SEC Comment:

Business, page 2

Proved Reserves, page 8

We note your disclosure of the table calculating the "Present Value" of your proved reserves (or what is more commonly known as PV10) as of December 31, 2004, which differs from the standardized measure, as calculated and presented in accordance with SFAS 69. Please be advised that this disclosure is considered a non-GAAP measure. As such, you must provide all disclosures required by Item 10(e) of Regulation S-K. . . .

Chesapeake 2004 Form 10-K, page 8:

Proved Reserves

The following table sets forth our estimated proved reserves and the present value (discounted at 10%) of the estimated pre-tax future net revenue of our proved reserves (based on our weighted average wellhead prices at December 31, 2004 of $39.91 per barrel of oil and $5.65 per mcf of gas). These weighted average wellhead prices were based on the cash spot prices for oil and natural gas at December 31, 2004.

	Oil (mbbl)	Gas (mmcf)	Gas Equivalent (mmcfe)	Percent of Proved Reserves		Present Value ($ in thousands)
Mid-Continent	46,726	3,157,081	3,437,439	70	%	$	7,112,733
South Texas and Texas Gulf Coast	2,162	377,163	390,136	8			1,067,889
Permian Basin	28,722	309,279	481,614	10			1,026,401
Ark-La-Tex	5,299	515,055	546,848	11			1,221,565
Other	5,051	15,411	45,714	1			75,802
Total	87,960	4,373,989	4,901,751	100	%	$	10,504,390	(a)

(a) The standardized measure of discounted future net cash flows, an after-tax measure, at December 31, 2004 was $7.6 billion. Additional information on the standardized measure of discounted future net cash flows is presented in note 11 of the notes to our consolidated financial statements included in Item 8 of this report. We also refer you to "Oil and Gas Reserves" on page 23 for additional discussion of our proved reserves and the differences between the present value of future net revenue of our proved reserves and the standardized measure of discounted future net cash flows.  

As of December 31, 2004, the volume of our proved developed reserves as a percentage of total proved reserves was 66%. Natural gas reserves accounted for 89% of the volume of total proved reserves at December 31, 2004.

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 our December 31, 2004 present value of estimated future net revenue of our proved reserves of approximately $215 million and $40 million, respectively. The estimated future net revenue used in this analysis does not include the effects of future income taxes.

SEC Comment:

Properties, page 22

Oil and Gas Reserves, page 23

We also note the disclosure of "estimated future net revenue" of $19,584,358 as of December 31, 2004. This disclosure appears to be a non-GAAP measure. Therefore, you must provide all disclosures required by Item 10(e) of Regulation S-K. Please revise your disclosures accordingly.

Chesapeake 2004 Form 10-K, pages 23-24:

Oil and Gas Reserves

The table below sets forth information as of December 31, 2004 with respect to our estimated proved reserves, the associated estimated future net revenue, and present value (discounted at 10%) of estimated future net revenue before income tax and after income tax (standardized measure) at such date. Chesapeake employed third party engineers to prepare independent reserve forecasts for approximately 75% of our proved reserves (by volume) and 76% (by value) at year-end 2004. These are not audits or reviews of internally prepared reserve reports. The company's own estimates of the proved reserves evaluated by third party engineers were within 99% of the third party estimates. Netherland, Sewell & Associates, Inc. evaluated 25%, Lee Keeling and Associates, Inc. evaluated 23%, Ryder Scott Company L.P. evaluated 12%, LaRoche Petroleum Consultants, Ltd. evaluated 7%, H. J. Gruy and Associates, Inc. evaluated 7% and Miller and Lents, Ltd. evaluated 2% of our estimated proved reserves at December 31, 2004 based on discounted future net revenues. Of the 25,264 properties included in the 2004 report, the reserve estimates prepared by the independent firms covered 8,761 properties, or 34.7% of the total well count. Because of the time, effort and cost involved in preparing reserve estimates on every oil and gas property owned by Chesapeake, the company's internal reservoir engineers evaluated many of the properties, but these represent only 24% of our proved reserves. All estimates were prepared based upon a review of production histories and other geologic, economic, ownership and engineering data we developed. The estimates are not based on any single significant assumption due to the diverse nature of the reserves and there is no significant concentration of proved reserves volume or value in any one well. Neither the pre-tax present value of estimated future net revenue nor the after-tax standardized measure is intended to represent the current market value of the estimated oil and gas reserves we own.

December 31, 2004
		Oil (mbbl)		Gas (mmcf)		Total (mmcfe)
Proved developed		62,713		2,842,141		3,218,418
Proved undeveloped		25,247		1,531,848		1,683,333
Total proved		87,960		4,373,989		4,901,751
		Proved Developed		Proved Undeveloped		Total Proved
		($ in thousands)
Estimated future net revenue (a)	$	13,323,584	$	6,260,774	$	19,584,358
Present value of future net revenue (a)	$	7,366,167	$	3,138,223	$	10,504,390
Standardized measure (a)(b)		_______		_______	$	7,645,539

(a) Estimated future net revenue represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at December 31, 2004. The prices used in the external and internal reports yield weighted average wellhead prices of $39.91 per barrel of oil and $5.65 per mcf of gas. These prices should not be interpreted as a prediction of future prices. The amounts do not give effect to non-property releated expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. Estimated future net revenue and the present value thereof differ from future net cash flows and standardized measure only because the former do not include the effects of future income tax expenses.   Management uses future net revenue, which is calculated without deducting estimated future income tax expenses, and the present value thereof as one measure of the value of the company's current proved reserves and to compare relative values among peer companies without to regard to income taxes. We also understand that securities analysts and rating agencies use this measure in similar ways. While future net revenue and present value are based on prices, costs and discount factors which are consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company.  

(b) Additional information on the standardized measure of discounted future net cash flows is presented in note 11 of the notes to our consolidated financial statements included in Item 8 of this report.  

As of December 31, 2004, our reserve estimates included 1,683.3 bcfe of reserves classified as proved undeveloped (PUD). Of this amount, approximately 68% (by volume) were initially classified as PUDs in 2004, 11% were initially classified as PUDs in 2003, 6% were initially classified as PUDs in 2002, and the remaining 15% were initially classified as PUDs prior to 2002. Of our proved developed reserves, 413 bcfe are non-producing, which are primarily "behind pipe" zones in producing wells.

The future net revenue attributable to our estimated proved undeveloped reserves of $6.3 billion at December 31, 2004, and the $3.1 billion present value thereof, has been calculated assuming that we will expend approximately $1.9 billion to develop these reserves. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, product prices and the availability of capital, but we have projected to incur $1.0 billion in 2005, $0.5 billion in 2006, $0.2 billion in 2007 and $0.2 billion in 2008 and beyond. We do not believe any of these proved undeveloped reserves are contingent upon installation of additional infrastructure and we are not subject to regulatory approval other than routine permits to drill, which we expect to obtain in the normal course of business.

No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the Securities and Exchange Commission.

Chesapeake's ownership interest used in calculating proved reserves and the associated estimated future net revenue was determined after giving effect to the assumed maximum participation by other parties to our farmout and participation agreements. The prices used in calculating the estimated future net revenue attributable to proved reserves do not reflect market prices for oil and gas production sold subsequent to December 31, 2004. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices.

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 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 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. 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. In addition, the estimated future net revenue from proved reserves and the associated present value do not include any estimates of corporate overhead, debt service costs, future income tax expense, or depreciation, depletion and amortization expense.

See Item 1 - Business and note 11 of notes to consolidated financial statements included in Item 8 of this report for a description of drilling, production and other information regarding our oil and gas properties.

SEC Comment:

We also note the disclosure of this measure [PV-10] in Note 11 on page 96. As the disclosure is not in accordance with GAAP, please remove the measure from your financial statement disclosures.

Chesapeake 2004 Form 10-K, pages 95-96:

Standardized Measure of Discounted Future Net Cash Flows (unaudited)

Statement of Financial Accounting Standards No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Chesapeake has followed these guidelines which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to the estimated quantities of oil and gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. Estimated future income taxes are computed using current statutory income tax rates including consideration for the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth our future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in SFAS 69:

	December 31,
	2004				2003			2002
($ in thousands)
Future cash inflows		$	28,245,336	(a)	$	17,807,624	(b)	$	9,640,070		(c)
Future production costs		(6,542,219		)	(3,816,607		)	(2,273,610			)
Future development costs		(2,115,511		)	(912,594		)	(606,042			)
Future income tax provisions		(5,663,575		)	(3,827,408		)	(1,867,315			)
Net future cash flows		13,924,031			9,251,015			4,893,103
Less effect of a 10% discount factor		(6,278,492		)	(3,924,262		)	(2,059,185			)
Standardized measure of discounted future net cash flows(d)		$	7,645,539		$	5,326,753		$		2,833,918

(a)	Calculated using weighted average prices of $39.91 per barrel of oil and $5.65 per mcf of gas.
(b)	Calculated using weighted average prices of $30.22 per barrel of oil and $5.68 per mcf of gas.
(c)	Calculated using weighted average prices of $30.18 per barrel of oil and $4.28 per mcf of gas.
(d)	Estimated future net cash flows before income tax expense, discounted at 10%, totaled $10,504,390, $7,333,142 and $3,717,645 as of December 31, 2004, 2003 and 2002, respectively.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

	December 31,
	2004				2003			2002
					($ in thousands)
Standardized measure, beginning of period(a)	$	5,326,753			$ 2,833,918				$1,460,973
Sales of oil and gas produced, net of production costs(b)	(1,741,438			)	(1,088,184		)	(431,116		)
Net changes in prices and production costs	(730,020)				(2,364		)	779,756
Extensions and discoveries, net of production and development costs	1,784,166				1,041,108			463,674
Changes in future development costs	33,284				74,719			32,812
Development costs incurred during the period that reduced future development costs	226,415				130,195			68,387
Revisions of previous quantity estimates	317,518				99,927			137,639
Purchase of reserves-in-place (c)	2,580,973				2,012,686			528,734
Sales of reserves-in-place (c)	(5,604)				(827		)	(535		)
Accretion of discount	733,314				371,765			164,667
Net change in income taxes	(852,462)				(1,122,661		)	(698,033		)
Changes in production rates and other	(27,360)				976,471			326,960
Standardized measure, end of period (a)	$		7,645,539		$	5,326,753		$	2,833,918

(a)	The discounted amounts related to cash flow hedges that would affect future net cash flows have not been included in any of the periods presented.
(b)	Excluding gains (losses) on derivatives.
(c)	In 2003, purchases and sales of reserves are shown net of the 9.9 bcfe which was acquired and immediately sold for $19 million.