Correspondence

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 May 30, 2008. We have repeated below the Staff’s comments and followed each comment with the company’s response.

Response: We discuss our competitive position on page 22 in Item 1A. Generally, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can lessen seasonal demand fluctuations. World weather and resultant prices for LNG can also affect deliveries of competing LNG into this country from abroad, affecting the price of domestically produced natural

gas. While the first risk factor included in Item 1A on oil and natural gas price volatility refers to a number of these factors, we will include a discussion of seasonality, such as the foregoing, in Item 1 of our 2008 Form 10-K.

Management Discussion and Analysis of Financial Condition and Results of Operations, page 31

Response: We confirm that Chesapeake has no off-balance sheet arrangements to disclose in accordance with Item 303(a)(4) of Regulation S-K.

Response: As described on page 50 under “Disclosures About Effects of Transactions with Related Parties” in Item 7 and on page 88 under note 6 in Item 8, the full related party balance at December 31, 2007 was due from Chesapeake’s Chairman and CEO, Aubrey McClendon. Mr. McClendon participates as a working interest owner in new oil and natural gas wells drilled by the company under the Founder Well Participation Program (the “FWPP”), which was approved by shareholders in June 2005 and a version of which has been in effect since our IPO in 1993. The company bills Mr. McClendon monthly for his share of leasehold, drilling, completing, equipping and operating costs. These costs are paid promptly by Mr. McClendon as each invoice is received. However, because Mr. McClendon, like all our other joint working interest owners, does not receive our invoices until the third week of the month after charges have been incurred and processed by the company, the balance sheet reflects one month’s billing due to the company from Mr. McClendon at the end of each accounting period. Additionally, there are minor amounts due to the company for reimbursement of Chesapeake accounting staff utilized by Mr. McClendon for personal business. These costs are paid at the time an invoice is received as well.

In addition to the description of the FWPP on page 50 of the 2007 Form 10-K, Chesapeake’s proxy statement for its 2008 annual meeting of shareholders, filed April 29, 2008 and incorporated by reference into the 2007 Form 10-K, discusses the FWPP on page 35 under “Compensation Discussion and Analysis” (reasons for and administration of the program) and on pages 53-54 under “Transactions with Related Persons—Founder Well Participation Program” (history, operation and administration of the program and billings during 2007 and the first quarter of 2008). We believe these disclosures provide an appropriate description of the transactions giving rise to related party receivables.

Response: Chesapeake invested in both of these companies principally for capital appreciation but also to support the critical early-stage credit needs of promising small companies entering our industry. We have historically made a number of investments in energy-related companies which we believed presented opportunities for investment returns. It is not uncommon for the funding provided to our investees to include debt as well as equity components.

We invested in Ventura in early 2007 (both equity and loan commitment). There were no refineries in western Oklahoma until Ventura opened one in 2006. Previously, diesel and other products sold in western Oklahoma for higher premiums than in Chesapeake’s other operating areas because of trucking transportation costs. The Ventura refinery is now a supply source of diesel for rigs which support our extensive drilling program in Oklahoma where off-road diesel was difficult to find and more expensive. As a result of a refinery operating in the area, we are also able to sell our oil production at a higher price than we previously received. In addition, the arrangements to support Ventura by providing credit allowed us to make our investment in the equity of the company at a price we considered attractive. Our primary motive in investing in Mountain Drilling was also for capital appreciation. Mountain Drilling specializes in hydraulic drilling rigs which are quieter, have less of a “footprint” and have reduced tower height, making them ideal for urban drilling. Our Barnett Shale play in Fort Worth and the DFW Airport are examples of where they have been useful.

The foregoing discussion of our business reasons for the credit arrangements we have with Ventura and Mountain Drilling is provided as supplemental information for the Staff. These investments, along with the various credit arrangements, are not considered material by management. We do not propose to include such disclosure in the contingencies and commitments note of our financial statements.

Response: Chesapeake’s 2007 proxy statement was reviewed by the Staff in August 2007 and the company received a comment also focusing on the benefits

associated with the FWPP. We refer you to our response to comment #3 in our correspondence to the Staff dated and filed on August 31, 2007. In that response, we maintained that it was inappropriate to disclose revenues received by Mr. McClendon from his participation in the FWPP. First, we distinguished FWPP revenue from compensation received by Mr. McClendon.

We believe such a comparison is inappropriate in that total compensation represents cash and the value of equity and other benefits received by Mr. McClendon; there is no countervailing expense charged to him. The FWPP, on the other hand, involves both revenues and expenses. Any revenue Mr. McClendon has received required the expenditure of his personal funds at considerable risk as to any one well. During 2006, participation revenue and expenditures for Mr. McClendon were $71.2 million and $106.2 million (an amount disclosed on page 47 of the proxy statement), resulting in a net expenditure by Mr. McClendon of $35 million to participate in the FWPP. Since inception in 1993, the amounts invested by Mr. McClendon in the program have significantly exceeded the revenues generated by his well participation interests.

For 2007, Mr. McClendon’s FWPP participation continued as a significantly larger net expenditure than in 2006. Our August 31, 2007 response to the Staff also made the point that Mr. McClendon’s FWPP participation interests are his separate property.

Another reason we have not disclosed Mr. McClendon’s annual FWPP revenue is that it flows from property that belongs to him, not the company. (An exception was our 2005 proxy statement, in which the FWPP was a matter put to a shareholder vote.) After the company assigns an interest in an oil and natural gas lease to Mr. McClendon pursuant to the FWPP, Mr. McClendon and the company become joint working interest owners in that lease. Mr. McClendon pays his expenses the same as any other joint working interest owner, and the company pays its expenses. Because related person transactions are involved (leasehold purchase/sale, operator services, etc.), our proxy statements have disclosed each year the amounts of FWPP leasehold, drilling, completion, equipping and operating costs billed by the company to and paid by Mr. McClendon. We do not, however, disclose income he receives from, or the value of, his FWPP interests—or any other of his personal assets.

We continue to believe it would be inappropriate to disclose Mr. McClendon’s FWPP revenue for the reasons stated in our August 31, 2007 letter. We note that the Staff had no further comment on the subject after receiving our response. We also believe the disclosures on the FWPP contained in our 2007 Form 10-K and incorporated therein from our 2008 proxy statement (referred to above in our response to comment #3) adequately inform readers of the nature and benefits of Mr. McClendon’s participation in the FWPP.

Response: We believe the 2007 Form 10-K adequately discusses each of the matters raised by the Staff with regard to the reserve replacement ratios presented.

A discussion of the uncertainties inherent in estimates of proved reserves appears on page 9 in the penultimate paragraph of “Oil and Natural Gas Reserves” in Item 1 and is reproduced below. While the discussion of uncertainties applies generally to reported proved reserves, the last sentence cautions the reader that these uncertainties are particularly true for proved undeveloped reserves. We also refer you to a risk factor on proved reserve estimates, “The actual quantities and present value of our proved reserves may prove to be lower than we have estimated,” which appears on pages 22-23.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond Chesapeake’s control. The reserve data represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material. Accordingly, reserve estimates are often different from the actual quantities of oil and natural gas that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. A change in price of $0.10 per mcf for natural gas and $1.00 per barrel for oil would result in a change in the December 31, 2007 present value of estimated future net revenue of our proved reserves of approximately $390 million and $56 million, respectively. The estimated future net revenue used in this analysis does not include the effects of future income taxes or hedging. The foregoing uncertainties are particularly true as to proved undeveloped reserves, which are inherently less certain than proved developed reserves and which comprise a significant portion of our proved reserves.

On page 33, at the end of the fifth paragraph under “Executive Summary,” we provide the following information about the time horizon of when the 2007 reserve additions are expected to be produced:

Our percentage of proved undeveloped reserve additions to total proved reserve additions was approximately 29% in 2007, 38% in 2006 and 36% in 2005. Based on our current drilling schedule and budget, we expect that virtually all of the proved undeveloped reserves added in 2007 will begin producing within the next three to five years. Generally, proved developed reserves are producing at the time they are added or will begin producing within one year.

Please refer to the defined term “reserve replacement” on page 19 for the following description of how management uses this measure and its limitations:

Management uses the reserve replacement ratio as an indicator of the company’s ability to replenish annual production volumes and grow its reserves, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not imbed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

Response: We provide for our cash needs in a variety ways, as explained in “Liquidity and Capital Resources.” Over the past year, we have increased the borrowing capacity under our revolving bank credit facility by $1 billion. It now has a credit limit of $3.5 billion. We use the facility to “accommodate timing differences between cash flow from operations, asset monetizations [such as the December 2007 VPP discussed under comment #8 below] and planned capital expenditures.” On page 33, we stated that we planned to raise approximately $3 billion by the end of 2009 through various asset monetization transactions. One of those transactions, a second VPP transaction, closed as planned in May 2008 and we received proceeds of $623 million. Another transaction described on page 33, the sale of a minority interest in a midstream partnership we are forming, is expected to close early in the third quarter and is expected to raise approximately $1 billion. In May 2008, we announced a new sale of oil and natural gas properties which we expect will generate over $1.5 billion of proceeds. From time to time, we also divest properties in smaller transactions as part of our effort to high-grade our leasehold inventory and to redeploy capital to higher priority areas.

Late in the first quarter 2008, we announced a new significant shale discovery and seven other new discoveries and projects. These and an acceleration of activity in existing plays caused us to increase our planned capital expenditures and to raise additional funds through public capital market transactions. On April 2, 2008, we completed a public offering of 23 million shares of common stock for total net proceeds of $1.011 billion, and on May 27, 2008, we completed public offerings of $800 million aggregate principal amount of 7.25% Senior Notes due 2018 and $1.380 billion aggregate principal amount of 2.25% Contingent Convertible Senior Notes due 2038.

We rely on many alternative external sources of capital to supplement our cash flows from operations (public markets, bank financing, VPP sales, potential joint venture partners, etc.). It is possible, although we believe highly unlikely, that all of these sources would simultaneously be unavailable to the company. However, our capital expenditure program is largely discretionary and can be reduced or deferred from time to time, a point we make on page 35. We believe the whole of our discussion of sources and uses of funds in the 2007 Form 10-K appropriately addressed how cash affects our ability to do business.

We believe the material terms of the December 2007 volumetric production payment (“VPP”) are disclosed on page 33 under “2008 - 2009 Financial Plan—Producing Property Sales” in Item 7 and on page 110 in note 13 of our financial statements. Our intention was to provide a plain-English description of the pertinent facts about this complex transaction, including the

In your comment, you refer to the following disclosure that appears on page 110 in note 13 to our financial statements: “Associated with the transaction, we have committed to purchase the VPP production over the 15 year term at market prices at the time of production, and the purchased gas will be resold.” This arrangement was not a material term of the transaction and is economically immaterial to us. Our obligation is to buy the production at published index prices, less a market-based gathering fee adjusted annually for inflation. We do not believe this aspect of the transaction warrants further discussion as we expect to resell the purchased natural gas on similar market-based terms.

In considering whether to file any or all of the VPP transaction agreements as material contracts, we reviewed the exhibit filing requirements in Regulation S-K Item 601(b)(10). We concluded that the substance of the transaction was ordinary course business for us, even though the form of the transaction was out of the ordinary. Our business is, primarily, finding, producing and selling natural gas and oil. Through the VPP, we sold approximately 208 bcfe of our natural gas reserves. The buyers’ obligation to pay us has been fully performed. Our obligation to purchase any VPP production will be performed in the future in conjunction with our normal operations.

We also concluded that the transaction was not material to us. The VPP represented only 2% of Chesapeake’s daily production and proved reserves at December 31, 2007. We further considered materiality in the context of Regulation S-K Item 601(b)(10)(ii)(B) and (C) and found those provisions inapplicable. Our business is not substantially dependent upon the VPP contracts, and the sale price of $1.1 billion is far less than 15% of our oil and natural gas properties at December 31, 2007 (15% of $26.185 billion = $3.928 billion).

For these reasons, we concluded the VPP transaction agreements were not “material contracts,” as contemplated in Regulation S-K Item 601(b)(10), and therefore did not file them as exhibits to our 2007 Form 10-K.

Response: We expect the VPP will have an immaterial impact on our liquidity in future periods. As noted in our response to comment #8, we used a volumetric production payment to sell a small portion of our proved reserves, quantified at approximately 208 bcfe with an initial production delivery rate of 55 mmcfe per day and representing approximately 2% of proved reserves and net production as of the sale date. Furthermore, the VPP sale was part of Chesapeake’s business strategy to fund its drilling program, as described on page 33 under “2008 – 2009 Financial Plan.” We are redeploying the VPP proceeds to develop new production that we expect will have a higher return to the company than the Appalachian production covered by the VPP. Although Chesapeake will bear the future operating expenses of the VPP, estimated to have a present value of approximately $90 million, such expenses on an annual basis will not significantly impact our liquidity.

Response: The company provided a comprehensive listing of its derivative positions as of December 31, 2007 on pages 55-57 in Item 7A, and we further provided an updated hedged percentage as of a current date on page 34 under “Liquidity and Capital Resources.” Our natural gas and oil derivatives allow us to predict with greater certainty the revenue we will receive for our hedged production, but we cannot predict the gains or losses we will realize from the derivatives. Gains or losses on open derivatives will be determined by future natural gas and oil prices at the time of settlement. Historically, the markets for natural gas and oil have been volatile and they are likely to continue to be volatile. We employ hedges primarily to mitigate the downside of price volatility but cannot reasonably predict what prices will be in future periods.

We have disclosed on page 56 the aggregate amount of gains ($215 million as of December 31, 2007) we will realize in future periods, from 2008 through 2022, as a result of natural gas and oil hedges we have settled prior to maturity. Those gains are locked in and are not subject to future price changes.

Response: Based on the VPP buyers’ assumption of significant production and reserve risks and substantially all price risk, Chesapeake concluded that the production payment should be accounted for as a sale of a volumetric production payment. Below is a more detailed analysis of the conclusions reached with respect to the accounting for this transaction.

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. Pursuant to Regulation S-X Rule 4-10(c)(6)(i), proceeds from the sale of oil and natural gas properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved properties, in which case a gain or loss is recognized.

To determine the appropriate accounting for the VPP production payment, we examined the substance of the transaction to identify which party had the risks of ownership following the transaction, including price and production and reserve risks. We were guided by the principles included in the following table, which is adapted from Petroleum Accounting – Principles, Procedures, & Issues, PricewaterhouseCoopers LLP and Professional Development Institute of the University of North Texas, 6^th ed. We believe this publication provides an important and relevant source of industry practice for the accounting for volumetric production payments.


	Price Risk	Production Risk
Loan, in substance	Seller	Seller
Prepaid commodity sale	Buyer	Seller
Volumetric production payment	Buyer	Buyer, primarily
Outright sale	Buyer	Buyer

In order for a production payment to be considered a volumetric production payment, as opposed to a production loan (dollar-denominated production payment) or a prepaid commodity sale, the purchaser must assume the risks typically associated with ownership. Below we discuss the principal owner risks: price risk and production/reserve risk.

Price Risk. The buyers assumed all, or substantially all, price risk associated with the VPP share of production, as the price is completely index based (i.e., variable). Even though Chesapeake transferred to the buyers derivatives that will serve to mitigate price risk, the buyers have sole control over the derivatives and bear the counterparty credit risk associated with the derivative positions. Chesapeake provided no guarantee or commitment as to pricing.

Production and Reserve Risk. The buyers assumed significant reserve risk. In the event the leasehold interests covering the VPP have insufficient reserves to satisfy the scheduled quantities of production to be delivered under the VPP, there is no recourse to Chesapeake. Chesapeake has no obligation to deliver hydrocarbons from any other property or lease or from Chesapeake’s retained interest in the subject leases.

The conveyance of the production payment contains a makeup mechanism to prevent either party from profiting on differences in the timing of actual delivery of the VPP share of hydrocarbons compared to the scheduled delivery of the VPP share of hydrocarbons. If there is a shortfall in scheduled deliveries, the quantity to be made up is adjusted to take into account any differences in the market price of the applicable hydrocarbons between the month in which the shortfall occurred and the month in which the shortfall is made up, and interest on the value of the deferred share of production is imposed. The shortfall quantity, as adjusted, is delivered in kind as soon as sufficient production is available from the properties. If market prices are higher in the month in which a makeup occurs compared to the month in which the production was scheduled to be delivered, the quantity of VPP hydrocarbons to be delivered will be reduced. If market prices are lower in the month in which the makeup occurs compared to the month in which the production was scheduled to be delivered, the quantity of VPP hydrocarbons will

be increased. Accordingly, the buyers are in no better or worse position in terms of pricing risk than they would have been had the VPP share of production actually been delivered on the scheduled date.

While the makeup provision could cause the volumes ultimately delivered to the buyers to differ from the originally scheduled volumes, Chesapeake believes this does not substantively change the overall attributes of the VPP. The value and interest components of any short-term disruption in the scheduled deliveries of the VPP owners’ share of production would have a negligible effect on the overall VPP arrangement in relative terms. Conversely, a long-term disruption in the delivery of the scheduled volumes, although likely to have a more than negligible effect on the VPP arrangement through the value and interest components of the makeup provision, would indicate a cumulative inability of the reserves to keep pace with the scheduled volumes. The buyers have assumed the risk of inadequate reserves as the production payment is without recourse to other reserves or to Chesapeake.

Based on the buyers’ assumption of significant production and reserve risks and substantially all price risk, Chesapeake concluded that the production payment should be accounted for as a volumetric production payment. Under Regulation S-X Rule 4-10(c)(6)(i), “sales of oil and gas properties . . . shall be accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves . . . attributable to the cost center.” Since the VPP constituted less than 2% of Chesapeake’s total proved reserves, a significant alteration of the relationship between capitalized costs and proved reserves did not take place (the impact of the sale on our 2007 fourth quarter DD&A rate was approximately 1.9%).

We also considered the provisions of Regulation S-X Rule 4-10(c)(6)(ii), which indicates that “purchases of oil and gas reserves in place ordinarily shall be accounted for as additional capitalized costs with the applicable cost center; however, significant purchases of production payments or properties with lives substantially shorter than the composite life of the cost center shall be accounted for separately.” While this provision is focused on the purchase of reserves, we believe it confirms that the full-cost rules consider production payments the transfer of a mineral interest as contemplated by Regulation S-X Rule 4-10(c)(6)(i) above.

A production loan, while similar to a volumetric production payment, requires the seller to deliver cash or quantities of oil and gas production having a value equal

to the amount of cash received by the seller plus a stated rate of interest. An important distinction between a production loan and a volumetric production payment is that the volumes to be delivered under a volumetric production payment are specified in the agreement and there are no mechanisms that guarantee the value of the production and reserves attributable to the purchaser’s ownership interest. As described above, the buyers of Chesapeake’s VPP assumed all, or substantially all, price risks and reserve risk. Because the makeup mechanism does serve to mitigate some of the risk associated with the timing of production, Chesapeake carefully evaluated whether the VPP should be accounted for as debt.

In addition to utilizing the concept of risk transfer in the table above, the company evaluated the sale of the VPP using the attributes provided in EITF 88-18, Sales of Future Revenues. Of the six attributes listed in EITF 88-18, only one was potentially met. It states, “The enterprise has significant continuing involvement in the generation of the cash flows due the investor (for example, active involvement in the generation of the operating revenues of a product line, subsidiary, or business segment).” Although the presence of this attribute creates the rebuttable presumption that classification of the proceeds as debt is required, there are numerous mineral conveyances (including those discussed in SFAS 19 for entities utilizing successful efforts) that involve some element of continuing involvement by the seller, and for which sale accounting is provided. Chesapeake believes that EITF 88-18 was not intended to alter the accounting for mineral conveyances of oil and gas companies as contemplated by SFAS 19 and Regulation S-X Rule 4-10.

In summary, we rejected the alternative of accounting for the VPP as debt. The characteristics of the VPP, taken as a whole, are more indicative of a volumetric production payment as contemplated in Regulation S-X Rule 4-10.

We rejected accounting for the VPP as a prepaid commodity sale because Chesapeake does not guarantee production and delivery of the scheduled volumes. These risks are assumed by the buyers.

As part of the VPP transaction, Chesapeake entered into a Novation Agreement to transfer full ownership of certain derivative contracts to the buyers. These derivatives will mitigate commodity price risk of the buyers in connection with future deliveries of scheduled volumes of production. Although the buyers could have independently entered into similar derivatives to manage their price risk, the Novation Agreement simply facilitated this process, and the value of the novated hedges was a determinant in the calculation of the purchase price. The buyers

have complete discretion over the derivatives. They could settle the contracts prior to maturity or hold them throughout the 15-year term of the VPP, and they have counterparty credit risk associated with the derivative positions. Chesapeake has provided no guarantee or commitment relating to the buyers’ VPP price risk.

The novated hedges were designated as cash flow hedges associated with Chesapeake production not part of the VPP transaction. Consequently, pursuant to SFAS 133, the associated fair value of the hedges (as of December 31, 2007) will be held in Other Comprehensive Income pending the respective months of related production pursuant to the original terms of the derivative contracts. The novated hedges had a net negative fair value of $52 million, which reduced the amount allocated to the properties sold.

Response: The company included an estimate of the interest related to the drilling rig leases for both the year ended December 31, 2007 and the quarter ended March 31, 2008. The interest expense related to the compressor leases was not significant and was therefore excluded from the calculation.

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 at (405) 879-9229 or me at (405) 879-9232, or you may contact our outside counsel Connie Stamets at (214) 758-1622 at Bracewell & Giuliani LLP.

Very truly yours,

/s/ Marcus C. Rowland

Marcus C. Rowland

Executive Vice President and Chief Financial Officer


Attention:		Mr. Roger Schwall, Assistant Director
		Mr. Chris White, Branch Chief
		Mr. Gary Newberry

Re:		Chesapeake Energy Corporation
		Form 10-K for Fiscal Year Ended December 31, 2007
		Filed February 29, 2008
		Form 10-Q for Fiscal Quarter Ended March 31, 2008
		Filed May 12, 2008
		File No. 1-13726