2012, we sold all of our common and subordinated units representing limited partner interests in Chesapeake Midstream Partners, L.P., now named Access Midstream Partners, L.P., and all of our limited liability company interests in the sole member of its general partner to funds affiliated with Global Infrastructure Partners for cash proceeds of $2.0 billion. We recorded a $1.032 billion gain associated with the transaction.

Glass Mountain Pipeline, LLC. In 2012, our wholly owned midstream subsidiary, Chesapeake Midstream Development, L.L.C. (CMD), entered into an agreement with two other parties to form Glass Mountain Pipeline, LLC to construct a 210 mile pipeline in western and north central Oklahoma in which CMD had a 50% ownership interest. In 2012, CMD sold its interest for $99 million and recorded a gain of $62 million.

Other. In 2014, we sold an equity investment in a natural gas trading and management firm for cash proceeds of $30 million and recorded a loss of $6 million associated with the transaction.

In 2013, we sold an equity investment for cash proceeds of $6 million and recorded a $5 million gain associated with the transaction.

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Employee Benefit Plans (Note)

12 Months Ended

Dec. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Compensation and Employee Benefit Plans [Text Block]

Employee Benefit Plans

Our qualified 401(k) profit sharing plan (401(k) Plan) is the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan, which is open to employees of Chesapeake and all our subsidiaries except certain employees of Chesapeake Appalachia, L.L.C. Eligible employees may elect to defer compensation through voluntary contributions to their 401(k) Plan accounts, subject to plan limits and those set by the IRS. Through December 31, 2014, Chesapeake matched employee contributions dollar for dollar (subject to a maximum contribution of 15% of an employee's base salary and performance bonus) with Chesapeake common stock purchased in the open market. The Company contributed $61 million, $81 million and $91 million to the 401(k) Plan in 2014, 2013 and 2012, respectively. Beginning January 1, 2015, Chesapeake will match employee contributions in cash.

Chesapeake also maintains a nonqualified deferred compensation plan (DC Plan). To be eligible to participate in the DC Plan, an active employee must have a base salary of at least $150,000, have a hire date on or before the December 1 immediately preceding the year in which the employee is able to participate, or be designated as eligible to participate. Only the top 10% of Company wage earners are eligible to participate. Additionally, the employee has to have made the maximum contribution allowable under the 401(k) Plan. Chesapeake matches 100% of employee contributions up to 15% of base salary and performance bonus in the aggregate for the DC Plan with Chesapeake common stock, and an employee who is at least age 55 may elect for the matching contributions to be made in any one of the DC Plan’s investment options. The maximum compensation that can be deferred by employees under all Company deferred compensation plans, including the Chesapeake 401(k) Plan, is a total of 75% of base salary and 100% of performance bonus. The Company contributed $7 million, $14 million and $16 million to the DC Plan during 2014, 2013 and 2012, respectively, to fund the match. In addition, in 2012 the Board of Directors adopted a deferred compensation plan for non-employee directors (Director DC Plan). The Company's non-employee directors are able to defer up to 100% of director cash compensation into the Director DC Plan and invest in Chesapeake common stock, but the plan does not provide for Company matching contributions.

Any assets placed in trust by Chesapeake to fund future obligations of the Company's nonqualified deferred compensation plans are subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their deferred compensation in the plans. Chesapeake maintains no post-employment benefit plans except those sponsored by its wholly owned subsidiary Chesapeake Appalachia, L.L.C. Participation in these plans is limited to existing employees who are union members and former employees who were union members. The Chesapeake Appalachia, L.L.C. benefit plans provide health care and life insurance benefits to eligible employees upon retirement. We account for these benefits on an accrual basis. As of December 31, 2014, the Company had accrued approximately $3 million in accumulated post-employment benefit liability.

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Equity - Convertible Preferred Stock Table (Details)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding, beginning of period	7,251,515	7,251,515
Shares outstanding, end of period	7,251,515	7,251,515
5.75% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding, beginning of period	1,497,000	1,497,000	1,497,000
Shares outstanding, end of period	1,497,000	1,497,000	1,497,000
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding, beginning of period	1,100,000	1,100,000	1,100,000
Shares outstanding, end of period	1,100,000	1,100,000	1,100,000
4.50% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding, beginning of period	2,559,000	2,559,000	2,559,000
Shares outstanding, end of period	2,559,000	2,559,000	2,559,000
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding, beginning of period	2,096,000	2,096,000	2,096,000
Shares outstanding, end of period	2,096,000	2,096,000	2,096,000

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Income Taxes (Note)

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

Income Taxes

The components of the income tax provision (benefit) for each of the periods presented below are as follows:

	Years Ended December 31,
	2014			2013		2012
	($ in millions)
Current
Federal	$	—		$	—	$	—
State	47			22		47
Current Income Taxes	47			22		47
Deferred
Federal	1,115			502		(358		)
State	(18		)	24		(69		)
Deferred Income Taxes	1,097			526		(427		)
Total	$	1,144		$	548	$	(380	)

The effective income tax expense (benefit) differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons:

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Income tax expense (benefit) at the federal statutory rate (35%)	$	1,120		$	505		$	(341	)
State income taxes (net of federal income tax benefit)	68			88			(38		)
Remeasurement of state deferred tax liabilities	(114		)	(38		)	(19		)
Change in valuation allowance	74			(12		)	—
Other	(4		)	5			18
Total	$	1,144		$	548		$	(380	)

During the 2014 fourth quarter, Chesapeake simplified its organizational structure which impacts how income (loss) is allocated and apportioned to various states. This change resulted in a $114 million tax benefit due to the remeasurement of state deferred tax liabilities. Additionally, we reassessed the realizability of our deferred tax assets given the decline in commodity prices. We recorded a $74 million tax expense for the increase in our valuation allowance.

Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:

	Years Ended December 31,
	2014			2013
	($ in millions)
Deferred tax liabilities:
Oil and natural gas properties	$	(3,950	)	$	(2,631	)
Other property and equipment	(14		)	(371		)
Volumetric production payments	(920		)	(1,216		)
Contingent convertible debt	(443		)	(439		)
Deferred revenue	(102		)	—
Derivative instruments	(428		)	—
Deferred tax liabilities	(5,857		)	(4,657		)
Deferred tax assets:
Net operating loss carryforwards (carrybacks)	945			535
Derivative instruments	—			108
Asset retirement obligations	165			153
Investments	88			130
Deferred stock compensation	50			66
Accrued liabilities	214			120
Noncontrolling interest liabilities	135			152
Alternative minimum tax credits	34			317
Other	56			40
Deferred tax assets	1,687			1,621
Valuation allowance	(222		)	(148		)
Net deferred tax assets	1,465			1,473
Net deferred tax assets (liabilities)	$	(4,392	)	$	(3,184	)
Reflected in accompanying balance sheets as:
Current deferred income tax asset	—			223
Current deferred income tax liability	(207		)	—
Non-current deferred income tax liability	(4,185		)	(3,407		)
Total	$	(4,392	)	$	(3,184	)

As of December 31, 2014, Chesapeake had federal income tax NOL carryforwards of approximately $1.6 billion and state NOL carryforwards of approximately $8.3 billion which excludes the NOL carryforwards related to unrecognized tax benefits and stock compensation windfalls that have not been recognized under U.S. GAAP. The associated deferred tax assets related to these NOL carryforwards were $551 million and $394 million, respectively. Additionally, we had $76 million of alternative minimum tax (AMT) NOL carryforwards, net of unrecognized tax benefits, available as a deduction against future AMT income. The NOL carryforwards expire from 2031 through 2033. The value of these carryforwards depends on the ability of Chesapeake to generate taxable income. As of December 31, 2014 and 2013, we had deferred tax assets of $1.687 billion and $1.621 billion, respectively, upon which we had a valuation allowance of $222 million and $148 million, respectively, for certain state NOL carryforwards and credits that we have concluded are not more likely than not to be utilized prior to expiration. The net change in the valuation allowance of $74 million is reflected as a component of income tax expense.

Deferred tax assets relating to tax benefits of employee share-based compensation have been reduced for stock options exercised and restricted stock that vested in periods in which Chesapeake was in a net operating loss (NOL) position. Some exercises and vestings result in tax deductions in excess of previously recorded benefits based on the stock option or restricted stock value at the time of grant (windfalls). Although these additional tax benefits or windfalls are reflected in NOL carryforwards in the tax return, the additional tax benefit associated with the windfalls is not recognized until the deduction reduces taxes payable pursuant to accounting for stock compensation under U.S. GAAP. Accordingly, since the tax benefit does not reduce Chesapeake's current taxes payable due to NOL carryforwards, these windfall tax benefits are not reflected in Chesapeake's NOLs in deferred tax assets. Windfalls included in NOL carryforwards but not reflected in deferred tax assets as of December 31, 2014 totaled $18 million. Any shortfalls resulting from tax deductions that were less than the previously recorded benefits were recorded as reductions to additional paid-in capital.

The ability of Chesapeake to utilize NOL carryforwards to reduce future federal taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of these carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Chesapeake.

As of December 31, 2014, we do not believe that an ownership change has occurred that would limit the carryforwards. Due to the spin-off of SSE, the limitation on previously acquired NOLs was increased such that the remaining carryforward became fully available. Future equity transactions by Chesapeake or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOLs.

Accounting guidance for recognizing and measuring uncertain tax positions prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. As of December 31, 2014 and 2013, the amount of unrecognized tax benefits related to NOL carryforwards and state tax liabilities associated with uncertain tax positions was $303 million and $644 million, respectively. Of the 2014 amount, $23 million and $17 million are related to AMT and state tax liabilities, respectively, while the remainder is related to NOL carryforwards. Of the 2013 amount, $4 million is related to state tax liabilities while the remainder is related to NOL carryforwards. If these unrecognized tax benefits are disallowed and our NOL carryforwards are reduced, the reduction will be offset by additional tax basis that will generate future deductions. The uncertain tax positions identified would not have a material effect on the effective tax rate. No material changes to the current uncertain tax positions are expected within the next 12 months. As of December 31, 2014 and 2013, we had accrued liabilities of $5 million and $13 million, respectively, for interest related to these uncertain tax positions. Chesapeake recognizes interest related to uncertain tax positions in interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses.

A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:

	2014			2013		2012
	($ in millions)
Unrecognized tax benefits at beginning of period	$	644		$	599	$	369
Additions based on tax positions related to the current year	13			15		134
Additions to tax positions of prior years	—			30		96
Reductions to tax positions of prior years	(354		)	—		—
Unrecognized tax benefits at end of period	$	303		$	644	$	599

Chesapeake's federal and state income tax returns are routinely audited by federal and state fiscal authorities. The Internal Revenue Service (IRS) is currently auditing our federal income tax returns for 2007 through 2013. The federal tax returns for 1999 through 2006 remain subject to examination for the purpose of determining the amount of remaining tax NOL and other carryforwards. The 2007 through 2014 years remain open for all purposes of examination by the IRS and other taxing authorities in material jurisdictions.

XML

Debt - Long-Term Debt Table (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014 Day	Dec. 31, 2013	Apr. 24, 2014	Dec. 31, 2006
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 11,756
Debt Instrument, Unamortized Discount	(231)	(357)
Long-term Debt	11,535	12,886
Long-term Debt, Current Maturities	(381)	0
Long-term debt, net	11,154	12,886
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	100.00%
Percentage Of Principal Amount Of Notes For Repurchase Requirement Of Contingent Convertible Senior Notes	100.00%
Debt Instrument, Convertible, Terms of Conversion Feature	5
Credit Facility Commitment Period	10 years
Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0
Interest Rate Contract [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	10	13
2.75% Contingent Convertible Senior Notes Due 2035 [Member]
Long-Term Debt Instrument [Line Items]
Common Stock Price Conversion Thresholds	$ 45.14
Debt Instrument, Date of First Required Payment	May 14, 2016
2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Common Stock Price Conversion Thresholds	$ 59.71
Debt Instrument, Date of First Required Payment	Nov. 14, 2017
2.25% Contingent Convertible Senior Notes Due 2038 [Member]
Long-Term Debt Instrument [Line Items]
Common Stock Price Conversion Thresholds	$ 100.35
Debt Instrument, Date of First Required Payment	Jun. 14, 2019
Unsecured Debt [Member] | Senior Unsecured Term Loan Due 2017 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	2,000
Debt Instrument, Unamortized Discount		(33)
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	3,000		3,000
Debt Instrument, Unamortized Discount	(224)	(303)
Senior Notes [Member] | Debt Instrument, Redemption, Period One [Member]
Long-Term Debt Instrument [Line Items]
Credit Facility Commitment Period	5 years
Senior Notes [Member] | Debt Instrument, Redemption, Period Two [Member]
Long-Term Debt Instrument [Line Items]
Credit Facility Commitment Period	10 years
Senior Notes [Member] | Debt Instrument, Redemption, Period Three [Member]
Long-Term Debt Instrument [Line Items]
Credit Facility Commitment Period	15 years
Senior Notes [Member] | Debt Instrument, Redemption, Period Four [Member]
Long-Term Debt Instrument [Line Items]
Credit Facility Commitment Period	20 years
Senior Notes [Member] | 9.5% Senior Notes Due 2015 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	1,265
Debt Instrument, Interest Rate, Stated Percentage	9.50%
Senior Notes [Member] | 3.25% Senior Notes due 2016 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	500	500
Debt Instrument, Interest Rate, Stated Percentage	3.25%	3.25%
Senior Notes [Member] | 6.25% Euro-Denominated Senior Notes Due 2017 [ Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	416	473		344
Senior Notes [Member] | 6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Cross Currency Interest Rate Contract [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	416
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Derivative, Forward Exchange Rate	1.2098	1.3743		1.3325
Senior Notes [Member] | 6.5% Senior Notes Due 2017 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	660	660
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Senior Notes [Member] | 6.875% Senior Notes Due 2018 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	97
Debt Instrument, Interest Rate, Stated Percentage	6.875%	6.875%
Senior Notes [Member] | 7.25% Senior Notes Due 2018 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	669	669
Debt Instrument, Interest Rate, Stated Percentage	7.25%
Senior Notes [Member] | Floating Rate Senior Notes due 2019 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,500	0
Senior Notes [Member] | 6.625% Senior Notes Due 2019 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	650
Debt Instrument, Interest Rate, Stated Percentage	6.625%
Senior Notes [Member] | 6.625% Senior Notes Due 2020 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,300	1,300
Debt Instrument, Interest Rate, Stated Percentage	6.625%
Senior Notes [Member] | 6.875% Senior Notes Due 2020 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	500	500
Debt Instrument, Interest Rate, Stated Percentage	6.875%
Senior Notes [Member] | 6.125% Senior Notes Due 2021 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,000	1,000
Debt Instrument, Interest Rate, Stated Percentage	6.125%
Senior Notes [Member] | 5.375% Senior Notes due 2021 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	700	700
Debt Instrument, Interest Rate, Stated Percentage	5.375%	5.375%
Senior Notes [Member] | 4.875% Senior Notes due 2022 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,500	0
Debt Instrument, Interest Rate, Stated Percentage	4.875%
Senior Notes [Member] | 5.75% Senior Notes due 2023 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,100	1,100
Debt Instrument, Interest Rate, Stated Percentage	5.75%	5.75%
Senior Notes [Member] | 2.75% Contingent Convertible Senior Notes Due 2035 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	396	396
Debt Instrument, Unamortized Discount	(15)
Debt Instrument, Interest Rate, Stated Percentage	2.75%
Senior Notes [Member] | 2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,168	1,168
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Senior Notes [Member] | 2.25% Contingent Convertible Senior Notes Due 2038 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	347	347
Debt Instrument, Interest Rate, Stated Percentage	2.25%
Line of Credit [Member] | Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	0
Line of Credit [Member] | Oilfield Services Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0	$ 405

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Natural Gas and Oil Property Transactions - VPP Volume Remaining to Be Delivered Table (Details)	12 Months Ended
	Dec. 31, 2014 Mcfe	May 31, 2011 Mcfe	Sep. 30, 2010 Mcfe	Dec. 31, 2008 Mcfe	Aug. 31, 2008 Mcfe	May 31, 2008 Mcfe	Dec. 31, 2007 Mcfe
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)	1,220,000,000,000
Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)	345,500,000,000
Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	5,200,000
Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	2,200,000
Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	1,105,000,000,000
Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	292,300,000,000
NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	14,000,000
NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	6,600,000
VPP 10 Anadarko Basin Granite Wash [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	86 months
Proved Developed Reserves (Energy)	74,000,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	1,300,000
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	38,000,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	4,700,000
VPP 9 Mid-Continent [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)		177,000,000,000
VPP 9 Mid-Continent [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	74 months
Proved Developed Reserves (Energy)	89,900,000,000
VPP 9 Mid-Continent [Member] | Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)		1,700,000
VPP 9 Mid-Continent [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	800,000
VPP 9 Mid-Continent [Member] | Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)		138,000,000,000
VPP 9 Mid-Continent [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	73,200,000,000
VPP 9 Mid-Continent [Member] | NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)		4,800,000
VPP 9 Mid-Continent [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	1,900,000
VPP 8 Barnett Shale [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)			390,000,000,000
VPP 8 Barnett Shale [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	8 months
Proved Developed Reserves (Energy)	36,600,000,000
VPP 8 Barnett Shale [Member] | Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)			0
VPP 8 Barnett Shale [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 8 Barnett Shale [Member] | Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)			390,000,000,000
VPP 8 Barnett Shale [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	36,600,000,000
VPP 8 Barnett Shale [Member] | NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)			0
VPP 8 Barnett Shale [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 4 Anadarko and Arkoma Basins [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)				98,000,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	24 months
Proved Developed Reserves (Energy)	15,800,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)				500,000
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	100,000
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)				95,000,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	15,300,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)				0
VPP 4 Anadarko and Arkoma Basins [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 3 Anadarko Basin [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)					93,000,000,000
VPP 3 Anadarko Basin [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	55 months
Proved Developed Reserves (Energy)	23,900,000,000
VPP 3 Anadarko Basin [Member] | Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)					0
VPP 3 Anadarko Basin [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)					93,000,000,000
VPP 3 Anadarko Basin [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	23,900,000,000
VPP 3 Anadarko Basin [Member] | NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)					0
VPP 3 Anadarko Basin [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 2 Texas, Oklahoma and Kansas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)						94,000,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	52 months
Proved Developed Reserves (Energy)	13,800,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)						0
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)						94,000,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	13,800,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)						0
VPP 2 Texas, Oklahoma and Kansas [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 1 Kentucky and West Virginia [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)							208,000,000,000
VPP 1 Kentucky and West Virginia [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	96 months
Proved Developed Reserves (Energy)	91,500,000,000
VPP 1 Kentucky and West Virginia [Member] | Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)							0
VPP 1 Kentucky and West Virginia [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)							208,000,000,000
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	91,500,000,000
VPP 1 Kentucky and West Virginia [Member] | NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)							0
VPP 1 Kentucky and West Virginia [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0

XML

Contingencies and Commitments (Note)

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

Contingencies and Commitments

Contingencies

Litigation and Regulatory Proceedings

The Company is involved in a number of litigation and regulatory proceedings (including those described below). Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. We estimate and provide for potential losses that may arise out of litigation and regulatory proceedings to the extent that such losses are probable and can be reasonably estimated. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different. Our total estimated liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. We account for legal defense costs in the period the costs are incurred.

July 2008 Common Stock Offering Litigation. On February 25, 2009, a putative class action was filed in the U.S. District Court for the Southern District of New York against the Company and certain of its officers and directors along with certain underwriters of the Company’s July 2008 common stock offering. The plaintiff filed an amended complaint on September 11, 2009 alleging that the registration statement for the offering contained material misstatements and omissions and seeking damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified amount and rescission. The action was transferred to the U.S. District Court for the Western District of Oklahoma on October 13, 2009. Chesapeake and the officer and director defendants moved for summary judgment on grounds of loss causation and materiality on December 28, 2011, and the motion was granted as to all claims as a matter of law on March 29, 2013. On appeal, the U.S. Court of Appeals for the Tenth Circuit affirmed the dismissal on August 8, 2014 and denied the plaintiffs’ petition for rehearing on November 12, 2014.

Shareholder Derivative Litigation. A derivative action relating to the July 2008 offering was filed in the U.S. District Court for the Western District of Oklahoma on September 6, 2011. The case was thereafter stayed by stipulation between the parties, and on November 20, 2014, the parties entered a stipulation to have the case voluntarily dismissed. On January 16, 2015, pursuant to Court order, the Company provided notice to shareholders of the voluntary dismissal and allowed eligible shareholders to intervene.

A federal consolidated derivative action and an Oklahoma state court derivative action have been stayed since 2012 pending resolution of a related, previously reported putative federal securities class action. The shareholder derivative actions allege breaches of fiduciary duty, among other things, related to the former CEO’s personal financial practices and purported conflicts of interest, and the Company’s accounting for volumetric production payments. With the dismissal of the federal securities class action now affirmed, the parties have stipulated to continue the stay of the Oklahoma state court derivative action while the plaintiffs pursue their claims in the federal consolidated derivative action. The plaintiffs filed a consolidated derivative complaint on October 31, 2014 and an amended consolidated derivative complaint on February 12, 2015. Chesapeake filed its motion to dismiss on February 23, 2015.

Regulatory Proceedings. The Company has received, from the U.S. Department of Justice (DOJ) and certain state governmental agencies and authorities, subpoenas and demands for documents, information and testimony in connection with investigations into possible violations of federal and state antitrust laws relating to our purchase and lease of oil and gas rights in various states. The Company also has received DOJ and state subpoenas seeking information on the Company’s royalty payment practices. Chesapeake has engaged in discussions with the DOJ and state representatives and continues to respond to such subpoenas and demands.

On March 5, 2014, the Attorney General of the State of Michigan filed a criminal complaint against Chesapeake in Michigan state court alleging misdemeanor antitrust violations and attempted antitrust violations under state law arising out of the Company’s leasing activities in Michigan during 2010. On July 9, 2014, following a preliminary hearing on the complaint, as amended, the 89^th District Court for Cheboygan County, Michigan ruled that one count alleging a bid-rigging conspiracy between Chesapeake and Encana Oil & Gas USA, Inc. regarding the October 2010 state lease auction would proceed to trial and dismissed claims alleging a second antitrust violation and an attempted antitrust violation. A trial date of April 15, 2015 has been set for this case. The Michigan Attorney General filed a second criminal complaint against Chesapeake in the same court on June 5, 2014 which, as amended, alleges that Chesapeake’s conduct in canceling lease offers to Michigan landowners in 2010 violated the state’s criminal enterprises and false pretenses felony statutes. On September 9, 2014, following a preliminary hearing, the Court ruled that all charges in the complaint would be tried. No trial date has been set for this matter.

Redemption of 2019 Notes. See Note 3 for a description of pending litigation regarding our redemption in May 2013 of our 2019 Notes. As a result of the reversal of the trial court’s decision in our declaratory judgment action against the indenture trustee, we have accrued a loss contingency of $100 million for this matter. We estimate the range of potential loss between $100 million to $380 million, plus prejudgment interest of up to 9%. The high end of this range is based upon the indenture trustee’s request in mid-February 2015 that the Court order us to pay noteholders the “make-whole” amount (as defined in the indenture) less the par amount already paid. Our $100 million accrual is based on an estimate of the remedy required to restore the redeemed noteholders and the Company to the economic positions they would have been in had the 2019 Notes not been redeemed. We are unable to estimate an amount or range of loss with respect to the recently filed putative class action by certain former holders of the 2019 Notes.

Business Operations. Chesapeake is involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. With regard to contract actions, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their oil and natural gas interests and pay acreage bonus payments, damages based on breach of contract and/or, in certain cases, punitive damages based on alleged fraud. The Company has successfully defended a number of these failure-to-close cases in various courts, has settled and resolved other such cases and disputes and believes that its remaining loss exposure for these claims will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. In addition, as described above, the Michigan Attorney General has commenced a criminal proceeding against us based on lease offers to Michigan landowners in 2010.

Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits against us allege, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL. The Company has resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. We are currently defending lawsuits seeking damages for royalty underpayment in various states, including cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The Company also has received DOJ and state subpoenas seeking information on the Company’s royalty payment practices.

Plaintiffs have varying royalty provisions in their respective leases and oil and gas law varies from state to state. Royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations, an issue in a putative class action filed in November 2010 in the District Court of Beaver County, Oklahoma on behalf of Oklahoma royalty owners asserting claims dating back to 2004. In July 2014, this case was remanded to the trial court for further proceedings following the reversal on appeal of certification of a statewide class. We and the named plaintiff participated in mediation concerning the claims asserted in the putative class action litigation and have negotiated a settlement requiring the Company to pay $119 million cash to compensate the putative settlement class for alleged past royalty underpayments in exchange for the release of claims for the ten-year period ended December 31, 2014. The plaintiff filed a motion for preliminary approval of the settlement on January 2, 2015. The Company has accrued a loss contingency for the settlement amount in the 2014 consolidated statement of operations. A fairness hearing on the settlement has been scheduled for April 17, 2015. Although Chesapeake believes that its royalty calculation and payment methodologies are appropriate under Oklahoma oil and gas law and denies that it committed any acts or omissions giving rise to any liability, it also believes that settlement is in the best interest of the Company considering the questions of law and fact involved and the uncertainty of continued litigation. There can be no assurance the court will approve the settlement, however, and the final resolution of the Oklahoma royalty claims could differ from the amount accrued.

We believe losses are reasonably possible in certain of the other pending royalty cases for which we have not accrued a loss contingency, but we are currently unable to estimate an amount or range of loss or the impact the actions could have on our future results of operations or cash flows. In Pennsylvania, three putative statewide class actions and one purported class arbitration have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the Company’s divestiture of substantially all of its midstream business and most of its gathering assets in 2012 and 2013. These Pennsylvania cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and one of the cases includes claims of intentional interference with contractual relations and violations of antitrust laws. Uncertainties in pending royalty cases generally include the complex nature of the claims and defenses, the potential size of the class in class actions, the scope and types of the properties and agreements involved, and the applicable production years.

Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to the Company’s business operations is likely to have a material adverse effect on its future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

Environmental Contingencies

The nature of the oil and gas business carries with it certain environmental risks for Chesapeake and its subsidiaries. Chesapeake has implemented various policies, procedures, training and auditing to reduce and mitigate such environmental risks. Chesapeake conducts periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, Chesapeake may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.

Commitments

Operating Leases

Future operating lease commitments related to other property and equipment are not recorded in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future lease payments are presented below.

	December 31, 2014
	($ in millions)
2015	$	5
2016	4
2017	1
2018	1
Total	$	11

Lease expense for the years ended December 31, 2014, 2013 and 2012 was $33 million, $158 million and $185 million, respectively. Lease expense decreased significantly in 2014 primarily due to the repurchase of all rigs and compressors previously sold under long-term sale-leaseback arrangements.

Gathering, Processing and Transportation Agreements

We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of natural gas and liquids to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded in the accompanying consolidated balance sheets; however, they are reflected as adjustments to oil, natural gas and NGL sales prices used in our proved reserves estimates.

The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners or credits for third-party volumes, are presented below.

	December 31, 2014
	($ in millions)
2015	$	1,855
2016	1,987
2017	2,003
2018	1,802
2019	1,516
2020 - 2099	6,880
Total	$	16,043

In addition to the gathering, processing and transportation agreements discussed above, we have entered into long-term agreements for certain natural gas gathering and related services within specified acreage dedication areas in exchange for cost-of-service based fees redetermined annually or tiered fees based on volumes delivered relative to scheduled volumes. Future gathering fees will vary depending on the applicable agreement. Two of these agreements, one for production in the Anadarko Basin and the other for production in the Haynesville/Bossier Shales in northwestern Louisiana, contain cost-of-service based fees that are redetermined annually through 2019 and 2020, respectively. The annual upward or downward fee adjustment for these two contracts is capped at 15% of the then-current fees at the time of redetermination. To the extent the actual rate of return on capital expended by the counterparty over the term of the agreement differs from the applicable rate of return, a payment is due to (from) the midstream service company.

Drilling Contracts

We have contracts with various drilling contractors, including those entered into with Seventy Seven Energy Inc. (SSE) in connection with the spin-off of our oilfield services business as discussed in Note 13, to utilize drilling services with terms ranging from three months to three years at market-based pricing. These commitments are not recorded in the accompanying consolidated balance sheets. As of December 31, 2014, the aggregate undiscounted minimum future payments under these drilling service commitments are detailed below.

	December 31, 2014
	($ in millions)
2015	$	232
2016	179
2017	91
Total	$	502

Pressure Pumping Contracts

As discussed in Note 13, in connection with the spin-off of our oilfield services business we entered into an agreement with a subsidiary of SSE related to pressure pumping services. The services agreement requires us to utilize, at market-based pricing, the lesser of (i) seven, five and three pressure pumping crews in years one, two and three of the agreement, respectively, or (ii) 50% of the total number of all pressure pumping crews working for us in all of our operating regions during the respective year. We are also required to utilize SSE pressure pumping services for a minimum number of fracture stages as set forth in the agreement. We are entitled to terminate the agreement in certain situations, including if SSE fails to provide the overall quality of service provided by similar service providers. The aggregate undiscounted minimum future payments under this agreement are detailed below.

	December 31, 2014
	($ in millions)
2015	$	245
2016	162
2017	59
Total	$	466

Drilling Commitments

We have committed to drill wells for the benefit of CHK Cleveland Tonkawa, L.L.C. and Chesapeake Granite Wash Trust. See Noncontrolling Interests in Note 8 for discussion of these commitments.

Natural Gas and Liquids Purchase Commitments

We regularly commit to purchase natural gas and liquids from other owners in the properties we operate, including owners associated with our volumetric production payment (VPP) transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices. See Note 12 for further discussion of our VPP transactions.

Net Acreage Maintenance Commitments

Under the terms of our joint venture agreements with Total and Sinopec (see Note 12), we are required to extend, renew or replace expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas as of future measurement dates. To date, we have satisfied our replacement commitments under the Sinopec agreement. In 2014, we settled a dispute with Total regarding our acreage maintenance obligation as of December 31, 2012 for $50 million. The payment was based on a shortfall of approximately 20,800 net acres.

Other Commitments

In July 2011, we agreed to invest $155 million in preferred equity securities of Sundrop Fuels, Inc. (Sundrop), a privately held cellulosic biofuels company based in Longmont, Colorado. We also provided Sundrop with a one-time option to require us to purchase up to $25 million in additional preferred equity securities following the full payment of the initial investment, subject to the occurrence of specified milestones. As of December 31, 2014, we had funded our $155 million commitment in full and the milestones related to Sundrop’s preferred equity call option had not been met. See Note 14 for further discussion of this investment.

As part of our normal course of business, we enter into various agreements providing, or otherwise arranging for, financial or performance assurances to third parties on behalf of our wholly owned guarantor subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance.

In connection with divestitures, our purchase and sale agreements generally provide indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party and/or other specified matters. These indemnifications generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or cannot be quantified at the time of entering into or consummating a particular transaction. For divestitures of oil and gas properties, our purchase and sale agreements may require the return of a portion of the proceeds we receive as a result of uncured title defects.

Certain of our oil and natural gas properties are burdened by non-operating interests such as royalty and overriding royalty interests, including overriding royalty interests sold through our VPP transactions. As the holder of the working interest from which these interests have been created, we have the responsibility to bear the cost of developing and producing the reserves attributable to these interests. See Note 12 for further discussion of our VPP transactions.

While executing our strategic priorities, we have incurred certain cash charges, including contract termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity. As we continue to focus on our strategic priorities, certain actions that may reduce financial leverage and complexity could negatively impact our future results of operations and/or liquidity, and we may incur additional cash and noncash charges.

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Other Liabilities (Note)

12 Months Ended

Dec. 31, 2014

Other Liabilities Disclosure [Abstract]

Other Liabilities Disclosure [Text Block]

Other Liabilities

Other current liabilities as of December 31, 2014 and 2013 are detailed below.

	December 31,
	2014		2013
	($ in millions)
Revenues and royalties due others	$	1,176	$	1,409
Accrued oil, natural gas and NGL drilling and production costs	385		457
Joint interest prepayments received	189		464
Accrued compensation and benefits	344		320
Other accrued taxes	55		161
Accrued dividends	101		101
Other	811		599
Total other current liabilities	$	3,061	$	3,511

Other long-term liabilities as of December 31, 2014 and 2013 are detailed below.

	December 31,
	2014		2013
	($ in millions)
CHK Utica ORRI conveyance obligation(a)	$	220	$	250
CHK C-T ORRI conveyance obligation(b)	135		149
Financing obligations	30		31
Unrecognized tax benefits	45		317
Other	249		237
Total other long-term liabilities	$	679	$	984

____________________________________________

(a) $14 million and $13 million of the total $234 million and $263 million obligations are recorded in other current liabilities as of December 31, 2014 and 2013, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction.

(b) $23 million and $12 million of the total $158 million and $161 million obligations are recorded in other current liabilities as of December 31, 2014 and 2013, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction.

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Related Party Transactions (Note)

12 Months Ended

Dec. 31, 2014

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

Related Party Transactions

Our equity method investees are considered related parties. During 2014, 2013 and 2012, we had the following transactions with our equity method investees:

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
Purchases(a)	$	—	$	—	$	73
Sales(b)	$	—	$	666	$	392
Services(c)	$	220	$	397	$	480

___________________________________________

(a) Purchase of equipment from FTS International, Inc. (FTS).

(b) In 2013 and 2012, Chesapeake sold produced gas to our 30%-owned investee, Twin Eagle Resource Management LLC (Twin Eagle). We sold our investment in Twin Eagle in 2014.

(c) Hydraulic fracturing and other services provided to us by FTS in the ordinary course of business. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs.

The table below shows the total amounts due from and due to our equity method investees.

	December 31,
	2014		2013		2012
	($ in millions)
Amounts due from equity method investees	$	—	$	47	$	67
Amounts due to equity method investees	$	—	$	1	$	42

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Debt - Senior Notes and Contingent Convertible Senior Notes Purchased Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Apr. 24, 2014
Long-Term Debt Instrument [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	50.00%
Long-term Debt, Gross	$ 11,756,000,000
Proceeds from issuance of senior notes, net of discount and offering costs	3,460,000,000
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	100.00%
Long-term Debt, Gross	3,000,000,000		3,000,000,000
Debt Instrument, Face Amount		2,300,000,000
Proceeds from issuance of senior notes, net of discount and offering costs	2,966,000,000	2,274,000,000
Debt Instrument, Repurchase Amount		405,000,000
Gain (Loss) on Repurchase of Debt Instrument		37,000,000
Senior Notes [Member] | Premium on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		32,000,000
Senior Notes [Member] | Unamortized Deferred Charges on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		5,000,000
Minimum [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	50,000,000
Maximum [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	75,000,000
2.5% Contingent Convertible Senior Notes due 2037 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,168,000,000	1,168,000,000
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Debt Instrument, Interest Rate, Effective Percentage	8.00%
2.75% Contingent Convertible Senior Notes Due 2035 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	396,000,000	396,000,000
Debt Instrument, Interest Rate, Stated Percentage	2.75%
Debt Instrument, Interest Rate, Effective Percentage	6.86%
2.25% Contingent Convertible Senior Notes Due 2038 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	347,000,000	347,000,000
Debt Instrument, Interest Rate, Stated Percentage	2.25%
Debt Instrument, Interest Rate, Effective Percentage	8.00%
Floating Rate Senior Notes due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,500,000,000	0
4.875% Senior Notes due 2022 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,500,000,000	0
Debt Instrument, Interest Rate, Stated Percentage	4.875%
3.25% Senior Notes due 2016 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	500,000,000	500,000,000
Debt Instrument, Interest Rate, Stated Percentage	3.25%	3.25%
5.375% Senior Notes due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	700,000,000	700,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.375%	5.375%
5.75% Senior Notes due 2023 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,100,000,000	1,100,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.75%	5.75%
7.625% Senior Notes Due 2013 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		247,000,000
Debt Instrument, Interest Rate, Stated Percentage		7.625%
Debt Instrument, Repurchase Amount		221,000,000
Debt Instrument, Repurchased Face Amount		217,000,000
6.875% Senior Notes Due 2018 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	97,000,000
Debt Instrument, Interest Rate, Stated Percentage	6.875%	6.875%
Debt Instrument, Repurchased Face Amount	97,000,000	377,000,000
Gain (Loss) on Repurchase of Debt Instrument	6,000,000
6.875% Senior Notes Due 2018 [Member] | Senior Notes [Member] | Premium on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument	5,000,000
6.875% Senior Notes Due 2018 [Member] | Senior Notes [Member] | Unamortized Deferred Charges on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument	1,000,000
9.5% Senior Notes Due 2015 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	1,265,000,000
Debt Instrument, Interest Rate, Stated Percentage	9.50%
Debt Instrument, Repurchased Face Amount	1,265,000,000	1,454,000,000
Gain (Loss) on Repurchase of Debt Instrument	99,000,000
9.5% Senior Notes Due 2015 [Member] | Senior Notes [Member] | Premium on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument	87,000,000
9.5% Senior Notes Due 2015 [Member] | Senior Notes [Member] | Unamortized Discount on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument	9,000,000
9.5% Senior Notes Due 2015 [Member] | Senior Notes [Member] | Unamortized Deferred Charges on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument	3,000,000
6.775% Senior Notes Due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.775%
Prejudgment Interest Statutory Rate	9.00%
Debt Instrument, Repurchased Face Amount		1,300,000,000
Gain (Loss) on Repurchase of Debt Instrument		33,000,000
6.775% Senior Notes Due 2019 [Member] | Senior Notes [Member] | Unamortized Discount on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		14,000,000
6.775% Senior Notes Due 2019 [Member] | Senior Notes [Member] | Unamortized Deferred Charges on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		$ 19,000,000

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Impairments Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	$ 88	$ 546	$ 340
Natural Gas Compressors [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	11	0	0
Gathering and Processing Equipment [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	13	22	6
Exploration and Production Equipment [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	23	71	60
Land and Building [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	18	366	248
Other Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	$ 23	$ 87	$ 26

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Equity - AOCI Changes Net of Tax Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	$ (162)
Net current period other comprehensive income	19	20	(16)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(143)	(162)
Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	(162)	(182)
Other comprehensive income before reclassifications	1	(4)
Amounts reclassified from accumulated other comprehensive income	18	24
Net current period other comprehensive income	19	20
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(143)	(162)
Accumulated Other Comprehensive Income (Loss) [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	(167)	(189)
Other comprehensive income before reclassifications	1	2
Amounts reclassified from accumulated other comprehensive income	23	20
Net current period other comprehensive income	24	22
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(143)	(167)
Accumulated Other Comprehensive Income (Loss) [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	5	7
Other comprehensive income before reclassifications	0	(6)
Amounts reclassified from accumulated other comprehensive income	(5)	4
Net current period other comprehensive income	(5)	(2)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	$ 0	$ 5

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Debt - Spin-Off Debt Transactions (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended	6 Months Ended	12 Months Ended
	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013	Apr. 24, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross	$ 11,756
Credit Facility Commitment Period	10 years
Proceeds from issuance of senior notes, net of discount and offering costs	3,460
Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Commitment Period		7 years
Seven Seven Energy Inc. Revolving Bank Credit Facility [Member] | Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Borrowing capacity		275
Payments of Financing Costs		3
Commitment Period		5 years
Secured Debt [Member] | Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross		400
Proceeds from Issuance of Secured Debt		394
Senior Notes [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross	3,000			3,000
Proceeds from issuance of senior notes, net of discount and offering costs	2,966		2,274
6.5% Senior Notes Due 2022 [Member] | Senior Notes [Member] | Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross		500
Debt Instrument, Interest Rate, Stated Percentage		6.50%
Proceeds from issuance of senior notes, net of discount and offering costs		494
General Partner Distributions		391

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Derivative and Hedging Activities - Components of Interest Income and Interest Expense Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Interest expense on senior notes	$ 704	$ 740	$ 732
Interest expense on term loans	36	116	173
Amortization of loan discount, issuance costs and other	42	91	89
Interest expense on credit facilities	28	38	70
Gains on terminated fair value hedges	(3)	(5)	(8)
(Gains) losses on undesignated interest rate derivatives	(81)	63	1
Capitalized interest	(637)	(816)	(980)
Total interest expense	$ 89	$ 227	$ 77

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Debt - Term Loans Narrative (Details) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012	Nov. 07, 2012	Apr. 24, 2014
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 11,756,000,000
Gains (Losses) on Extinguishment of Debt	(63,000,000)	(40,000,000)	(200,000,000)
Unsecured Debt [Member]
Long-Term Debt Instrument [Line Items]
Commitment Period				5 years
Unsecured Debt					2,000,000,000
Proceeds from Issuance of Unsecured Debt				1,935,000,000
Gains (Losses) on Extinguishment of Debt	90,000,000
Unsecured Debt [Member] | Premium on Extinguishment of Term Loan Debt [Member]
Long-Term Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt	40,000,000
Unsecured Debt [Member] | Unamortized Discount on Extinguishment of Term Loan Debt [Member]
Long-Term Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt	30,000,000
Unsecured Debt [Member] | Unamortized Deferred Charges on Extinguishment of Term Loan Debt [Member]
Long-Term Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt	20,000,000
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 3,000,000,000					$ 3,000,000,000

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Share-Based Compensation - Stock Option Activity Table (Details) (USD $) In Millions, except Share data in Thousands, unless otherwise specified	0 Months Ended	12 Months Ended
	Dec. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number Period Start		5,268	481	1,051
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures		994	5,264
Share Based Compensation Arrangement By Share Based Payment Award Shares Underlying Options Exercised In Period		(1,322)	(346)	(570)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period		(28)	(131)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested Options Forfeited, Number of Shares		(313)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number Period End		4,599	5,268	481	1,051
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number		1,304	1,552
Weighted Average Exercise Price [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period Start		$ 19.28	$ 12.69	$ 9.84
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 24.43	$ 19.32
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price		$ 18.71	$ 10.82	$ 7.45
Share-based Compensation Arrangements by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price		$ 18.97	$ 19.31
Share-based Compensation Arrangements by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price		$ 21.05
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period End		$ 19.55	$ 19.28	$ 12.69	$ 9.84
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price		$ 18.71	$ 18.82
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period Start		$ 41	$ 2	$ 13
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value		11	3	7
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period End		5	41	2	13
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value		$ 1	$ 13
Weighted Average Contract Life (in years) [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	6 years 7 months 29 days	7 years 12 days		11 months 16 days	1 year 4 months 28 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term		5 years 8 months 13 days	1 year 11 months 19 days

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Condensed Consolidating Financial Information -Statement Of Operations Table (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	12 Months Ended
	Sep. 30, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES
Oil, natural gas and NGL		$ 8,180	$ 7,052	$ 6,278
Marketing, gathering and compression		12,225	9,559	5,431
Oilfield services		546	895	607
Total Revenues		20,951	17,506	12,316
OPERATING EXPENSES
Oil, natural gas and NGL production		1,208	1,159	1,304
Production taxes		232	229	188
Marketing, gathering and compression		12,236	9,461	5,312
Oilfield services		431	736	465
General and administrative		322	457	535
Restructuring and other termination costs		7	248	7
Provision for legal contingencies		234	0	0
Oil, natural gas and NGL depreciation, depletion and amortization		2,683	2,589	2,507
Depreciation and amortization of other assets		232	314	304
Impairment of oil and natural gas properties	3,315	0	0	3,315
Impairments of fixed assets and other		88	546	340
Net gains on sales of fixed assets		(199)	(302)	(267)
Total Operating Expenses		17,474	15,437	14,010
INCOME FROM OPERATIONS		3,477	2,069	(1,694)
OTHER INCOME (EXPENSE):
Interest expense		(89)	(227)	(77)
Losses on investments		(80)	(226)	(103)
Net gain (loss) on sales of investments		67	(7)	1,092
Losses on purchases of debt		(197)	(193)	(200)
Other income		22	26	8
Equity in net earnings (losses) of subsidiary		0	0
Total Other Expense		(277)	(627)	720
Income (Loss) Before Income Taxes		3,200	1,442	(974)
INCOME TAX EXPENSE (BENEFIT)		1,144	548	(380)
NET INCOME		2,056	894	(594)
Net income attributable to noncontrolling interests		(139)	(170)	(175)
Net income (loss) attributable to Chesapeake		1,917	724	(769)
Other Comprehensive Income (Loss), Net of Tax		19	20	(16)
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE		1,936	744	(785)
Parent Company Member]
REVENUES
Oil, natural gas and NGL		0	0	0
Marketing, gathering and compression		0	0	0
Oilfield services		0	0	0
Total Revenues		0	0	0
OPERATING EXPENSES
Oil, natural gas and NGL production		0	0	0
Production taxes		0	0	0
Marketing, gathering and compression		0	0	0
Oilfield services		0	0	0
General and administrative		0	0	0
Restructuring and other termination costs		0	0	0
Provision for legal contingencies		100
Oil, natural gas and NGL depreciation, depletion and amortization		0	0	0
Depreciation and amortization of other assets		0	0	0
Impairment of oil and natural gas properties		0	0	0
Impairments of fixed assets and other		0	0	0
Net gains on sales of fixed assets		0	0	0
Total Operating Expenses		100	0	0
INCOME FROM OPERATIONS		(100)	0	0
OTHER INCOME (EXPENSE):
Interest expense		(657)	(921)	(879)
Losses on investments		0	0	0
Net gain (loss) on sales of investments		0	0	0
Losses on purchases of debt		(195)	(70)	(200)
Other income		502	3,979	819
Equity in net earnings (losses) of subsidiary		2,206	(1,129)	(610)
Total Other Expense		1,856	1,859	(870)
Income (Loss) Before Income Taxes		1,756	1,859	(870)
INCOME TAX EXPENSE (BENEFIT)		(161)	1,135	(101)
NET INCOME		1,917	724	(769)
Net income attributable to noncontrolling interests		0	0	0
Net income (loss) attributable to Chesapeake		1,917	724	(769)
Other Comprehensive Income (Loss), Net of Tax		1	3	6
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE		1,918	727	(763)
Guarantor Subsidiaries [Member]
REVENUES
Oil, natural gas and NGL		7,765	6,439	5,920
Marketing, gathering and compression		12,220	9,547	5,218
Oilfield services		41	221	154
Total Revenues		20,026	16,207	11,292
OPERATING EXPENSES
Oil, natural gas and NGL production		1,166	1,112	1,278
Production taxes		227	222	182
Marketing, gathering and compression		12,232	9,455	5,197
Oilfield services		53	239	301
General and administrative		273	375	431
Restructuring and other termination costs		4	244	5
Provision for legal contingencies		134
Oil, natural gas and NGL depreciation, depletion and amortization		2,523	2,336	2,353
Depreciation and amortization of other assets		153	180	187
Impairment of oil and natural gas properties		0	(2)	3,192
Impairments of fixed assets and other		65	417	275
Net gains on sales of fixed assets		(192)	(301)	(269)
Total Operating Expenses		16,638	14,277	13,132
INCOME FROM OPERATIONS		3,388	1,930	(1,840)
OTHER INCOME (EXPENSE):
Interest expense		(37)	(4)	45
Losses on investments		(77)	(225)	(167)
Net gain (loss) on sales of investments		67	(7)	29
Losses on purchases of debt		(2)	(123)	0
Other income		198	(603)	203
Equity in net earnings (losses) of subsidiary		(258)	(383)	436
Total Other Expense		(109)	(1,345)	546
Income (Loss) Before Income Taxes		3,279	585	(1,294)
INCOME TAX EXPENSE (BENEFIT)		1,264	370	(675)
NET INCOME		2,015	215	(619)
Net income attributable to noncontrolling interests		0	0	0
Net income (loss) attributable to Chesapeake		2,015	215	(619)
Other Comprehensive Income (Loss), Net of Tax		18	19	(22)
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE		2,033	234	(641)
Non-Guarantor Subsidiaries [Member]
REVENUES
Oil, natural gas and NGL		418	553	351
Marketing, gathering and compression		5	12	212
Oilfield services		983	1,836	1,553
Total Revenues		1,406	2,401	2,116
OPERATING EXPENSES
Oil, natural gas and NGL production		42	47	26
Production taxes		5	7	6
Marketing, gathering and compression		4	6	115
Oilfield services		769	1,434	1,096
General and administrative		49	83	105
Restructuring and other termination costs		3	4	2
Provision for legal contingencies		0
Oil, natural gas and NGL depreciation, depletion and amortization		162	253	154
Depreciation and amortization of other assets		143	281	266
Impairment of oil and natural gas properties		349	313	123
Impairments of fixed assets and other		23	129	65
Net gains on sales of fixed assets		(7)	(1)	2
Total Operating Expenses		1,542	2,556	1,960
INCOME FROM OPERATIONS		(136)	(155)	156
OTHER INCOME (EXPENSE):
Interest expense		(42)	(85)	(84)
Losses on investments		(5)	(1)	55
Net gain (loss) on sales of investments		0	0	1,063
Losses on purchases of debt		0	0	0
Other income		(2)	13	14
Equity in net earnings (losses) of subsidiary		0	0	0
Total Other Expense		(49)	(73)	1,048
Income (Loss) Before Income Taxes		(185)	(228)	1,204
INCOME TAX EXPENSE (BENEFIT)		(66)	(87)	470
NET INCOME		(119)	(141)	734
Net income attributable to noncontrolling interests		0	0	0
Net income (loss) attributable to Chesapeake		(119)	(141)	734
Other Comprehensive Income (Loss), Net of Tax		0	(2)	0
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE		(119)	(143)	734
Eliminations [Member]
REVENUES
Oil, natural gas and NGL		(3)	60	7
Marketing, gathering and compression		0	0	1
Oilfield services		(478)	(1,162)	(1,100)
Total Revenues		(481)	(1,102)	(1,092)
OPERATING EXPENSES
Oil, natural gas and NGL production		0	0	0
Production taxes		0	0	0
Marketing, gathering and compression		0	0	0
Oilfield services		(391)	(937)	(932)
General and administrative		0	(1)	(1)
Restructuring and other termination costs		0	0	0
Provision for legal contingencies		0
Oil, natural gas and NGL depreciation, depletion and amortization		(2)	0	0
Depreciation and amortization of other assets		(64)	(147)	(149)
Impairment of oil and natural gas properties		(349)	(311)	0
Impairments of fixed assets and other		0	0	0
Net gains on sales of fixed assets		0	0	0
Total Operating Expenses		(806)	(1,396)	(1,082)
INCOME FROM OPERATIONS		325	294	(10)
OTHER INCOME (EXPENSE):
Interest expense		647	783	841
Losses on investments		2	0	9
Net gain (loss) on sales of investments		0	0	0
Losses on purchases of debt		0	0	0
Other income		(676)	(3,363)	(1,028)
Equity in net earnings (losses) of subsidiary		(1,948)	1,512	174
Total Other Expense		(1,975)	(1,068)	(4)
Income (Loss) Before Income Taxes		(1,650)	(774)	(14)
INCOME TAX EXPENSE (BENEFIT)		107	(870)	(74)
NET INCOME		(1,757)	96	60
Net income attributable to noncontrolling interests		(139)	(170)	(175)
Net income (loss) attributable to Chesapeake		(1,896)	(74)	(115)
Other Comprehensive Income (Loss), Net of Tax		0	0	0
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE		$ (1,896)	$ (74)	$ (115)

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Variable Interest Entities (Policies)

12 Months Ended

Dec. 31, 2014

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

Consolidation, Variable Interest Entity, Policy [Policy Text Block]

Variable Interest Entities

VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

Along with a VIE that we consolidate, we also hold a variable interest in another VIE that is not consolidated because we are not the primary beneficiary. We continually monitor both our consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs.

We consolidate the activities of VIEs for which we are the primary beneficiary. In order to determine whether we own a variable interest in a VIE, we perform qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:

	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Fair Value
			($ in millions)
As of December 31, 2014
Derivative Assets (Liabilities):
Commodity assets	$	—	$	785		$	205		$	990
Commodity liabilities	—		(9		)	(259		)	(268		)
Interest rate liabilities	—		(17		)	—			(17		)
Foreign currency liabilities	—		(53		)	—			(53		)
Total derivatives	$	—	$	706		$	(54	)	$	652
As of December 31, 2013
Derivative Assets (Liabilities):
Commodity assets	$	—	$	25		$	15		$	40
Commodity liabilities	—		(100		)	(493		)	(593		)
Interest rate liabilities	—		(98		)	—			(98		)
Foreign currency assets	—		2			—			2
Total derivatives	$	—	$	(171	)	$	(478	)	$	(649	)

The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:

	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value
				($ in millions)
As of December 31, 2014
Financial Assets (Liabilities):
Other current assets	$	57		$	—	$	—	$	57
Other current liabilities	(58		)	—		—		(58		)
Total	$	(1	)	$	—	$	—	$	(1	)
As of December 31, 2013
Financial Assets (Liabilities):
Other current assets	$	80		$	—	$	—	$	80
Other current liabilities	(82		)	—		—		(82		)
Total	$	(2	)	$	—	$	—	$	(2	)

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Natural Gas and Oil Property Transactions (Note)

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Mergers, Acquisitions and Dispositions Disclosure [Text Block]

Oil and Natural Gas Property Transactions

Under full cost accounting rules, we have accounted for the sale of oil and natural gas properties as an adjustment to capitalized costs, with no recognition of gain or loss as the sales have not involved a significant change in proved reserves or significantly altered the relationship between costs and proved reserves.

2014 Transactions

We sold certain assets in the southern Marcellus Shale and a portion of the eastern Utica Shale to a subsidiary of Southwestern Energy Company for aggregate net proceeds of approximately $4.975 billion. We sold approximately 413,000 net acres and approximately 1,500 wells in northern West Virginia and southern Pennsylvania, of which 435 wells are in the Marcellus or Utica formations, along with related gathering assets and property, plant and equipment.

We exchanged interests in approximately 440,000 gross acres in the Powder River Basin in southeastern Wyoming with RKI Exploration & Production, LLC (RKI). Under the agreement, we conveyed to RKI approximately 137,000 net acres and our interest in 67 gross wells with an average working interest of approximately 22% in the northern portion of the Powder River Basin, where RKI is currently designated operator. In exchange, RKI conveyed to us approximately 203,000 net acres and its interest in 186 gross wells with an average working interest of 48% in the southern portion of the Powder River Basin, where we are currently designated operator. In addition to the exchange, we paid RKI approximately $450 million in cash.

We sold noncore leasehold interests in the Marcellus Shale to a subsidiary of Rice Energy Inc. for net proceeds of approximately $233 million.

We sold noncore leasehold interests, producing properties and 61 wellhead compressor units in South Texas to Hilcorp Energy Company for net proceeds of approximately $133 million. All commitments related to VPP #5 were also transferred. See Volumetric Production Payments below.

We sold noncore leasehold interests and producing properties in East Texas and Louisiana for net proceeds of approximately $63 million. All commitments related to VPP #6 were also transferred. See Volumetric Production Payments below.

Excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds of approximately $379 million related to the divestiture of various other oil and natural gas properties.

2013 Transactions

We sold a wholly owned subsidiary, MKR Holdings, L.L.C. (MKR), to Chief Oil and Gas and two of its working interest partners, Enerplus Corporation and Tug Hill Operating. Net proceeds from the transaction were approximately $490 million. MKR held producing wells and undeveloped acreage in the Marcellus Shale.

We sold assets in the Haynesville Shale to EXCO Operating Company, LP (EXCO) for net proceeds of approximately $257 million. Subsequent to closing, we received approximately $47 million of additional net proceeds for post-closing adjustments. The assets sold included our operated and non-operated interests in approximately 9,600 net acres in DeSoto and Caddo parishes, Louisiana.

We sold noncore leasehold interests and producing properties in the northern Eagle Ford Shale to EXCO for net proceeds of approximately $617 million. Subsequent to closing, we received approximately $57 million and $32 million in 2014 and 2013, respectively, of additional net proceeds and for post-closing adjustments. The assets sold included approximately 55,000 net acres in Zavala, Dimmit, La Salle and Frio counties, Texas.

2012 Transactions

We sold the vast majority of our Permian Basin assets, representing approximately 6% of our total proved reserves as of June 30, 2012, in three separate transactions for total net cash proceeds of approximately $3.091 billion. Following the closing, we received $466 million of additional consideration that was withheld subject to certain title, environmental and other standard contingencies. Of the total proceeds, we allocated approximately $42 million to our Permian Basin midstream and other fixed assets. The remaining proceeds were allocated to our Permian Basin oil and natural gas properties.

We sold approximately 40,000 net acres of noncore leasehold in the Chitwood Knox play in Oklahoma for approximately $540 million in cash.

We sold approximately 72,000 net acres of noncore leasehold in the Utica Shale play in Ohio to affiliates of EnerVest, Ltd. for approximately $358 million in cash.

We sold approximately 60,000 net acres of leasehold in the Texoma Woodford play in Oklahoma to XTO Energy Inc., a subsidiary of Exxon Mobil Corporation, for net proceeds of approximately $572 million.

Joint Ventures

Between July 2008 and June 2013, we entered into eight significant joint ventures with other leading energy companies including Sinopec International Petroleum Exploration and Production (Sinopec), Total S.A. (Total), CNOOC Limited, Statoil, BP America and Freeport-McMoRan Copper & Gold (formerly known as Plains Exploration & Production Company), pursuant to which we sold portions ranging from 20% to 50% of certain leasehold, producing properties and other assets located in eight different resource plays. In return, we received aggregate cash proceeds of $8.0 billion and commitments by our joint venture partners to pay, in the aggregate, our share of future drilling and completion costs of $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all drilling, completion and operations, the majority of leasing and, in certain transactions, marketing activities for the project. Each joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner and, if applicable, pays a specified percentage of our drilling and completion costs in designated wells. As of December 31, 2014, we had utilized all drilling carries from our joint venture partners except for Total’s remaining $51 million commitment to pay 60% of our drilling and completion costs for wells drilled in the Utica Shale play. We fully expect to use this drilling carry commitment prior to its expiration in December 2018.

In 2014, 2013 and 2012, our drilling and completion costs included the benefit of approximately $679 million, $884 million and $784 million, respectively, in drilling and completion carries paid by our joint venture partners.

In 2013, we entered into a joint venture with Sinopec in which Sinopec purchased a 50% undivided interest in approximately 850,000 acres in the Mississippian Lime play in northern Oklahoma for $1.11 billion, including $90 million we received for closing adjustments and $71 million placed in escrow with respect to certain post-closing adjustments. As of December 31, 2014, we had received $64 million of the $71 million held in escrow. There was no drilling and completion carry associated with this transaction.

In addition, in 2014, 2013 and 2012, we sold interests in additional leasehold we acquired in the Marcellus, Barnett, Utica, Eagle Ford and Mid-Continent plays to our joint venture partners for approximately $33 million, $58 million and $272 million, respectively.

Volumetric Production Payments

From time to time, we have sold certain of our producing assets located in more mature producing regions through the sale of VPPs. A VPP is a limited-term overriding royalty interest in oil and natural gas reserves that (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser’s only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain all production beyond the specified volumes, if any, after the scheduled production volumes have been delivered. For all of our VPP transactions, we have novated hedges to each of the respective VPP buyers and these hedges covered all VPP volumes sold. If contractually scheduled volumes exceed the actual volumes produced from the VPP wellbores that are attributable to the ORRI conveyed, either the shortfall will be made up from future production from these wellbores (or, at our option, from our retained interest in the wellbores) through an adjustment mechanism, or the initial term of the VPP will be extended until all scheduled volumes, to the extent produced, are delivered from the VPP wellbores to the VPP buyer. We retain drilling rights on the properties below currently producing intervals and outside of producing wellbores.

As the operator of the properties from which the VPP volumes have been sold, we bear the cost of producing the reserves attributable to these interests, which we include as a component of production expenses and production taxes in our consolidated statements of operations in the periods these costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining our full cost ceiling test for impairment purposes and in determining our standardized measure. Pursuant to SEC guidelines, the estimates used for purposes of determining the cost center ceiling and the standardized measure are based on current costs. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet. The costs that will apply in the future will depend on the actual production volumes as well as the production costs and taxes in effect during the periods in which the production actually occurs, which could differ materially from our current and historical costs, and production may not occur at the times or in the quantities projected, or at all.

For accounting purposes, cash proceeds from the sale of VPPs were reflected as a reduction of oil and natural gas properties with no gain or loss recognized, and our proved reserves were reduced accordingly. We have also committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices.

As of December 31, 2014, our outstanding VPPs consisted of the following:

					Volume Sold
VPP #	Date of VPP	Location	Proceeds		Oil	Natural Gas	NGL	Total
			($ in millions)		(mmbbl)	(bcf)	(mmbbl)	(bcfe)
10	March 2012	Anadarko Basin Granite Wash	$	744	3.0	87	9.2	160
9	May 2011	Mid-Continent	853		1.7	138	4.8	177
8	September 2010	Barnett Shale	1,150		—	390	—	390
4	December 2008	Anadarko and Arkoma Basins	412		0.5	95	—	98
3	August 2008	Anadarko Basin	600		—	93	—	93
2	May 2008	Texas, Oklahoma and Kansas	622		—	94	—	94
1	December 2007	Kentucky and West Virginia	1,100		—	208	—	208
			$	5,481	5.2	1,105	14.0	1,220

The volumes produced on behalf of our VPP buyers during 2014, 2013 and 2012 were as follows:

	Year Ended December 31, 2014
VPP #	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)
10	403.0	10.6	1,296.5	20.7
9	187.5	15.4	411.0	19.0
8	—	60.1	—	60.1
6(a)	23.1	4.2	—	4.3
5(a)	16.5	4.6	—	4.7
4	48.1	9.0	—	9.2
3	—	7.2	—	7.2
2	—	6.2	—	6.2
1	—	13.8	—	13.8
	678.2	131.1	1,707.5	145.2
	Year Ended December 31, 2013
VPP #	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)
10	547.0	13.5	1,509.0	25.8
9	213.2	17.0	455.7	21.0
8	—	68.1	—	68.1
6	24.0	4.8	—	4.9
5	25.4	7.5	—	7.7
4	54.7	10.2	—	10.5
3	—	8.1	—	8.1
2	—	10.3	—	10.3
1	—	14.5	—	14.5
	864.3	154.0	1,964.7	170.9
	Year Ended December 31, 2012
VPP #	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)
10	727.0	18.1	1,729.1	32.8
9	249.3	18.4	643.6	23.7
8	—	79.7	—	79.7
7(b)	490.3	0.4	—	3.4
6	24.0	5.3	—	5.5
5	27.4	8.8	—	9.0
4	62.8	11.7	—	12.2
3	—	9.3	—	9.3
2	—	11.4	—	11.3
1	—	15.3	—	15.3
	1,580.8	178.4	2,372.7	202.2

____________________________________________

(a) In 2014, we divested the properties associated with VPP #5 and VPP #6.

(b) In 2012, to facilitate the sales process associated with our Permian Basin divestiture packages, we purchased the remaining reserves from our Permian Basin VPP (VPP #7). The reserves purchased were subsequently sold to the buyers of our Permian Basin assets.

The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2014 were as follows:

		Volume Remaining as of December 31, 2014
VPP #	Term Remaining	Oil	Natural Gas	NGL	Total
	(in months)	(mmbbl)	(bcf)	(mmbbl)	(bcfe)
10	86	1.3	38.0	4.7	74.0
9	74	0.8	73.2	1.9	89.9
8	8	—	36.6	—	36.6
4	24	0.1	15.3	—	15.8
3	55	—	23.9	—	23.9
2	52	—	13.8	—	13.8
1	96	—	91.5	—	91.5
		2.2	292.3	6.6	345.5

XML

Variable Interest Entities - Narrative (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 4,108	$ 837	$ 287	$ 351
Short-term derivative assets	879	0
Proved natural gas and oil properties	58,594	56,157
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	39,043	37,161
Other Liabilities, Current	3,061	3,511
Variable Interest Entities, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	1	1
Short-term derivative assets	16	0
Proved natural gas and oil properties	488	488
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	251	168
Other Liabilities, Current	15	22
Corporate Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Percentage of acquisition	10.00%
Carrying value of investment	9
Corporate Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. [Member] | Minimum [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Royalty percentage minimum	7.00%
Royalty percentage maximum	7.00%
Corporate Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. [Member] | Maximum [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Other Commitment	25
Royalty percentage minimum	22.50%
Royalty percentage maximum	22.50%
Partner Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Percentage of acquisition	90.00%
Partner Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. [Member] | Maximum [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Other Commitment	$ 225

XML

Impairments (Note)

12 Months Ended

Dec. 31, 2014

Asset Impairment Charges [Abstract]

Asset Impairment Charges [Text Block]

Impairments

Impairments of Oil and Natural Gas Properties

Our oil and natural gas properties are subject to quarterly full cost ceiling tests. As of September 30, 2012, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment in the carrying value of oil and natural gas properties of $3.315 billion. Cash flow hedges as of September 30, 2012, which related to future periods, increased the ceiling test impairment by $279 million. We were not required to record impairments of oil and natural gas properties for any other quarter in 2012 or for any quarters in 2013 or 2014. Based on the decline in oil and natural gas prices in the second half of 2014 and into 2015, we expect to have a material write-down of the carrying value of our oil and natural gas properties in the 2015 first quarter. Further material write-downs in subsequent quarters will occur if the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters.

Impairments of Fixed Assets and Other

We review our long-lived assets, other than oil and natural gas properties, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable. We recognize an impairment loss if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2014, 2013 and 2012 is as follows:

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
Natural gas compressors	$	11	$	—	$	—
Gathering systems and treating plants	13		22		6
Oilfield services equipment	23		71		60
Buildings and land	18		366		248
Other	23		87		26
Total impairments of fixed assets and other	$	88	$	546	$	340

Oilfield Services Equipment. In 2014, we purchased 31 leased rigs and equipment from various lessors for an aggregate purchase price of $140 million. In connection with these purchases, we paid $8 million in early lease termination costs, which are included in impairments of fixed assets and other in the consolidated statement of operations. We recognized an impairment loss of approximately $15 million related to leasehold improvements associated with these assets. In 2013, we purchased 23 leased rigs (two of which were classified as held for sale assets as of December 31, 2013) from various lessors for an aggregate purchase price of $141 million and paid approximately $22 million in early lease termination costs, which is included in impairments of fixed assets and other in the consolidated statement of operations. In addition, we impaired approximately $22 million related to leasehold improvements and other costs associated with these assets. In 2013, we also recognized $27 million of impairment losses on certain of our drilling rigs that qualified as held for sale during 2013 for the difference between the carrying amount and fair value, less the anticipated costs to sell. We estimated the fair value using prices expected to be received. In 2012, we purchased 25 leased rigs from various lessors for an aggregate purchase price of $36 million and paid approximately $25 million in early lease termination costs, which is included in impairments of fixed assets and otherin the consolidated statement of operations. In addition, in 2012, we recognized $26 million of impairment losses on certain of our drilling rigs that we expected would have insufficient cash flow to recover carrying values because of a change in business climate resulting from depressed natural gas prices. In 2012, we also recognized $9 million of impairment losses primarily related to drill pipe and other oilfield services equipment.

Buildings and Land. In 2013, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. We recognized an impairment loss of $186 million on these assets for the difference between the carrying amount and fair value of the assets, less the anticipated costs to sell. Given the impairment losses associated with these assets, we tested other noncore buildings and land that we owned in the Oklahoma City area for recoverability. As a result of this test, we recognized an impairment loss of $69 million on these assets in 2013.

Due to a decrease in the estimated market prices of certain property classified as held for sale in the Fort Worth area, we recognized an additional impairment loss of $86 million in 2013. We tested other noncore surface land that we owned in the Fort Worth area for recoverability in 2013 and recognized an additional impairment loss of $10 million on these assets for the difference between the carrying amount and fair value of the assets. In addition, in 2012, we recognized $248 million of impairment losses associated with an office building and surface land located in our Barnett Shale operating area. The change in business climate in the Barnett Shale in 2012, evidenced by our significant reduction in Barnett Shale operations and depressed natural gas prices, required us to test these long-lived assets for recoverability. 

Finally, we recorded an impairment loss of approximately $15 million on certain of our buildings and land outside of the Oklahoma City and Fort Worth areas in 2013. All the buildings and land for which impairment losses were recognized in 2014, 2013 and 2012 are included in our other segment.

Other. Under the terms of our joint venture agreements (see Note 12), we are required to extend, renew or replace certain expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas. In 2014, we revised our estimate of our net acreage shortfall as of December 31, 2012 under the terms of our Barnett Shale joint venture agreement with Total and recorded an additional $22 million charge. See Note 4 for additional discussion regarding our net acreage maintenance commitments. In 2013, we recorded approximately $87 million of other charges, including $26 million for the termination of a gas gathering agreement, $28 million for the impairment of certain assets used to promote natural gas demand, $15 million for the termination of a contract drilling agreement with a third party, $2 million related to the estimated 2012 shortfall of our net acreage maintenance commitment with Total in the Barnett Shale and $16 million related to various other assets. In 2012, we recorded a $26 million charge related to the estimated 2012 shortfall of our net acreage maintenance commitment with Total in the Barnett Shale.

Nonrecurring Fair Value Measurements. Fair value measurements for certain of the impairments discussed above were based on recent sales information for comparable assets. As the fair value was estimated using the market approach based on recent prices from orderly sales transactions for comparable assets between market participants, the values were classified as Level 2 in the fair value hierarchy. Fair value measurements of the buildings and land discussed above were based on prices from orderly sales transactions for comparable properties between market participants, purchase offers we received from third parties and, in certain cases, discounted cash flows. As some inputs used were not observable in the market, these values were classified as Level 3 in the fair value hierarchy.

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Share-Based Compensation - Performance Share Unit Breakout (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 104	$ 150	$ 191
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	(1)	48	14
Performance Shares [Member] | Year of 2012 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	11	2
Performance Shares [Member] | Payable 2015 [Member] | Year of 2012 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	884,507
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	12
Fair Value of Share Based Award	12		23
Performance Shares [Member] | Payable 2016 [Member] | Year of 2013 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	1,701,941
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	39
Fair Value of Share Based Award	42		35
Performance Shares [Member] | Payable 2017 [Member] | Year of 2014 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	609,637
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	7
Fair Value of Share Based Award	$ 10		$ 16

XML

Impairments (Tables)

12 Months Ended

Dec. 31, 2014

Asset Impairment Charges [Abstract]

Details of Impairment of Long-Lived Assets Held and Used by Asset [Table Text Block]

A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2014, 2013 and 2012 is as follows:

	Years Ended December 31,
	2014		2013		2012
	($ in millions)
Natural gas compressors	$	11	$	—	$	—
Gathering systems and treating plants	13		22		6
Oilfield services equipment	23		71		60
Buildings and land	18		366		248
Other	23		87		26
Total impairments of fixed assets and other	$	88	$	546	$	340

XML

Derivative and Hedging Activities - Fair Value Level 3 Measurements Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Interest Rate Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, End of Period		$ 0
Fair Value, Inputs, Level 3 [Member] | Natural Gas And Oil Sales [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	262	382
Fair Value, Inputs, Level 3 [Member] | Interest Expense [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	0	0
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Beginning of Period	(478)	(1,016)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	292	410
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	136	128
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	(4)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, End of Period	(54)	(478)
Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Beginning of Period	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	0	(1)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales		1
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, End of Period	$ 0	$ 0

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

The components of the income tax provision (benefit) for each of the periods presented below are as follows:

	Years Ended December 31,
	2014			2013		2012
	($ in millions)
Current
Federal	$	—		$	—	$	—
State	47			22		47
Current Income Taxes	47			22		47
Deferred
Federal	1,115			502		(358		)
State	(18		)	24		(69		)
Deferred Income Taxes	1,097			526		(427		)
Total	$	1,144		$	548	$	(380	)

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The effective income tax expense (benefit) differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons:

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Income tax expense (benefit) at the federal statutory rate (35%)	$	1,120		$	505		$	(341	)
State income taxes (net of federal income tax benefit)	68			88			(38		)
Remeasurement of state deferred tax liabilities	(114		)	(38		)	(19		)
Change in valuation allowance	74			(12		)	—
Other	(4		)	5			18
Total	$	1,144		$	548		$	(380	)

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:

	Years Ended December 31,
	2014			2013
	($ in millions)
Deferred tax liabilities:
Oil and natural gas properties	$	(3,950	)	$	(2,631	)
Other property and equipment	(14		)	(371		)
Volumetric production payments	(920		)	(1,216		)
Contingent convertible debt	(443		)	(439		)
Deferred revenue	(102		)	—
Derivative instruments	(428		)	—
Deferred tax liabilities	(5,857		)	(4,657		)
Deferred tax assets:
Net operating loss carryforwards (carrybacks)	945			535
Derivative instruments	—			108
Asset retirement obligations	165			153
Investments	88			130
Deferred stock compensation	50			66
Accrued liabilities	214			120
Noncontrolling interest liabilities	135			152
Alternative minimum tax credits	34			317
Other	56			40
Deferred tax assets	1,687			1,621
Valuation allowance	(222		)	(148		)
Net deferred tax assets	1,465			1,473
Net deferred tax assets (liabilities)	$	(4,392	)	$	(3,184	)
Reflected in accompanying balance sheets as:
Current deferred income tax asset	—			223
Current deferred income tax liability	(207		)	—
Non-current deferred income tax liability	(4,185		)	(3,407		)
Total	$	(4,392	)	$	(3,184	)

Summary of Positions for which Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Table Text Block]

A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:

	2014			2013		2012
	($ in millions)
Unrecognized tax benefits at beginning of period	$	644		$	599	$	369
Additions based on tax positions related to the current year	13			15		134
Additions to tax positions of prior years	—			30		96
Reductions to tax positions of prior years	(354		)	—		—
Unrecognized tax benefits at end of period	$	303		$	644	$	599

XML

Derivative and Hedging Activities - Narrative (Details) In Millions, unless otherwise specified			12 Months Ended												1 Months Ended
	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2014 Interest Rate Contract [Member] USD ($)	Dec. 31, 2013 Interest Rate Contract [Member] USD ($)	Dec. 31, 2014 Senior Notes [Member] USD ($)	Apr. 24, 2014 Senior Notes [Member] USD ($)	Dec. 31, 2014 Multi-Counterparty Hedging Facility [Member] USD ($) counterparty	Dec. 31, 2014 Multi-Counterparty Hedging Facility [Member] Credit Risk [Member] counterparty	Dec. 31, 2014 Multi-Counterparty Hedging Facility [Member] Energy Related Derivative [Member] MMBoe	Dec. 31, 2014 Multi-Counterparty Hedging Facility [Member] Price Risk Derivative [Member] MMBoe	Dec. 31, 2014 Multi-Counterparty Hedging Facility [Member] Basis Derivative [Member] MMBoe	Dec. 31, 2014 6.25% Euro-Denominated Senior Notes Due 2017 [ Member] Senior Notes [Member] USD ($)	Dec. 31, 2013 6.25% Euro-Denominated Senior Notes Due 2017 [ Member] Senior Notes [Member] USD ($)	Dec. 31, 2006 6.25% Euro-Denominated Senior Notes Due 2017 [ Member] Senior Notes [Member] USD ($)	Dec. 31, 2006 6.25% Euro-Denominated Senior Notes Due 2017 [ Member] Senior Notes [Member] Cross Currency Interest Rate Contract [Member] USD ($)	Dec. 31, 2006 6.25% Euro-Denominated Senior Notes Due 2017 [ Member] Senior Notes [Member] Cross Currency Interest Rate Contract [Member] EUR (€)	Dec. 31, 2014 6.25% Euro-Denominated Senior Notes Due 2017 [ Member] Senior Notes [Member] Cross Currency Interest Rate Contract [Member] USD ($)	Dec. 31, 2014 6.25% Euro-Denominated Senior Notes Due 2017 [ Member] Senior Notes [Member] Cross Currency Interest Rate Contract [Member] EUR (€)	Dec. 31, 2013 6.25% Euro-Denominated Senior Notes Due 2017 [ Member] Senior Notes [Member] Cross Currency Interest Rate Contract [Member] USD ($)	Dec. 31, 2014 Minimum [Member] Senior Notes [Member] USD ($)	Dec. 31, 2014 Minimum [Member] Multi-Counterparty Hedging Facility [Member]	Dec. 31, 2014 Accumulated Other Comprehensive Deferred Loss [Member] Cash Flow Hedging [Member] USD ($)	Dec. 31, 2014 Accumulated Other Comprehensive Income (Loss) [Member] USD ($)	Dec. 31, 2013 Accumulated Other Comprehensive Income (Loss) [Member] USD ($)	Dec. 31, 2012 Accumulated Other Comprehensive Income (Loss) [Member] USD ($)	Dec. 31, 2014 Accumulated Other Comprehensive Income (Loss) [Member] Cash Flow Hedging [Member] USD ($)	Dec. 31, 2013 Accumulated Other Comprehensive Income (Loss) [Member] Cash Flow Hedging [Member] USD ($)	Dec. 31, 2012 Accumulated Other Comprehensive Income (Loss) [Member] Cash Flow Hedging [Member] USD ($)	Dec. 31, 2011 Accumulated Other Comprehensive Income (Loss) [Member] Cash Flow Hedging [Member] USD ($)
Derivative [Line Items]
Derivative, Amount of Hedged Item			$ 850	$ 2,250
Interest Rate Derivatives, at Fair Value, Net	17	98
Amortization Period of Deferred Gain (Loss) on Discontinuation of Fair Value Hedge			6 years
Deferred (Gain) Loss on Discontinuation of Fair Value Hedge			10
Euro-denominated debt in notes payable, adjusted value	11,756		10	13	3,000	3,000						416	473	344			416			50
Derivative, Forward Exchange Rate															1.3325		1.2098		1.3743
Semi Annual Interest Rate Swap Payments By Counterparty																11		344
Dollar Equivalent Interest Rate															7.491%	7.491%
Short-term Debt, Refinanced, Description															17		459
Derivative liability, gross liability		649															53
Derivative Asset, Fair Value, Gross Asset	652																		2
Accumulated other comprehensive loss	(143)	(162)																				(136)	(143)	(162)	(182)	(143)	(167)	(189)	(178)
Expected amount to be transferred of during the next 12 months	23
Number of counterparties in hedge facility							17	18
Multi-counterparty hedging facility, committed to provide a trading capacity (in tcfe)									1,031,000,000
Borrowing capacity							$ 16,500
Natural gas and oil proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility, multiplier							1.30														1.65
Multi-counterparty hedge facility, hedged total (in tcfe)										164,000,000	10,000,000

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
NET INCOME (LOSS)	$ 2,056	$ 894	$ (594)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:
Unrealized gain on derivative instruments, net of income tax expense of $0, $1 and $4	1	2	6
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $14, $12 and ($10)	23	20	(17)
Unrealized loss on investments, net of income tax benefit of $0, ($4) and ($4)	0	(6)	(5)
Reclassification of (gain) loss on investment, net of income tax expense of ($3), $3 and $0	(5)	4	0
Other Comprehensive Income (Loss)	19	20	(16)
COMPREHENSIVE INCOME (LOSS)	2,075	914	(610)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(139)	(170)	(175)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$ 1,936	$ 744	$ (785)

XML

Equity - Noncontrolling Interests Narrative (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended			0 Months Ended	1 Months Ended	6 Months Ended	1 Months Ended	12 Months Ended	3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 30, 2012 well	Mar. 30, 2012 acre	Jun. 30, 2014 well	Oct. 31, 2011 acre	Dec. 31, 2011 County	Dec. 31, 2011	Mar. 31, 2012	Nov. 30, 2011
Noncontrolling Interest [Line Items]
Payments for (Proceeds from) Investments	$ 17	$ 44	$ 395
Restricted cash and cash equivalents, current	38	75
Stockholders' Equity Attributable to Noncontrolling Interest	1,302	2,145
Net income attributable to noncontrolling interests	139	170	175
Preferred Stock Redemption Premium	447	69	0
Common Stock, Shares, Issued	664,944,232	666,192,371	666,468,000					660,888,000	660,888,000
Common stock, par value (usd per share)	$ 0.01	$ 0.01
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]
Noncontrolling Interest [Line Items]
Number Of Net Acres					245,000
Payments for (Proceeds from) Investments			1,250
Preferred Stock, Shares Issued			1,250,000
Number of Wells, Net				1,000
Overriding Royalty Interest Percentage	3.75%									3.75%
Restricted cash and cash equivalents, current	38	38
Preferred Stock, Dividend Rate, Percentage	6.00%
Preferred Stock, Dividends, Per Share, Cash Paid	$ 1,000
Distribution of Excess Cash	100.00%
Percentage of internal rate of return	9.00%
Internal return on investment, multiplier	1.35
Preferred Stock, Redemption Price Per Share	$ 1,185	$ 1,245
Acre Spacing	160
Stockholders' Equity Attributable to Noncontrolling Interest	1,015
Net income attributable to noncontrolling interests	75	75	57
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Days in Notice	45
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Maximum, March 31, 2019 [Member]
Noncontrolling Interest [Line Items]
Percentage of internal rate of return	15.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six-Month Period Through 2013 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net Decimal	37.5
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six-Month Period in 2014 Through 2016 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	25
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Cumulative Well Total [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	300
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six-Month Period of April 1, 2014 - June 30,2014 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net Decimal						162.5
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six-Month Period of June 30,2014 Through December 31, 2014 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net Decimal	175.0
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six Month Period, 1.1.15 - 6.30.15 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	225
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six Month Periods, 7.1.15 - 12.31.17 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	25
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Maximum, Two Consecutive Six-Month Periods [Member]
Noncontrolling Interest [Line Items]
Percentage of internal rate of return	3.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Maximum, Four Consecutive Six-Month Periods [Member]
Noncontrolling Interest [Line Items]
Percentage of internal rate of return	3.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Wells, Future Wells [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net				1,000
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Wells, Qualified Wells [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	17	77	84
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Wells, Percentage Increase in Future Net Wells [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Percentage of increase in leasehold in which commitment to drill is not met	5.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Wells, Drilled Wells [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	867
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Preferred Stock [Member]
Noncontrolling Interest [Line Items]
Preferred Stock, Dividend Rate, Percentage	6.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Cash Distribution [Member]
Noncontrolling Interest [Line Items]
Payments for (Proceeds from) Investments					225
Distribution of Excess Cash	75.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Share Distribution [Member]
Noncontrolling Interest [Line Items]
Payments for (Proceeds from) Investments					1,025
Distribution of Excess Cash	25.00%
Noncontrolling Interest, Chesapeake Utica L L C [Member]
Noncontrolling Interest [Line Items]
Number Of Net Acres							700,000
Payments for (Proceeds from) Investments								1,250
Preferred Stock, Shares Issued								1,250,000	1,250,000
Number of Wells, Net	1,500
Overriding Royalty Interest Percentage								3.00%	3.00%
Preferred Stock, Redemption Price Per Share	$ 1,189
Percentage of increase in leasehold in which commitment to drill is not met	4.00%
Stockholders' Equity Attributable to Noncontrolling Interest	0	807
Net income attributable to noncontrolling interests	43	79	88
Number of counties present in the leasehold land (Counties)								13
Payments for Repurchase of Preferred Stock and Preference Stock	1,254
Preferred Stock Redemption Premium	447
Spacing for Wells Drilled	150
Noncontrolling Interest, Chesapeake Utica L L C [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	1,300
Noncontrolling Interest, Chesapeake Utica L L C [Member] | Wells, Percentage Increase in Future Net Wells [Member]
Noncontrolling Interest [Line Items]
Percentage of increase in leasehold in which commitment to drill is not met	4.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]
Noncontrolling Interest [Line Items]
Number Of Net Acres	29,000
Stockholders' Equity Attributable to Noncontrolling Interest	287	314
Net income attributable to noncontrolling interests	24	20	35
Percentage Of Beneficial Interest Owned	51.00%
Common stock, par value (usd per share)											$ 19.00
Common shares, outstanding	46,750,000
Number of producing wells	69
Number of development wells drilled	102	82
Number Of Gross Acres	45,400
Maximum amount recoverable by trust under lien	$ 36	$ 79							$ 263
Percentage of incentive distributions received	50.00%
Percentage of remaining cash available for distribution in excess of the incentive threshold	50.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Percentage of proceeds from royalty interest conveyed to trust	50.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Maximum [Member]
Noncontrolling Interest [Line Items]
Percentage of proceeds from royalty interest conveyed to trust	90.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Wells, Initial Number of Wells [Member]
Noncontrolling Interest [Line Items]
Number of development wells drilled	118
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Common Unit [Member]
Noncontrolling Interest [Line Items]
Common Stock, Shares, Issued											23,000,000
Common shares, outstanding	12,062,500
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Subordinated Units [Member]
Noncontrolling Interest [Line Items]
Common shares, outstanding	11,687,500

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Basis of Presentation and Summary of Significant Accounting Policies (Note)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Organization, Consolidation, Basis of Presentation, Business Description and Accounting Policies [Text Block]

Basis of Presentation and Summary of Significant Accounting Policies

Description of Company

Chesapeake Energy Corporation ("Chesapeake" or the "Company") is an oil and natural gas exploration and production company engaged in the acquisition, exploration and development of properties for the production of oil, natural gas and natural gas liquids (NGL) from underground reservoirs. We also own oil and natural gas marketing and natural gas gathering and compression businesses, and prior to June 30, 2014, an oilfield services business (see Note 13). Our operations are located onshore in the United States.

Basis of Presentation

The accompanying consolidated financial statements of Chesapeake were prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated.

Accounting Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in actual results differing significantly from our estimates.

Consolidation

Chesapeake consolidates entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake has the ability to exercise significant influence through its investment. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Investments in securities not accounted for under the equity method have been designated as available-for-sale and, as such, are carried at fair value whenever this value is readily determinable. Otherwise, the investment is carried at cost. See Note 14 for further discussion of our investments. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis.

Noncontrolling Interests

Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests.

Variable Interest Entities

VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

Along with a VIE that we consolidate, we also hold a variable interest in another VIE that is not consolidated because we are not the primary beneficiary. We continually monitor both our consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs.

Cash and Cash Equivalents and Restricted Cash

For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. Restricted cash consists of the balance required to be maintained by the terms of the agreement governing the activities of CHK Cleveland Tonkawa, L.L.C. (CHK C-T) and, prior to our repurchase of all of the outstanding preferred shares of CHK Utica, L.L.C. (CHK Utica) in 2014, also consisted of a balance required to be maintained by the terms of the agreement governing the activities of CHK Utica. The repurchase of outstanding preferred shares of CHK Utica eliminated the restricted cash maintenance requirement related to this entity. See Note 8 for further discussion of these entities.

Accounts Receivable

Our accounts receivable are primarily from purchasers of oil, natural gas and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables we believe may be uncollectible. During 2014, 2013 and 2012, we recognized $2 million, $2 million and a nominal amount of bad debt expense related to potentially uncollectible receivables, and we reduced our allowance by $3 million in 2013 as we wrote off specific receivables against our allowance. Accounts receivable as of December 31, 2014 and 2013 are detailed below.

	December 31,
	2014			2013
	($ in millions)
Oil, natural gas and NGL sales	$	1,340		$	1,548
Joint interest	691			417
Oilfield services(a)	—			63
Related parties(b)	—			62
Other	226			150
Allowance for doubtful accounts	(21		)	(18		)
Total accounts receivable, net	$	2,236		$	2,222

___________________________________________

(a) In 2014, in connection with the spin-off of our oilfield services business, accounts receivable related to oilfield services were removed from our consolidated balance sheet.

(b) See Note 7 for discussion of related party transactions.

Oil and Natural Gas Properties

Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with these activities and do not capitalize any costs related to production, general corporate overhead or similar activities (see Supplementary Information - Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. Estimates of our proved reserves as of December 31, 2014 were prepared by independent engineering firms and Chesapeake's internal staff. Approximately 79% of these proved reserves estimates (by volume) as of December 31, 2014 were prepared by independent engineering firms. In addition, our internal engineers review and update our reserves on a quarterly basis.

Proceeds from the sale of oil and natural gas properties are accounted for as reductions of capitalized costs unless these sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized.

The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unproved properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unproved properties are grouped by major prospect area where individual property costs are not significant. In addition, we analyze our unproved leasehold and transfer to proved properties leasehold that can be associated with proved reserves, leasehold that expired in the quarter or leasehold that is not a part of our development strategy and will be abandoned.

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2014 and the year in which the associated costs were incurred.

	Year of Acquisition
	2014		2013		2012		Prior		Total
	($ in millions)
Leasehold acquisition cost	$	577	$	199	$	1,462	$	5,149	$	7,387
Exploration cost	340		90		244		42		716
Capitalized interest	492		421		325		447		1,685
Total	$	1,409	$	710	$	2,031	$	5,638	$	9,788

We also review, on a quarterly basis, the carrying value of our oil and natural gas properties under the full cost accounting rules of the Securities and Exchange Commission (SEC). This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for oil and natural gas derivatives designated as cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The ceiling test calculation uses costs as of the end of the applicable quarterly period and the unweighted arithmetic average of oil, natural gas and NGL prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. As of December 31, 2014, none of our open derivative instruments were designated as cash flow hedges. Our oil and natural gas hedging activities are discussed in Note 11.

Two primary factors impacting the ceiling test are reserves levels and oil, natural gas and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an extended increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value over the ceiling is written off as an expense.

We account for seismic costs as part of our oil and natural gas properties. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. These costs are capitalized as incurred. The Company reviews its unproved properties and associated seismic costs quarterly to determine whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unproved properties, they are included in the amortization base as incurred.

Other Property and Equipment

Other property and equipment consists primarily of natural gas compressors, buildings and improvements, land, vehicles, computer and office equipment, oil and natural gas gathering systems and treating plants. We have no remaining oilfield services equipment as a result of the spin-off of our oilfield services business in 2014 as discussed in Note 13, and substantially all of our natural gas gathering systems and treating plants were sold in 2013 and 2012 as discussed in Note 16. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating costs. See Note 16 for further discussion of our gains and losses on the sales of other property and equipment and a summary of our other property and equipment held for sale as of December 31, 2014 and 2013. Other property and equipment costs, excluding land, are depreciated on a straight-line basis.

Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. During 2014, 2013 and 2012, we determined that certain of our property and equipment was being carried at values that were not recoverable and in excess of fair value. See Note 17 for further discussion of these impairments.

Capitalized Interest

Interest from external borrowings is capitalized on significant projects until the asset is ready for service using the weighted average cost of outstanding borrowings. Capitalized interest is determined by multiplying our weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.

Goodwill

Goodwill represents the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment at least annually. This test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. When the qualitative assessment indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, the quantitative assessment is then performed. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense.

Our goodwill, which is included in other long-term assets on our consolidated balance sheets, was $15 million and $43 million, respectively, as of December 31, 2014 and 2013. The 2014 amount consists of $15 million of excess consideration over the fair value of assets acquired in our Horizon Drilling Services acquisition in 2011. The 2013 amount also included $28 million of excess consideration over the fair value of assets acquired in our Bronco Drilling Company acquisition in 2011. We no longer have the goodwill balance related to Bronco Drilling Company as a result of the spin-off of our oilfield services business in June 2014. We performed annual impairment tests of goodwill in the fourth quarters of 2014 and 2013. Based on these assessments, no impairment of goodwill was required. Goodwill was included in our exploration and production segment as of December 31, 2014 and as of December 31, 2013 was included in our former oilfield services segment.

Accounts Payable

Included in accounts payable as of December 31, 2014 and 2013 are liabilities of approximately $333 million and $397 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts.

Debt Issuance and Hedging Facility Costs

Included in other long-term assets are costs associated with the issuance of our senior notes, revolving credit facility, hedging facility and, as of December 31, 2013, costs associated with our former term loan and former oilfield services credit facility. The remaining unamortized issuance costs as of December 31, 2014 and 2013 totaled $130 million and $145 million, respectively, and are being amortized over the life of the applicable debt or facility using the effective interest method.

Environmental Remediation Costs

Chesapeake records environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

Asset Retirement Obligations

We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. See Note 20 for further discussion of asset retirement obligations.

Revenue Recognition

Oil, Natural Gas and NGL Sales. Revenue from the sale of oil, natural gas and NGL is recognized when title passes, net of royalties due to third parties and gathering and transportation charges.

Natural Gas Imbalances. We follow the "sales method" of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of the remaining natural gas reserves on the underlying properties. The natural gas imbalance net liability position as of December 31, 2014 and 2013 was $12 million and $11 million, respectively.

Marketing, Gathering and Compression Sales. Chesapeake takes title to the oil, natural gas and NGL it purchases from other interest owners in operated wells at defined delivery points and delivers the product to third parties, at which time revenues are recorded. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments. In circumstances where we act as a principal rather than an agent, Chesapeake's results of operations related to its oil, natural gas and NGL marketing activities are presented on a "gross" basis. Gathering and compression revenues consist of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated.

Oilfield Services Revenue. Prior to the spin-off of our oilfield services business in June 2014, we reported oilfield services revenue. Our former oilfield services operating segment was responsible for contract drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Our oilfield services revenues prior to the spin-off were as follows:

• Drilling. Revenues were generated by drilling oil and natural gas wells for our customers under daywork contracts and recognized for the days completed based on the dayrate specified in each contract. Revenue generated and costs incurred for mobilization services were recognized over the days of actual mobilization.

• Hydraulic Fracturing. Revenue was recognized upon the completion of each fracturing stage. Typically, one or more fracturing stages per day per active crew was completed during the course of a job. A stage was considered complete when the customer requested or the job design dictated that pumping discontinue for that stage. Invoices typically included a lump sum equipment charge determined by the rate per stage specified in each contract and product charges for sand, chemicals and other products actually consumed during the course of providing fracturing services.

• Oilfield Rentals. Oilfield equipment rentals included drill pipe, drill collars, tubing, blowout preventers, and frac and mud tanks, and services included air drilling services and services associated with the transfer of fresh water to the wellsite. Rentals and services were priced by the day or hour based on the type of equipment rented and the service job performed. Revenue was recognized ratably over the term of the rental.

• Oilfield Trucking. Oilfield trucking provided rig relocation and logistics services as well as fluid handling services. Trucks moved drilling rigs, crude oil, other fluids and construction materials to and from the wellsites and also transported produced water from the wellsites. These services were priced on a per barrel basis based on mileage and revenue was recognized as services were performed.

• Other Operations. A manufacturing subsidiary designed, engineered and fabricated natural gas compressor packages that were purchased primarily by Chesapeake. Compression units were priced based on certain specifications such as horsepower, stages and additional options. Revenue was recognized upon completion and transfer of ownership of the natural gas compression unit.

Fair Value Measurements

Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

The carrying values of financial instruments comprising cash and cash equivalents, restricted cash, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments.

Derivatives

Derivative instruments are recorded on our consolidated balance sheets as derivative assets or derivative liabilities at fair value, and changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. For qualifying commodity derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Locked-in gains and losses of settled cash flow hedges are recorded in accumulated other comprehensive income and are transferred to earnings in the month of production. Changes in the fair value of interest rate derivative instruments designated as fair value hedges are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent hedge ineffectiveness and are recognized currently in earnings. Locked-in gains and losses related to settled fair value hedges are amortized as an adjustment to interest expense over the remaining term of the related senior notes. We have elected not to designate any of our qualifying commodity and interest rate derivatives as cash flow or fair value hedges. Therefore, changes in fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in our consolidated statements of operations within oil, natural gas and NGL sales and interest expense, respectively.

Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our derivative instruments are subject to master netting arrangements by contract type (i.e., commodity, interest rate and cross currency contracts) which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets.

We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. See Note 11 for further discussion of our derivative instruments.

Share-Based Compensation

Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize in our financial statements the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three or four years from the grant date. For directors, although restricted stock grants vest over three years, this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units can only be settled in cash, they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as compensation expense in the consolidated statements of operations.

To the extent compensation cost relates to employees directly involved in the acquisition of oil and natural gas leasehold and exploration and development activities, these amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses, oil, natural gas and NGL production expenses, or marketing, gathering and compression expenses, based on the employees involved in those activities.

Cash inflows resulting from tax deductions in excess of compensation expense recognized for stock options and restricted stock are classified as financing cash inflows, while reductions in tax benefits are classified as operating cash outflows in our consolidated statements of cash flows. See Note 9 for further discussion of share-based compensation.

Reclassifications

Certain reclassifications have been made to the consolidated financial statements for 2012 and 2013 to conform to the presentation used for the 2014 consolidated financial statements.

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Earnings Per Share - Antidilutive Securities Excluded from Computation of EPS Table (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Earnings Per Share, Basic	$ 1.93	$ 0.73	$ (1.46)
Earnings Per Share, Diluted	$ 1.87	$ 0.73	$ (1.46)
Weighted Average Number of Shares Outstanding, Basic	659	653	643
Weighted Average Number of Shares Outstanding, Diluted	772	653	643
5.75% Cumulative Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments		$ 86	$ 86
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		56	56
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments		63	63
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		40	39
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments		10	10
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		5	5
4.50% Cumulative Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments		12	12
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		6	6
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 22	$ 10	$ 0
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	3	5	5

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Equity - Common Stock Table (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Issued Beginning of Period	666,192,371	666,468,000	660,888,000
Stock Issued During Period, Shares, Restricted Stock Award, Net of Forfeitures	(2,529,000)	(599,000)	5,038,000
Stock option exercises	1,281,000	323,000	542,000
Common Stock, Shares, Issued End of Period	664,944,232	666,192,371	666,468,000

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Derivative and Hedging Activities - Quantitative Disclosures Level 3 Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Natural Gas [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	(5)
Natural Gas [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	18.71%
Natural Gas [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	63.70%
Natural Gas [Member] | Weighted Average [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	34.38%
Crude Oil [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	(49)
Crude Oil [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	27.33%
Crude Oil [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	43.56%
Crude Oil [Member] | Weighted Average [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	34.09%

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Commitments - Undiscounted Lease Payments Table (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 5
Operating Leases, Future Minimum Payments, Due in Two Years	4
Operating Leases, Future Minimum Payments, Due in Three Years	1
Operating Leases, Future Minimum Payments, Due in Four Years	1
Future Minimum Payments Due	$ 11

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Restructuring and Other Termination Benefits (Note)

12 Months Ended

Dec. 31, 2014

Restructuring and Related Activities [Abstract]

Restructuring and Related Activities Disclosure [Text Block]

Restructuring and Other Termination Costs

On June 30, 2014, we completed the spin-off of our oilfield services business through a pro rata distribution of SSE common stock to holders of Chesapeake common stock. In connection with the spin-off, in 2014, we incurred restructuring charges of $15 million consisting of transaction costs, stock-based compensation adjustments and debt extinguishment costs. See Note 13 for further discussion of the spin-off.

On September 9, 2013, we committed to a workforce reduction plan as part of a company-wide reorganization effort intended to reduce costs. The reduction was communicated to affected employees on various dates within the months of September and October, and all notifications were completed by October 11, 2013. The plan resulted in a reduction of approximately 900 employees. In connection with the reduction, we incurred a charge of approximately $66 million.

On April 1, 2013, Aubrey K. McClendon, the co-founder of the Company, ceased serving as President and CEO and as a director of the Company pursuant to his agreement with the Board of Directors announced on January 29, 2013. Mr. McClendon’s departure from the Company was treated as a termination without cause under his employment agreement. On April 18, 2013, the Company and Mr. McClendon entered into a Founder Separation and Services Agreement, effective January 29, 2013, regarding his separation from employment and to facilitate the relationship between the Company and Mr. McClendon as joint working interest owners of oil and gas wells, leases and acreage. In 2013, we incurred charges of approximately $69 million related to Mr. McClendon’s departure.

During 2013, we also incurred charges of approximately $50 million related to other workforce reductions, including separations of executive officers other than the former CEO. Substantially all of the restructuring and other termination costs in 2013 are in the exploration and production operating segment.

In December 2012, Chesapeake announced that it had offered a voluntary separation program (VSP) to certain employees as part of the Company's ongoing efforts to improve efficiencies and reduce costs. The VSP was offered to approximately 275 employees who met criteria based upon a combination of age and years of Chesapeake service, and 211 accepted prior to the expiration of the offer in February 2013. We recognized the expense related to their termination benefits over their remaining service period, which resulted in $63 million of expense for 2013.

Below is a summary of our restructuring and other termination costs for the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014			2013		2012
	($ in millions)
Oilfield services spin-off costs:
Transaction costs	$	17		$	—	$	—
Stock-based compensation adjustments for Chesapeake employees	5			—		—
Stock-based compensation forfeitures for SSE employees	(10		)	—		—
Debt extinguishment costs	3			—		—
Total oilfield services spin-off costs	15			—		—
Restructuring charges under workforce reduction plan:
Salary expense	—			20		—
Acceleration of stock-based compensation	—			45		—
Other termination benefits	—			1		—
Total restructuring changes under workforce reduction plan	—			66		—
Termination benefits provided to Mr. McClendon:
Salary and bonus expense	—			11		—
Acceleration of 2008 performance bonus clawback	—			11		—
Acceleration of stock-based compensation	—			22		—
Acceleration of performance share unit awards(a)	(8		)	18		—
Estimated aircraft usage benefits	—			7		—
Total termination benefits provided to Mr. McClendon	(8		)	69		—
Termination benefits provided to VSP participants:
Salary and bonus expense	—			33		1
Acceleration of stock-based compensation	—			29		1
Other termination benefits	—			1		—
Total termination benefits provided to VSP participants	—			63		2
Other termination benefits(a)	—			50		5
Total restructuring and other termination costs	$	7		$	248	$	7

____________________________________________

(a) Amounts for the year ended December 31, 2014 are primarily related to negative fair value adjustments to PSUs granted to former executives of the Company. For further discussion of our PSUs, see Note 9.

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Other Property and Equipment Net Gains (Losses) on Sales of Fixed Assets Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	$ 199	$ 302	$ 267
Natural Gas Compressors [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	195	0	0
Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	(8)	326	286
Exploration and Production Equipment [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	7	(2)	(10)
Land and Building [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	2	(27)	(7)
Other Assets [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	$ 3	$ 5	$ (2)

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Condensed Consolidating Financial Information - Statements Of Cash Flows Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	$ 4,634	$ 4,614	$ 2,837
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(4,581)	(5,604)	(8,930)
Acquisitions of proved and unproved properties	(1,311)	(1,032)	(3,161)
Proceeds from divestitures of proved and unproved properties	5,813	3,467	5,884
Additions to other property and equipment	(726)	(972)	(2,651)
Other	(3)	4	(1)
Net Cash Used In Investing Activities	454	(2,967)	(4,984)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	7,406	7,669	20,318
Payments on credit facilities borrowings	(7,788)	(7,682)	(21,650)
Proceeds from issuance of senior notes, net of discount and offering costs	3,460
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	394
Cash paid to purchase debt	(3,362)	(2,141)	(4,000)
Proceeds from sales of noncontrolling interests	0	6	1,077
Other	(34)	(105)	(251)
Intercompany advances, net	0	0	0
Net Cash Provided By (Used In) Financing Activities	(1,817)	(1,097)	2,083
Net increase (decrease) in cash and cash equivalents	3,271	550	(64)
Cash and cash equivalents, beginning of period	837	287	351
Cash and cash equivalents, end of period	4,108	837	287
Parent Company Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	0	0	0
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	0	0	0
Acquisitions of proved and unproved properties	0	0	0
Proceeds from divestitures of proved and unproved properties	0	0	0
Additions to other property and equipment	0	0	0
Other	0	0	0
Net Cash Used In Investing Activities	0	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	0	0	0
Payments on credit facilities borrowings	0	0	0
Proceeds from issuance of senior notes, net of discount and offering costs	2,966	2,274	1,263
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	0		5,722
Cash paid to purchase debt	(3,362)	(2,141)	(4,000)
Proceeds from sales of noncontrolling interests		0	0
Other	(439)	1,819	(477)
Intercompany advances, net	4,136	(1,381)	(2,282)
Net Cash Provided By (Used In) Financing Activities	3,301	571	226
Net increase (decrease) in cash and cash equivalents	3,301	571	226
Cash and cash equivalents, beginning of period	799	228	2
Cash and cash equivalents, end of period	4,100	799	228
Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	4,201	4,218	1,711
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(4,445)	(4,838)	(8,605)
Acquisitions of proved and unproved properties	(1,306)	(1,378)	(3,622)
Proceeds from divestitures of proved and unproved properties	5,812	3,466	5,884
Additions to other property and equipment	(480)	(271)	(1,736)
Other	1,199	246	5,083
Net Cash Used In Investing Activities	780	(2,775)	(2,996)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	6,689	6,452	18,930
Payments on credit facilities borrowings	(6,689)	(6,452)	(20,651)
Proceeds from issuance of senior notes, net of discount and offering costs	0	0	0
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	0		0
Cash paid to purchase debt	0	0	0
Proceeds from sales of noncontrolling interests		0	63
Other	(1,278)	(2,897)	(299)
Intercompany advances, net	(3,709)	1,462	3,242
Net Cash Provided By (Used In) Financing Activities	(4,987)	(1,435)	1,285
Net increase (decrease) in cash and cash equivalents	(6)	8	0
Cash and cash equivalents, beginning of period	8	0	0
Cash and cash equivalents, end of period	2	8	0
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	462	439	1,182
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(136)	(766)	(325)
Acquisitions of proved and unproved properties	(5)	346	461
Proceeds from divestitures of proved and unproved properties	1	1	0
Additions to other property and equipment	(246)	(701)	(915)
Other	60	765	(316)
Net Cash Used In Investing Activities	(326)	(355)	(1,095)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	717	1,217	1,388
Payments on credit facilities borrowings	(1,099)	(1,230)	(999)
Proceeds from issuance of senior notes, net of discount and offering costs	494	0	0
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	394		0
Cash paid to purchase debt	0	0	0
Proceeds from sales of noncontrolling interests		6	1,014
Other	(169)	(17)	(820)
Intercompany advances, net	(427)	(81)	(960)
Net Cash Provided By (Used In) Financing Activities	(90)	(105)	(377)
Net increase (decrease) in cash and cash equivalents	46	(21)	(290)
Cash and cash equivalents, beginning of period	38	59	349
Cash and cash equivalents, end of period	84	38	59
Eliminations [Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	(29)	(43)	(56)
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	0	0	0
Acquisitions of proved and unproved properties	0	0	0
Proceeds from divestitures of proved and unproved properties	0	0	0
Additions to other property and equipment	0	0	0
Other	0	163	(893)
Net Cash Used In Investing Activities	0	163	(893)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	0	0	0
Payments on credit facilities borrowings	0	0	0
Proceeds from issuance of senior notes, net of discount and offering costs	0	0	0
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	0		0
Cash paid to purchase debt	0	0	0
Proceeds from sales of noncontrolling interests		0	0
Other	(41)	(128)	949
Intercompany advances, net	0	0	0
Net Cash Provided By (Used In) Financing Activities	(41)	(128)	949
Net increase (decrease) in cash and cash equivalents	(70)	(8)	0
Cash and cash equivalents, beginning of period	(8)	0	0
Cash and cash equivalents, end of period	(78)	(8)	0
Chesapeake Energy [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of senior notes, net of discount and offering costs	2,966	2,274	1,263
Proceeds from issuance of oilfield services term loan, net of discount and offering costs			5,722
Consolidated Entities [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Other	1,259	1,174	3,874
CASH FLOWS FROM FINANCING ACTIVITIES:
Other	$ (1,927)	$ (1,223)	$ (647)

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Major Customers and Segment Information - Table (Details) (USD $)	1 Months Ended	12 Months Ended
	Sep. 30, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Total Revenues		$ 20,951,000,000	$ 17,506,000,000	$ 12,316,000,000
Unrealized Gain (Loss) on Derivatives		(1,394,000,000)	(228,000,000)	(561,000,000)
Depreciation, depletion and amortization		2,915,000,000	2,903,000,000	2,811,000,000
Impairment of oil and natural gas properties	3,315,000,000	0	0	3,315,000,000
Impairments of fixed assets and other		88,000,000	546,000,000	340,000,000
Gain (Loss) on Disposition of Property Plant Equipment		(199,000,000)	(302,000,000)	(267,000,000)
Interest expense		(89,000,000)	(227,000,000)	(77,000,000)
Losses on investments		(80,000,000)	(226,000,000)	(103,000,000)
Net gain (loss) on sales of investments		67,000,000	(7,000,000)	1,092,000,000
Losses on purchases of debt		(197,000,000)	(193,000,000)	(200,000,000)
Income (Loss) Before Income Taxes		3,200,000,000	1,442,000,000	(974,000,000)
Total Assets		40,751,000,000	41,782,000,000	41,611,000,000
Payments to Acquire Productive Assets		6,667,000,000	7,190,000,000	14,108,000,000
Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues		8,180,000,000	7,052,000,000	6,278,000,000
Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues		12,225,000,000	9,559,000,000	5,431,000,000
Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues		516,000,000	879,000,000	602,000,000
Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues		30,000,000	16,000,000	5,000,000
Reportable Subsegments [Member]
Segment Reporting Information [Line Items]
Total Revenues		20,951,000,000	17,506,000,000	12,316,000,000
Intersubsegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues		0	0	0
Operating Segments [Member] | Reportable Subsegments [Member] | Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues		8,180,000,000	7,052,000,000	6,278,000,000
Unrealized Gain (Loss) on Derivatives		(1,394,000,000)	(228,000,000)	(561,000,000)
Depreciation, depletion and amortization		2,756,000,000	2,674,000,000	2,624,000,000
Impairment of oil and natural gas properties				3,315,000,000
Impairments of fixed assets and other		22,000,000	27,000,000	28,000,000
Gain (Loss) on Disposition of Property Plant Equipment		(2,000,000)	2,000,000	14,000,000
Interest expense		(709,000,000)	(918,000,000)	(47,000,000)
Losses on investments		2,000,000	3,000,000	0
Net gain (loss) on sales of investments		(6,000,000)	0	(2,000,000)
Losses on purchases of debt		197,000,000	(193,000,000)	(200,000,000)
Income (Loss) Before Income Taxes		2,874,000,000	2,997,000,000	(1,798,000,000)
Total Assets		35,381,000,000	35,341,000,000	37,004,000,000
Payments to Acquire Productive Assets		6,173,000,000	6,198,000,000	12,044,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues		20,790,000,000	17,129,000,000	10,895,000,000
Unrealized Gain (Loss) on Derivatives		0	0	0
Depreciation, depletion and amortization		38,000,000	46,000,000	54,000,000
Impairment of oil and natural gas properties				0
Impairments of fixed assets and other		24,000,000	50,000,000	6,000,000
Gain (Loss) on Disposition of Property Plant Equipment		(187,000,000)	(329,000,000)	(298,000,000)
Interest expense		(21,000,000)	(24,000,000)	(20,000,000)
Losses on investments		0	0	49,000,000
Net gain (loss) on sales of investments		0	0	1,094,000,000
Losses on purchases of debt		0	0	0
Income (Loss) Before Income Taxes		326,000,000	511,000,000	1,665,000,000
Total Assets		1,978,000,000	2,430,000,000	2,291,000,000
Payments to Acquire Productive Assets		298,000,000	299,000,000	852,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues		1,060,000,000	2,188,000,000	1,917,000,000
Unrealized Gain (Loss) on Derivatives		0	0	0
Depreciation, depletion and amortization		145,000,000	289,000,000	232,000,000
Impairment of oil and natural gas properties				0
Impairments of fixed assets and other		23,000,000	75,000,000	60,000,000
Gain (Loss) on Disposition of Property Plant Equipment		(8,000,000)	(1,000,000)	10,000,000
Interest expense		(42,000,000)	(82,000,000)	(76,000,000)
Losses on investments		(6,000,000)	(1,000,000)	0
Net gain (loss) on sales of investments		0	0	0
Losses on purchases of debt		0	0	0
Income (Loss) Before Income Taxes		(16,000,000)	(51,000,000)	112,000,000
Total Assets		0	2,018,000,000	2,115,000,000
Payments to Acquire Productive Assets		158,000,000	272,000,000	658,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues		30,000,000	29,000,000	21,000,000
Unrealized Gain (Loss) on Derivatives		0	0	0
Depreciation, depletion and amortization		42,000,000	49,000,000	46,000,000
Impairment of oil and natural gas properties				0
Impairments of fixed assets and other		19,000,000	394,000,000	246,000,000
Gain (Loss) on Disposition of Property Plant Equipment		(2,000,000)	26,000,000	7,000,000
Interest expense		3,000,000	(74,000,000)	(364,000,000)
Losses on investments		(76,000,000)	(229,000,000)	(152,000,000)
Net gain (loss) on sales of investments		73,000,000	(7,000,000)	0
Losses on purchases of debt		0	0	0
Income (Loss) Before Income Taxes		(30,000,000)	(727,000,000)	(478,000,000)
Total Assets		4,283,000,000	5,750,000,000	2,529,000,000
Payments to Acquire Productive Assets		38,000,000	421,000,000	554,000,000
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues		0	0	0
Intersegment Eliminations [Member] | Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues		0	0	0
Intersegment Eliminations [Member] | Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues		8,565,000,000	7,570,000,000	5,464,000,000
Intersegment Eliminations [Member] | Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues		544,000,000	1,309,000,000	1,315,000,000
Intersegment Eliminations [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues		0	13,000,000	16,000,000
Intersegment Eliminations [Member] | Reportable Subsegments [Member]
Segment Reporting Information [Line Items]
Total Revenues		9,109,000,000	8,892,000,000	6,795,000,000
Unrealized Gain (Loss) on Derivatives		0	0	0
Depreciation, depletion and amortization		(66,000,000)	(155,000,000)	(145,000,000)
Impairment of oil and natural gas properties				0
Impairments of fixed assets and other		0	0	0
Gain (Loss) on Disposition of Property Plant Equipment		0	0	0
Interest expense		680,000,000	871,000,000	430,000,000
Losses on investments		0	1,000,000	0
Net gain (loss) on sales of investments		0	0	0
Losses on purchases of debt		0	0	0
Income (Loss) Before Income Taxes		46,000,000	(1,288,000,000)	(475,000,000)
Total Assets		(891,000,000)	(3,757,000,000)	(2,328,000,000)
Payments to Acquire Productive Assets		0	0	0
Intersegment Eliminations [Member] | Intersubsegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues		$ 9,109,000,000	$ 8,892,000,000	$ 6,795,000,000

XML

Other Liabilities - Current Table (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Other Liabilities Disclosure [Abstract]
Revenues and royalties due others	$ 1,176	$ 1,409
Accrued natural gas, oil and NGL drilling and production costs	385	457
Joint interest prepayments received	189	464
Accrued compensation and benefits	344	320
Other accrued taxes	55	161
Accrued dividends	101	101
Other	811	599
Total other current liabilities	$ 3,061	$ 3,511

XML

Debt (Tables)

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Schedule of Debt [Table Text Block]

Our long-term debt consisted of the following as of December 31, 2014 and 2013:

	December 31,
	2014			2013
	($ in millions)
Term loan due 2017(a)	$	—		$	2,000
9.5% senior notes due 2015(b)	—			1,265
3.25% senior notes due 2016	500			500
6.25% euro-denominated senior notes due 2017(c)	416			473
6.5% senior notes due 2017	660			660
6.875% senior notes due 2018(d)	—			97
7.25% senior notes due 2018	669			669
Floating rate senior notes due 2019	1,500			—
6.625% senior notes due 2019(e)	—			650
6.625% senior notes due 2020	1,300			1,300
6.875% senior notes due 2020	500			500
6.125% senior notes due 2021	1,000			1,000
5.375% senior notes due 2021	700			700
4.875% senior notes due 2022	1,500			—
5.75% senior notes due 2023	1,100			1,100
2.75% contingent convertible senior notes due 2035(f)	396			396
2.5% contingent convertible senior notes due 2037(f)	1,168			1,168
2.25% contingent convertible senior notes due 2038(f)	347			347
Revolving credit facility	—			—
Oilfield services revolving credit facility(g)	—			405
Discount on senior notes and term loan(h)	(231		)	(357		)
Interest rate derivatives(i)	10			13
Total debt, net	11,535			12,886
Less current maturities of long-term debt, net(j)	(381		)	—
Total long-term debt, net	$	11,154		$	12,886

___________________________________________

(a) In 2014, we repaid the borrowings outstanding under and terminated the term loan due 2017.

(b) In 2014, we completed a tender offer for a portion of the 9.5% Senior Notes due 2015, and we redeemed the remaining balance of the notes.

(c) The principal amount shown is based on the exchange rate of $1.2098 to €1.00 and $1.3743 to €1.00 as of December 31, 2014 and 2013, respectively. See Note 11 for information on our related foreign currency derivatives.

(d) In 2014, we redeemed all outstanding 6.875% Senior Notes due 2018.

(e) Initial issuers were Chesapeake Oilfield Operating, L.L.C. (COO) and Chesapeake Oilfield Finance, Inc., a wholly owned subsidiary of COO. Chesapeake Energy Corporation is the issuer of all other senior notes and the contingent convertible senior notes. In 2014, in connection with the spin-off of our oilfield services business, the obligations with respect to the COO senior notes were removed from our consolidated balance sheet. See Note 13 for further discussion of the spin-off.

(f) The repurchase, conversion, contingent interest and redemption provisions of our contingent convertible senior notes are as follows:

Holders’ Demand Repurchase Rights. The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date.

Optional Conversion by Holders. At the holder’s option, prior to maturity under certain circumstances, the notes are convertible into cash and, if applicable, shares of our common stock using a net share settlement process. One such triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the specified period in the fourth quarter of 2014, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash and common stock in the first quarter of 2015 under this provision.

The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. The notes were not convertible under this provision in 2014, 2013 or 2012. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note’s conversion value in excess of the principal amount.

Contingent Interest. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years during certain periods if the average trading price of the notes exceeds the threshold defined in the indenture.

The holders’ demand repurchase dates, the common stock price conversion threshold amounts (as adjusted to give effect to the dividend of SSE common stock paid in the spin-off of our oilfield services business and cash dividends on our common stock) and the ending date of the first six-month period in which contingent interest may be payable for the contingent convertible senior notes are as follows:

Contingent       Convertible       Senior  Notes	Holders' Demand Repurchase Dates	Common Stock  Price Conversion  Thresholds		Contingent Interest First Payable (if applicable)
2.75% due 2035	November 15, 2015, 2020, 2025, 2030	$	45.14	May 14, 2016
2.5% due 2037	May 15, 2017, 2022, 2027, 2032	$	59.71	November 14, 2017
2.25% due 2038	December 15, 2018, 2023, 2028, 2033	$	100.35	June 14, 2019

Optional Redemption by the Company. We may redeem the contingent convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of the notes, payable in cash.

(g) In 2014, in connection with the spin-off of our oilfield services business, we terminated our oilfield services credit facility. See Note 13 for further discussion of the spin-off.

(h) Discount as of December 31, 2014 and 2013 included $224 million and $303 million, respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. Discount also included $33 million as of December 31, 2013 associated with our term loan due 2017 discussed below.

(i) See Note 11 for further discussion related to these instruments.

(j) As of December 31, 2014, there was $15 million of discount associated with the equity component of the 2.75% Contingent Convertible Senior Notes due 2035. As discussed in footnote (f) above, the holders of our 2.75% Contingent Convertible Senior Notes due 2035 could exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the principal amount of the notes.

Schedule of Maturities of Long-term Debt [Table Text Block]

Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes, for the five years ended after December 31, 2014 and thereafter are as follows:

	Principal Amount of Debt Securities
	($ in millions)
2015	$	396
2016	500
2017	2,244
2018	1,016
2019	1,500
2020 and thereafter	6,100
Total	$	11,756

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]

Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.

	December 31, 2014				December 31, 2013
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
			($ in millions)
Long-term debt (Level 1)	$	11,525	$	12,052	$	10,501	$	11,557
Long-term debt (Level 2)	$	—	$	—	$	2,372	$	2,369

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Derivative and Hedging Activities (Note)

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative and Hedging Activities Disclosure [Text Block]

Derivative and Hedging Activities

Chesapeake uses commodity derivative instruments to secure attractive pricing and margins on expected production, to reduce its exposure to fluctuations in future commodity prices and to protect its expected operating cash flow against significant market movements or volatility. Chesapeake also uses derivative instruments to mitigate a portion of its exposure to interest rate and foreign currency exchange rate fluctuations. All of our derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty.

Oil and Natural Gas Derivatives

As of December 31, 2014 and 2013, our oil and natural gas derivative instruments consisted of the following types of instruments:

• Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.

• Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.

• Options: Chesapeake sells, and occasionally buys, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty the excess on sold call options, and Chesapeake receives the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.

• Call Swaptions: Chesapeake sells call swaptions in exchange for a premium that allows a counterparty, on a specific date, to enter into a fixed-price swap for a certain period of time.

• Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. Chesapeake receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity.

The estimated fair values of our oil and natural gas derivative instrument assets (liabilities) as of December 31, 2014 and 2013 are provided below. 

	December 31, 2014				December 31, 2013
	Volume	Fair Value			Volume	Fair Value
		($ in millions)				($ in millions)
Oil (mmbbl):
Fixed-price swaps	12.5	471			25.3	(50		)
Three-way collars	4.4	40			—	—
Call options	35.8	(89		)	42.5	(265		)
Basis protection swaps	—	—			0.4	1
Total oil	52.7	422			68.2	(314		)
Natural gas (tbtu):
Fixed-price swaps	275	$	281		448	$	(23	)
Three-way collars	207	165			288	(7		)
Call options	193	(170		)	193	(210		)
Call swaptions	—	—			12	—
Basis protection swaps	60	23			68	3
Total natural gas	735	299			1,009	(237		)
Total estimated fair value		$	721			$	(551	)

We have terminated certain commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. See further discussion below underEffect of Derivative Instruments - Accumulated Other Comprehensive Income (Loss).

Interest Rate Derivatives

As of December 31, 2014 and 2013, our interest rate derivative instruments consisted of swaps. We enter into fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes. We enter into floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our bank credit facility borrowings.

The notional amount of our interest rate derivatives, associated with our long-term debt, as of December 31, 2014 and 2013 was $850 million and $2.250 billion, respectively. The estimated fair value of our interest rate derivative liabilities as of December 31, 2014 and 2013 was $17 million and $98 million, respectively. 

We have terminated certain fair value hedges related to senior notes. Gains and losses related to these terminated hedges will be amortized as an adjustment to interest expense over the remaining term of the related senior notes. Over the next six years, we will recognize $10 million in net gains related to these transactions.

Foreign Currency Derivatives

We are party to cross currency swaps to mitigate our exposure to foreign currency exchange rate fluctuations that may result from the €344 million principal amount of our euro-denominated senior notes. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. Under the terms of the cross currency swaps we currently hold, on each semi-annual interest payment date, the counterparties pay us €11 million and we pay the counterparties $17 million, which yields an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay us €344 million and we will pay the counterparties $459 million. The swaps are designated as cash flow hedges and, because they are entirely effective in having eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates, changes in their fair value do not impact earnings. The fair values of the cross currency swaps are recorded on the consolidated balance sheet as a liability of $53 million and an asset of $2 million as of December 31, 2014 and 2013, respectively. The euro-denominated debt in long-term debt has been adjusted to $416 million as of December 31, 2014 using an exchange rate of $1.2098 to €1.00.

Effect of Derivative Instruments – Consolidated Balance Sheets

The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2014 and 2013 on a gross basis and after same-counterparty netting: 

Balance Sheet Classification	Gross Fair Value			Amounts Netted in Consolidated Balance Sheet			Net Fair Value Presented in Consolidated Balance Sheet
	($ in millions)
As of December 31, 2014
Commodity Contracts
Short-term derivative asset	$	974		$	(95	)	$	879
Long-term derivative asset	16			(10		)	6
Short-term derivative liability	(105		)	95			(10		)
Long-term derivative liability	(163		)	10			(153		)
Total commodity contracts	722			—			722
Interest Rate Contracts
Short-term derivative liability	(5		)	—			(5		)
Long-term derivative liability	(12		)	—			(12		)
Total interest rate contracts	(17		)	—			(17		)
Foreign Currency Contracts(a)
Long-term derivative liability	(53		)	—			(53		)
Total foreign currency contracts	(53		)	—			(53		)
Total Derivatives	$	652		$	—		$	652
As of December 31, 2013
Commodity Contracts
Short-term derivative asset	$	29		$	(29	)	$	—
Long-term derivative asset	11			(9		)	2
Short-term derivative liability	(231		)	29			(202		)
Long-term derivative liability	(362		)	9			(353		)
Total commodity contracts	(553		)	—			(553		)
Interest Rate Contracts
Short-term derivative liability	(6		)	—			(6		)
Long-term derivative liability	(92		)	—			(92		)
Total interest rate contracts	(98		)	—			(98		)
Foreign Currency Contracts(a)
Long-term derivative asset	2			—			2
Total foreign currency contracts	2			—			2
Total Derivatives	$	(649	)	$	—		$	(649	)

____________________________________________

(a) Designated as cash flow hedging instruments.

As of December 31, 2014 and 2013, we did not have any cash collateral balances for these derivatives.

Effect of Derivative Instruments – Consolidated Statements of Operations

The components of oil, natural gas and NGL sales for the years ended December 31, 2014, 2013 and 2012 are presented below. 

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Oil, natural gas and NGL sales	$	7,162		$	6,923		$	5,359
Gains on undesignated oil and natural gas derivatives	1,055			443			857
Gains (losses) on terminated cash flow hedges	(37		)	(314		)	62
Total oil, natural gas and NGL sales	$	8,180		$	7,052		$	6,278

The components of interest expense for the years ended December 31, 2014, 2013 and 2012 are presented below. 

	Years Ended December 31,
	2014			2013			2012
	($ in millions)
Interest expense on senior notes	$	704		$	740		$	732
Interest expense on term loans	36			116			173
Amortization of loan discount, issuance costs and other	42			91			89
Interest expense on credit facilities	28			38			70
Gains on terminated fair value hedges	(3		)	(5		)	(8		)
(Gains) losses on undesignated interest rate derivatives	(81		)	63			1
Capitalized interest	(637		)	(816		)	(980		)
Total interest expense	$	89		$	227		$	77

Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss)

A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.

	Years Ended December 31,
	2014						2013						2012
	Before  Tax			After  Tax			Before  Tax			After  Tax			Before  Tax			After  Tax
	($ in millions)
Balance, beginning of period	$	(269	)	$	(167	)	$	(304	)	$	(189	)	$	(287	)	$	(178	)
Net change in fair value	1			1			3			2			10			6
Gains (losses) reclassified to income	37			23			32			20			(27		)	(17		)
Balance, end of period	$	(231	)	$	(143	)	$	(269	)	$	(167	)	$	(304	)	$	(189	)

Approximately $136 million of the $143 million of accumulated other comprehensive loss as of December 31, 2014 represents the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. These amounts will be recognized in earnings in the month in which the originally forecasted hedged production occurs. As of December 31, 2014, we expect to transfer approximately $23 million of net loss included in accumulated other comprehensive income to net income during the next 12 months. The remaining amounts will be transferred by December 31, 2022.

Credit Risk Considerations

Over-the-counter traded derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment grade and deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2014, our oil, natural gas and interest rate derivative instruments were spread among 18 counterparties.

Hedging Facility

Our secured commodity hedging facility with 17 counterparties provides approximately 1.031 bboe of hedging capacity for oil, natural gas and NGL price derivatives and 1.031 bboe for basis derivatives with an aggregate mark-to-market capacity of $16.5 billion. The facility is secured by proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times at semi-annual collateral redetermination dates and 1.30 times in between those dates, and guarantees by certain subsidiaries that also guarantee our revolving credit facility and indentures. Chesapeake has significant flexibility with regard to releases and/or substitutions of pledged reserves, provided that certain requirements are met including maintaining specified collateral coverage ratios as well as maintaining credit ratings with either of the designated rating agencies at or above current levels. The counterparties’ obligations under the facility must be secured by cash or short-term U.S. treasury instruments to the extent that any mark-to-market amounts they owe Chesapeake exceed defined thresholds. As of December 31, 2014, we had hedged under the facility 164 mmboe of our future production with price derivatives and 10 mmboe with basis derivatives.

Fair Value

The fair value of our derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil and natural gas forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are compared to the values given by our counterparties for reasonableness. Since oil, natural gas, interest rate and cross currency swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives.

The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:

	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Fair Value
			($ in millions)
As of December 31, 2014
Derivative Assets (Liabilities):
Commodity assets	$	—	$	785		$	205		$	990
Commodity liabilities	—		(9		)	(259		)	(268		)
Interest rate liabilities	—		(17		)	—			(17		)
Foreign currency liabilities	—		(53		)	—			(53		)
Total derivatives	$	—	$	706		$	(54	)	$	652
As of December 31, 2013
Derivative Assets (Liabilities):
Commodity assets	$	—	$	25		$	15		$	40
Commodity liabilities	—		(100		)	(493		)	(593		)
Interest rate liabilities	—		(98		)	—			(98		)
Foreign currency assets	—		2			—			2
Total derivatives	$	—	$	(171	)	$	(478	)	$	(649	)

A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2014 and 2013 is presented below.

	Derivatives
	Commodity			Interest Rate
	($ in millions)
Beginning Balance as of January 1, 2014	$	(478	)	$	—
Total gains (losses) (realized/unrealized):
Included in earnings(a)	292			—
Total purchases, issuances, sales and settlements:
Settlements	136			—
Transfers(b)	(4		)	—
Ending Balance as of December 31, 2014	$	(54	)	$	—
Beginning Balance as of January 1, 2013	$	(1,016	)	$	—
Total gains (losses) (realized/unrealized):
Included in earnings(a)	410			(1		)
Total purchases, issuances, sales and settlements:
Sales	—			1
Settlements	128			—
Ending Balance as of December 31, 2013	$	(478	)	$	—

___________________________________________

(a)	Oil, Natural Gas and NGL Sales				Interest Expense
	2014		2013		2014		2013
	($ in millions)
Total gains (losses) included in earnings for the period	$	292	$	410	$	—	$	(1	)
Change in unrealized gains (losses) related to assets still held at reporting date	$	262	$	382	$	—	$	—

(b) The values related to basis swaps were transferred from Level 3 to Level 2 as a result of our ability to begin using data readily available in the public market to corroborate our estimated fair values.

Qualitative and Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements

The significant unobservable inputs for Level 3 derivative contracts include unpublished forward prices of oil and natural gas, market volatility and credit risk of counterparties. Changes in these inputs impact the fair value measurement of our derivative contracts. For example, an increase (decrease) in the forward prices and volatility of oil and natural gas prices decreases (increases) the fair value of oil and natural gas derivatives and adverse changes to our counterparties’ creditworthiness decreases the fair value of our derivatives. The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of December 31, 2014:

Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value December 31, 2014(a)
				($ in millions)
Oil trades	Oil price volatility curves	27.33% - 43.56%	34.09%	$	(49	)
Natural gas trades	Natural gas price volatility curves	18.71% - 63.70%	34.38%	$	(5	)

___________________________________________

(a) Fair value is based on an estimate derived from option models.

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Derivative and Hedging Activities - Natural Gas and Oil Sales Table (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Gains on undesignated oil and natural gas derivatives	$ 81	$ (63)	$ (1)
Total Revenues	20,951	17,506	12,316
Oil And Gas Exploration And Production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil, natural gas and NGL sales	7,162	6,923	5,359
Gains on undesignated oil and natural gas derivatives	1,055	443	857
Gains (losses) on terminated cash flow hedges	(37)	(314)	62
Total Revenues	$ 8,180	$ 7,052	$ 6,278