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

Chesapeake Energy Corporation

6100 North Western Avenue

Oklahoma City, Oklahoma 73118

October 11, 2011

Division of Corporation Finance

Securities and Exchange Commission

100 F Street, NE

Washington, DC 20549-7010

Attention: Mr. H. Roger Schwall, Assistant Director

Re: Chesapeake Energy Corporation

Form 10-K for Fiscal Year Ended December 31, 2010

Filed March 1, 2011

File No. 1-13726

Ladies and Gentlemen:

This letter sets forth the responses of Chesapeake Energy Corporation to the comments of the staff (the “Staff”) of the Division of Corporation Finance of the Securities and Exchange Commission received by letter dated October 5, 2011. We have repeated below the Staff’s comments and followed each comment with the company’s response.

Form 10-K for Fiscal Year Ended December 31, 2010

Business, page 1

Natural Gas and Reserves, page 10

1. Your August 22, 2011 response to our prior comment seven presents 7 normalized producing rate vs. time field plots in support of a five percent terminal production decline rate. Per our October 4, 2011 teleconference, please:

• Tell us the field names and locations;

• Tell us the criteria for the wells you included and the portion of total available wells included in the plots. Address the reasons that you have not included nonproducing field wells with productive lives over 10 years;

• Explain the remedies you have employed in horizontal wells to address liquid loading and fracture healing; and

• Tell us the extent of your refracturing treatments, if any.

Securities and Exchange Commission

October 11, 2011

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Response: The table below addresses the nature of the seven normalized type curves previously submitted as part of our response. Please note that no wells were eliminated or ignored in this evaluation based on their current production status. Our efforts focused on finding the oldest well sets available and achieving statistically meaningful well counts.

Plot Title	Fields	Location	Criteria(1)	% Wells(2)
Barnett Vertical	Newark East	TX Counties: Wise, Denton	Barnett shale reservoir Vertical wells First production from January 1996 to December 2000	100% (3)
Appalachian Huron	15 fields(4)	KY Counties: Floyd, Martin, Pike VA County: Buchanan WV Counties: Lincoln, Logan, Mingo, Wayne	Chesapeake propriety data base - working interest wells Lower Huron formation only First production prior to 1981 and rate/time data available	100%
Wamsutter	Wamsutter	WY County: Sweetwater	First production prior to September 1999	100%
Sahara	62 fields(5)	OK Counties: Alfalfa, Beaver, Blain, Garfield, Harper, Lincoln, Major, Noble, Oklahoma KS Counties: Finney, Haskell, Kearny, Kingman, Kiowa, Ness, Stanton TX County: Ochiltree	Chesapeake proprietary data base - working interest wells First production prior to September 1999	100%

Securities and Exchange Commission

October 11, 2011

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Giddings	Giddings	TX Counties: Brazos, Burleson, Fayette, Grimes, Lee, Washington	Horizontal gas wells First production prior to September 1994	100%
Jonah	Jonah	WY County: Sublette	First production prior to September 1999	100%
Texas Panhandle	Lipscomb, Pan Petro	TX County: Ochiltree	First production prior to September 1999	100%

⁽¹⁾  Unless otherwise noted, all production data was obtained from publicly available sources.

⁽²⁾  Percentage of wells within the specified criteria used to create the normalized type curve.

⁽³⁾  Originally submitted plot title was in error. The submitted plot indicated a well count of 371 wells. The actual well count used was 474.

⁽⁴⁾  Fields are Boone Block, Chapmanville, Dingess Rum, Harts Creek Center, Harts Creek North, Harts Creek South, Inez, Miller Creek, Pawpaw North, Pike County, Prestonsburg, Rubin, Spartan, Tug River and Warfield.

⁽⁵⁾  Fields are 25-DLB, Antelope Northwest, Arnold, Ashley Southeast, Avard Northwest, Avard NW, Beaver Northeast, Billings, Billings East, Campbell, Cedardale NE, Cedardale Northeast, Ceres Northeast, Cherokee West, Cheyenne Valley, Echo East, Edith North, Edith NW, Edith South, Elmwood South, Enid Northeast, Eubank, Eubank East, Fair Valley East, Farnsworth-Conner (Kansas City), Fort Supply NE (Btrg-Oswg), Fort Supply Northeast, Fort Supply Northeast, (Chester), Fort Supply,NE, Happy Star North, Happy Star Northeast, Kansas Hugoton, Lambert Southeast, Lovedale, Lovedale Northwest, Lovedale NW, Lovedale NW (Manning), Lovedale SE, Lovedale, NW, Lucien, Mocane-Laverne, Mule Creek Northeast, Oakdale, Okeene Northwest, Oklahoma City, Orion Northeast, Panoma, Perry, Polo, Ringwood, Sahara, Sahara Field, Sooner Trend, Spicer, Spivey-Grabs, Tonkawa, Tonkawa South, Watonga-Chickasha Trend, Waynoka NE, Waynoka Northeast, Waynoka South and Wellston.

Chesapeake is currently applying several conventional technology remedies to liquid loading in horizontal wells with consistent success. As of October 6, 2011, Chesapeake operates 3,811 producing horizontal wells. Of these, 1,890 wells, or 49.6%, are “free flowing,” with nearly all of them having tubing installed. The remaining 50.4% of our operated producing horizontal wells are on artificial lift consisting of gas lift (993 wells), plunger lift (595 wells), rod pump (117 wells), electric submersible pumps (24 wells) and progressive cavity pumps (2 wells). Our analysis of these various lifting techniques indicates the ability to achieve reservoir abandonment pressures aligned with our reserve estimates.

Chesapeake has not observed any evidence of loss of fracture conductivity associated with the healing of hydraulic fractures in horizontal well bores. We do not believe this to be an issue and have not had to re-stimulate any horizontal wells due to the loss of hydraulic fracture conductivity. We engineer our completions with the proper proppant strength and volume to eliminate or minimize the unproved hypothesis that fractures heal over time.

Securities and Exchange Commission

October 11, 2011

Page 4 of 8

To date, Chesapeake has re-fracture stimulated 14 wells in its three largest fields at year-end 2010 (2 Fayetteville, 12 Barnett and no Haynesville wells). In each case, the re-stimulation was designed to contact new reserves associated with a horizontal well having been initially under-stimulated. None of these re-fracs was associated with any perceived or measured healing of the original fractures. These 14 re-fraced wells represent 0.4% of the horizontal wells Chesapeake operated in these fields at year-end 2010.

2. Your response to our prior comment seven also presents your projected time from first production to terminal production decline rate for the Barnett, Fayetteville and Haynesville shales. Please tell us the “b-factors” you used in determining these projected times and confirm, if true, that you used these decline parameter values in the estimation of your disclosed proved reserves in these respective shale reservoirs.

Response: The time estimates to terminal decline for each field provided in our August 22, 2011 response were based on normalized production versus time for the earliest well sets in each field. We based our well selection on first production dates obtained from public records.

For the Barnett, we used the first 500 horizontal producing wells, resulting in a b-factor fit of 1.6. The wells are located in Cooke, Denton, Erath, Johnson, Parker, Tarrant and Wise Counties, Texas and have first production dates ranging from March 1992 to August 2004.

For the Fayetteville, we used the first 100 horizontal producing wells, and this resulted in a b-factor fit of 1.5. The wells are located in Conway, Van Buren, Faulkner and White Counties, Arkansas and range in start dates from March 2005 to January 2007.

For the Haynesville, we used the first 100 horizontal producing wells. The resulting fit for the Haynesville was a b-factor of 1.0. The wells are located in Bossier, Red River, Sabine, Caddo, Bienville and De Soto Parishes of Louisiana. Their start dates cover the time span October 2007 to July 2009.

The b-factor used in our type curves for proved reserve estimations at year-end 2010, as disclosed in our 2010 Form 10-K, was 1.6 for the Barnett, 1.5 for the Fayetteville and 1.0 for the Haynesville.

Risk Factors, page 23

3. We note your response to our prior comment two, as well as your risk factor discussion at page 27 under “Natural gas and oil drilling and producing operations…” and under “Potential legislative and regulatory actions could increase our costs…” Specifically, we note that your risk factors do not disclose any specific risks associated with hydraulic fracturing, such as the underground migration and the surface spillage or mishandling of fracturing fluids, including chemical additives. In light of the information you have provided in response to our prior comment two regarding your procedures and historical experience with your

Securities and Exchange Commission

October 11, 2011

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hydraulic fracturing operations, please advise whether you believe your current risk factor disclosure addresses all your material risks or whether there are additional material operational and financial risks stemming from your operations that require disclosure in your Risk Factors section.

Response: We acknowledge the Staff’s comment and note that when preparing our annual and quarterly reports on Forms 10-K and 10-Q and when we offer securities, we review our risk factor disclosures to assess whether they address all our material risks, whether from operations or otherwise. We have reviewed the referenced risk factor disclosures and believe they do address our material risks.

With respect to risks associated with surface spillage or mishandling of fracturing fluids, including chemical additives, we believe our risk factor disclosure on page 27 (see “Natural gas and oil and gas drilling and producing operations can be hazardous and may expose us to liabilities, including environmental liabilities.”) adequately addresses these risks, as follows:

• the first sentence of paragraph one of the referenced risk factor refers to the risks of “well blowouts . . . pipe failures . . . uncontrollable flows of natural gas, oil, brine or well fluids and other environmental hazards and risks”;

• paragraph one also refers to the losses that could occur as a result of these risks, including injury or the loss of life; severe damage to or destruction of property, natural resources or equipment; pollution or other environmental damage; clean-up responsibilities; investigations and administrative, civil and criminal penalties; and injunctions resulting in limitation or suspension of operations; and

• the first sentence of paragraph two describes the “inherent risk of incurring significant environmental costs and liabilities . . . due to our generation, handling and disposal of materials, including wastes and petroleum hydrocarbons.”

We have not specifically referred to hydraulic fracturing, or to the fluids or additives used in connection therewith, as hydraulic fracturing is only one part of one stage of designing, drilling, completing and equipping a well and making that well ready for production, most of which parts and stages are subject to the disclosed risks. Limiting our disclosure of the risks to hydraulic fracturing would be inaccurate, as these risks are similarly pronounced in other phases of the drilling and completion process. Likewise, we believe that singling out the application of hydraulic fracturing treatments to a well would wrongly suggest that hydraulic fracturing poses heightened risk to human health and the environment and the other stages, such as drilling the well and other aspects of completing the well, are somehow less subject to environmental risks. Similarly, a number of substances, products and chemicals are present at every well site and are used in different stages of the drilling and completion process, and the release or spillage of, or improper human exposure to, any of such substances, products and chemicals would subject Chesapeake to the enumerated risks. Accordingly, we believe it would be inaccurate to limit our disclosure to fracturing fluids and chemicals and it would be misleading to specifically mention such fluids and chemicals to the exclusion of others.

Securities and Exchange Commission

October 11, 2011

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With respect to the risk of underground migration of hydraulic fracturing fluids from the reservoir into freshwater aquifers, we have considered both the test for evaluating the materiality of events that are contingent or speculative in nature enumerated by the United States Supreme Court in Basic v. Levinson, 485 U.S. 224 (1988), and the relevant guidance issued by the Commission, and we have concluded that such migration is not reasonably likely to occur and accordingly does not create a material risk as to which disclosure is required.

The Supreme Court in Basic stated that materiality “with respect to contingent or speculative information or events . . . will depend at any given time upon a balancing of both the indicated probability that the event will occur and the anticipated magnitude of the event in light of the totality of the company activity” (internal quotations omitted), and we note that the Commission has adopted this “probability/magnitude” standard in subsequent interpretive releases as being applicable to the analysis of contingent or speculative events generally.¹ The Commission has also repeatedly stated that, in the context of management’s discussion and analysis of financial condition and results of operations, management is not required to disclose a known trend, demand, commitment, event or uncertainty if it determines that such trend, demand, commitment, event or uncertainty is not reasonably likely to occur.²

We believe that, based on both the underlying geologic principles and Chesapeake’s (and the industry’s) extensive history of performing hydraulic fracturing treatments on wells, the possibility of underground migration of hydraulic fracturing fluids from the reservoir into freshwater aquifers is so remote that it does not present a material risk under either the Basic probability/magnitude standard or the Commission’s reasonable likelihood

¹ See Interpretive Release No. 33-9106, Commission Guidance Regarding Disclosure Related to Climate Change, effective February 8, 2010, at 17-18 (“In addition, the time horizon of a known trend, event or uncertainty may be relevant to a registrant’s assessment of the materiality of the matter and whether or not the impact is reasonably likely. As with respect to other subjects of disclosure, materiality ‘with respect to contingent or speculative information or events . . . will depend at any given time upon a balancing of both the indicated probability that the event will occur and the anticipated magnitude of the event in light of the totality of the company activity.’” [quoting Basic at 238]).

² Release No. 33-6835, Management’s Discussion and Analysis of Financial Condition and Results of Operations; Certain Investment Company Disclosures, (May 18, 1989): “Where a trend, demand, commitment, event or uncertainty is known, management must make two assessments: (1) Is the known trend, demand, commitment, event or uncertainty likely to come to fruition? If management determines that it is not reasonably likely to occur, no disclosure is required. (2) If management cannot make that determination, it must evaluate objectively the consequences of the known trend, demand, commitment, event or uncertainty, on the assumption that it will come to fruition. Disclosure is then required unless management determines that a material effect on the registrant's financial condition or results of operations is not reasonably likely to occur. Each final determination resulting from the assessments made by management must be objectively reasonable, viewed as of the time the determination is made.”

Securities and Exchange Commission

October 11, 2011

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standard. In particular, we note that nearly all water wells are drilled into freshwater aquifers that lie a few hundred feet below the surface. By contrast, the reservoirs into which Chesapeake injects hydraulic fracturing fluids lie several thousand feet below the surface and are separated from freshwater aquifers by several thousand feet of impermeable rock formations, making it highly improbable (if not technically impossible) that hydraulic fracturing fluids could migrate several thousand feet upwards against great pressures and through multiple impermeable rock formations to negatively impact underground fresh water sources. Additionally, we note that Chesapeake has applied hydraulic fracturing treatments to approximately 15,000 wells since 1989, and the industry as a whole applies hydraulic fracturing treatments to approximately 95% of all wells drilled today. We have considered this extensive company and industry experience and are not aware of any documented cases of hydraulic fracturing fluids migrating from the target reservoir into fresh water sources. Accordingly, we have concluded that, with respect to the risk of underground migration of hydraulic fracturing fluids, any such migration is not reasonably likely to occur and has a sufficiently low probability of actually occurring that Chesapeake does not consider it a material risk.

Exhibit 99.1

4. Please provide a third party report that discusses the considerations of and sources for the estimated future capital costs used.

Response: Attached as Exhibit A to this correspondence is a revised report, currently dated, from Netherland, Sewell & Associates, Inc. containing a new paragraph on page 2 discussing the considerations of and sources for the estimated future capital costs used. The last two sentences of the fourth paragraph on page 2 of the letter included as Exhibit 99.1 to our 2010 Form 10-K filed on March 1, 2011 were deleted and replaced with the immediately following new paragraph:

Capital costs used in this report were provided by Chesapeake and are based on results from recent activity and authorizations for expenditure. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of Chesapeake’s future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard the cost estimates used in this report to be reasonable.

Other than this revision and a minor change in the first paragraph of the report (“guidelines” was changed to “regulations”), the text of the report in Exhibit A is identical to that in the Exhibit 99.1 report in the Form 10-K. We will ensure that any reserve report included with our future filings will contain a discussion of estimated future capital costs.

Exhibit 99.3

5. Please provide a third party report that presents the purpose for which the report was prepared.

Securities and Exchange Commission

October 11, 2011

Page 8 of 8

Response: Attached as Exhibit B to this correspondence is a revised report, currently dated, from Lee Keeling and Associates, Inc. containing in the first paragraph the following description of the purpose for which the report was prepared:

This report has been prepared for public disclosure by Chesapeake in filings with the SEC in accordance with the disclosure requirements set forth in SEC regulations. In our opinion, the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

Other than this revision, the text of the report in Exhibit B is identical to that in the Exhibit 99.3 report in the 2010 Form 10-K. Please note as well that the report in Exhibit B has been signed by Mr. Gordon L. Romine, Manager – Engineering on behalf of Lee Keeling and Associates, Inc. We will ensure that any reserve report included with our future filings will contain a description of the purpose for which the report was prepared.

Should any member of the Staff have a question regarding our responses to the comments set forth above, or need additional information, please do not hesitate to call Mike Johnson, our Chief Accounting Officer, at (405) 935-9229 or me at (405) 935-6125, or you may contact our outside counsel Connie Stamets at (214) 758-1622 at Bracewell & Giuliani LLP. For any future written correspondence sent by email, please use the following addresses: nick.dellosso@chk.com, mike.johnson@chk.com and connie.stamets@bgllp.com.

As you requested in the comment letter, we acknowledge that:

• the company is responsible for the adequacy and accuracy of the disclosure in the filing;

• staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

• the company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Very truly yours,

/s/ DOMENIC J. DELL’OSSO, JR.

Domenic J. Dell’Osso, Jr.

Executive Vice President and Chief Financial Officer

Exhibit A

October 7, 2011

Mr. Gary L. Egger

Chesapeake Energy Corporation

6100 North Western Avenue

Oklahoma City, Oklahoma 73118

Dear Mr. Egger:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2010, to the Chesapeake Energy Corporation (Chesapeake) interest in certain oil and gas properties located in Anadarko, Barnett, Fayetteville, Haynesville, Permian, and other districts in the United States. We completed our evaluation on January 21, 2011. It is our understanding that the proved reserves estimated in this report constitute approximately 58 percent of all proved reserves owned by Chesapeake. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Chesapeake’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Chesapeake interest in these properties, as of December 31, 2010, to be:

	Net Reserves						Future Net Revenue (M$)
	Oil		NGL		Gas				Present Worth
Category	(MBBL)		(MBBL)		(MMCF)		Total		at 10%
Proved Developed Producing		17,869.4		21,931.8		4,553,759.5		11,124,482.0		5,719,255.5
Proved Developed Non-Producing		02,896.1		00,644.3		0,325,897.7		00,794,154.4		0,414,652.8
Proved Undeveloped		09,353.4		17,546.4		4,612,335.5		06,779,634.5		1,422,761.5
Total Proved		30,118.8		40,122.5		9,491,993.0		18,698,266.0		7,556,669.5

Totals may not add because of rounding.

The oil reserves shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves might be established for these properties. Estimates of proved undeveloped reserves have been included for certain locations that generate positive future net revenue but have negative present worth discounted at 10 percent based on the constant prices and costs discussed in subsequent paragraphs of this letter. These locations have been included based on the operators’ declared intent to drill these wells, as evidenced by Chesapeake’s internal budget, reserves estimates, and price forecast. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Future gross revenue to the Chesapeake interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deductions for these taxes, future capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. Future revenue estimates include Chesapeake’s estimates of the costs to abandon the wells and production facilities, net of any salvage value. In some cases, the salvage value exceeds the abandonment cost.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2010. For oil and NGL volumes, the average Platts Gas Daily West Texas Intermediate Crude spot price of $79.42 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For gas volumes, the average Platts Gas Daily Henry Hub spot price of $4.376 per MMBTU is adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $75.89 per barrel of oil, $30.42 per barrel of NGL, and $3.203 per MCF of gas.

Lease and well operating costs used in this report are based on operating expense records of Chesapeake. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, lease and well operating costs for the operated properties are limited to direct lease- and field-level costs and $200 per well per month, which is Chesapeake’s estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties; these overhead expenses are not included in the determination of the economic limits for the properties. As requested, ad valorem taxes are included in the operating costs for the nonoperated properties. Lease and well operating costs are held constant throughout the lives of the properties.

Capital costs used in this report were provided by Chesapeake and are based on results from recent activity and authorizations for expenditure. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of Chesapeake’s future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard the cost estimates used in this report to be reasonable.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Chesapeake interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Chesapeake receiving its net revenue interest share of estimated future gross gas production. Some of these properties are subject to volumetric production payment (VPP) transactions completed by Chesapeake during 2008 and 2010. Our estimates of reserves and future revenue do not include adjustments for any of these VPP transactions; however, it is our understanding that Chesapeake has given effect to those transactions by reducing their reserves at the corporate level.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of Chesapeake to recover the reserves, and that our

projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and statistical analysis, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and guidelines. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Chesapeake, other interest owners, various operators of the properties, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting geoscience, performance, and work data are on file in our office. The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

		Sincerely,
		NETHERLAND, SEWELL & ASSOCIATES, INC.
		Texas Registered Engineering Firm F-002699
			/s/ C.H. (Scott) Rees III
		By:
			C.H. (Scott) Rees III, P.E.
			Chairman and Chief Executive Officer
	/s/ Randolph K. Green		/s/ William J. Knights
By:		By:
	Randolph K. Green, P.E. 72951		William J. Knights, P.G. 1532
	Vice President		Vice President
Date Signed: October 7, 2011		Date Signed: October 7, 2011

RKG:ERH

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

Definitions - Page 1 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

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

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

Definitions - Page 2 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

Definitions - Page 3 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

Definitions - Page 4 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a. Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

Definitions - Page 5 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

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

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

• The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

• The company’s historical record at completing development of comparable long-term projects;

• The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

• The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

• The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 6 of 6

Exhibit B

LEE KEELING AND ASSOCIATES, INC.

PETROLEUM CONSULTANTS

First Place Tower

15 East Fifth Street — Suite 3500

Tulsa, Oklahoma 74103-4350

(918) 587-5521 — Fax: (918) 587-2881

October 7, 2011

Chesapeake Energy Corporation

6206 North Western

Oklahoma City, Oklahoma 73118

Attention:	Mr. Gary L. Egger, Vice President Reservoir Engineering
		Re:	Estimated Reserves and Future Net Revenue
			Selected Interests Owned by
			Chesapeake Energy Corporation
			Constant Prices and Expenses

Gentlemen:

In accordance with your request, we have prepared an estimate of reserves and future net revenue to be realized from interests owned by Chesapeake Energy Corporation (Chesapeake) and located in the states of Arkansas, Louisiana, Oklahoma and Texas. It is our understanding that the proved reserves estimated in this report constitute approximately seven per cent (7%) of the total proved reserves of Chesapeake. The effective date of the estimate is December 31, 2010. This report has been prepared for public disclosure by Chesapeake in filings with the SEC in accordance with the disclosure requirements set forth in SEC regulations. In our opinion, the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose. Our estimate was completed on February 1, 2011, and the results are summarized as follows:

	ESTIMATED REMAINING NET RESERVES								FUTURE NET REVENUE
RESERVE CLASSIFICATION	Oil (MBL)		Gas (MMCF)		NGL (MBL)		Net Equiv. (MMCFE)*		Total (M$)		Present Worth Disc.@10% (M$)
Proved Developed
Producing		11,266.000		636,077.440		5,900.100		739,074.120		2,659,474.000		1,368,673.120
Non-Producing		811.270		20,468.100		44.550		25,603.020		112,049.420		61,089.360
Behind-Pipe		2,053.380		138,645.660		1,451.550		159,675.230		513,068.340		280,370.810
Sub-Total		14,130.650		795,191.200		7,396.200		924,352.370		3,284,591.760		1,710,133.290
Proved Undeveloped		4,206.790		172,600.440		4,509.810		224,900.060		600,492.060		215,902.340
Total All Reserves		18,337.440		967,791.640		11,906.010		1,149,252.430		3,885,083.820		1,926,035.630

* Net Gas Equivalent is calculated based on a conversion factor of 6 MCF of Gas per BBL of Oil.

Notes: (1) Totals may not agree with schedules due to roundoff. (2) Totals exclude shut-in reserves.

W W W . L K A E N G I N E E R S.COM

For the proved developed producing, future net revenue is the amount, exclusive of income taxes, which will accrue to the subject interests from the continued operation of the properties either to depletion or through the year 2076 AD, whichever is projected first. For all other reserve categories, future net revenue is the amount, exclusive of income taxes, which will accrue to the subject interests from the continued operation of the properties to depletion. Future net revenue should not be construed as a fair market or trading value. Provisions have been made for the cost of plugging and abandoning the properties and for the value of salvable equipment.

The preparation of this report included the use of all methods and procedures considered necessary under the circumstances.

No attempt has been made to determine whether or not the wells and facilities comply with various governmental regulations, nor have costs been included in the event they are not.

Summary forecasts of annual gross and net production, severance and ad valorem taxes, operating income, and net revenue by reserve type are included in Schedule No. 1. Also presented in Schedule No. 1 are present worth determinations at ten discount rates, ranging from 5 to 100 per cent. Schedules No. 2 and 3 are sequential listings of the individual properties based on discounted future net revenue for the various reserve categories. Schedule No. 4 is an alphabetical listing by lease name.

CLASSIFICATION OF RESERVES

Reserves assigned to the various leases and/or wells have been classified as either “proved developed” or “proved undeveloped” in accordance with the definitions of the proved reserves as promulgated by the SEC. These are as follows:

Proved Developed Oil and Gas Reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Undeveloped Oil and Gas Reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Proved Developed Oil and Gas Reserves attributed to the subject leases have been further classified as “proved developed producing,” “proved developed non-producing,” “proved developed behind-pipe,” and “proved developed shut-in.”

Proved Developed Producing Reserves are those reserves expected to be recovered from currently producing zones under continuation of present operating methods.

Proved Developed Non-Producing Reserves are those reserves expected to be recovered from zones that have been completed and tested but are not yet producing due to situations including, but not limited to, awaiting connection to a market, minor completion problems that are expected to be corrected, or reserves expected from future stimulation treatments based on analogy to nearby wells. This category also includes “proved developed shut-in reserves.”

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Proved Developed Behind-Pipe Reserves are those reserves currently behind the pipe in existing wells that are considered proved by virtue of successful testing or production in offsetting wells.

ESTIMATION OF RESERVES

The majority of the subject wells have been producing for a considerable length of time. Reserves attributable to wells with well-defined production trends or relationships were based upon extrapolation of these trends or relationships to economic limits and/or abandonment pressures.

Reserves anticipated from new wells were based upon volumetric calculations or analogy with similar properties, which are producing from the same horizons in the respective areas. Structural position, net pay thickness, well productivity, gas-oil ratios, water production, pressures and other pertinent factors were considered in the estimations of these reserves.

Reserves classified as non-producing and/or shut in are attributable to remedial work or stimulations to be performed on the currently perforated zones, i.e., fracture treatments or pumping unit installation. These reserves are based on volumetric calculations and/or analogy with other wells in the area producing from the same horizon.

Reserves assigned to behind-pipe zones have been estimated based on volumetric calculations and/or analogy with other wells in the area producing from the same horizon.

Primary reserves attributable to undeveloped locations have been based on volumetric calculations and/or analogy with offsetting wells.

FUTURE NET REVENUE

Oil Income

Income from the sale of oil was estimated using the average price received for oil sold from the subject properties the first day of each month during 2010. These prices were provided by the staff of Chesapeake. The average price, $79.42 per barrel, was held constant throughout the economic life determined for each well. Adjustments for each well were made for the historical difference between the actual field price received and the above reference price.

Gas Income

Income from the sale of gas was also estimated using the average price received for gas sold from the subject properties the first day of each month during 2010. These prices were provided by the staff of Chesapeake. The average price, $4.737 per million cubic feet, was held constant throughout the economic life determined for each well. Adjustments for each well were made for the historical difference between the actual field price received and the above-referenced price.

NGL Income

Income from the recovery and sale of natural gas liquids (NGL) was based on a price that was approximately forty per cent (40%) of the oil price. Adjustments were made for historical price differentials.

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Operating Expenses

Operating expenses and data used to determine operating expenses were provided by the staff of Chesapeake. These expenses are based upon the actual operating costs charged by the respective operators or are based upon the actual experience of the operators in the various areas. Like income, expenses have also been held constant throughout the life of each lease. Monthly operating costs for Chesapeake-operated wells do not include COPAS overhead charges. They do, however, include Chesapeake’s actual overhead expenses for the Chesapeake-operated wells.

Future Expenditures

Future expenditures have been based on the data provided by the staff of Chesapeake.

GENERAL

All assumptions, data, methods and procedures were appropriate for the purpose served by the report.

Information upon which this estimate has been based was furnished by the staff of Chesapeake or was obtained by us from outside sources we consider to be reliable. This information is assumed to be correct. No attempt has been made to verify title or ownership of the subject properties.

Leases were not inspected by a representative of this firm, nor were the wells tested under our supervision; however, the performance of the wells was discussed with employees of Chesapeake.

This estimate has been prepared utilizing methods and procedures regularly used by petroleum engineers to estimate oil and gas reserves for properties of this type and character. We consider the assumptions, data, methods and procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves and future net revenue herein. The recovery of oil and gas reserves and projection of producing rates are dependent upon many variable factors, including prudent operation, compression of gas when needed, market demand, installation of lifting equipment, and remedial work when required. Government regulations and policies affect Chesapeake’s ability to recover oil and gas reserves, and changes may cause volumes of reserves actually recovered to increase or decrease from the estimated quantities. The reserves included in this report have been based upon the assumption that the wells will continue to be operated in a prudent manner under the same conditions existing at the present time. Actual production results and future well data may yield additional facts, not presently available to us, which will require an adjustment to our estimates.

The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and, if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. As in all aspects of oil and gas estimation, there are uncertainties inherent in the interpretation of engineering data and, therefore, our conclusions necessarily represent only informed professional judgments.

The projection of cash flow has been made assuming constant prices. There is no assurance that prices will not vary. For this reason and those listed in the previous paragraph, the future net cash from the sale of production from the subject properties may vary from the estimates contained in this report.

The information developed during the course of this investigation, basic data, maps and worksheets showing recovery determinations are available for inspection in our office.

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This report is to be used only in its entirety. Individual projections are not to be distributed unless accompanied by this letter.

We appreciate this opportunity to be of service to you.

Very truly yours,
LEE KEELING AND ASSOCIATES, INC. (CA49 PE)
By:	/s/ Gordon L. Romine
	Gordon L. Romine (PE6057)
	Manager - Engineering

LKA7034

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