8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): December 28, 2009

CHESAPEAKE ENERGY CORPORATION

(Exact name of Registrant as specified in its Charter)

Oklahoma	1-13726	73-1395733
(State or other jurisdiction of incorporation)	(Commission File No.)	(IRS 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)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

*           Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

*           Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

*           Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

*           Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Section 7 – Regulation FD

Item 7.01 Regulation FD Disclosure.

On January 4, 2010, Chesapeake Energy Corporation (the “Company”) issued a press release announcing the execution of an agreement for a joint venture with Total E&P USA, Inc., a wholly-owned subsidiary of Total S.A.(“Total”), whereby Total will acquire a 25% interest in Chesapeake’s upstream Barnett Shale assets for $2.25 billion.  The press release is attached herewith as Exhibit 99.1.

Also, on January 4, 2010, the Company issued an updated outlook for 2010 and 2011.  The updated outlook is attached herewith as Exhibit 99.2

On December 28, 2009, the Company issued a press release announcing that Chesapeake Energy Marketing, Inc., a subsidiary of the Company, has entered into an agreement to be the largest of three anchor shippers on a new Spectra Energy Corp natural gas pipeline project to serve the large and growing New York City metropolitan area natural gas market.  The press release is attached herewith as Exhibit 99.3.

Section 9 – Financial Statements and Exhibits

Item 9.01 Financial Statements and Exhibits

(d)Exhibits.  See "Index to Exhibits" attached to this Current Report on Form 8-K, which is incorporated by reference herein.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

CHESAPEAKE ENERGY CORPORATION
By:	/s/ JENNIFER M. GRIGSBY
	Jennifer M. Grigsby
	Senior Vice President, Treasurer and Corporate Secretary

Date:           January 4, 2010

EXHIBIT INDEX

Exhibit No.	Document Description
99.1	Chesapeake Energy Corporation press release dated January 4, 2010
99.2	Chesapeake Energy Corporation updated outlook for 2010 and 2011
99.3	Chesapeake Energy Corporation press release dated December 28, 2009

EX-99.1

Exhibit 99.1

N e w s   R e l e a s e   Chesapeake Energy Corporation P. O. Box 18496 Oklahoma City, OK  73154

FOR IMMEDIATE RELEASE

JANUARY 4, 2010

INVESTOR CONTACT: JEFFREY L. MOBLEY, CFA SENIOR VICE PRESIDENT – INVESTOR RELATIONS AND RESEARCH (405) 767-4763 jeff.mobley@chk.com MEDIA CONTACT: JIM GIPSON DIRECTOR – MEDIA RELATIONS  (405) 935-1310 jim.gipson@chk.com

CHESAPEAKE ENERGY CORPORATION ANNOUNCES $2.25 BILLION BARNETT

SHALE JOINT VENTURE WITH TOTAL E&P USA, INC.

OKLAHOMA CITY, OK, JANUARY 4, 2010 – Chesapeake Energy Corporation (NYSE:CHK) today announced the execution of an agreement for a $2.25 billion joint venture with Total E&P USA, Inc., a wholly-owned subsidiary of Total S.A. (NYSE:TOT, FP:FP) (“Total”), whereby Total will acquire a 25% interest in Chesapeake’s upstream Barnett Shale assets. Total will pay $800 million in cash at closing and will pay an additional $1.45 billion by funding 60% of Chesapeake’s share of drilling and completion expenditures until the $1.45 billion obligation has been funded, which Chesapeake expects to occur by year-end 2012.  Closing of the transaction, which is subject to regulatory approval, is anticipated by the end of January 2010.

The assets subject to the Chesapeake-Total joint venture include approximately 270,000 net acres of leasehold in the Core and Tier 1 areas of the Barnett, approximately 700 million cubic feet of natural gas equivalent per day of current net production and approximately 3.0 trillion cubic feet of natural gas equivalent (tcfe) of proved reserves (0.75 tcfe net to Total).  In addition, Chesapeake believes that its leasehold position will support the drilling of approximately 3,100 additional net locations (775 net to Total) with approximately 6.3 tcfe of unrisked unproved reserves (1.6 tcfe net to Total).  Approximately 60% of Chesapeake’s Core and Tier 1 leasehold is held by production (HBP) and therefore considered developed.

In the framework of the joint venture, Chesapeake plans to continue acquiring leasehold in the Barnett and Total will acquire its 25% share of the new acreage on promoted terms until December 31, 2015.  After such date, Total’s right to acquire its 25% proportionate share of Chesapeake’s leasehold will be on an unpromoted basis and Total will also begin paying 25% of Chesapeake’s support costs related to the joint venture’s corporate development activities.

Christophe de Margerie, Chief Executive Officer of Total, stated, “Total is pleased to be making a strategically important move by entering into the U.S. shale gas business with Chesapeake, the world’s leading shale gas operator.  This joint venture will provide us with a solid position in an attractive long-term resource base under competitive terms.  It will allow Total to develop its expertise in unconventional hydrocarbons in order to expand its unconventional business worldwide.  Additionally, this transaction adds yet another key support for Total to build the gas value chain position the Group has established in the U.S., the world’s largest and most liquid natural gas market, with our existing capacity rights in the Sabine Pass LNG terminal and our gas trading and marketing organization.  Total is conscious of the environmental aspect linked to producing shale gas and has confidence in Chesapeake’s capacity to contain the impact of the Barnett Shale gas’ operations on the environment and respect local and federal regulations and guidelines.”

Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, commented, “We are very pleased to announce our fourth joint venture transaction in the Big 4 shales and we are honored to partner with Total to further develop the Barnett Shale.  Total is one of the largest and most well respected industrial enterprises in the world.  It was established in 1924, is the fifth largest integrated natural gas and oil company, has approximately 97,000 employees and has a market valuation exceeding $150 billion.  Total approached Chesapeake about a Barnett joint venture approximately seven months ago and during this time the companies have worked diligently and thoughtfully to structure this mutually beneficial joint venture.

“This transaction will allow Chesapeake to reduce its financial leverage and future capital expenditures and further position us to deliver industry-leading finding and development costs and returns on capital for years to come.  This brings our combined shale joint venture proceeds, including upfront cash payments and drilling carries, during the past 18 months to approximately $10.8 billion, which compares very favorably against a cost basis in the assets sold of approximately $2.7 billion.  Chesapeake has maintained majority positions in these joint venture shale assets ranging from 67.5% to 80% that have an implied remaining value of approximately $33 billion based on the original valuations of the four joint ventures.

“We are proud to welcome Total into our family of joint venture partners, which also includes the world-class companies Plains Exploration & Production Company (NYSE:PXP), BP America (NYSE:BP) and Statoil (NYSE:STO).  We believe these partnerships have proven to be mutually beneficial to both Chesapeake and its partners.  We plan to continue to take advantage of our large asset base by pursuing other joint ventures, including potentially our large acreage positions in the Eagle Ford Shale and in several Mid-Continent unconventional plays that we believe would be attractive to potential partners.  We have agreed to discuss with Total an Eagle Ford joint venture as well as joint ventures covering several Canadian natural gas shale plays in which Total has shown an interest.”

Chesapeake’s exclusive advisor on the transaction was Jefferies & Company, Inc.

Conference Call Information

A conference call to discuss this release has been scheduled for Monday morning, January 4, 2010, at 10:00 a.m. EST.  The telephone number to access the conference call is 913-312-0635 or toll-free 888-668-1637.  The passcode for the call is 5634585.  We encourage those who would like to participate in the call to dial the access number between 9:50 and 10:00 a.m. EST.  For those unable to participate in the conference call, a replay will be available for audio playback from 2:00 p.m. EST on January 4, 2010 through midnight EST on January 18, 2010.  The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112.  The passcode for the replay is 5634585.  The conference call will also be webcast live on the Internet and can be accessed by going to Chesapeake’s website at www.chk.com in the “Events” subsection of the “Investors” section of our website.  The webcast of the conference call will be available on our website for one year.

This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  They include the anticipated closing of the Total joint venture transaction, an estimate of natural gas and oil reserves, planned drilling activity and plans to pursue other joint venture transactions.  Actual results, including the timing of the closing of the Total joint venture, could differ materially as a result of a variety of risks and uncertainties.  Estimates of unproved reserves are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the company.  While we believe our calculations of future drillsites and estimation of unproved reserves are reasonable, such calculations and estimates have not been reviewed by third-party engineers or appraisers.  See “Risk Factors” in our 2008 Form 10-K and 2009 second quarter Form 10-Q filed with the U.S. Securities and Exchange Commission on March 2, 2009 and August 10, 2009, respectively, for a discussion of risk factors that affect our business and could affect the joint venture announced today and other potential joint ventures.  We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information.

Chesapeake Energy Corporation is the second largest producer of natural gas in the U.S.  Headquartered in Oklahoma City, the company's operations are focused on the development of onshore unconventional and conventional natural gas in the U.S. in the Barnett Shale, Haynesville Shale, Fayetteville Shale, Marcellus Shale, Anadarko Basin, Arkoma Basin, Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast and East Texas regions of the United States.  Further information is available at www.chk.com.

Total is one of the world’s major oil and gas groups, with activities in more than 130 countries.  Its 97,000 employees put their expertise to work in every part of the industry – exploration and production of oil and natural gas, refining and marketing, gas & power and trading.  Total is working to keep the world supplied with energy, both today and tomorrow.  The Group is also a first rank player in chemicals.  Further information is available at www.total.com.

EX-99.2

Exhibit 99.2

SCHEDULE “A”

CHESAPEAKE’S OUTLOOK AS OF JANUARY 4, 2010

Years Ending December 31, 2010 and 2011

Our policy is to periodically provide guidance on certain factors that affect our future financial performance.  As of January 4, 2010, we are using the following key assumptions in our projections for 2010 and 2011.

The primary changes from our November 2, 2009 Outlook are in italicized bold and are explained as follows:

1)   Projected production volumes have been updated to reflect the production loss from the expected sale of 25% of our Barnett assets to Total (initially approximately 175 mmcfe per day) and production gains from the ongoing outperformance of our drilling programs. We believe these two factors will cancel each other in 2010 and therefore our 2010 production guidance remains unchanged at 2,650 mmcfe per day.  However, we have increased  our 2011 production forecast by 50 mmcfe per day to reflect the anticipated ongoing outperformance of our drilling programs;

2)   Projected effects of changes in our hedging positions have been updated; and

3)   Our cash flow projections have been updated.

	Year Ending 12/31/2010	Year Ending 12/31/2011
Estimated Production:
Natural gas – bcf	882 – 902	1,022 – 1,047
Oil – mbbls	12,500	13,000
Natural gas equivalent – bcfe	957 – 977	1,100 – 1,125
Daily natural gas equivalent midpoint – mmcfe	2,650	3,050
Year-over-year estimated production increase	6 – 8%	14 – 16%
Year-over-year estimated production increase excluding divestitures and curtailments	12 – 14%	15 – 17%
NYMEX Price (for calculation of realized hedging effects only):
Natural gas - $/mcf	$7.00	$7.50
Oil - $/bbl	$80.00	$80.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$0.70	$0.23
Oil - $/bbl	$4.74	$8.30
Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	15 – 25%	15 – 25%
Oil - $/bbl	7 – 10%	7 – 10%
Operating Costs per Mcfe of Projected Production:
Production expense	$0.90 – 1.10	$0.90 – 1.10
Production taxes (~ 5% of O&G revenues)	$0.30 – 0.35	$0.30 – 0.35
General and administrative(a)	$0.33 – 0.37	$0.33 – 0.37
Stock-based compensation (non-cash)	$0.10 – 0.12	$0.10 – 0.12
DD&A of natural gas and oil assets	$1.50 – 1.70	$1.50 – 1.70
Depreciation of other assets	$0.20 – 0.25	$0.20 – 0.25
Interest expense(b)	$0.35 – 0.40	$0.35 – 0.40
Other Income per Mcfe:
Marketing, gathering and compression net margin	$0.07 – 0.09	$0.07 – 0.09
Service operations net margin	$0.04 – 0.06	$0.04 – 0.06
Equity in income of midstream joint venture (CMP)	$0.04 – 0.06	$0.04 – 0.06
Book Tax Rate (all deferred)	39%	39%
Equivalent Shares Outstanding (in millions):
Basic	625 – 630	635 – 640
Diluted	640 – 645	645 – 650

	Year Ending 12/31/2010	Year Ending 12/31/2011
Cash Flow Projections ($ in millions):
Operating cash flow before changes in assets and liabilities(c)(d)	$4,450 – 4,750	$5,000 – 5,600
Net leasehold and producing property transactions	$1,300 – 1,700	$1,000 – 1,300
Drilling capital expenditures	($4,000 – 4,300)	($4,100 – 4,400)
Dividends, capitalized interest, cash income taxes, etc.	($350 – 400)	($450 – 550)
Other	($500 – 600)	($250 – 300)
Projected Net Cash Change	$900 – 1,150	$1,200 – 1,650

At December 31, 2009, the company had approximately $2.5 billion of cash and cash equivalents and additional borrowing capacity under its three revolving bank credit facilities.

(a)	Excludes expenses associated with noncash stock compensation.
(b)	Does not include gains or losses on interest rate derivatives (ASC 815).
(c)	A non-GAAP financial measure.  We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.
(d)	Assumes NYMEX natural gas prices of $6.50 to $7.50 per mcf and NYMEX oil prices of $80.00 per bbl in 2010 and  NYMEX natural gas prices of $ 7.00 to $8.00 per mcf and NYMEX oil prices of $80.00 per bbl in 2011.

Commodity Hedging Activities

The company utilizes hedging strategies to hedge the price of a portion of its future natural gas and oil production.  These strategies include:

1)	Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.
2)	Collars: These instruments contain a fixed floor price (put) and ceiling price (call).  If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price.  If the market price is between the put and the call strike price, no payments are due from either party.  On occasion, we make a three-way collar by selling an additional put option with the collar in exchange for a more favorable strike price on the collar.  This eliminates the counterparty’s downside exposure below the second put option.
3)	Knockout swaps: Chesapeake receives a fixed price and pays a floating market price.  The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain pre-determined knockout prices.
4)	Call options: Chesapeake receives a premium from the counterparty in exchange for the sale of a call option.  If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess.  If the market price settles below the fixed price of the call option, no payment is due from either party.
5)	Basis protection swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point.  For non-Appalachian Basin basis protection swaps, which typically have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.  For Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

All of our derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty.

Commodity markets are volatile, and as a result, Chesapeake’s hedging activity is dynamic.  As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction.

Chesapeake enters into natural gas and oil derivative transactions in order to mitigate a portion of its exposure to adverse market changes in natural gas and oil prices.  Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to natural gas and oil sales.  All realized gains and losses from natural gas and oil derivatives are included in natural gas and oil sales in the month of related production.  Pursuant to ASC 815, certain derivatives do not qualify for designation as cash flow hedges.  Changes in the fair value of these nonqualifying derivatives that occur prior to their maturity (i.e., because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within natural gas and oil sales.  Following provisions of ASC 815, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings.  Any change in fair value resulting from ineffectiveness is recognized currently in natural gas and oil sales.

The company currently has the following open natural gas swaps in place and also has the following gains from lifted natural gas trades:

	Open Swaps (Bcf)	Avg. NYMEX  Strike Price of Open Swaps	Assuming Natural Gas Production (Bcf)	Open Swap Positions as a % of Estimated Total Natural Gas Production	Total Gains from Lifted Trades ($ millions)	Total Lifted Gain per Mcf of Estimated Total Natural Gas Production
Q1 2010	97	$7.46			$35.9
Q2 2010	99	$7.27			$37.9
Q3 2010	94	$7.54			$65.7
Q4 2010	96	$7.69			$65.2
Total 2010(a)	386	$7.49	892	43%	$204.7	$0.23
Total 2011(a)	64	$8.69	1,035	6%	$62.7	$0.06

(a) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure at $5.50 to $6.75 covering 15 bcf in 2010 and $5.75 to 6.50 covering 24 bcf in 2011.

The company currently has the following open natural gas collars in place:

	Open Collars (Bcf)	Avg. NYMEX Floor Price	Avg. NYMEX Ceiling Price	Assuming Natural Gas Production (Bcf)	Open Collars as a % of Estimated Total Natural Gas Production
Q1 2010	43	$6.49	$8.51
Q2 2010	16	$7.04	$9.17
Q3 2010	4	$7.60	$11.75
Q4 2010	4	$7.60	$11.75
Total 2010(a)	67	$6.75	$9.03	892	8%
Total 2011	7	$7.70	$11.50	1,035	1%

(a) Certain collar arrangements include three-way collars that include written put options with a strike price ranging from $4.25 to $4.35 covering 12 bcf in 2010.

The company currently has the following natural gas written call options in place:

	Call Options (Bcf)	Avg. NYMEX Floor Price	Avg. Premium per mcf	Assuming Natural Gas Production (Bcf)	Call Options as a % of Estimated Total Natural Gas Production
Q1 2010	28	$10.19	$1.47
Q2 2010	38	$9.87	$1.11
Q3 2010	43	$9.93	$0.98
Q4 2010	43	$10.10	$0.98
Total 2010	152	$10.01	$1.10	892	17%
Total 2011	73	$10.25	$0.57	1,035	7%

The company has the following natural gas basis protection swaps in place:

	Non-Appalachia		Appalachia
	Volume (Bcf)	NYMEX less(a)	Volume (Bcf)	NYMEX plus(a)
2010	—	—	10	0.26
2011	45	0.82	12	0.25
2012	43	0.85	—	—
Totals	88	$0.84	22	$0.26

(a) weighted average

The company also has the following crude oil swaps in place:

	Open Swaps (mbbls)	Avg. NYMEX Strike Price	Assuming Oil Production (mbbls)	Open Swap Positions as a % of Estimated Total Oil Production	Total Gains (Losses) from Lifted Trades ($ millions)	Total Lifted Gains (Losses) per bbl of Estimated Total Oil Production
Q1 2010	1,980	$89.56	—	—	$(4.0)	—
Q2 2010	2,002	$89.56	—	—	$(4.0)	—
Q3 2010	2,024	$89.56	—	—	$(4.2)	—
Q4 2010	2,024	$89.56	—	—	$(4.2)	—
Total 2010(a)	8,030	$89.56	12,500	64%	$(16.4)	$(1.31)
Total 2011(a)	3,285	$96.09	13,000	25%	$32.8	$2.53

(a) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 5 mmbbls and 1 mmbbls in 2010 and 2011, respectively.

Note:  Not shown above are written call options covering 3 mmbbls of oil production in 2010 at a weighted average price of $105.00 per bbl for a weighted average discount of $1.10 per bbl and 4 mmbls of oil production in 2011 at a weighted average price of $105.00 per bbl for a weighted average premium of $4.27 per bbl.

SCHEDULE “B”

CHESAPEAKE’S PREVIOUS OUTLOOK AS OF NOVEMBER 2, 2009

(PROVIDED FOR REFERENCE ONLY)

NOW SUPERSEDED BY OUTLOOK AS OF JANURARY 4, 2010

Years Ending December 31, 2009, 2010 and 2011

Our policy is to periodically provide guidance on certain factors that affect our future financial performance.  As of November 2, 2009, we are using the following key assumptions in our projections for 2009, 2010 and 2011.

The primary changes from our October 13, 2009 Outlook are in italicized bold and are explained as follows:

1)   Projected effects of changes in our hedging positions have been updated;

2)   Our NYMEX natural gas and oil price assumptions for realized hedging effects and estimating future operating cash flow have been updated; and

3)   Our cash flow projections have been updated.

	Year Ending 12/31/2009	Year Ending 12/31/2010	Year Ending 12/31/2011
Estimated Production:
Natural gas – bcf	815 – 825	882 – 902	1,007 – 1,027
Oil – mbbls	12,000	12,500	13,000
Natural gas equivalent – bcfe	885 – 895	957 – 977	1,085 – 1,105
Daily natural gas equivalent midpoint – mmcfe	2,440	2,650	3,000
Year-over-year estimated production increase	5 – 6%	8 – 10%	12 – 14%
Year-over-year estimated production increase excluding divestitures and curtailments	9 – 10%	10 – 12%	13 – 15%
NYMEX Prices (a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$3.91	$7.00	$7.50
Oil - $/bbl	$57.75	$80.00	$80.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$2.97	$0.85	$0.22
Oil - $/bbl	$3.78	$1.99	$5.71
Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	20 – 30%	15 – 25%	15 – 25%
Oil - $/bbl	7 – 10%	7 – 10%	7 – 10%
Operating Costs per Mcfe of Projected Production:
Production expense	$1.10 – 1.20	$0.90 – 1.10	$0.90 – 1.10
Production taxes (~ 5% of O&G revenues)(b)	$0.20 – 0.25	$0.30 – 0.35	$0.30 – 0.35
General and administrative(c)	$0.33 – 0.37	$0.33 – 0.37	$0.33 – 0.37
Stock-based compensation (non-cash)	$0.10 – 0.12	$0.10 – 0.12	$0.10 – 0.12
DD&A of natural gas and oil assets	$1.50 – 1.70	$1.50 – 1.70	$1.50 – 1.70
Depreciation of other assets	$0.25 – 0.30	$0.20 – 0.25	$0.20 – 0.25
Interest expense(d)	$0.30 – 0.35	$0.35 – 0.40	$0.35 – 0.40
Other Income per Mcfe:
Marketing, gathering and compression net margin	$0.10 – 0.12	$0.07 – 0.09	$0.07 – 0.09
Service operations net margin	$0.04 – 0.06	$0.04 – 0.06	$0.04 – 0.06
Equity in income of midstream joint venture (CMP)	–	$0.04 – 0.06	$0.04 – 0.06
Book Tax Rate (all deferred)	37.5%	39%	39%
Equivalent Shares Outstanding (in millions):
Basic	610 – 615	625 – 630	635 – 640
Diluted	625 – 630	640 – 645	645 – 650

	Year Ending 12/31/2009	Year Ending 12/31/2010	Year Ending 12/31/2011
Cash Flow Projections ($ in millions):
Operating cash flow before changes in assets and liabilities(e)(f)	$3,700 – 3,750	$4,350 – 5,050	$4,750 – 5,450
Net leasehold and producing property transactions	$750 – 900	$1,000 – 1,350	$900 – 1,250
Drilling capital expenditures	($3,150 – 3,350)	($4,400 – 4,700)	($4,600 – 4,900)
Dividends, senior notes redemption, capitalized interest, cash income taxes, etc.	($600 – 825)	($400 – 500)	($450 – 550)
Other	($375 – 550)	($225 – 300)	($50 – 125)
Projected Net Cash Change	($75) – 325	$325 – 900	$550 – 1,125

At September 30, 2009, the company had $3.1 billion of cash and cash equivalents and additional borrowing capacity under its three revolving bank credit facilities.

(a)	NYMEX natural gas prices have been updated for actual contract prices through November 2009 and NYMEX oil prices have been updated for actual contract prices through September 2009.
(b)	Production tax per mcfe is based on NYMEX prices of $57.75 per bbl of oil and $4.75 to $6.25 per mcf of natural gas during 2009 and $80.00 per bbl of oil and $7.00 to $8.25 per mcf of natural gas during 2010 and 2011.
(c)	Excludes expenses associated with noncash stock compensation.
(d)	Does not include gains or losses on interest rate derivatives (ASC 815).
(e)	A non-GAAP financial measure.  We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.
(f)	Assumes NYMEX natural gas prices of $5.00 to $6.00 per mcf and NYMEX oil prices of $57.75 per bbl in 2009,  NYMEX natural gas prices of $6.50 to $7.50 per mcf and NYMEX oil prices of $80.00 per bbl in 2010 and  NYMEX natural gas prices of $ 7.00 to $8.00 per mcf and NYMEX oil prices of $80.00 per bbl in 2011.

Commodity Hedging Activities

The company utilizes hedging strategies to hedge the price of a portion of its future natural gas and oil production.  These strategies include:

1)	For swap instruments, Chesapeake receives a fixed price for the commodity and pays a floating market price to the counterparty.
2)	Collars contain a fixed floor price (put) and ceiling price (call).  If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price.  If the market price is between the call and the put strike price, no payments are due from either party.
3)	For knockout swaps, Chesapeake receives a fixed price and pays a floating market price.  The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain pre-determined knockout prices.
4)	For written call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option.  If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess.  If the market price settles below the fixed price of the call option, no payment is due from Chesapeake.
5)	Basis protection swaps are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point.  For non-Appalachian Basin basis protection swaps, which typically have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.  For Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.
6)	A three-way collar contract consists of a standard collar contract plus a written put option with a strike price below the floor price of the collar.  In addition to the settlement of the collar, the put option requires Chesapeake to make a payment to the counterparty equal to the difference between the put option price and the settlement price if the settlement price for any settlement period is below the put option strike price.

All of our derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty.

Commodity markets are volatile, and as a result, Chesapeake’s hedging activity is dynamic.  As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction.

Chesapeake enters into natural gas and oil derivative transactions in order to mitigate a portion of its exposure to adverse market changes in natural gas and oil prices.  Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to natural gas and oil sales.  All realized gains and losses from natural gas and oil derivatives are included in natural gas and oil sales in the month of related production.  Pursuant to ASC 815, certain derivatives do not qualify for designation as cash flow hedges.  Changes in the fair value of these nonqualifying derivatives that occur prior to their maturity (i.e., because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within natural gas and oil sales.  Following provisions of ASC 815, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings.  Any change in fair value resulting from ineffectiveness is recognized currently in natural gas and oil sales.

Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following open natural gas swaps in place and also has the following gains from lifted natural gas trades:

	Open Swaps (Bcf)	Avg. NYMEX  Strike Price of Open Swaps	Assuming Natural Gas Production (Bcf)	Open Swap Positions as a % of Estimated Total Natural Gas Production	Total Gains from Lifted Trades ($ millions)	Total Lifted Gain per Mcf of Estimated Total Natural Gas Production
Q4 2009(a)	107.2	$6.83	210	51%	$114.2	$0.54
Q1 2010	28.7	$9.84			$50.6
Q2 2010	27.5	$8.83			$52.7
Q3 2010	31.7	$9.60			$60.1
Q4 2010	33.0	$9.77			$59.5
Total 2010(a)	120.9	$9.53	892	14%	$222.9	$0.25
Total 2011(a)	23.7	$9.86	1,017	2%	$62.7	$0.06

(a) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure at $6.00 covering 1 bcf for the remainder of 2009, $5.45 to $6.75 covering 70 bcf in 2010 and $5.75 to 6.50 covering 24 bcf in 2011.

The company currently has the following open natural gas collars in place:

	Open Collars (Bcf)	Avg. NYMEX Floor Price	Avg. NYMEX Ceiling Price	Assuming Natural Gas Production (Bcf)	Open Collars as a % of Estimated Total Natural Gas Production
Q4 2009(a)	52.1	$7.34	$8.88	210	25%
Q1 2010	43.2	$6.49	$8.51
Q2 2010	16.4	$7.04	$9.17
Q3 2010	3.7	$7.60	$11.75
Q4 2010	3.7	$7.60	$11.75
Total 2010(a)	67.0	$6.75	$9.03	892	8%
Total 2011	7.2	$7.70	$11.50	1,017	1%

(a) Certain collar arrangements include three-way collars that include written put options with a strike price of $6.00 covering 11 bcf for the remainder of 2009 and ranging from $4.25 to $5.50 covering 26 bcf in 2010.

The company currently has the following natural gas written call options in place:

	Call Options (Bcf)	Avg. NYMEX Floor Price	Avg. Premium per mcf	Assuming Natural Gas Production (Bcf)	Call Options as a % of Estimated Total Natural Gas Production
Q4 2009	9.7	$6.51	$2.25	210	5%
Q1 2010	69.3	$10.26	$0.61
Q2 2010	74.6	$10.08	$0.56
Q3 2010	75.4	$10.17	$0.56
Q4 2010	75.4	$10.27	$0.56
Total 2010	294.7	$10.19	$0.57	892	33%
Total 2011	73.1	$10.25	$0.57	1,017	7%

The company has the following natural gas basis protection swaps in place:

	Non-Appalachia		Appalachia
	Volume (Bcf)	NYMEX less(a)	Volume (Bcf)	NYMEX plus(a)
2009	10.4	$1.64	4.4	$0.27
2010	—	—	10.2	0.26
2011	45.1	0.82	12.1	0.25
2012	43.2	0.85	—	—
Totals	98.7	$0.92	26.7	$0.26

(a) weighted average

We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition in November 2005.  In accordance with ASC 805, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($11 million as of September 30, 2009).  The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired.  Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our natural gas and oil revenues upon settlement.  For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to natural gas and oil revenues related to the derivative positions.  If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in natural gas and oil revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation.  For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR.

Pursuant to ASC 815 Derivatives and Hedging, the assumed CNR derivative instruments are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows.

The following details the CNR derivatives (natural gas swaps) we have assumed:

	Open Swaps (Bcf)	Avg. NYMEX Strike Price Of Open Swaps	Avg. Fair Value Upon Acquisition of Open Swaps	Initial Liability Acquired	Assuming Natural Gas Production (Bcf)	Open Swap Positions as a % of Estimated Total Natural Gas Production
Q4 2009	4.6	$5.18	$7.32	$(2.14)	210	2%

Note:  Not shown above are collars covering 1 bcf of production for the remainder of 2009 at an average floor and ceiling of $4.50 and $6.00.

The company also has the following crude oil swaps in place:

	Open Swaps (mbbls)	Avg. NYMEX Strike Price	Assuming Oil Production (mbbls)	Open Swap Positions as a % of Estimated Total Oil Production	Total Gains (Losses) from Lifted Trades ($ millions)	Total Lifted Gains (Losses) per bbl of Estimated Total Oil Production
Q4 2009	1,058	$87.05	2,947	36%	$9.4	$3.20
Q1 2010	1,170	$90.25	—	—	$(4.0)	—
Q2 2010	1,183	$90.25	—	—	$(4.0)	—
Q3 2010	1,196	$90.25	—	—	$(4.2)	—
Q4 2010	1,196	$90.25	—	—	$(4.2)	—
Total 2010(a)	4,745	$90.25	12,500	38%	$(16.4)	$(1.31)
Total 2011(a)	1,095	$104.75	13,000	8%	$32.8	$2.53

(a) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $50.00 to $60.00 covering 1 mmbbls for the remainder of 2009 and $60.00 covering 5 mmbbls and 1 mmbbls in 2010 and 2011, respectively.

Note:  Not shown above are written call options covering 1 mmbbls of oil production for the remainder of 2009 at a weighted average price of $112.50 per bbl for a weighted average discount of $1.21 per bbl, 3 mmbbls of oil production in 2010 at a weighted average price of $115.00 per bbl for a weighted average discount of $0.86 per bbl and 4 mmbls of oil production in 2011 at a weighted average price of $105.00 per bbl for a weighted average premium of $4.27 per bbl.

EX-99.3

Exhibit 99.3

N e w s   R e l e a s e   Chesapeake Energy Corporation P. O. Box 18496 Oklahoma City, OK  73154

FOR IMMEDIATE RELEASE

DECEMBER 28, 2009

INVESTOR CONTACT: JEFFREY L. MOBLEY, CFA SENIOR VICE PRESIDENT – INVESTOR RELATIONS AND RESEARCH (405) 767-4763 jeff.mobley@chk.com MEDIA CONTACT: JIM GIPSON DIRECTOR – MEDIA RELATIONS  (405) 935-1310 jim.gipson@chk.com

CHESAPEAKE ENERGY CORPORATION SECURES NEW PIPELINE CAPACITY

TO EXPAND NATURAL GAS MARKET IN NEW YORK CITY METRO AREA

Spectra Energy Pipeline to Deliver Natural Gas from

Chesapeake’s Marcellus Shale Production

OKLAHOMA CITY, OKLAHOMA, DECEMBER 28, 2009 – Chesapeake Energy Marketing, Inc., a subsidiary of Chesapeake Energy Corporation (NYSE:CHK), announced today that it has entered into an agreement to be the largest of three anchor shippers on a new Spectra Energy Corp (NYSE:SE) natural gas pipeline project to serve the large and growing New York City metropolitan area natural gas market.  Spectra Energy will construct facilities on its Algonquin Gas Transmission and Texas Eastern Transmission pipeline systems, including approximately 16 miles of 30-inch pipeline from Staten Island to Manhattan.  Once completed, the pipeline will provide a new interconnect with facilities of Consolidated Edison of New York (NYSE:ED), which will deliver up to 800 million cubic feet per day (mmcf/d) of additional natural gas to Con Edison’s service area.  Chesapeake is the largest capacity holder with a commitment of up to 425 mmcf/d.  The expansion is expected to be in service by year-end 2013.

Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, commented, “Chesapeake is pleased to make the commitments necessary to transport our growing Marcellus Shale production into the best natural gas market in the U.S.  The relative proximity of abundant Marcellus natural gas reserves to New York City will provide the public, utilities and businesses with a clean-burning alternative to existing dirtier fuel sources.  Increased investment in natural gas production and distribution will create tens of thousands of well-paying American jobs in areas that have been suffering economically and will reduce our dependence on expensive foreign oil and other carbon-heavy fuels such as coal.  Natural gas provides a cleaner alternative that will reduce greenhouse emissions and improve air quality in the New York City metropolitan area – a major goal of the city’s long-term clean-air initiative.

“With the newfound abundance of domestic natural gas unfolding in many parts of the country through deep shale development, American energy consumers can now more fully embrace the substantial economic and environmental benefits of natural gas,” McClendon said.

This is the first major pipeline expansion in the Northeast U.S. that is designed to transport Chesapeake’s rapidly expanding Marcellus Shale natural gas production and will likely be followed by other pipeline expansion projects from the Marcellus to other high-value eastern U.S. markets.  The New York City metropolitan area is the logical first expanded distribution delivery point for this production based on proximity to the Marcellus and the need for the New York City area to reduce its greenhouse gas emissions and improve air quality by burning less fuel oil in electricity-generating power plants and in building and home furnaces.

Chesapeake believes the Marcellus will become one of the two largest natural gas fields in the U.S., along with the Haynesville Shale.  Chesapeake is both the largest leasehold owner and most active driller in both the Marcellus and the Haynesville with more than 1.5 million and 0.5 million net acres owned, respectively, and with 23 and 38 operated rigs currently drilling, respectively.

To date, Chesapeake has invested more than $1.0 billion in acquiring leasehold drilling rights from landowners in New York and Pennsylvania and in 2009 created more than 650 new jobs in Pennsylvania to explore for and develop Marcellus natural gas.  The company expects to continue hiring at least 1,000 Pennsylvanians directly and indirectly annually for years to come.  The company has no employee hiring plans in New York until the current Marcellus drilling moratorium is lifted.

Although New York Marcellus natural gas volumes will not be required to support the pipeline expansion announced today, McClendon said, “We look forward to the day when we can re-activate our Marcellus drilling program in the Southern Tier of New York using our advanced drilling and completion technologies, which will demonstrate our ability to safely and responsibly explore for and produce natural gas in an environmentally sensitive way, just as we do every day in Pennsylvania and in many other states across the country.”

Chesapeake Energy Corporation is one of the leading producers of natural gas in the U.S.  Headquartered in Oklahoma City, the company's operations are focused on the development of onshore unconventional and conventional natural gas in the U.S. in the Barnett Shale, Haynesville Shale, Fayetteville Shale, Marcellus Shale, Anadarko Basin, Arkoma Basin, Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast and East Texas regions of the United States.  Further information is available at www.chk.com.