Chesapeake Energy Corporation

6100 North Western Avenue

Oklahoma City, Oklahoma 73118

August 7, 2007

Ms. April M. Sifford

Branch Chief

Mr. Gary Newberry

Ms. Kimberly Calder

Division of Corporation Finance

Securities and Exchange Commission

100 F Street, NE

Washington, DC 20549-7010

Re: Chesapeake Energy Corporation

Form 10-K for the Fiscal Year Ended December 31, 2006

Filed March 1, 2007

Form 10-Q for Fiscal Quarter Ended March 31, 2007

Filed May 8, 2007

File No. 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 August 3, 2007.

The comments relate to the Staff’s review of the company’s Annual Report on Form 10-K for the year ended December 31, 2006 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 and request the company to amend these reports in order to reflect certain of the Staff’s comments. We respectfully request that the Staff allow the company to comply with the comments in a prospective manner in future filings with the Commission as outlined in our responses below. The company is preparing to file its Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (our “Second Quarter 10-Q”) on August 8, 2007 and will include disclosure that is responsive to the applicable Staff comment. We believe amendments to our prior filings would not materially enhance the total mix of information about our company currently available to investors.

For the convenience of the Staff, we have repeated below the comments of the Staff in the review letter and followed each comment with the company’s response.

Securities and Exchange Commission

August 7, 2007

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Form 10-K for the Fiscal Year Ended December 31, 2006

Management Discussion and Analysis of Financial Condition and Results of Operations

Liquidity and Capital Resources, page 33

1. You have identified cash flow from operations as a primary source of liquidity. Provide a discussion of the information necessary to understanding the changes in this item as disclosed in your statements of cash flows. Refer to Regulation S-K Item 303(a), the related instructions to Item 303(a) and Financial Reporting Codification Section 501.03.a.

Response: We are providing enhanced disclosure regarding cash flow from operations in our Second Quarter 10-Q to be responsive to the Staff’s comment. The relevant portion of the Liquidity and Capital Resources section is attached hereto. We would propose to include disclosure along the lines of that shown in the attachment in our future filings.

Consolidated Balance Sheet, page 65

2. The line item accrued liabilities exceeds 5% of total current liabilities. Separately state in the balance sheet, or as footnote disclosure, any item within accrued liabilities that exceeds 5% of total current liabilities as required by Regulation S-X Rule 5-02(20).

Response: Note 1 to the company’s financial statements included in the 2006 Annual Report on Form 10-K contains the following disclosure under “Accounts Payable and Accrued Liabilities” on page 75:

“Other accrued liabilities include $176.7 million and $88.3 million of accrued drilling costs as of December 31, 2006 and 2005, respectively.”

No other item within accrued liabilities exceeded 5% of current liabilities as of December 31, 2006 and 2005. Accordingly, the company believes that it has provided the disclosure required by Regulation S-X, Rule 5-02(20).

Notes to Consolidated Financial Statements

Note 11 – Supplemental Disclosures about Oil and Natural Gas Producing Activities

Net Capitalized Costs, page 105

3. Your policy footnote disclosed that the present value of estimated future net revenues is adjusted for cash flow hedges. In addition to disclosing the impact of cash flow hedges on your ceiling limitation test, disclose the portion of future production hedged, and the dollar amount that would have been charged to income had the effect of cash flow hedges not been considered. Refer to Staff Accounting Bulletin Topic 12.D.3.b.

Securities and Exchange Commission

August 7, 2007

Page 3 of 6

Response: We acknowledge the requirement of Staff Accounting Bulletin Topic 12 to disclose the portion of our production hedged in future years and would propose to include disclosure of volumes hedged in our future filings. Specifically, we propose to add disclosure such as the following (as it would have appeared in the 2006 Form 10-K) in any applicable future filing:

“As of December 31, 2006, the company had cash flow hedges covering 203 bcfe, 267 bcfe and 23 bcfe in 2007, 2008 and 2009, respectively.”

We note that our periodic reports routinely show the volumes of cash flow hedges at period end in the Quantitative and Qualitative Disclosures about Market Risk item. See the tables on pages 54-56 of our 2006 Form 10-K and pages 37-39 of our first quarter 2007 Form 10-Q.

With respect to the effect on our impairment test from cash flow hedges, on page 105 of our 2006 Form 10-K (pursuant to SAB Topic 12.D.3.b), we reported the calculated impairment as of December 31, 2006 (approximately $500 million, net of tax) and the amount by which our cash flow hedges increased the full-cost ceiling (approximately $1.6 billion). We believe that an investor could calculate, by adding these numbers, that our impairment would have been $2.1 billion in the absence of our hedging activities. However, in future filings, we propose to amplify our disclosure (as and if necessary) and state the amount that would have been charged to income had we not had any cash flow hedges. For example, in our December 31, 2006 Form 10-K, we would have added the following statement to the final paragraph on page 105:

“Had the effects of our cash flow hedges not been considered in calculating the ceiling limitation, the impairment as of December 31, 2006 would have been approximately $2.1 billion, net of income tax.”

Standardized Measure of Discounted Future Net Cash Flows (unaudited), page 110

4. Your 2006 standardized measure of discounted future net cash flows (SMOG), as disclosed on page 110, is significantly lower than the net book value of your oil and gas capitalized costs as disclosed on page 64. This difference appears to exceed any difference between a fair value cash flow model with price and cost escalations and SMOG, which is not considered representative of fair value, and calculated using fixed year-end price and cost assumptions. Explain the reasons for the difference between SMOG and capitalized costs and provide us with your SFAS 144 impairment analysis for 2006. We may have further comments.

Response: Chesapeake follows the full-cost method of accounting under which all costs associated with oil and natural gas property acquisition, exploration and development activities are capitalized. The limitation on capitalized costs for full-cost companies is specified in Regulation S-X, Rule 4-10(c)(4). We believe the impairment

Securities and Exchange Commission

August 7, 2007

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tests required under FAS 144 (previously FAS 121) do not apply to our investment in oil and natural gas properties. We therefore completed a ceiling test consistent with the provisions of Regulation S-X, Rule 4-10(c)(4) rather than the impairment analysis specified by SFAS 144 for 2006.

Moreover, we believe that the net book value of our oil and gas properties and the measure of SMOG are different calculations with different conceptual underpinnings. As such, they are not susceptible to a line item reconciliation. The net book value of our oil and natural gas properties represents the historical costs incurred in oil and natural gas property acquisition, exploration and development activities and is calculated in accordance with Rule 4-10 of Regulation S-X. The SMOG measure, on the other hand, represents the future cash inflows we might expect to receive from our proved reserves, reduced by certain expenses, discounted to the present. The SMOG measure is calculated pursuant to SFAS No. 69, and is subject to a number of assumptions and estimates regarding prices, taxes, timing and the like. Given the inherently historical nature of the net book value of our oil and natural gas properties and the forward-looking nature of the SMOG measure, we are unsure how to present a formal meaningful reconciliation of these two numbers.

We can advise the Staff that the following factors had a significant impact upon our ceiling test calculation as of December 31, 2006:

(1) we had deferred income taxes associated with oil and gas properties of $3.3 billion;

(2) the net book value of our oil and natural gas properties includes unevaluated properties with a value of approximately $3.8 billion; and

(3) we benefited from the impact of cash flow hedges in an amount of approximately $1.6 billion.

In addition, we note that a reconciliation of our net capitalized costs, as well as a schedule detailing our costs incurred in oil and natural gas acquisition, exploration and development activities, is provided in note 11 to the financial statements included in our 2006 Annual Report on Form 10-K. With respect to the measure of SMOG, a complete reconciliation of beginning and ending SMOG is provided in note 11 as well.

Should any member of the staff have any questions regarding our responses to your comments set forth above, or need additional information, please do not hesitate to call Mike Johnson at (405) 879-9229 or me at (405) 879-9232, or you may contact our outside counsel Connie Stamets at (214) 758-1622 or Mike Telle at (713) 221-1327 at Bracewell & Giuliani LLP.

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

Securities and Exchange Commission

August 7, 2007

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• 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/ MARCUS C. ROWLAND

Marcus C. Rowland

Executive Vice President

And Chief Financial Officer

ATTACHMENT A

EXCERPT FROM LIQUIDITY AND CAPITAL RESOURCES SECTION

OF

CHESAPEAKE ENERGY CORPORATION’S

2007 SECOND QUARTER FORM 10-Q

Liquidity and Capital Resources

Sources and Uses of Funds

Cash flow from operations is our primary source of liquidity to meet operating expenses and fund capital expenditures (other than for acquisitions). Cash provided by operating activities was $2.122 billion in the Current Period compared to $2.045 billion in the Prior Period. The $77 million increase in the Current Period was primarily due to higher oil and natural gas production. Changes in cash flow from operations are largely due to the same factors that affect our net income and reflect the impact on earnings of non-cash items, such as depreciation, depletion and amortization ($903 million and $674 million during the Current Period and the Prior Period, respectively), deferred income taxes ($460 million and $627 million during the Current Period and the Prior Period, respectively) and unrealized gains and (losses) on derivatives ($152 million and ($212) million during the Current Period and the Prior Period, respectively). Net income decreased to $776 million in the Current Period from $984 million in the Prior Period and is discussed below under Results of Operations.

Changes in market prices for oil and natural gas directly impact the level of our cash flow from operations. While a decline in oil or natural gas prices in 2007 would affect the amount of cash flow that would be generated from operations, we currently have oil swaps in place covering 73% of our expected remaining oil production in 2007 at an average NYMEX price of $71.59 per barrel of oil and natural gas swaps in place covering 59% of our expected remaining natural gas production in 2007 at an average NYMEX price of $8.66 per mcf, along with natural gas collars covering 12% of our anticipated remaining natural gas production for 2007 with an average NYMEX floor of $6.94 per mcf and an average NYMEX ceiling of $8.52 per mcf. Additionally, we have written call options covering 15% of our 2007 remaining natural gas production at a weighted average price of $9.45 for a weighted average premium of $0.55 per mcf. This level of hedging provides certainty of the cash flow we will receive for a substantial portion of our 2007 production. Depending on changes in oil and natural gas futures markets and management’s view of underlying oil and natural gas supply and demand trends, we may increase or decrease our current hedging positions.

Based on fluctuations in natural gas and oil prices, some of our hedging counterparties may require us to deliver cash collateral or other assurances of performance from time to time. All but two of our commodity price risk management counterparties require us to provide assurances of performance in the event that the counterparties’ mark-to-market exposure to us exceeds certain levels. Most of these arrangements allow us to minimize the potential liquidity impact of significant mark-to-market fluctuations by making collateral allocations from our bank credit facility or directly pledging oil and natural gas properties, rather than posting cash or letters of credit with the counterparties. As of June 30, 2007 and August 6, 2007, we had outstanding collateral allocations and pledges of oil and natural gas properties with respect to commodity price risk management transactions but were not required to post any other collateral. Future collateral requirements are uncertain and will depend on the arrangements with our counterparties and highly volatile natural gas and oil prices.

We use borrowings under our $2.5 billion revolving bank credit facility to supplement cash flow from operations. At August 6, 2007, there was $453 million of borrowing capacity available under the revolving bank credit facility. We use the facility to fund daily operating activities and acquisitions as needed. We borrowed $3.544 billion and repaid $2.624 billion in the Current Period, and we borrowed $4.055 billion and repaid $4.127 billion in the Prior Period under the credit facility.

The public and institutional markets provide us additional liquidity and over time have been our principal source of long-term financing for acquisitions. We have sold debt and equity in both public and private offerings in the past, and we expect that these sources of capital will continue to be available to us in the future. Nevertheless, we caution that ready access to capital on reasonable terms is subject to many uncertainties, as explained under “Risk Factors” in Item 1A of our Form 10-K for the year ended December 31, 2006. The recent volatility in the U.S. securities markets heightens the risk for us that capital might not be available when needed to supplement operating cash flow to fund our budgeted capital expenditures, or might only be available on terms we consider unattractive.

In the Current Quarter, we completed a public offering of $1.15 billion of 2.5% Contingent Convertible Senior Notes due 2037. Net proceeds of approximately $1.124 billion were used to repay outstanding borrowings under our revolving bank credit facility. The following table reflects the proceeds from sales of securities we issued in the Current Period and the Prior Period ($ in millions):

	For the Six Months Ended June 30,
	2007				2006
	Total Proceeds		Net Proceeds		Total Proceeds		Net Proceeds
Convertible preferred stock	$	—	$	—	$	500	$	485
Common stock		—		—		726		699
Unsecured senior notes guaranteed by subsidiaries		1,150		1,124		1,000		969
Total	$	1,150	$	1,124	$	2,226	$	2,153

Our primary use of funds is our capital expenditures for exploration and development of oil and natural gas reserves. We refer you to the table under Investing Activities below, which sets forth the components of our oil and natural gas investing activities for the Current Period and the Prior Period. Our drilling, land and seismic capital expenditures in 2007 are currently budgeted at $5.1 billion to $5.6 billion and are expected to exceed our 2007 cash flow from operating activities. We believe this level of exploration and development will enable us to increase our proved oil and natural gas reserves in 2007 by more than 15% and increase our total production by 18% to 22% (inclusive of acquisitions completed or scheduled to close in 2007 through the filing date of this report but without regard to any additional acquisitions that may be completed in 2007).

At times during the remainder of 2007 and 2008, we expect our capital expenditures, operating costs, debt service, short-term contractual obligations and dividend payments will exceed our available cash, cash provided by operating activities and funds available under our revolving bank credit facility. We plan to obtain additional liquidity through the sale of a portion of our Appalachian production and proved reserves and the sale and leaseback of drilling rig and compressor assets. We believe these transactions could provide the company more than $1 billion of cash proceeds by year-end 2007. We may also arrange long-term financing by accessing the capital markets.

We retain a significant degree of control over the timing of our capital expenditures which permits us to defer or accelerate certain capital expenditures if necessary to address liquidity issues. In addition, higher drilling and field operating costs, drilling results that alter planned development schedules, acquisitions or other factors could cause us to revise our drilling program, which is largely discretionary.