chk11032010

Exhibit 99.1

News Release

FOR IMMEDIATE RELEASE
NOVEMBER 3, 2010

CHESAPEAKE ENERGY CORPORATION REPORTS FINANCIAL AND OPERATIONAL

RESULTS FOR THE 2010 THIRD QUARTER

Company Reports 2010 Third Quarter Net Income to Common Stockholders of

$515 Million, or $0.75 per Fully Diluted Common Share, on Revenue of $2.6 Billion;

Company Reports Adjusted Net Income Available to Common Stockholders of

$478 Million, or $0.70 per Fully Diluted Common Share, Adjusted Ebitda

of $1.3 Billion and Operating Cash Flow of $1.1 Billion

Company Reports 2010 Third Quarter Production of 3.043 Bcfe per Day, an Increase of 23%

over 2009 Third Quarter Production and 9% over 2010 Second Quarter Production;

2010 Third Quarter Liquids Production Increases 50% Year-over-Year to 10%

of Total Production and 17% of Realized Natural Gas and Oil Revenue

Company Expects Production Growth of Approximately 13% in 2010, 18% in 2011

and 18% in 2012, Including Liquids Production Growth of Approximately 60%

in 2010, 80% in 2011 and 60% in 2012

Proved Reserves Reach 16.2 Tcfe; Company Adds Proved Reserves of 4.0 Tcfe

through the Drillbit for the First Three Quarters of 2010 at a Drilling

and Completion Cost of $0.97 per Mcfe

OKLAHOMA CITY, OKLAHOMA, NOVEMBER 3, 2010 – Chesapeake Energy Corporation (NYSE:CHK) today announced financial and operational results for the 2010 third quarter. For the 2010 third quarter, Chesapeake reported net income to common stockholders of $515 million ($0.75 per fully diluted common share), operating cash flow of $1.068 billion (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $1.344 billion (defined as net income before income taxes, interest expense, and depreciation, depletion and amortization) on revenue of $2.581 billion and production of 280 billion cubic feet of natural gas equivalent (bcfe).

The company’s 2010 third quarter results 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 2010 third quarter, Chesapeake reported adjusted net income to common stockholders of $478 million ($0.70 per fully diluted common share) and adjusted ebitda of $1.282 billion. The excluded items and their effects on 2010 third quarter reported results are detailed as follows:

INVESTOR CONTACTS:		MEDIA CONTACTS:	CHESAPEAKE ENERGY CORPORATION
Jeffrey L. Mobley, CFA	John J. Kilgallon	Jim Gipson	6100 North Western Avenue
(405) 767-4763	(405) 935-4441	(405) 935-1310	P.O. Box 18496
jeff.mobley@chk.com	john.kilgallon@chk.com	jim.gipson@chk.com	Oklahoma City, OK 73154

·	a non-cash after-tax gain of $74 million associated with certain equity investments where the investee sold additional equity to third parties at a price in excess of the company’s basis;

·	an after-tax loss of $36 million related to the redemption of certain of the company's senior notes;

·	a non-cash unrealized after-tax mark-to-market gain of $31 million resulting from the company’s natural gas, oil and interest rate hedging programs;

·	an after-tax charge of $23 million related to the impairment or loss on sale of certain of the company's fixed assets; and

·	an after-tax impairment charge of $9 million related to certain equity investments.

The various items described above do not materially affect the calculation of operating cash flow. A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 16 – 20 of this release.

Key Operational and Financial Statistics Summarized

The table below summarizes Chesapeake’s key results during the 2010 third quarter and compares them to results during the 2010 second quarter and the 2009 third quarter.

		Three Months Ended
		9/30/10	6/30/10	9/30/09
Average daily production (in mmcfe) (a)		3,043	2,789	2,483
Natural gas as % of total production		90	90	92
Natural gas production (in bcf)		252.8	227.2	210.3
Average realized natural gas price ($/mcf) (b)		5.20	5.66	6.04
Oil and NGL production (in mbbls)		4,533	4,429	3,027
Average realized oil and NGL price ($/bbl) (b)		59.81	61.43	66.42
Natural gas equivalent production (in bcfe)		280.0	253.8	228.5
Natural gas equivalent realized price ($/mcfe) (b)		5.67	6.14	6.44
Marketing, gathering and compression net margin($/mcfe)		.12	.12	.13
Service operations income ($/mcfe)		.03	.02	.00
Production expenses ($/mcfe)		(.83)	(.84)	(.96)
Production taxes ($/mcfe)		(.12)	(.15)	(.11)
General and administrative costs ($/mcfe) (c)		(.37)	(.34)	(.32)
Stock-based compensation ($/mcfe)		(.07)	(.08)	(.09)
DD&A of natural gas and oil properties ($/mcfe)		(1.35)	(1.34)	(1.29)
D&A of other assets ($/mcfe)		(.20)	(.21)	(.27)
Interest expense ($/mcfe) (b)		(.00)	(.13)	(.28)
Operating cash flow ($ in millions) (d)		1,068	1,127	1,116
Operating cash flow ($/mcfe)		3.82	4.44	4.89
Adjusted ebitda ($ in millions) (e)		1,282	1,256	1,133
Adjusted ebitda ($/mcfe)		4.58	4.95	4.96
Net income to common stockholders ($ in millions)		515	235	186
Earnings per share – assuming dilution ($)		.75	.37	.30
Adjusted net income to common stockholders ($ in millions) (f)		478	491	440
Adjusted earnings per share – assuming dilution ($)		.70	.75	.70

(a)	2010 production reflects the sale of a 25% joint venture interest in the company’s Barnett Shale assets on January 25, 2010 and various other asset sales, including VPP 6 and VPP 7 completed in the first half of 2010. VPP 8 was completed on September 30, 2010.
(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 non-cash 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 18
(f)	Defined as net income (loss) available to common stockholders, as adjusted to remove the effects of certain items detailed on page 19

2010 Third Quarter Average Daily Production of 3.043 Bcfe per Day Increases 23% over 2009

Third Quarter Production and 9% over 2010 Second Quarter Production; 2010 Third Quarter

Liquids Production Increases 50% Year-over-Year to 10% of Total Production

Chesapeake’s daily production for the 2010 third quarter averaged 3.043 bcfe, an increase of 560 million cubic feet of natural gas equivalent (mmcfe), or 23%, over the 2.483 bcfe produced per day in the 2009 third quarter and an increase of 254 mmcfe, or 9%, above the 2.789 bcfe produced per day in the 2010 second quarter.

Chesapeake’s average daily production of 3.043 bcfe for the 2010 third quarter consisted of 2.748 billion cubic feet of natural gas (bcf) and 49,272 barrels of oil and natural gas liquids (NGLs) (bbls). The company’s 2010 third quarter production of 280.0 bcfe was comprised of 252.8 bcf (90% on a natural gas equivalent basis) and 4.5 million barrels of oil and NGLs (mmbbls) (10% on a natural gas equivalent basis). The company’s year-over-year growth rate of natural gas production was 20% and its year-over-year growth rate of oil and NGL (liquids) production was 50%. The company’s percentage of revenue from liquids in the 2010 third quarter was 17% of realized natural gas and oil revenue compared to 14% in the 2009 third quarter.

2010 Third Quarter Average Realized Prices Benefit from Realized

Hedging Gains of $512 Million, or $1.83 per Mcfe

Average prices realized during the 2010 third quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.20 per thousand cubic feet (mcf) and $59.81 per bbl, for a realized natural gas equivalent price of $5.67 per thousand cubic feet of natural gas equivalent (mcfe). Realized gains from natural gas and oil hedging activities during the 2010 third quarter generated a $1.92 gain per mcf and a $5.56 gain per bbl, for 2010 third quarter realized hedging gains of $512 million, or $1.83 per mcfe.

By comparison, average prices realized during the 2009 third quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $6.04 per mcf and $66.42 per bbl, for a realized natural gas equivalent price of $6.44 per mcfe. Realized gains from natural gas and oil hedging activities during the 2009 third quarter generated a $3.20 gain per mcf and a $3.95 gain per bbl, for 2009 third quarter realized hedging gains of $687 million, or $3.00 per mcfe.

The company’s natural gas and oil realized net hedging gains for the first nine months of 2010 were $1.5 billion and since January 1, 2001 have been $5.9 billion.

Company Provides 2010-12 Production Outlook and Details Updated Hedging Positions

Chesapeake is projecting full-year production growth of approximately 13% in 2010, 18% in 2011 and 18% in 2012, including production growth from liquids of approximately 60% in 2010, 80% in 2011 and 60% in 2012. Of Chesapeake’s projected production growth rates in 2010, 2011 and 2012, approximately 35%, 50% and 55%, respectively, of the growth is projected to come from increased liquids production.

The following table summarizes Chesapeake’s 2010 fourth quarter, 2011 and 2012 open hedge positions through swaps as of November 3, 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 November 3, 2010

	Natural Gas			Oil
Year	% Hedged		$ NYMEX	% Hedged		$ NYMEX
4Q 2010	53	%	7.66	28	%	89.94
2011	60	%	6.44	3	%	104.75
2012	2	%	6.50	1	%	109.50

The company’s updated forecasts and hedging positions for the 2010 fourth quarter, 2011 and 2012 are attached to this release in an Outlook dated November 3, 2010, labeled as Schedule “A,” which begins on page 21. This Outlook has been changed from the Outlook dated October 12, 2010, attached as Schedule “B,” which begins on page 25, to reflect various updated information.

Chesapeake’s Proved Natural Gas and Oil Reserves Increase by 2.0 Tcfe, or 14%,

in the First Three Quarters of 2010 to 16.2 Tcfe; Company Adds Proved Reserves

of 4.0 Tcfe through the Drillbit for the First Three Quarters of 2010

at a Drilling and Completion Cost of $0.97 per Mcfe

During the first three quarters of 2010, Chesapeake continued the industry’s most active drilling program, drilling 1,041 gross operated wells (676 net wells with an average working interest of 65%) and participating in another 911 gross wells operated by other companies (118 net wells with an average working interest of 13%). The company’s drilling success rate was 99% for company-operated wells and 98% for non-operated wells. During the first three quarters of 2010, Chesapeake’s drilling and completion costs include the benefit of approximately $745 million of drilling and completion carries from its joint venture partners.

The following table compares Chesapeake’s September 30, 2010 proved reserves, the increase over its year-end 2009 proved reserves, reserve replacement ratio, estimated future net cash flows from proved reserves (discounted at an annual rate of 10% before income taxes (PV-10)), and proved developed percentage based on the trailing 12-month average price required under SEC rules and the 10-year average NYMEX strip prices at September 30, 2010.

Pricing Method	Natural Gas Price ($/mcf)	Oil Price ($/bbl)	Proved Reserves (tcfe)(a)	Proved Reserves Growth (tcfe)(b)	Proved Reserves Growth %(b)	Reserve Replacement Ratio	PV-10 (billions)	Proved Developed Percentage
Trailing 12-month average (SEC)(c)	$4.41	$77.33	16.2	2.0	13.8%	357%	$15.1	54%
9/30/10 10-year average NYMEX strip(d)	$5.42	$89.60	16.7	1.2	7.5%	252%	$22.5	54%

(a)	After sales of proved reserves of approximately 1.5 tcfe during the first three quarters of 2010.

(b)

Compares proved reserve growth for the first three quarters of 2010 under comparable pricing methods. At year-end 2009, Chesapeake’s proved reserves were 14.3 tcfe using trailing 12-month average prices, which are required by SEC reporting rules, and 15.5 tcfe using the 10-year average NYMEX strip prices at December 31, 2009.

(c)

Reserve volumes estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of September 2010 of $4.41 per mcf of natural gas and $77.33 per bbl of oil, before field differential adjustments. This pricing yields estimated "proved reserves" for SEC reporting purposes. Natural gas and oil volumes estimated under any alternative pricing scenario reflect the sensitivity of proved reserves to a different pricing assumption.

(d)

Futures prices represent an unbiased consensus estimate by market participants about the likely prices to be received for future production. Management believes that 10-year average NYMEX strip prices provide a better indicator of the likely economic producibility of the company’s proved reserves than the historical 12-month average price.

The following table summarizes Chesapeake’s development costs for the first three quarters of 2010 using the two pricing methods described above.

Development Cost Category	Trailing 12-Month Average (SEC) Pricing ($/mcfe)	9/30/10 10-year Average NYMEX Strip Pricing ($/mcfe)
Drilling and completion costs (1)	$0.97	$1.05
Drilling, completion and net acquisition costs of proved properties (1)	$0.46	$0.54

(1)	Includes performance-related revisions and drilling and completion carries and excludes price-related revisions

A complete reconciliation of proved reserves and reserve replacement ratios based on these two alternative pricing methods, along with total costs, is presented on pages 12 and 13 of this release.

In addition to the PV-10 value of its proved reserves, the company also has substantial value in its undeveloped leasehold, particularly in the Haynesville, Marcellus, Barnett and Fayetteville unconventional natural gas shale plays and the company’s unconventional liquids-rich plays, particularly in the Granite Wash, Tonkawa, Cleveland and Mississippian plays of the Anadarko Basin; the Avalon, Bone Spring and Wolfcamp plays of the Permian Basin; the Eagle Ford Shale in South Texas; and the Niobrara Shale in the Powder River and DJ Basins.

Additionally, the net book value of the company’s other assets (including gathering systems, compressors, land and buildings, investments and other non-current assets) was $6.2 billion as of September 30, 2010 compared to $6.7 billion as of December 31, 2009. The decline in other assets is primarily due to the deconsolidation of the company’s midstream joint venture reflecting the implementation of new accounting guidance for certain investments.

Chesapeake’s Leasehold and 3-D Seismic Inventories Total 13.8 Million Net Acres and 27.4

Million Acres; Risked Unproved Resources in the Company’s Inventory Total 102 Tcfe

Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (13.8 million net acres) and 3-D seismic (27.4 million acres) in the U.S. and the largest inventory of U.S. natural gas shale play leasehold (2.8 million net acres) and now owns the largest inventory of leasehold in two of the Top 3 new unconventional liquids-rich plays – the Eagle Ford Shale and the Niobrara Shale.

On its total leasehold inventory, Chesapeake has identified an estimated 16.7 trillion cubic feet of natural gas equivalent (tcfe) of proved reserves (using volume estimates based on the 10-year average NYMEX strip prices at September 30, 2010), 102 tcfe of risked unproved resources and 259 tcfe of unrisked unproved resources. The company is currently using 140 operated drilling rigs to further develop its inventory of approximately 40,000 net drillsites. Of Chesapeake’s 140 operated rigs, 95 are drilling wells primarily focused on unconventional natural gas plays (including 48 operated rigs utilizing drilling carries) and 45 are drilling wells primarily focused on liquids-rich plays. In addition, 133 of the company’s 140 operated rigs are drilling horizontal wells.

In recognition of the value gap between oil and natural gas prices, during the past two years, Chesapeake has directed a significant portion of its technological and leasehold acquisition expertise to identify, secure and commercialize new unconventional liquids-rich plays. To date, Chesapeake has built leasehold positions and established production in multiple liquids-rich plays on approximately 3.1 million net leasehold acres with 4.3 billion barrels of oil equivalent (bboe) (25.9 tcfe) of risked unproved resources and 13.7 bboe (82.4 tcfe) of unrisked unproved resources. As a result of its success to date, Chesapeake expects to increase its oil and natural gas liquids production through its drilling activities to more than 150,000 bbls per day, or 20%-25% of total production, by year-end 2012 and to more than 2 50,000 bbls per day, or 25%-30% of total production, through organic growth by year-end 2015.

The following table summarizes Chesapeake’s ownership and activity in its unconventional natural gas shale plays, its unconventional liquids-rich plays and its other conventional and unconventional plays. Chesapeake uses a probability-weighted statistical approach to estimate the potential number of drillsites and unproved resources associated with such drillsites.


		Est.		Risked	Total	Risked	Unrisked	Oct-10	Oct-10
	CHK	Drilling		Net	Proved	Unproved	Unproved	Daily Net	Operated
	Net	Density	Risk	Undrilled	Reserves	Resources	Resources	Production	Rig
Play Type/Area	Acreage(1)	(Acres)	Factor	Wells	(bcfe)(1)(2)	(bcfe)(1)	(bcfe)(1)	(mmcfe)	Count
Unconventional Natural Gas Plays:
Marcellus	1,620,000	80	60%	8,070	596	35,700	89,700	185	27
Haynesville	525,000	80	30%	4,400	3,119	19,100	28,300	785	34
Bossier(3)	200,000	80	60%	990	4	4,100	10,200	ND	1
Fayetteville	440,000	80	20%	3,950	2,462	7,100	9,300	410	8
Barnett	215,000	60	20%	1,760	2,912	3,100	4,000	240	21
Subtotal	2,800,000			19,170	9,093	69,100	141,500	1,620	91

Unconventional Liquids Plays:
Anadarko Basin(4)	1,015,000	140	60%	2,775	1,968	10,200	23,100	400	23
Eagle Ford	625,000	80	ND	ND	98	ND	20,800	ND	10
Permian Basin(5)	680,000	90	ND	ND	191	ND	11,300	ND	7
Powder River and DJ Basin(6)	800,000	90	ND	ND	28	ND	27,200	ND	4
Subtotal	3,120,000			9,550	2,285	25,900	82,400	470	44

Other Conventional and
Unconventional Plays:	7,880,000	Various	Various	11,680	5,323	7,100	35,100	735	5
Total	13,800,000			40,400	16,701	102,100	259,000	2,825	140

Note: ND denotes “not disclosed”

(1) As of September 30, 2010

(2) Based on 10-year average NYMEX strip prices at September 30, 2010

(3) Bossier Shale acreage overlaps with Haynesville Shale acreage and is excluded from the shale play sub-total to avoid double counting of acreage

(4) Includes Colony, Texas Panhandle and other Granite Washes, Cleveland, Tonkawa and Mississippian plays

(5) Includes only Delaware and Midland Basin plays

(6) Includes Niobrara, Frontier and Codell plays

Company Provides Update on Recently Completed and Pending Asset Sales

At the end of the 2010 third quarter, Chesapeake sold certain of its producing assets in the Barnett Shale in its eighth volumetric production payment (VPP) transaction for proceeds of $1.15 billion. The transaction included approximately 390 bcf of proved reserves and approximately 280 mmcf per day of average net production in 2011. Since December 2007, in a program designed to advance the present value of some of its producing natural gas and oil assets on a tax-advantaged basis, Chesapeake has completed eight VPP transactions and sold approximately 1.0 tcfe of proved reserves for combined proceeds of approximately $4.7 billion, or approximately $4.70 per mcfe.

In October, Chesapeake entered into an industry cooperation agreement whereby CNOOC International Limited, a wholly owned subsidiary of CNOOC Limited (CNOOC), agreed to purchase a 33.3% undivided interest in Chesapeake’s 600,000 net natural gas and oil leasehold acres in the Eagle Ford Shale project in South Texas. The consideration for the sale will be approximately $1.08 billion in cash at closing. In addition, CNOOC has agreed to fund 75% of Chesapeake’s share of drilling and completion costs until an additional $1.08 billion has been paid, which Chesapeake expects to occur by year-end 2012. Closing of the transaction is anticipated later this month.

Chesapeake has commenced an initiative to create its sixth industry cooperation agreement to develop its liquids-rich plays in the Powder River and DJ Basins, where the company owns a combined approximate 800,000 net acres of leasehold. The company anticipates completing a transaction in the 2011 first quarter.

Additionally, Chesapeake continues to build its industry-leading unconventional liquids portfolio through its new play identification systems and subsequent leasing programs. Recently, the company had the opportunity to acquire a significant additional position in the Appalachian Basin from privately-held Anschutz Corporation. In this transaction, which is scheduled to close later this month, the company has agreed to acquire approximately 500,000 net acres of Appalachian Basin leasehold and option rights for approximately $850 million. Approximately 25% of these assets will be immediately marketed for resale after closing while the remainder of the assets will be combined with Chesapeake leasehold in a play in which the company expects to execute a new industry joint venture in the first half of 2011.& #160; As with all of Chesapeake’s leasehold acquisitions in new plays, the company’s goal remains the same: acquire an industry-leading leasehold position in a new play and then bring in a minority industry partner to help de-risk the play and to provide reimbursement of all or most of Chesapeake’s leasehold costs in the new play.

Company Syndicating New Senior Secured Revolving Bank Credit Facility

In anticipation of the maturity of its existing credit facility in November 2012, Chesapeake is in the process of syndicating a new $4.0 billion senior secured revolving bank credit facility. The new facility will replace the company’s existing $3.5 billion facility in its entirety and have a term of five years. The syndication of the new facility is anticipated to be completed later this month.

Conference Call Information

A conference call to discuss this release has been scheduled for Thursday, November 4, 2010, at 9:00 a.m. EDT. The telephone number to access the conference call is 913-981-5510 or toll-free 888-215-7015. The passcode for the call is 5815149. We encourage those who would like to participate in the call to dial the access number between 8:50 and 9:00 a.m. EDT. For those unable to participate in the conference call, a replay will be available for audio playback from 1:00 p.m. EDT on November 4, 2010 through midnight EST on Thursday, November 18, 2010. The num ber to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 5815149. The conference call will also be webcast live on Chesapeake’s website at www.chk.com in the “Events” subsection of the “Investors” section of the website. The webcast of the conference call will be available on Chesapeake’s website for one year.

This news 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 drilling activity, drilling and completion costs and anticipated asset 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 news 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 “Risks Related to our Business” in our Prospectus Supplement filed with the U.S. Securities and Exchange Commission on August 10, 2010. These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; 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 producti on and the amount and timing of development expenditures; inability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas and oil sales, the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their obligations; a reduced ability to borrow or raise additional capital as a result of lower natural gas and oil prices; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business; general economic conditions negatively impacting us and our business counterparties; transportation capacity constraints and interruptions that could adversely affect our cash flow; 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.

The SEC requires natural gas and oil companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of natural gas and oil that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. In this news release, we use the terms "risked and unrisked unproved resources" to describe Chesapeake’s internal estimates of volumes of natural gas and oil that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques. These are broader descriptions of potentially recoverable volumes than probable and possible reserves, as defined by SEC regulations. Estimates of unproved resources 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. We believe our estimates of unproved resources are reasonable, but such estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.

The company calculates the standardized measure of future net cash flows of proved reserves only at year end because applicable income tax information on properties, including recently acquired natural gas and oil interests, is not readily available at other times during the year. As a result, the company is not able to reconcile interim period-end PV-10 values to the standardized measure at such dates. The only difference between the two measures is that PV-10 is calculated before considering the impact of future income tax expenses, while the standardized measure includes such effects. Year-end standardized measure calculations are provided in the financial statement notes in our annual reports on Form 10-K.

Chesapeake Energy Corporation is the second-largest producer of natural gas and the most active driller of new wells in the U.S. Headquartered in Oklahoma City, the company's operations are focused on discovering and developing unconventional natural gas and oil fields onshore in the U.S. Chesapeake owns leading positions in the Barnett, Fayetteville, Haynesville, Marcellus and Bossier natural gas shale plays and in the Granite Wash, Eagle Ford, Niobrara and various other unconventional liquids plays. The company has also vertically integrated its operations and owns substantial midstream, compression, drilling and oilfield service assets. 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:	September 30,			September 30,
THREE MONTHS ENDED:	2010			2009
	$		$/mcfe	$		$/mcfe
REVENUES:
Natural gas and oil sales		1,639	5.86		1,187	5.20
Marketing, gathering and compression sales		883	3.15		575	2.52
Service operations revenue		59	0.21		49	0.21
Total Revenues		2,581	9.22		1,811	7.93

OPERATING COSTS:
Production expenses		231	0.83		218	0.96
Production taxes		34	0.12		25	0.11
General and administrative expenses		125	0.45		95	0.42
Marketing, gathering and compression expenses		851	3.04		546	2.39
Service operations expense		52	0.18		49	0.21
Natural gas and oil depreciation, depletion and amortization		378	1.35		295	1.29
Depreciation and amortization of other assets		56	0.20		62	0.27
Impairment or loss on sale of other property and equipment		37	0.13		124	0.54
Total Operating Costs		1,764	6.30		1,414	6.19

INCOME FROM OPERATIONS		817	2.92		397	1.74

OTHER INCOME (EXPENSE):
Interest expense		(3)	(0.01)		(43)	(0.19)
Loss on redemptions or exchanges of Chesapeake debt		(59)	(0.21)		(17)	(0.07)
Impairment of investments		(16)	(0.06)		—	—
Other income (expense)		168	0.60		(30)	(0.14)
Total Other Income (Expense)		90	0.32		(90)	(0.40)

INCOME BEFORE INCOME TAXES		907	3.24		307	1.34

Income Tax Expense:
Current income taxes		(1)	—		—	—
Deferred income taxes		350	1.25		115	0.50
Total Income Tax Expense		349	1.25		115	0.50

NET INCOME		558	1.99		192	0.84

Preferred stock dividends		(43)	(0.15)		(6)	(0.03)

NET INCOME AVAILABLE TO CHESAPEAKE COMMON STOCKHOLDERS		515	1.84		186	0.81

EARNINGS PER COMMON SHARE:
Basic	$	0.81		$	0.30
Diluted	$	0.75		$	0.30

WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions)
Basic		632			619
Diluted		744			626

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)

NINE MONTHS ENDED:	September 30,				September 30,
NINE MONTHS ENDED:	2010				2009
	$		$/mcfe		$		$/mcfe
REVENUES:
Natural gas and oil sales		4,698		6.13		3,681		5.54
Marketing, gathering and compression sales		2,520		3.29		1,660		2.50
Service operations revenue		173		0.22		139		0.20
Total Revenues		7,391		9.64		5,480		8.24

OPERATING COSTS:
Production expenses		652		0.85		670		1.01
Production taxes		119		0.16		71		0.11
General and administrative expenses		340		0.44		259		0.39
Marketing, gathering and compression expenses		2,429		3.17		1,569		2.36
Service operations expense		154		0.19		136		0.20
Natural gas and oil depreciation, depletion and amortization		1,025		1.34		1,037		1.56
Depreciation and amortization of other assets		159		0.21		177		0.27
Impairment of natural gas and oil properties		—		—		9,600		14.44
Impairment or loss on sale of other property and equipment		37		0.05		159		0.23
Restructuring costs		—		—		34		0.05
Total Operating Costs		4,915		6.41		13,712		20.62

INCOME (LOSS) FROM OPERATIONS		2,476		3.23		(8,232)		(12.38)

OTHER INCOME (EXPENSE):
Interest expense		(12)		(0.01)		(52)		(0.08)
Loss on redemptions or exchanges of Chesapeake debt		(130)		(0.17)		(19)		(0.03)
Impairment of investments		(16)		(0.02)		(162)		(0.24)
Other income (expense)		202		0.26		(25)		(0.04)
Total Other Income (Expense)		44		0.06		(258)		(0.39)

INCOME (LOSS) BEFORE INCOME TAXES		2,520		3.29		(8,490)		(12.77)

Income Tax Expense (Benefit):
Current income taxes		4		0.01		1		—
Deferred income taxes		966		1.26		(3,185)		(4.79)
Total Income Tax Expense (Benefit)		970		1.27		(3,184)		(4.79)

NET INCOME (LOSS)		1,550		2.02		(5,306)		(7.98)

Preferred stock dividends		(68)		(0.09)		(18)		(0.03)

NET INCOME (LOSS) AVAILABLE TO CHESAPEAKE COMMON STOCKHOLDERS		1,482		1.93		(5,324)		(8.01)

EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	2.35			$	(8.78)
Diluted	$	2.24			$	(8.78)

WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions)
Basic		631				606
Diluted		692				606

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

($ in millions)

(unaudited)

	September 30,		December 31,
	2010		2009

Cash and cash equivalents	$	609	$	307
Other current assets		2,664		2,139
Total Current Assets		3,273		2,446

Property and equipment (net)		29,480		26,710
Other assets		1,580		758
Total Assets	$	34,333	$	29,914

Current liabilities	$	4,123	$	2,688
Long-term debt, net (a)		11,445		12,295
Asset retirement obligations		291		282
Other long-term liabilities		1,362		1,249
Deferred tax liability		1,839		1,059
Total Liabilities		19,060		17,573

Chesapeake stockholders’ equity		15,273		11,444
Noncontrolling interest(b)		—		897
Total Equity		15,273		12,341

Total Liabilities & Equity	$	34,333	$	29,914

Common Shares Outstanding (in millions)		654		648

CHESAPEAKE ENERGY CORPORATION

CAPITALIZATION

($ in millions)

(unaudited)

	September 30, 2010	% of Total Book Capitalization	December 31, 2009	% of Total Book Capitalization

Total debt, net of cash(a)	$10,836	42%	$11,988	49%
Chesapeake stockholders' equity	15,273	58%	11,444	47%
Noncontrolling interest(b)	—	—	897	4%
Total	$26,109	100%	$24,329	100%

(a)	At September 30, 2010, includes $2.487 billion of combined borrowings under the company’s $3.5 billion revolving bank credit facility and the company’s $300 million midstream revolving bank credit facility. At September 30, 2010, the company had $1.3 billion of additional borrowing capacity under these two revolving bank credit facilities.
(b)	Effective January 1, 2010, we no longer consolidate the company’s midstream joint venture and consequently no longer report a noncontrolling interest related to this investment.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF 2010 ADDITIONS TO NATURAL GAS AND OIL PROPERTIES

BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES

($ in millions, except per-unit data)

(unaudited)

	Proved Reserves
	Cost		Bcfe(a)		$/Mcfe

Drilling and completion costs(b)	$	3,853	3,966	(c)	0.97
Acquisition of proved properties		139	50		2.78
Sale of proved properties		(2,825)	(1,499)		1.88
Drilling, completion and net acquisition costs of proved properties		1,167	2,517		0.46

Revisions – price		—	219		—

Acquisition of unproved properties and leasehold		3,511	—		—
Sale of unproved properties and leasehold		(237)	—		—
Net unproved properties and leasehold acquisition		3,274	—		—

Capitalized interest on leasehold and unproved property		522	—		—
Geological and geophysical costs		124	—		—
Capitalized interest and geological and geophysical costs		646	—		—

Subtotal		5,087	2,736		1.86

Asset retirement obligation and other		(2)	—		—
Total costs	$	5,085	2,736		1.86

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

NINE MONTHS ENDED SEPTEMBER 30, 2010

BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES

(unaudited)

	Bcfe(a)

Beginning balance, 01/01/10	14,254
Production	(767)
Acquisitions	50
Divestitures	(1,499)
Revisions – changes to previous estimates	611
Revisions – price	219
Extensions and discoveries	3,355
Ending balance, 09/30/10	16,223

Proved reserves growth rate	13.8	%

Proved developed reserves	8,756
Proved developed reserves percentage	54	%

Reserve replacement	2,736
Reserve replacement ratio (d)	357	%

(a)	Reserve volumes estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of September 2010 of $4.41 per mcf of natural gas and $77.33 per bbl of oil, before field differential adjustments.
(b)	Includes drilling and completion carries associated with the Statoil and Total joint ventures.
(c)	Includes 611 bcfe of positive revisions resulting from changes to previous estimates and excludes positive revisions of 219 bcfe resulting from higher natural gas and oil prices using the average first-day-of-the-month price for the twelve months ended September 2010 compared to the twelve months ended December 2009.
(d)	The company uses the reserve replacement ratio as an indicator of the company’s ability to replenish annual production volumes and grow its reserves. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF 2010 ADDITIONS TO NATURAL GAS AND OIL PROPERTIES

BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT SEPTEMBER 30, 2010

($ in millions, except per-unit data)

(unaudited)

	Proved Reserves
	Cost		Bcfe(a)		$/Mcfe

Drilling and completion costs(b)	$	3,853	3,672	(c)	1.05
Acquisition of proved properties		139	51		2.71
Sale of proved properties		(2,825)	(1,550)		1.82
Drilling, completion and net acquisition costs of proved properties		1,167	2,173		0.54

Revisions – price		—	(244)		—

Acquisition of unproved properties and leasehold		3,511	—		—
Sale of unproved properties and leasehold		(237)	—		—
Net unproved properties and leasehold acquisition		3,274	—		—

Capitalized interest on leasehold and unproved property		522	—		—
Geological and geophysical costs		124	—		—
Capitalized interest and geological and geophysical costs		646	—		—

Subtotal		5,087	1,929		2.64

Asset retirement obligation and other		(2)	—		—
Total costs	$	5,085	1,929		2.64

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

NINE MONTHS ENDED SEPTEMBER 30, 2010

BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT SEPTEMBER 30, 2010

(unaudited)

	Bcfe(a)

Beginning balance, 01/01/10	15,540
Production	(767)
Acquisitions	51
Divestitures	(1,550)
Revisions – changes to previous estimates	296
Revisions – price	(244)
Extensions and discoveries	3,376
Ending balance, 09/30/10	16,702

Proved reserves growth rate	7.5	%

Proved developed reserves	9,042
Proved developed reserves percentage	54	%

Reserve replacement	1,929
Reserve replacement ratio (d)	252	%

(a)	Reserve volumes estimated using SEC reserve recognition standards and 10-year average NYMEX strip prices as of September 30, 2010 of $5.42 per mcf of natural gas and $89.60 per bbl of oil, before field differential adjustments. Futures prices, such as the 10-year average NYMEX strip prices, represent an unbiased consensus estimate by market participants about the likely prices to be received for our future production. Chesapeake uses such forward-looking market-based data in developing its drilling plans, assessing its capital expenditure needs and projecting future cash flows. Chesapeake believes these prices are better indicators of the likely economic producibility of proved reserves than the trailing 12-month average price required by the SEC's reporting rule.
(b)	Includes drilling and completion carries associated with the Statoil and Total joint ventures.
(c)	Includes 296 bcfe of positive revisions resulting from changes to previous estimates and excludes downward revisions of 244 bcfe resulting from lower natural gas and oil prices using 10-year average NYMEX strip prices as of September 30, 2010 compared to NYMEX strip prices as of December 31, 2009.
(d)	The company uses the reserve replacement ratio as an indicator of the company’s ability to replenish annual production volumes and grow its reserves. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

CHESAPEAKE ENERGY CORPORATION

SUPPLEMENTAL DATA – NATURAL GAS AND OIL SALES AND INTEREST EXPENSE

(unaudited)

	THREE MONTHS ENDED				NINE MONTHS ENDED
	SEPTEMBER 30,				SEPTEMBER 30,
	2010			2009	2010		2009

Natural Gas and Oil Sales ($ in millions):
Natural gas sales	$	828	$	596	$	2,504	$	1,819
Natural gas derivatives – realized gains (losses)		487		675		1,418		1,771
Natural gas derivatives – unrealized gains (losses)		315		(275)		534		(398)

Total Natural Gas Sales		1,630		996		4,456		3,192

Oil sales		246		189		739		461
Oil derivatives – realized gains (losses)		25		12		66		31
Oil derivatives – unrealized gains (losses)		(262)		(10)		(563)		(30)

Total Oil Sales		9		191		242		489

Total Natural Gas and Oil Sales	$	1,639	$	1,187	$	4,698	$	3,681

Average Sales Price – excluding gains (losses) on derivatives:
Natural gas ($ per mcf)	$	3.28	$	2.84	$	3.63	$	2.98
Oil ($ per bbl)	$	54.25	$	62.47	$	57.57	$	50.97
Natural gas equivalent ($ per mcfe)	$	3.84	$	3.44	$	4.23	$	3.43

Average Sales Price – excluding unrealized gains (losses) on derivatives:
Natural gas ($ per mcf)	$	5.20	$	6.04	$	5.69	$	5.88
Oil ($ per bbl)	$	59.81	$	66.42	$	62.75	$	54.37
Natural gas equivalent ($ per mcfe)	$	5.67	$	6.44	$	6.17	$	6.14

Interest Expense ($ in millions):
Interest	$	3	$	70	$	93	$	177
Derivatives – realized (gains) losses		(2)		(70		(6)		(19)
Derivatives – unrealized (gains) losses		2		(20)		(75)		(106)
Total Interest Expense (Income)	$	3	$	43	$	12	$	52

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED CASH FLOW DATA

($ in millions)

(unaudited)

THREE MONTHS ENDED:	September 30,		September 30,
THREE MONTHS ENDED:	2010		2009

Beginning cash	$	601	$	554
Cash provided by operating activities	$	993	$	1,132
Cash (used in) provided by investing activities:
Exploration and development of natural gas and oil properties	$	(1,387)	$	(682)
Acquisitions of natural gas and oil proved and unproved properties		(1,362)		(639)
Divestitures of proved and unproved properties and VPPs		1,174		1,501
Investments, net		(4)		(42)
Other property and equipment, net		(267)		(329)
Other		(87)		2
Total cash (used in) investing activities	$	(1,933)	$	(189)
Cash provided by financing activities	$	948	$	(977)
Ending cash	$	609	$	520

NINE MONTHS ENDED:	September 30,		September 30,
NINE MONTHS ENDED:	2010		2009

Beginning cash	$	307	$	1,749
Cash provided by operating activities	$	3,971	$	3,131
Cash (used in) provided by investing activities:
Exploration and development of natural gas and oil properties	$	(3,718)	$	(2,790)
Acquisitions of natural gas and oil proved and unproved properties		(4,217)		(1,348)
Divestitures of proved and unproved properties and VPPs		3,107		1,729
Investments, net		(113)		(40)
Other property and equipment, net		(640)		(1,205)
Other		(84)		—
Total cash (used in) investing activities	$	(5,665)	$	(3,654)
Cash provided by financing activities	$	1,996	$	(706)
Ending cash	$	609	$	520

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)

THREE MONTHS ENDED:	September 30,		June 30,		September 30,
THREE MONTHS ENDED:	2010		2010		2009

CASH PROVIDED BY OPERATING ACTIVITIES	$	993	$	1,795	$	1,132

Changes in assets and liabilities		75		(668)		(16)

OPERATING CASH FLOW(a)	$	1,068	$	1,127	$	1,116

THREE MONTHS ENDED:	September 30,		June 30,		September 30,
THREE MONTHS ENDED:	2010		2010		2009

NET INCOME (LOSS)	$	558	$	255	$	192

Income tax expense (benefit)		349		159		115
Interest expense		3		(16)		43
Depreciation and amortization of other assets		56		53		62
Natural gas and oil depreciation, depletion andamortization		378		340		295

EBITDA (b)	$	1,344	$	791	$	707

THREE MONTHS ENDED:	September 30,		June 30,		September 30,
THREE MONTHS ENDED:	2010		2010		2009

CASH PROVIDED BY OPERATING ACTIVITIES	$	993	$	1,795	$	1,132

Changes in assets and liabilities		75		(668)		(16)
Interest expense (income)		3		(16)		43
Unrealized gains (losses) on natural gas and oil derivatives		53		(396)		(285)
Realized gains on financing derivatives		165		177		18
Impairment or loss on sale of other property and equipment		(37)		—		(124)
Gains (losses) on equity investments		155		(48)		(24)
Impairment of investments		(16)		—		—
Other items		(47)		(53)		(37)

EBITDA(b)	$	1,344	$	791	$	707

(a)

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 per formance 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.

(b)

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)

NINE MONTHS ENDED:	September 30,		September 30,
NINE MONTHS ENDED:	2010		2009

CASH PROVIDED BY OPERATING ACTIVITIES	$	3,971	$	3,131

Changes in assets and liabilities		(609)		(10)

OPERATING CASH FLOW(a)	$	3,362	$	3,121

NINE MONTHS ENDED:	September 30,		September 30,
NINE MONTHS ENDED:	2010		2009

NET INCOME (LOSS)	$	1,550	$	(5,306)

Income tax expense (benefit)		970		(3,184)
Interest expense (income)		12		52
Depreciation and amortization of other assets		159		177
Natural gas and oil depreciation, depletion and amortization		1,025		1,037

EBITDA(b)	$	3,716	$	(7,224)

NINE MONTHS ENDED:	September 30,		September 30,
NINE MONTHS ENDED:	2010		2009

CASH PROVIDED BY OPERATING ACTIVITIES	$	3,971	$	3,131

Changes in assets and liabilities		(609)		(10)
Interest expense (income)		12		52
Unrealized gains (losses) on natural gas and oil derivatives		(29)		(401)
Realized gains on financing derivatives		436		53
Impairment of natural gas and oil properties		—		(9,600)
Impairment or loss on sale of other property and equipment		(37)		(159)
Gains (losses) on equity investments		120		(32)
Impairment of investments		(16)		(162)
Other items		(132)		(96)

EBITDA(b)	$	3,716	$	(7,224)

(a)

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 perfor mance 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.

(b)

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED EBITDA

($ in millions)

(unaudited)

	September 30,		June 30,		September 30,
THREE MONTHS ENDED:	2010		2010		2009

EBITDA	$	1,344	$	791	$	707

Adjustments:
Unrealized (gains) losses on natural gas and oil derivatives		(53)		396		285
(Gains) losses on investments		(121)		—		—
Impairment of investments		16		—		—
Loss on redemptions or exchanges of Chesapeake debt		59		69		17
Impairment or loss on sale of other property and equipment		37		—		124

Adjusted EBITDA(a)	$	1,282	$	1,256	$	1,133

(a)	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.

	September 30,		September 30,
NINE MONTHS ENDED:	2010		2009

EBITDA	$	3,716	$	(7,224)

Adjustments:
Unrealized (gains) losses on natural gas and oil derivatives		29		401
Loss on redemptions or exchanges of Chesapeake debt		130		19
Impairment of natural gas and oil properties		—		9,600
(Gains) losses on investments		(121)		—
Impairment of investments		16		162
Impairment or loss on sale of other property and equipment		37		159
Restructuring costs		—		34

Adjusted EBITDA(a)	$	3,807	$	3,151

(a)	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 STOCKHOLDERS

($ in millions, except per-share data)

(unaudited)

	September 30,		June 30,		September 30,
THREE MONTHS ENDED:	2010		2010		2009

Net income available to Chesapeake common stockholders	$	515		235	$	186

Adjustments:
(Gains) losses on investment activity, net of tax		(74)		—		—
Unrealized (gains) losses on derivatives, net of tax		(31)		214		166
Loss on redemptions or exchanges of Chesapeake debt, net of tax		36		42		10
Impairment of investments, net of tax		9		—		—
Impairment or loss on sale of other property and equipment, net of tax		23		—		78

Adjusted net income available to Chesapeake common stockholders (a)		478		491		440
Preferred stock dividends		43		20		6
Total adjusted net income	$	521	$	511	$	446

Weighted average fully diluted shares outstanding(b)		744		682		637

Adjusted earnings per share assuming dilution(a)	$	0.70	$	0.75	$	0.70

(a)	Adjusted net income available to common stockholders 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 stockholders 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 stockholders 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.
(b)	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 STOCKHOLDERS

($ in millions, except per-share data)

(unaudited)

	September 30,		September 30,
NINE MONTHS ENDED:	2010		2009

Net income (loss) available to Chesapeake common stockholders	$	1,482	$	(5,324)

Adjustments:
Unrealized (gains) losses on derivatives, net of tax		(28)		184
Loss on redemptions or exchanges of Chesapeake debt, net of tax		80		11
(Gains) losses on investment activity, net of tax		(74)		—
Impairment of natural gas and oil properties, net of tax		—		6,000
Impairment of investments, net of tax		9		102
Impairment or loss on sale of other property and equipment, net of tax		23		100
Restructuring costs, net of tax		—		21

Adjusted net income available to Chesapeake common stockholders (a)		1,492		1,094
Preferred stock dividends		68		18
Total adjusted net income	$	1,560	$	1,112

Weighted average fully diluted shares outstanding(b)		692		625

Adjusted earnings per share assuming dilution(a)	$	2.26	$	1.78

(a)	Adjusted net income available to common stockholders 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 stockholders 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 stockholders 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.
(b)	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 NOVEMBER 3, 2010

Years Ending December 31, 2010, 2011 and 2012

Our policy is to periodically provide guidance on certain factors that affect our future financial performance. As of November 3, 2010, we are using the following key assumptions in our projections for 2010, 2011 and 2012.

The primary changes from our October 12, 2010 Outlook are in italicized bold and are explained as follows:

1)	Our production guidance has been updated;

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

3)	Our NYMEX natural gas and oil price assumptions for realized hedging effects have been updated;

4)	Certain cost assumptions have been updated; and

5)	Our cash flow projections have been updated, including increased drilling and completion costs to reflect additional drilling on liquids-rich plays.

	Year Ending 12/31/2010	Year Ending 12/31/2011	Year Ending 12/31/2012
Estimated Production:
Natural gas – bcf	898 – 918	990 – 1,010	1,086 – 1,130
Oil – mbbls	18,000 – 19,000	32,000 – 36,000	51,000 – 57,000
Natural gas equivalent – bcfe	1,006 – 1,032	1,182 – 1,226	1,392 – 1,472

Daily natural gas equivalent midpoint – mmcfe	2,800	3,300	3,900

Year-over-year (YOY) estimated production increase	11 – 14%	16 – 20%	15 - 22%
YOY estimated production increase excluding asset sales	19 – 22%	19 – 23%	16 - 23%

NYMEX Price(a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$4.37	$4.50	$5.50
Oil - $/bbl	$76.99	$85.00	$85.00

Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$2.16	$1.35	$0.00
Oil - $/bbl	$4.56	$1.00	$0.52

Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices:
Natural gas	19 – 23%	20 – 25%	20 – 25%
Oil	23 – 27%	25 – 30%	25 – 30%

Operating Costs per Mcfe of Projected Production:
Production expense	$0.85 – 0.95	$0.85 – 0.95	$0.85 – 0.95
Production taxes (~ 5% of O&G revenues)	$0.25 – 0.30	$0.25 – 0.30	$0.25 – 0.30
General and administrative(b)	$0.30 – 0.35	$0.33 – 0.38	$0.33 – 0.38
Stock-based compensation (non-cash)	$0.09 – 0.11	$0.09 – 0.11	$0.09 – 0.11
DD&A of natural gas and oil assets	$1.35 – 1.55	$1.35 – 1.55	$1.35 – 1.55
Depreciation of other assets	$0.20 – 0.25	$0.20 – 0.25	$0.20 – 0.25
Interest expense(c)	$0.15 – 0.20	$0.20 – 0.25	$0.20 – 0.25

Other Income per Mcfe:
Marketing, gathering and compression net margin	$0.09 – 0.11	$0.09 – 0.11	$0.09 – 0.11
Service operations net margin	$0.02 – 0.04	$0.02 – 0.04	$0.02 – 0.04
Other income (including equity investments)	$0.06 – 0.08	$0.06 – 0.08	$0.06 – 0.08

Book Tax Rate (all deferred)	38.5%	38.5%	38.5%

Equivalent Shares Outstanding (in millions):
Basic	630 – 635	640 – 645	647 – 652
Diluted	705 – 710	750 – 755	757 – 762

Operating cash flow before changes in assets and liabilities(d)(e)	$4,700 – 4,800	$4,800 – 5,000	$5,200 – 6,000
Drilling and completion costs, net of joint venture carries	($4,800 – 5,000)	($4,800 – 5,000)	($4,800 – 5,000)

Note: refer to footnotes on following page

(a)	NYMEX natural gas prices have been updated for actual contract prices through November 2010 and NYMEX oil prices have been updated for actual contract prices through September 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 $4.00 to $5.00 per mcf and $75.00 per bbl in 2010, $4.00 to $5.00 per mcf and $85.00 per bbl in 2011 and $5.00 to $6.00 per mcf and $85.00 per bbl in 2012.

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.
3)	Call options: Chesapeake sells call options in exchange for a premium from the counterparty. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess and if the market price settles below the fixed price of the call option, no payment is due from either party.
4)	Put options: Chesapeake sells put options in exchange for a premium from the counterparty. At the time of settlement, if the market prices falls below the fixed price of the put option, Chesapeake pays the counterparty such shortfall, and if the market price settles above the fixed price of the put option, no payment is due from either party.
5)	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.
6)	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 i s 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. In the latter half of 2009 and in 2010, the company took advantage of attractive strip prices in 2012 through 2016 and sold natural gas and oil call options to its counterparties in exchange for 2010 and 2011 natural gas swaps with strike prices above the then current market price. This effectively allowed the company to sell out-year volatility through call options at terms acceptable to Chesapeake in exchange for straight natural gas swaps with strike prices well in excess of the then current market price for natural gas.

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., 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 for 2010, 2011 and 2012 and also has the following gains (losses) 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 (Losses) from Lifted Trades ($ millions)			Total Lifted Gains (Losses) per Mcf of Estimated Total Natural Gas Production
Q4 2010	117	$	7.66	220	53%		$	60.2		$	0.27

Q1 2011	192	$	6.41				$	30.0
Q2 2011	186	$	6.28				$	46.9
Q3 2011	113	$	6.60				$	40.7
Q4 2011	113	$	6.62				$	28.0
Total 2011	604	$	6.44	1,000	60%		$	145.6		$	0.15

Total 2012	18	$	6.50	1,108	2%		$	(35.0)		$	(0.03)

The company currently has the following natural gas written call options in place for 2010, 2011 and 2012:

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)

	CHESAPEAKE ENERGY CORPORATION

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

Exhibit No.		Document Description

99.1		Chesapeake Energy Corporation press release dated November 3, 2010 - Third quarter financial and operational results and updated outlook

	Call Options (mbbls)	Avg. NYMEX Strike Price		Avg. Premium per bbl			Assuming Oil Production (mbbls)	Call Options as a % of Estimated Total Oil Production
Q4 2010	368	$	101.25	$	(1.93	)	5,700	6%

Q1 2011	1,980	$	84.44	$	1.97
Q2 2011	2,002	$	84.44	$	1.95
Q3 2011	2,024	$	84.44	$	1.93
Q4 2011	2,024	$	84.44	$	1.93
Total 2011	8,030	$	84.44	$	1.94		34,000	24%

Total 2012	9,150	$	87.00	$	1.70		54,000	17%

	(405) 848-8000
	(Registrant’s telephone number, including area code)

	Call Options (Bcf)	Avg. NYMEX Strike Price		Avg. Premium per mcf		Assuming Natural Gas Production (Bcf)	Call Options as a % of Estimated Total Natural Gas Production
Q4 2010	34	$	10.08	$	1.25	220	15%

Q1 2011	22	$	8.57	$	0.46
Q2 2011	22	$	8.57	$	0.46
Q3 2011	23	$	8.57	$	0.46
Q4 2011	23	$	8.57	$	0.46
Total 2011	90	$	8.57	$	0.46	1,000	9%

Total 2012	161	$	6.54	$	0.11	1,108	15%

	Non-Appalachia			Appalachia
	Volume (Bcf)	Avg. NYMEX less		Volume (Bcf)	Avg. NYMEX plus
Q4 2010	—	$	—	3	$	0.26
2011	45	$	0.82	49	$	0.14
2012	51	$	0.78	—	$	—
Totals	96	$	0.80	52	$	0.15

	Open Swaps (mbbls)	Avg. NYMEX Strike Price		Assuming Oil Production (mbbls)	Open Swap Positions as a % of Estimated Total Oil Production	Total Gains from Lifted Trades ($ millions)		Total Lifted Gains per bbl of Estimated Total Oil Production
Q4 2010(a)	1,568	$	89.94	5,700	28%	$	0.0	$	0.0

Q1 2011	270	$	104.75	—	—	$	7.3		—
Q2 2011	273	$	104.75	—	—	$	7.3		—
Q3 2011	276	$	104.75	—	—	$	7.4		—
Q4 2011	276	$	104.75	—	—	$	7.4		—
Total 2011(a)	1,095	$	104.75	34,000	3%	$	29.4	$	0.86

Total 2012(a)	732	$	109.50	54,000	1%	$	29.3	$	0.54

	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
Q3 2010	4	$	7.60	$	11.75
Q4 2010	4	$	7.60	$	11.75
Q3-Q4 2010	8	$	7.60	$	11.75	472	2%

Q1 2011	2	$	7.70	$	11.50
Q2 2011	2	$	7.70	$	11.50
Q3 2011	2	$	7.70	$	11.50
Q4 2011	2	$	7.70	$	11.50
Total 2011	8	$	7.70	$	11.50	1,000	1%

	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
Q3 2010	2,300	$	89.62	—	—	$	(4.1	)		—
Q4 2010	2,300	$	89.62	—	—	$	(4.1	)		—
Q3-Q4 2010(a)	4,600	$	89.62	10,700	43%	$	(8.2	)	$	(0.76)

Q1 2011	810	$	96.09	—	—	$	7.3			—
Q2 2011	819	$	96.09	—	—	$	7.3			—
Q3 2011	828	$	96.09	—	—	$	7.4			—
Q4 2011	828	$	96.09	—	—	$	7.4			—
Total 2011(a)	3,285	$	96.09	34,000	10%	$	29.4		$	0.86

Total 2012(a)	732	$	109.50	41,000	2%	$	29.3		$	0.72