Exhibit 99.2

  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

FEBRUARY 17, 2010

INVESTOR CONTACTS:	MEDIA CONTACT:
JEFFREY L. MOBLEY, CFA (405) 767-4763 jeff.mobley@chk.com JOHN J. KILGALLON (405) 935-4441 john.kilgallon@chk.com	JIM GIPSON  (405) 935-1310 jim.gipson@chk.com

CHESAPEAKE ENERGY CORPORATION REPORTS FINANCIAL RESULTS

FOR THE 2009 FOURTH QUARTER AND FULL YEAR

Company Reports 2009 Fourth Quarter Net Loss to Common Shareholders of $530 Million,

or $0.84 per Fully Diluted Common Share, on Revenue of $2.2 Billion; Adjusted

Net Income Available to Common Shareholders Was $490 Million,

or $0.77 per Fully Diluted Common Share

2009 Full Year Net Loss to Common Shareholders Was $5.9 Billion, or $9.57 per

 Fully Diluted Common Share, on Revenue of $7.7 Billion; Adjusted Net Income

 Available to Common Shareholders Was $1.6 Billion,

or $2.55 per Fully Diluted Common Share

2009 Fourth Quarter Production of 2.6 Bcfe per Day Increases 13% Over 2008 Fourth

Quarter Production; 2009 Full Year Production of 2.5 Bcfe per Day

Increases 8% Over 2008 Full Year Production

OKLAHOMA CITY, OKLAHOMA, FEBRUARY 17, 2010 – Chesapeake Energy Corporation (NYSE:CHK) today announced financial results for the 2009 fourth quarter and full year.  For the 2009 fourth quarter, Chesapeake reported a net loss to common shareholders of $530 million ($0.84 per fully diluted common share) and operating cash flow (defined as cash flow from operating activities before changes in assets and liabilities) of $1.212 billion on revenue of $2.222 billion and production of 241 billion cubic feet of natural gas equivalent (bcfe).  For the 2009 full year, Chesapeake reported a net loss to common shareholders of $5.853 billion ($9.57 per fully diluted common share) and operating cash flow of $4.333 billion on revenue of $7.702 billion and production of 906 bcfe.

The company’s 2009 fourth quarter and full year results include a realized natural gas and oil hedging gain of $544 million and $2.346 billion, respectively.  The results also include various items that are typically not included in published estimates of the company’s financial results by certain securities analysts.  Excluding the items detailed below, for the 2009 fourth quarter, Chesapeake reported adjusted net income to common shareholders of $490 million ($0.77 per fully diluted common share) and adjusted ebitda of $1.256 billion.  For the 2009 full year, Chesapeake generated adjusted net income to common shareholders of $1.585 billion ($2.55 per fully diluted common share) and adjusted ebitda of $4.407 billion.  The excluded items and their effects on 2009 fourth quarter and full year reported results are detailed as follows:

·   a net non-cash unrealized after-tax mark-to-market loss of $126 million for 2009 fourth quarter and $311 million for the full year resulting from the company’s natural gas, oil and interest rate hedging programs;

·   a non-cash after-tax impairment charge of $875 million for the 2009 fourth quarter and $6.875 billion for the full year related to the carrying value of natural gas and oil properties under the full-cost method of accounting;

·   a non-cash combined after-tax impairment charge of $5 million for the 2009 fourth quarter and $80 million for the full year related primarily to certain midstream assets contributed to the newly formed midstream joint venture with Global Infrastructure Partners;

·   a non-cash after-tax impairment charge of $102 million for the full year related to certain investments;

·   a non-cash after-tax charge of $14 million for the 2009 fourth quarter and $25 million for the full year on exchanges of certain of the company’s contingent convertible senior notes for shares of common stock; and

·   a combined after-tax charge of $45 million for the 2009 full year related to restructuring and relocation costs related to the company’s Eastern Division, other workforce reduction costs and losses on the sales of certain gathering systems.

The various items described above do not materially affect the calculation of operating cash flow.  A reconciliation of operating cash flow, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 12 – 16 of this release.

Key Operational and Financial Statistics Summarized

The table below summarizes Chesapeake’s key results during the 2009 fourth quarter and compares them to results during the 2009 third quarter and the 2008 fourth quarter and also compares the 2009 full year to the 2008 full year.

	Three Months Ended							Full Year Ended
	12/31/09		9/30/09			12/31/08(a)		12/31/09	12/31/08(a)
Average daily production (in mmcfe)		2,618		2,483			2,316	2,481	2,303
Natural gas as % of total production		93		92			92	92	92
Natural gas production (in bcf)		224.5		210.3			196.0	834.8	775.4
Average realized natural gas price ($/mcf) (b)		6.05		6.04			7.13	5.93	8.09
Oil production (in mbbls)		2,737		3,027			2,848	11,790	11,220
Average realized oil price ($/bbl) (b)		71.61		66.42			54.80	58.38	70.48
Natural gas equivalent production (in bcfe)		240.9		228.5			213.1	905.5	842.7
Natural gas equivalent realized price ($/mcfe) (b)		6.45		6.44			7.29	6.22	8.38
Marketing, gathering and compression
net margin ($/mcfe)		.23		.13			.11	.16	.11
Service operations net margin ($/mcfe)		.02		.00			.04	.01	.04
Production expenses ($/mcfe)		(.86)		(.96	)		(1.09)	(.97)	(1.05)
Production taxes ($/mcfe)		(.15)		(.11	)		(.16)	(.12)	(.34)
General and administrative costs ($/mcfe) (c)		(.28)		(.32	)		(.33)	(.29)	(.35)
Stock-based compensation ($/mcfe)		(.09)		(.09	)		(.09)	(.09)	(.10)
DD&A of natural gas and oil properties ($/mcfe)		(1.39)		(1.29	)		(2.12)	(1.51)	(2.34)
D&A of other assets ($/mcfe)		(.28)		(.27	)		(.24)	(.27)	(.21)
Interest expense ($/mcfe) (b)		(.19)		(.28	)		.05	(.22)	(.22)
Operating cash flow ($ in millions) (d)		1,212		1,116			1,054	4,333	5,299
Operating cash flow ($/mcfe)		5.03		4.89			4.95	4.78	6.29
Adjusted ebitda ($ in millions) (e)		1,256		1,133			1,242	4,407	5,633
Adjusted ebitda ($/mcfe)		5.21		4.96			5.83	4.87	6.68
Net income to common shareholders ($ in millions)		(530)		186			(1,001)	(5,853)	504
Earnings per share – assuming dilution ($)		(.84)		.30			(1.74)	(9.57)	.93
Adjusted net income to common shareholders ($ in millions) (f)		490		440			438	1,585	1,981
Adjusted earnings per share – assuming dilution ($)		.77		.70			.75	2.55	3.60

(a)	Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options
(b)	Includes the effects of realized gains (losses) from hedging, but does not include the effects of unrealized gains (losses) from hedging
(c)	Excludes expenses associated with noncash stock-based compensation
(d)	Defined as cash flow provided by operating activities before changes in assets and liabilities
(e)	Defined as net income (loss) before income taxes, interest expense, and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 14
(f)	Defined as net income (loss) available to common shareholders, as adjusted to remove the effects of certain items detailed on pages 15 and 16

2009 Fourth Quarter Average Daily Production Increases 5% Over 2009 Third Quarter

Production and 13% Over 2008 Fourth Quarter Production; 2009 Full Year Average

Daily Production Increases 8% Over 2008 Full Year Average Daily Production,

Setting Record for 20th Consecutive Year

As announced on February 16, 2010, Chesapeake’s daily production for the 2009 fourth quarter averaged 2.618 bcfe, an increase of 135 million cubic feet of natural gas equivalent (mmcfe), or 5%, over the 2.483 bcfe produced per day in the 2009 third quarter and an increase of 302 mmcfe, or 13%, over the 2.316 bcfe produced per day in the 2008 fourth quarter.  Adjusted for the company’s voluntary production curtailments due to low natural gas prices (approximately 26 mmcfe per day during the 2009 fourth quarter), the company’s volumetric production payment transactions (which combined averaged approximately 96 mmcfe per day during the 2009 fourth quarter) and the estimated impact from various divestitures (which would have averaged approximately 49 mmcfe per day during the 2009 fourth quarter), Chesapeake’s sequential and year-over-year production growth rates would have been 5% and 17%, respectively, after making similar adjustments to prior quarters.  Chesapeake’s 2009 fourth quarter average daily production of 2.618 bcfe consisted of 2.440 billion cubic feet of natural gas (bcf) and 29,750 barrels of oil and natural gas liquids (bbls).  The company’s 2009 fourth quarter production of 241 bcfe was comprised of 225 bcf (93% on a natural gas equivalent basis) and 2.7 million barrels of oil and natural gas liquids (mmbbls) (7% on a natural gas equivalent basis).

The company’s daily production for the 2009 full year averaged 2.481 bcfe, an increase of 178 mmcfe, or 8%, over the 2.303 bcfe of daily production for the 2008 full year.  Adjusted for the company’s voluntary production curtailments due to low natural gas prices (approximately 47 mmcfe per day during the 2009 full year), the company’s volumetric production payment transactions (which combined averaged approximately 157 mmcfe per day during the 2009 full year) and the estimated impact from various divestitures (which would have averaged approximately 193 mmcfe per day during the 2009 full year), Chesapeake’s year-over-year production growth rate would have been 19%, after making similar adjustments to the 2008 full year.  Chesapeake’s average daily production for the 2009 full year of 2.481 bcfe consisted of 2.287 bcf and 32,301 bbls.  The company’s 2009 full year production of 906 bcfe was comprised of 835 bcf (92% on a natural gas equivalent basis) and 11.8 mmbbls (8% on a natural gas equivalent basis).  The 2009 full year was Chesapeake’s 20th consecutive year of sequential production growth.  Chesapeake anticipates delivering full-year production growth of approximately 8-10% in 2010 and 15-17% in 2011, net of property divestitures.

Average Realized Prices, Hedging Results and Hedging Positions Detailed

Average prices realized during the 2009 fourth quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives), were $6.05 per thousand cubic feet (mcf) and $71.61 per bbl, for a realized natural gas equivalent price of $6.45 per thousand cubic feet of natural gas equivalent (mcfe).  Realized gains from natural gas and oil hedging activities during the 2009 fourth quarter generated a $2.42 gain per mcf and a $0.69 gain per bbl for a 2009 fourth quarter realized hedging gain of $544 million, or $2.26 per mcfe.  Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to NYMEX during the 2009 fourth quarter were a negative $0.53 per mcf and a negative $5.27 per bbl.

By comparison, average prices realized during the 2008 fourth quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $7.13 per mcf and $54.80 per bbl, for a realized natural gas equivalent price of $7.29 per mcfe.  Realized gains from natural gas and oil hedging activities during the 2008 fourth quarter generated a $2.25 gain per mcf and a $1.61 gain per bbl for a 2008 fourth quarter realized hedging gain of $446 million, or $2.09 per mcfe.  Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to NYMEX during the 2008 fourth quarter were a negative $2.07 per mcf and a negative $5.55 per bbl.

For the 2009 full year, average prices realized (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.93 per mcf and $58.38 per bbl, for a realized natural gas equivalent price of $6.22 per mcfe.  Realized gains and losses from natural gas and oil hedging activities during the 2009 full year generated a $2.77 gain per mcf and a $2.78 gain per bbl for a 2009 full year realized hedging gain of $2.346 billion, or $2.59 per mcfe.  Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to NYMEX during the 2009 full year were a negative $0.83 per mcf and a negative $6.20 per bbl.

By comparison, average prices realized during the 2008 full year (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $8.09 per mcf and $70.48 per bbl, for a realized natural gas equivalent price of $8.38 per mcfe.  Realized gains and losses from natural gas and oil hedging activities during the 2008 full year generated a $0.35 gain per mcf and a $24.56 loss per bbl for a 2008 full year realized hedging loss of $8 million, or $0.01 per mcfe.  Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to NYMEX during the 2008 full year were a negative $1.30 per mcf and a negative $4.61 per bbl.

The following tables summarize Chesapeake’s open hedge position through swaps and collars as of February 17, 2010.  Depending on changes in natural gas and oil futures markets and management’s view of underlying natural gas and oil supply and demand trends, Chesapeake may either increase or decrease its hedging positions at any time in the future without notice.

Open Swap Positions as of February 17, 2010

	Natural Gas		Oil
Year	% Hedged	$ NYMEX	% Hedged	$ NYMEX
2010	53%	7.58	59%	89.62
2011	7%	8.71	19%	96.09

Open Natural Gas Collar Positions as of February 17, 2010

		Average Floor	Average Ceiling
Year	% Hedged	$ NYMEX	$ NYMEX
2010	8%	6.75	9.03
2011	1%	7.70	11.50

Note:  Certain open natural gas swap positions include knockout swaps with knockout provisions at prices ranging from $5.50 to $6.75 per mcf covering 15 bcf in 2010, or approximately 3% of the company’s natural gas swap positions in 2010, and $5.75 to $6.50 per mcf covering 24 bcf in 2011, or approximately 33% of the company’s natural gas swap positions in 2011.  Certain open natural gas collar positions include three-way collars that include written put options with strike prices ranging from $4.25 to $4.35 per mcf covering 12 bcf in 2010, or approximately 18% of the company’s natural gas collar positions in 2010.  Also, certain open oil swap positions include knockout swaps with knockout provisions at a price of $60 per bbl covering 5 mmbbls and 1 mmbbls in 2010 and 2011, respectively, or approximately 52% and 33% of the company’s oil swap positions in 2010 and in 2011, respectively.

As of February 12, 2010, Chesapeake’s natural gas and oil hedging positions with 14 different counterparties had a positive mark-to-market value of approximately $95 million.  The company’s realized hedging gains for the 2009 full year were $2.346 billion and since January 1, 2001 have been $4.421 billion.

The company’s updated forecasts for 2010 and 2011 are attached to this release in an Outlook dated February 17, 2010, labeled as Schedule “A,” which begins on page 17.  This Outlook has been changed from the Outlook dated January 4, 2010, attached as Schedule “B,” which begins on page 21, to reflect various updated information.

Company Closes Barnett Shale Joint Venture with Total and

Closes Sixth Volumetric Production Payment Transaction

As previously disclosed, on January 26, 2010, Chesapeake and Total E&P USA, Inc., a wholly-owned subsidiary of Total S.A. (NYSE: TOT, FP: FP) (“Total”), closed the $2.25 billion Barnett Shale joint venture transaction, whereby Total acquired a 25% interest in Chesapeake’s upstream Barnett Shale assets.  Total paid Chesapeake approximately $800 million in cash at closing and will pay a further $1.45 billion over time by funding 60% of Chesapeake’s share of future drilling and completion expenditures.  Chesapeake expects this drilling carry to be funded by year-end 2012.  Additionally, on February 5, 2010 the company sold certain Chesapeake-operated long-lived producing assets in East Texas and the Texas Gulf Coast in its sixth volumetric production payment (VPP) transaction for proceeds of $180 million, or $3.95 per mcfe of proved reserves.  The assets in the VPP included proved reserves of approximately 45.5 bcfe and current net production of approximately 20 mmcfe per day. 

Conference Call Information

A conference call to discuss this release of financial results and the company's release of its operational results issued on February 16, 2010 has been scheduled for Thursday morning, February 18, 2010, at 9:00 a.m. EST.  The telephone number to access the conference call is913-312-0688 or toll-free 800-930-1344.  The passcode for the call is 2347767.  We encourage those who would like to participate in the call to dial the access number between 8:50 and 9:00 a.m. EST.  For those unable to participate in the conference call, a replay will be available for audio playback from 1:00 p.m. EST on February 18, 2010 through midnight EST on March 4, 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 2347767.  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 press release and the accompanying Outlooks include “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.  Forward-looking statements give our current expectations or forecasts of future events.  They include expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, planned capital expenditures and anticipated asset acquisitions and sales, projected cash flow and liquidity, business strategy and other plans and objectives for future operations.  Disclosures concerning the fair value of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date.  These market prices are subject to significant volatility.  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.

Factors that could cause actual results to differ materially from expected results are described under “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.  These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; impacts the current economic downturn may have on our business and financial condition; declines in the values of our natural gas and oil properties resulting in ceiling test write-downs; the availability of capital on an economic basis, including planned asset monetization transactions, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the amount and timing of development expenditures; exploration and development drilling that does not result in commercially productive reserves; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas and oil sales and the need to secure hedging liabilities; uncertainties in evaluating natural gas and oil reserves of acquired properties and potential liabilities; the negative impact lower natural gas and oil prices could have on our ability to borrow; drilling and operating risks, including potential environmental liabilities; transportation capacity constraints and interruptions that could adversely affect our cash flow; potential increased operating costs resulting from proposed legislative and regulatory changes affecting our operations; and adverse results in pending or future litigation.

Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity.  Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct.  They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.

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.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in millions, except per-share and unit data)

(unaudited)

THREE MONTHS ENDED:	December 31,					December 31,
	2009					2008 (a)
	$			$/mcfe		$			$/mcfe
REVENUES:
Natural gas and oil sales		1,368		5.68			2,271		10.66
Marketing, gathering and compression sales		803		3.33			664		3.12
Service operations revenue		51		0.21			46		0.21
Total Revenues		2,222		9.22			2,981		13.99
OPERATING COSTS:
Production expenses		206		0.86			231		1.09
Production taxes		36		0.15			35		0.16
General and administrative expenses		89		0.37			89		0.42
Marketing, gathering and compression expenses		747		3.10			641		3.01
Service operations expense		47		0.19			38		0.17
Natural gas and oil depreciation, depletion and amortization		335		1.39			452		2.12
Depreciation and amortization of other assets		67		0.28			50		0.24
Impairment of natural gas and oil properties and other assets		1,408		5.84			2,830		13.28
Total Operating Costs		2,935		12.18			4,366		20.49
INCOME (LOSS) FROM OPERATIONS		(713	)	(2.96	)		(1,385	)	(6.50	)
OTHER INCOME (EXPENSE):
Other income (expense)		(2	)	(0.01	)		12		0.05
Interest expense		(62	)	(0.25	)		(84	)	(0.40	)
Impairment of investments		—		—			(180	)	(0.84	)
Gain (Loss) on exchanges of Chesapeake debt		(21	)	(0.09	)		27		0.13
Total Other Income (Expense)		(85	)	(0.35	)		(225	)	(1.06	)
INCOME (LOSS) BEFORE INCOME TAXES		(798	)	(3.31	)		(1,610	)	(7.56	)
Income Tax Expense (Benefit):
Current income taxes		3		0.01			227		1.06
Deferred income taxes		(302	)	(1.25	)		(842	)	(3.95	)
Total Income Tax Expense  (Benefit)		(299	)	(1.24	)		(615	)	(2.89	)
NET INCOME (LOSS)		(499	)	(2.07	)		(995	)	(4.67	)
Net (income) loss attributable to noncontrolling interest		(25	)	(0.11	)		—		—
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE		(524	)	(2.18	)		(995	)	(4.67	)
Preferred stock dividends		(6	)	(0.02	)		(6	)	(0.03	)
NET INCOME (LOSS) AVAILABLE TO CHESAPEAKE   COMMON STOCKHOLDERS		(530	)	(2.20	)		(1,001	)	(4.70	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	(0.84	)			$	(1.74	)
Assuming dilution	$	(0.84	)			$	(1.74	)
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions)
Basic		628					575
Assuming dilution		628					575

(a) Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in millions, except per-share and unit data)

(unaudited)

TWELVE MONTHS ENDED:	December 31,					December 31,
	2009					2008 (a)
	$			$/mcfe		$			$/mcfe
REVENUES:
Natural gas and oil sales		5,049		5.57			7,858		9.32
Marketing, gathering and compression sales		2,463		2.72			3,598		4.27
Service operations revenue		190		0.21			173		0.21
Total Revenues		7,702		8.50			11,629		13.80
OPERATING COSTS:
Production expenses		876		0.97			889		1.05
Production taxes		107		0.12			284		0.34
General and administrative expenses		349		0.38			377		0.45
Marketing, gathering and compression expenses		2,316		2.56			3,505		4.16
Service operations expense		182		0.20			143		0.17
Natural gas and oil depreciation, depletion and amortization		1,371		1.51			1,970		2.34
Depreciation and amortization of other assets		244		0.27			174		0.21
Impairment of natural gas and oil properties and other assets		11,130		12.29			2,830		3.35
Loss on sale of other property and equipment		38		0.04			—		—
Restructuring costs		34		0.04			—		—
Total Operating Costs		16,647		18.38			10,172		12.07
INCOME (LOSS) FROM OPERATIONS		(8,945	)	(9.88	)		1,457		1.73
OTHER INCOME (EXPENSE):
Other income (expense)		(28	)	(0.03	)		(11	)	(0.01	)
Interest expense		(113	)	(0.13	)		(271	)	(0.32	)
Impairment of investments		(162	)	(0.18	)		(180	)	(0.21	)
Loss on exchanges or repurchases of Chesapeake debt		(40	)	(0.04	)		(4	)	(0.01	)
Total Other Income (Expense)		(343	)	(0.38	)		(466	)	(0.55	)
INCOME (LOSS) BEFORE INCOME TAXES		(9,288	)	(10.26	)		991		1.18
Income Tax Expense (Benefit):
Current income taxes		4		—			423		0.50
Deferred income taxes		(3,487	)	(3.85	)		(36	)	(0.04	)
Total Income Tax Expense (Benefit)		(3,483	)	(3.85	)		387		0.46
NET INCOME (LOSS)		(5,805	)	(6.41	)		604		0.72
Net (income) loss attributable to noncontrolling interest		(25	)	(0.03	)		—		—
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE		(5,830	)	(6.44	)		604		0.72
Preferred stock dividends		(23	)	(0.02	)		(33	)	(0.04	)
Loss on conversion/exchange of preferred stock		—		—			(67	)	(0.08	)
NET INCOME (LOSS) AVAILABLE TO CHESAPEAKE COMMON STOCKHOLDERS		(5,853	)	(6.46	)		504		0.60
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	(9.57	)			$	0.94
Assuming dilution	$	(9.57	)			$	0.93
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions)
Basic		612					536
Assuming dilution		612					545

(a) Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

($ in millions)

(unaudited)

	December 31,		December 31,
	2009		2008 (a)
Cash and cash equivalents	$	307	$	1,749
Other current assets		2,139		2,543
Total Current Assets		2,446		4,292
Property and equipment (net)		26,710		33,308
Other assets		758		993
Total Assets	$	29,914	$	38,593
Current liabilities	$	2,688	$	3,621
Long-term debt, net (b)		12,295		13,175
Asset retirement obligation		282		269
Other long-term liabilities		1,249		311
Deferred tax liability		1,059		4,200
Total Liabilities		17,573		21,576
Chesapeake Stockholders’ Equity		11,444		17,017
Noncontrolling interest		897		—
Total equity		12,341		17,017
Total Liabilities & Equity	$	29,914	$	38,593
Common Shares Outstanding (in millions)		648		607

CHESAPEAKE ENERGY CORPORATION

CAPITALIZATION

($ in millions)

(unaudited)

	December 31,	% of Total Book	December 31,	% of Total Book
	2009	Capitalization	2008 (a)	Capitalization
Total debt, net of cash (b)	$11,988	49%	$11,426	40%
Chesapeake Stockholders' equity	11,444	47%	17,017	60%
Noncontrolling interest	897	4%	—	—
Total	$24,329	100%	$28,443	100%

(a)	Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.
(b)	Includes $1.936 billion of borrowings under the company’s $3.5 billion revolving bank credit facility, the company’s $250 million midstream revolving bank credit facility and the company’s $500 million midstream joint venture revolving bank credit facility.  At December 31, 2009, the company had $2.273 billion of additional borrowing capacity under these three revolving bank credit facilities.

CHESAPEAKE ENERGY CORPORATION

SUPPLEMENTAL DATA – NATURAL GAS AND OIL SALES AND INTEREST EXPENSE

 (unaudited)

	THREE MONTHS ENDED						TWELVE MONTHS ENDED
	DECEMBER 31,							DECEMBER 31,
		2009			2008			2009			2008
Natural Gas and Oil Sales ($ in millions):
Natural gas sales	$	816		$	957			$	2,635		$	6,003
Natural gas derivatives – realized gains (losses)		542			441				2,313			267
Natural gas derivatives – unrealized gains (losses)		(94	)		195				(492	)		521
Total Natural Gas Sales		1,264			1,593				4,456			6,791
Oil sales		194			151				656			1,066
Oil derivatives – realized gains (losses)		2			5				33			(275	)
Oil derivatives – unrealized gains (losses)		(92	)		522				(96	)		276
Total Oil Sales		104			678				593			1,067
Total Natural Gas and Oil Sales	$	1,368		$	2,271			$	5,049		$	7,858
Average Sales Price – excluding gains (losses) on derivatives:
Natural gas ($ per mcf)	$	3.63		$	4.88			$	3.16		$	7.74
Oil ($ per bbl)	$	70.92		$	53.19			$	55.60		$	95.04
Natural gas equivalent ($ per mcfe)	$	4.19		$	5.20			$	3.63		$	8.39
Average Sales Price – excluding unrealized gains (losses)  on derivatives:
Natural gas ($ per mcf)	$	6.05		$	7.13			$	5.93		$	8.09
Oil ($ per bbl)	$	71.61		$	54.80			$	58.38		$	70.48
Natural gas equivalent ($ per mcfe)	$	6.45		$	7.29			$	6.22		$	8.38
Interest Expense (Income) ($ in millions):(a)
Interest	$	50		$	(3	)		$	227		$	192
Derivatives – realized (gains) losses		(4	)		(7	)			(23	)		(6	)
Derivatives – unrealized (gains) losses		16			94				(91	)		85
Total Interest Expense	$	62		$	84			$	113		$	271

(a) Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED CASH FLOW DATA

($ in millions)

(unaudited)

THREE MONTHS ENDED:	December 31,			December 31,
	2009			2008 (a)
Beginning cash	$	520		$	1,964
Cash provided by operating activities	$	1,226		$	971
Cash (used in) provided by investing activities:
Exploration and development of natural gas and oil properties	$	(776	)	$	(1,483	)
Acquisitions of natural gas and oil companies, proved and unproved properties and leasehold, net of cash acquired		(927	)		(902	)
Proceeds from divestitures of proved and unproved properties, leasehold and VPPs		197			1,794
Additions to other property and equipment		(321	)		(1,104	)
Proceeds from sales of drilling rigs and compressors		—			18
Other		19			(6	)
Total cash used in investing activities	$	(1,808	)	$	(1,683	)
Cash provided by financing activities	$	369		$	497
Ending cash	$	307		$	1,749

TWELVE MONTHS ENDED:	December 31,			December 31,
	2009			2008 (a)
Beginning cash	$	1,749		$	1
Cash provided by operating activities	$	4,356		$	5,357
Cash (used in) provided by investing activities:
Exploration and development of natural gas and oil properties	$	(3,543	)	$	(6,104	)
Acquisitions of natural gas and oil companies, proved and unproved properties and leasehold, net of cash acquired		(2,298	)		(8,593	)
Proceeds from divestitures of proved and unproved properties, leasehold and VPPs		1,926			7,670
Additions to other property and equipment		(1,683	)		(3,073	)
Proceeds from sales of drilling rigs and compressors		68			178
Other		68			(43	)
Total cash used in investing activities	$	(5,462	)	$	(9,965	)
Cash (used in) provided by financing activities	$	(336	)	$	6,356
Ending cash	$	307		$	1,749

(a) Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)

THREE MONTHS ENDED:	December 31,			September 30,			December 31,
	2009			2009			2008 (a)
CASH PROVIDED BY OPERATING ACTIVITIES	$	1,226		$	1,132		$	971
Changes in assets and liabilities		(14	)		(16	)		83
OPERATING CASH FLOW (b)	$	1,212		$	1,116		$	1,054

THREE MONTHS ENDED:	December 31,			September 30,		December 31,
	2009			2009		2008 (a)
NET INCOME (LOSS)	$	(499	)	$	192	$	(995	)
Income tax expense (benefit)		(299	)		115		(615	)
Interest expense		62			43		84
Depreciation and amortization of other assets		67			62		50
Natural gas and oil depreciation, depletion and amortization		335			295		452
EBITDA (c)	$	(334	)	$	707	$	(1,024	)

THREE MONTHS ENDED:	December 31,			September 30,			December 31,
	2009			2009			2008 (a)
CASH PROVIDED BY OPERATING ACTIVITIES	$	1,226		$	1,132		$	971
Changes in assets and liabilities		(14	)		(16	)		83
Interest expense		62			43			84
Unrealized gains (losses) on natural gas and oil derivatives		(186	)		(285	)		717
Impairment of natural gas and oil properties and other assets		(1,408	)		(86	)		(2,830	)
Loss on sale of other property and equipment		—			(38	)		—
Impairment of investments		—			—			(180	)
Other non-cash items		(14	)		(43	)		131
EBITDA (c)	$	(334	)	$	707		$	(1,024	)

(a)	Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.
(b)	Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities.  Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP).  Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt.  This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry.  Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity.
(c)	Ebitda represents net income (loss) before income tax expense, interest expense and depreciation, depletion and amortization expense.  Ebitda is presented as a supplemental financial measurement in the evaluation of our business.  We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements.  This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies.  Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements and our senior note indentures.  Ebitda is not a measure of financial performance under GAAP.  Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)

TWELVE MONTHS ENDED:	December 31,			December 31,
	2009			2008 (a)
CASH PROVIDED BY OPERATING ACTIVITIES	$	4,356		$	5,357
Changes in assets and liabilities		(23	)		(58	)
OPERATING CASH FLOW (b)	$	4,333		$	5,299

TWELVE MONTHS ENDED:	December 31,			December 31,
	2009			2008 (a)
NET INCOME (LOSS)	$	(5,805	)	$	604
Income tax expense (benefit)		(3,483	)		387
Interest expense		113			271
Depreciation and amortization of other assets		244			174
Natural gas and oil depreciation, depletion and amortization		1,371			1,970
EBITDA (c)	$	(7,560	)	$	3,406

TWELVE MONTHS ENDED:	December 31,			December 31,
	2009			2008 (a)
CASH PROVIDED BY OPERATING ACTIVITIES	$	4,356		$	5,357
Changes in assets and liabilities		(23	)		(58	)
Interest expense		113			271
Unrealized gains (losses) on natural gas and oil derivatives		(588	)		797
Impairment of natural gas and oil properties and other assets		(11,130	)		(2,830	)
Loss on sale of other property and equipment		(38	)		—
Impairment of investments		(162	)		(180	)
Restructuring costs		(12	)		—
Other non-cash items		(76	)		49
EBITDA (c)	$	(7,560	)	$	3,406

(a)	Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.
(b)	Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities.  Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP).  Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt.  This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry.  Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity.
(c)	Ebitda represents net income (loss) before income tax expense, interest expense and depreciation, depletion and amortization expense.  Ebitda is presented as a supplemental financial measurement in the evaluation of our business.  We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements.  This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies.  Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements and our senior note indentures.  Ebitda is not a measure of financial performance under GAAP.  Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED EBITDA

($ in millions)

(unaudited)

	December 31,			September 30,		December 31,
THREE MONTHS ENDED:	2009			2009		2008 (a)
EBITDA	$	(334	)	$	707	$	(1,024	)
Adjustments, before tax:
(Income) attributable to noncontrolling interest		(25	)		—		—
Unrealized (gains) losses on natural gas and oil derivatives		186			285		(717	)
Loss (gain) on exchanges of Chesapeake debt		21			17		(27	)
Impairment of natural gas and oil properties and other assets		1,408			86		2,830
Loss on sale of other property and equipment		—			38		—
Impairment of investments		—			—		180
Adjusted ebitda (b)	$	1,256		$	1,133	$	1,242

	December 31,			December 31,
TWELVE  MONTHS ENDED:	2009			2008 (a)
EBITDA	$	(7,560	)	$	3,406
Adjustments, before tax:
(Income) attributable to noncontrolling interest		(25	)		—
Unrealized (gains) losses on natural gas and oil derivatives		588			(797	)
Loss on exchanges of Chesapeake debt		40			4
Impairment of natural gas and oil properties and other assets		11,130			2,830
Loss on sale of other property and equipment		38			—
Impairment of investments		162			180
Restructuring costs		34			—
Consent fees on senior notes		—			10
Adjusted ebitda (b)	$	4,407		$	5,633

(a)	Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.
(b)	Adjusted ebitda excludes certain items that management believes affect the comparability of operating results.  The company discloses these non-GAAP financial measures as a useful adjunct to ebitda because:
	i.	Management uses adjusted ebitda to evaluate the company’s operational trends and performance relative to other natural gas and oil producing companies.
	ii.	Adjusted ebitda is more comparable to estimates provided by securities analysts.
	iii.	Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated.  Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS

($ in millions, except per-share data)

(unaudited)

	December 31,			September 30,		December 31,
THREE MONTHS ENDED:	2009			2009		2008 (a)
Net income (loss) available to Chesapeake common shareholders	$	(530	)		186	$	(1,001	)
Adjustments:
Unrealized (gains) losses on derivatives, net of tax		126			166		(380	)
Impairment of natural gas and oil properties and other assets, net of tax		880			54		1,726
Loss on sale of other property and equipment, net of tax		—			24		—
Impairment of investments, net of tax		—			—		110
Loss (gain) on exchanges of Chesapeake debt, net of tax		14			10		(17	)
Adjusted net income available to Chesapeake common shareholders (b)		490			440		438
Preferred stock dividends		6			6		6
Total adjusted net income	$	496		$	446	$	444
Weighted average fully diluted shares outstanding (c)		644			637		590
Adjusted earnings per share assuming dilution(b)	$	0.77		$	0.70	$	0.75

(a)	Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.
(b)	Adjusted net income available to common shareholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results.  The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because:
	i.	Management uses adjusted net income available to common shareholders to evaluate the company’s operational trends and performance relative to other natural gas and oil producing companies.
	ii.	Adjusted net income available to common shareholders is more comparable to earnings estimates provided by securities analysts.
	iii.	Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated.  Accordingly, any guidance provided by the company generally excludes information regarding these types of items.
(c)	Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS

($ in millions, except per-share data)

(unaudited)

	December 31,			December 31,
TWELVE MONTHS ENDED:	2009			2008 (a)
Net income (loss) available to Chesapeake common shareholders	$	(5,853	)	$	504
Adjustments:
Unrealized (gains) losses on derivatives, net of tax		311			(434	)
Impairment of natural gas and oil properties and other assets, net of tax		6,955			1,726
Loss on sale of other property and equipment, net of tax		24			—
Impairment of investments, net of tax		102			110
Restructuring costs, net of tax		21			—
Loss on exchanges of Chesapeake debt, net of tax		25			2
Consent fees on senior notes, net of tax		—			6
Loss on conversions or exchanges of preferred stock		—			67
Adjusted net income available to Chesapeake common shareholders (b)		1,585			1,981
Preferred stock dividends		23			33
Interest on contingent convertible notes, net of tax		—			12
Total adjusted net income	$	1,608		$	2,026
Weighted average fully diluted shares outstanding (c)		631			562
Adjusted earnings per share assuming dilution(b)	$	2.55		$	3.60

(a)	Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.
(b)	Adjusted net income available to common shareholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results.  The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because:
	i.	Management uses adjusted net income available to common shareholders to evaluate the company’s operational trends and performance relative to other natural gas and oil producing companies.
	ii.	Adjusted net income available to common shareholders is more comparable to earnings estimates provided by securities analysts.
	iii.	Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated.  Accordingly, any guidance provided by the company generally excludes information regarding these types of items.
(c)	Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

SCHEDULE “A”

CHESAPEAKE’S OUTLOOK AS OF FEBRUARY 17, 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 February 17, 2010, we are using the following key assumptions in our projections for 2010 and 2011.

The primary changes from our January 4, 2010 Outlook are in italicized bold and are explained as follows:

1)   Our production guidance has been increased;

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

3)   Certain cost assumptions have been updated;

4)   Our rate of DD&A for natural gas and oil has been reduced to reflect our 2009 year-end impairment charge; and

5)   Our cash flow projections have been updated, including increased drilling capital expenditures to reflect additional drilling on oil and natural gas liquids rich plays and anticipated cost inflation, partially offset by improved drilling efficiencies.

	Year Ending 12/31/2010	Year Ending 12/31/2011
Estimated Production:
Natural gas – bcf	882 – 902	1,025 – 1,045
Oil – mbbls	15,500	17,500
Natural gas equivalent – bcfe	975 – 995	1,130 – 1,150
Daily natural gas equivalent midpoint – mmcfe	2,700	3,125
Year-over-year estimated production increase	8 – 10%	15 – 17%
Year-over-year estimated production increase excluding divestitures and curtailments	15 – 17%	16 – 18%
NYMEX Price(a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$6.26	$7.50
Oil - $/bbl	$79.87	$80.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$1.24	$0.25
Oil - $/bbl	$4.25	$5.78
Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	15 – 25%	15 – 25%
Oil - $/bbl	10 – 15%	10 – 15%
Operating Costs per Mcfe of Projected Production:
Production expense	$0.85 – 0.95	$0.85 – 0.95
Production taxes (~ 5% of O&G revenues)	$0.25 – 0.30	$0.30 – 0.35
General and administrative(b)	$0.30 – 0.35	$0.30 – 0.35
Stock-based compensation (non-cash)	$0.09 – 0.11	$0.09 – 0.11
DD&A of natural gas and oil assets	$1.35 – 1.55	$1.35 – 1.55
Depreciation of other assets	$0.20 – 0.25	$0.20 – 0.25
Interest expense(c)	$0.30 – 0.35	$0.30 – 0.35
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)	38.5%	38.5%
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(d)(e)		$4,900 – 5,000	$5,300 – 6,000
Net leasehold and producing property transactions		$1,300 – 1,700	$1,000 – 1,300
Drilling capital expenditures		($4,100 – 4,400)	($4,300 – 4,600)
Dividends, capitalized interest, cash income taxes, etc.		($350 – 400)	($500 – 600)
Other		($500 – 600)	($250 – 300)
Projected Net Cash Change		$1,250 – 1,300	$1,250 – 1,800
(a)	NYMEX natural gas prices have been updated for actual contract prices through February 2010 and NYMEX oil prices have been updated for actual contract prices through January 2010.
(b)	Excludes expenses associated with noncash stock compensation.
(c)	Does not include gains or losses on interest rate derivatives.
(d)	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.
(e)	Assumes NYMEX prices of $6.50 to $7.50 per mcf and $80.00 per bbl in 2010 and $7.00 to $8.00 per mcf and $80.00 per bbl in 2011.

At December 31, 2009, the company had approximately $2.6 billion of cash and cash equivalents and additional borrowing capacity under its three revolving bank credit facilities.

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.  In accordance with generally accepted accounting principles, 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.  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	110	$7.53			$35.9
Q2 2010	123	$7.43			$37.9
Q3 2010	118	$7.60			$65.7
Q4 2010	119	$7.75			$65.2
Total 2010(a)	470	$7.58	892	53%	$204.7	$0.23
Total 2011(a)	72	$8.71	1,035	7%	$62.7	$0.06

(a) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure at prices ranging from $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	2,250	$89.62	—	—	$(4.0)	—
Q2 2010	2,275	$89.62	—	—	$(4.0)	—
Q3 2010	2,300	$89.62	—	—	$(4.2)	—
Q4 2010	2,300	$89.62	—	—	$(4.2)	—
Total 2010(a)	9,125	$89.62	15,500	59%	$(16.4)	$(1.06)
Total 2011(a)	3,285	$96.09	17,500	19%	$32.8	$1.88

(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 1 mmbbls of oil production in 2010 at a weighted average price of $101.25 per bbl for a weighted average discount of $1.93 per bbl and 5 mmbls of oil production in 2011 at a weighted average price of $101.54 per bbl for a weighted average premium of $3.29 per bbl.

SCHEDULE “B”

CHESAPEAKE’S OUTLOOK AS OF JANUARY 4, 2010

(PROVIDED FOR REFERENCE ONLY)

NOW SUPERSEDED BY OUTLOOK AS OF FEBRUARY 17, 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
(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.

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.

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.