10-K 1 chk-20141231_10k.htm 10-K CHK-2014.12.31_10K







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




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

1



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.

2



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 into Seventy 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.

3



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.

4



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


5



___________________________________________
(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.

7



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:
24 years 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.

8



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

9



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.

12



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 renewals could 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

13



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.

14



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.

15



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.

16



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

26



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;    

27



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

28



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 that would 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.

30



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.

31



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 89th 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.

33



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.

34



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.

35



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.

36



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

 
 
 
 
 
 
 
 
 
 
 

37



 
 
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


38



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

 
 
 
 
 
 
 

39



 
 
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

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