chk05202009.htm

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 6, 2009. We have repeated below the Staff's comments and followed each comment with the company's response.

You disclose that you have borrowed your remaining credit facility capacity to ensure its full utilization, which increased your year-end cash balances. On page 38, you disclosed that you replaced this borrowing with 9.5% senior notes in February 2009 and further disclosed on page 40 that you have reduced your budget for investing activities. On this basis, disclose the reasons for the increase in your cash balance, and how the issuance of the 9.5% notes fits into your overall business plan. Describe any material effects from the change in the mix of your capital resources. Refer to Financial Reporting Codification 501.03, 501.13a, and 501.13d for guidance.

Response: The comment refers to our disclosure on page 41 of our 2008 Form 10-K that we borrowed the remaining capacity under our revolving bank credit facility at the end of the third quarter in order to ensure that the facility could be fully utilized. As a result, on December 31, 2008 and September 30, 2008, we had cash and cash equivalents on hand of approximately $1.749 billion and $1.964 billion, respectively. More typically, our cash balance would be small (e.g., $1.0 million at December 31, 2007), and we would have borrowing capacity available under our revolver. However, following the Lehman bankruptcy filing in mid-September 2008 and the rumored potential failure of other banks, we cautiously maximized our cash resources as we evaluated the financial health of our bank credit facility lenders.

We believe the first paragraph on page 41 adequately explained the background of our decision to fully draw our revolver and maintain higher than normal cash balances. We referred to the "turbulent economic times" of the 2008 fourth quarter and note the performance by 35 of our 36 revolving credit facility lenders in funding their full commitment (the exception being the Lehman affiliate). While such performance would in other times be unremarkable, the chaos in the financial industry during the fourth quarter was unprecedented. Other disclosures highlight the economic environment of late 2008 and early 2009. For example, our risk factor on page 24, The current financial crisis may have impacts on our business and financial condition that we cannot predict, specifically addressed a number of challenges resulting from turmoil in the global economic financial systems.

The comment further inquires how our issuances of 9.5% senior notes due 2015 in February 2009 fit into our overall business plan. We have regularly refinanced bank revolver borrowings with long-term debt to increase our available liquidity and extend debt maturities. The additional long-term debt from the February 2009 issuances increased our financial flexibility at a time of great uncertainty in the capital markets (public debt financing had been largely non-existent for several months) and a developing oversupply of natural gas. Having adequate liquidity was an important consideration in our decisions to reduce our 2009 natural gas and oil exploration, development and leasehold and property acquisition budget and to implement production curtailments. With adequate liquidity to maintain our operations, we are able to defer our long-term growth strategy while natural gas and oil prices are unusually low.

We refer you to Note 19. Subsequent Events of our consolidated financial statements (page 127) where we disclose that net proceeds of $1.343 billion from the February 2009 debt offerings were used to repay outstanding indebtedness under our revolving bank credit facility, and that we anticipated re-borrowing on the bank credit facility from time to time to fund drilling and leasehold acquisition initiatives and for general corporate purposes.

The company has numerous sources of liquidity available to provide additional capital. As described on page 36, in addition to capital markets transactions in 2008, we relied on a number of asset monetization transactions, such as sales of producing properties, undeveloped acreage and non-strategic assets, joint venture arrangements and volumetric production payment, or VPP, transactions. Overall, the February 2009 refinancing of approximately 11% of our total long-term debt was not a material change in our overall mix of capital resources.

Provide a discussion of the material effects that the known uncertainties of your hedging position as of December 31, 2008 may have on your future financial condition or results of operations as required by Financial Reporting Codification 501.02. Such disclosures should be based on uncertainties that are reasonably expected to have a material effect on your operating results. To the extent you cannot predict the gains or losses from your hedges due to price uncertainties, objectively evaluate the consequences due to the uncertainty on the assumption that it will come to fruition and provide disclosure unless management determines a material effect is not reasonably likely to occur.

Response: On page 45, we explained that our natural gas and oil hedging activities allow us to predict with greater certainty the effective prices we will receive for our hedged production. In other words, the purpose of our commodity hedging program is to bring certainty to a portion of our future cash flow and revenue stream. A loss or gain reported for a derivative instrument would be substantially offset by an increase or decrease, respectively, in the value of the production covered by the instrument. Our hedging program does not create new uncertainties; it reduces uncertainty for future operating results.

Accounting for hedges, on the other hand, can materially affect quarter-to-quarter financial results. Our response to comment #8 below notes that we reported unrealized hedging losses of $1.132 billion and $3.404 billion in the 2008 first and second quarters, respectively, and we reported a $4.618 billion unrealized hedging gain in the 2008 third quarter. Unrealized hedging gains and losses are directly tied to commodity prices on the day the hedges are marked to market prices. The wide swings in reported gains and losses at these three quarter ends reflect the extreme volatility of natural gas and oil prices from quarter end to quarter end in 2008.

Because future commodity prices are unknowable, we included a sensitivity analysis of the effect of price changes on our natural gas and oil revenues and cash flows, absent the effect of hedging, on page 48 of the 2008 Form 10-K (assuming 2008 production levels, a change of $0.10 per mcf of natural gas sold would result in an increase or decrease in 2008 revenues and cash flows of approximately $78 million and $75 million, respectively, and a change of $1.00 per barrel of oil sold would result in an increase or decrease in 2008 revenues and cash flows of approximately $11 million). On page 37, we stated that we had swaps and collars in place that hedged 78% of our expected remaining natural gas and oil production in 2009 at an average price of $7.71 per mcf and directed readers to the listing of our natural gas and oil hedges as of December 31, 2008 in Item 7A. We recognize that our hedging program is complicated and therefore provide readers sufficient information to model the effects of our hedges as prices and our operations change throughout a quarter.

We also cautioned on page 37 that, depending on changes in natural gas and oil futures markets and management’s view of underlying natural gas and oil supply and demand trends, we may increase or decrease our current hedging positions. Indeed, our hedging is most dynamic during periods of extreme volatility.

The Staff's comment seems to acknowledge that we cannot predict the gains or losses from our hedges due to price uncertainties, and asks us to evaluate the consequences due to the uncertainty. Generally speaking, management does not consider mark-to-market (unrealized) hedging gains and losses in its business planning but instead focuses on actual realized gains and losses. Also, our credit facility agreement excludes the effects of unrealized hedging gains and losses in the calculation of financial covenants. From an external perspective, in our experience, analysts and rating agencies largely disregard unrealized hedging gains and losses in evaluating exploration and production companies. Realized hedging gains and losses, on the other hand, represent the results of the contractual arrangements we have made with our hedge counterparties to ensure predictable revenues and cash flow. We believe our quarterly updating of hedging positions prepares readers for these results. In addition, at the top of page 53, we disclosed that, due to the volatility of natural gas and oil prices, the company's financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments.

In summary, the analysis recommended in the Staff's comment (applying the prospective information guidance of Financial Reporting Codification 501.02) does not lead us to new disclosure that we believe would help readers better understand our business and the risks we face. We do acknowledge that the accounting for hedging activities may cause confusion and it is important for us to make our explanations as meaningful as possible.

For your knock-out swaps as described in your tabular presentation, please disclose the pre-determined knockout prices that are part of the contract terms, based on the definition presented on page 59, or tell us how future cash flows can be determined based on the definition and information as presented.

Response: With respect to the natural gas and oil knockout swaps listed on pages 60 and 61, please refer to the columns labeled “Weighted Average Put Fixed Price” for the knockout price below which the counterparty will not be obligated to pay the stated fixed price of the contract. We believe our disclosure of the key terms of the knockout swaps on page 59 and the detail of these derivatives outstanding at December 31, 2008 on pages 60 and 61 provide sufficient detail to enable the user to properly understand the trades and the prices at which the knockouts will have no value to the company.

As illustrated by the various types of derivatives included in the company's portfolio, there are numerous ways to structure a trade to meet the risk management objectives of the parties involved. We believe we have disclosed the critical terms of our trades in sufficient detail to enable users of this information to adequately understand the purpose, structure, critical terms and economic limits of our trades. However, in response to the Staff’s comment, we expanded our disclosures in our March 31, 2009 Form 10-Q to include additional information concerning our “other collars” (see Part I, Item 3. Quantitative and Qualitative Disclosures About Market Risk, footnote (c) to the tabular presentation of our hedges) and will include similar disclosure in our future filings on Form 10-K and Form 10-Q.

We note your tabular disclosure presents the volume of your natural gas derivative instruments in terms of billions of btu's (bbtu). Under instructions 2.A and 2.F to paragraph 305(a), disclosures should be based on contract or notional amounts. Please clarify how the underlying price presented in your table relates to the notional amounts and volumes presented.

Response: The “notional amounts” of our hedging contracts are stated in terms of british thermal units (btus) with respect to natural gas derivatives, and barrels with respect to crude oil derivatives. Correspondingly, the “underlyings” of our contracts are denominated in terms of dollars per million btus with respect to natural gas, and dollars per barrel with respect to crude oil. In response to the Staff’s comment, we expanded our disclosures in our March 31, 2009 Form 10-Q (see Part I, Item 3. Quantitative and Qualitative Disclosures About Market Risk) to include references to “per mmbtu” and “per bbl” in our tabular disclosure in order to clarify the relationship between the notional amounts and the underlying.

Response: We have had an active hedging program for a number of years and the essential market risks do not materially change from year to year. We hedge the prices of our natural gas and oil production and the interest rates of our outstanding debt, and we have a foreign currency derivative on our 2006 euro-denominated senior notes. In Item 7A and in Note 9 of the consolidated financial statements, we provided detail on the effect of our hedging activities on the consolidated statements of operations. In the tables at the top of page 60 and the bottom of page 103, we presented the components of natural gas and oil sales for 2008, 2007 and 2006. On pages 63 and 105, we set forth the realized and unrealized gains and losses in interest expense for 2008, 2007 and 2006. On page 62, we described in tabular form the changes in fair value of natural gas and oil derivatives during each of 2008, 2007 and 2006, and our discussion of hedging under "Application of Critical Accounting Policies" in Item 7 on page 53 provided the net market value of our natural gas and oil derivatives as of December 31, 2008, 2007 and 2006. The fair values by type of derivative as of December 31, 2008 and 2007 were detailed on page 104. We believe these disclosures are responsive to the requirement of Regulation S-K Item 305(a)(3) for summarized market information for the preceding year.

6.	For your natural gas commodity price exposure, provide a discussion of your general strategy for achieving your stated objective of mitigating exposure to adverse market changes, as required by Regulation S-K Item 305(b)(2). We would expect this to address the following:

	·	the factors you consider when selecting which of the various instruments you describe will be used,
	·	why you engage in selling put and call options as opposed to buying them,
	·	how you determine the volume, underlying prices and settlement dates of these contracts, and
	·	the factors you consider when deciding to close a position or use counter-swaps.

Response: In response to the Staff’s comment, we expanded our disclosures in our March 31, 2009 Form 10-Q (see page 47 at the beginning of Part I, Item 3. Quantitative and Qualitative Disclosures About Market Risk) to include a discussion of the general strategy of our natural gas and oil hedging program. This discussion reads as follows:

Our general strategy for attempting to mitigate exposure to adverse natural gas price changes is to hedge into strengthening gas futures markets when prices allow us to generate high cash margins and when we view prices to be in the upper range of our predicted most likely future price range. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas import trends, gas storage inventory levels, industry decline rates for base production and weather trends.

We use a wide range of instruments to achieve our risk management objectives, including swaps, swaps with imbedded puts (knockouts), various collar arrangements, and options (puts or calls). All of these are more fully described below. We typically use swaps or knockouts for much of the volume of gas we are hedging. Swaps are used when the price level is acceptable, and we are not paid a sufficient premium for selling an additional put (the knockouts) that could cause the swap to become ineffective if the NYMEX future price closes below some lower threshold on the settlement date, typically the last trading date of the production month. We do use the knockouts when we are able to obtain a premium for the put that increases our swap pricing when we think the put level is more likely than not to be reached. We also sell calls, taking advantage of the volatility counterparties are willing to pay us, for some smaller portion of our predicted volumes when the absolute price level and the call premium are attractive to us, meaning that we believe it to be more likely than not that the future gas price will not exceed the call strike plus the premium we receive.

The volume of the potential hedging we may enter into is determined by reviewing the company’s estimated future production levels, which are derived from extensive examination of existing producing reserve estimates, coupled with our estimates of likely production (risked) from new drilling. These are updated at least every month and adjusted if necessary to actual results and activity levels. We do not hedge more volumes than we expect to produce, and if production estimates are lowered for future periods and hedges are already executed for some volume above the new predicted volumes, the hedges are reversed. The actual price level we decide on with a counterparty is derived from market discovery and bidding and the reference NYMEX price as reflected in current NYMEX trading. Settlement dates of these contracts follow the future NYMEX month and the posted penultimate or last trading day of that contract, which is all standardized in the industry and set by NYMEX.

If our view of future market conditions changes, and prices have fallen to levels we believe are unsustainable, we may close a position by doing a cash settlement with our counterparty, or by entering into a new swap that effectively reverses the position (a counter-swap). The factors we consider in closing a position before the settlement date are identical to those we reviewed when deciding to enter into the original hedge position.

You have referred to a discussion incorporated by reference in Part III of Form 10K. Please clarify how you have evaluated Exchange Act Rule 12b-23 when determining that it is appropriate to incorporation information required to be disclosed in the financial by reference to another Exchange Act filing. Please clarify how your current disclosure complies with the disclosure requirements of Financial Accounting Standards 57 and related pronouncements.

Response: The reference on page 95 to the discussion of the Founder Well Participation Program ("FWPP") and Mr. McClendon's employment agreement contained in our proxy statement for our 2009 annual meeting of shareholders was intended to guide readers of the financial statements to this additional related information, not to incorporate such information by reference. For this reason, we believe Exchange Act Rule 12b-23 is not applicable. To avoid confusion in future filings, we will avoid references in our consolidated financial statements to information outside the consolidated financial statements.

We also note that the disclosure requirements of FAS 57 specifically exclude compensation arrangements, which must be described in annual meeting proxy statements of registrants. The company's definitive proxy statement for the 2009 annual meeting of shareholders, filed April 30, 2009, contains extensive discussion of the FWPP and Mr. McClendon's employment agreement, along with other aspects of executive compensation. See, for example, "Compensation Discussion and Analysis – 2008 CEO Compensation." Because of the unique nature of the FWPP and its purpose to align the company's core business activities with the economic interest of its CEO, however, the company believed that the material elements of the FWPP should be disclosed in our consolidated financial statements.

Response: We note the Staff’s comment requesting a description of any unusual or infrequently occurring items recognized in each quarter of the last two fiscal years. We believe the Staff observed that the quarters ended March 31, 2008 and June 30, 2008 reflected net losses of $132 million and $1.60 billion, respectively, and that such losses were atypical with respect to the company’s performance during the other quarterly periods presented. The losses during the 2008 first and second quarters were the result of unrealized hedging losses of $1.132 billion and $3.404 billion, respectively. Although the magnitude of the unrealized hedging losses was significant, management views unrealized hedging gains and losses as neither unusual nor infrequently occurring insofar as the company is exposed to such gains and losses routinely as a result of the company's active hedging program. Although we do not believe any additional disclosure was required under these circumstances, we do recognize that additional disclosure concerning these losses would have enhanced the usefulness of this financial information and will endeavor in future filings to provide explanations of reasons for wide swings in our results of operations.

We note the disclosure of your hedging positions and the impact on your 2008 quarterly results. Please tell us the circumstances existing at the time you filed Form 10-Q for the quarter ended March 31, 2008 which allowed you to conclude that the uncertainties related to changes in the fair value of your hedging positions, as reported in your Form 10-Q for the quarter ended June 30, 2008, were not reasonably likely to occur. Refer to Financial Reporting Codification 501.02 and 501.05.

Response: The only "uncertainty" related to the changes in fair value of our natural gas and oil hedging positions during the 2008 second quarter was the prices of these commodities. In our Form 10-Q for the quarter ended March 31, 2008, we advised readers that natural gas and oil prices are volatile and that the company's results of operations and operating cash flows can be significantly impacted by changes in the prices we receive for our production (see, for example, Part I, Item 2 page 25 and Item 3 page 34). On page 32 of the 2008 first quarter Form 10-Q, we also referred to the discussion of our critical accounting policies in our Form 10-K for the year ended December 31, 2007, where we disclosed that, due to the volatility of natural gas and oil prices, the company's financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments (see page 48 of the 2007 Form 10-K). In addition, the historical results presented in the 2008 first quarter Form 10-Q showed the significant income statement effects of unrealized mark-to-market derivative losses during the 2008 first quarter.

We believe it is helpful to describe for you, as requested, the circumstances existing at the time we filed the 2008 first quarter Form 10-Q. Because over 90% of our production is natural gas, we will focus on natural gas prices. On May 12, 2008, the 2008 first quarter Form 10-Q filing date, natural gas prices were continuing to rise (NYMEX spot prices of $11.39 per mcf at May 12, 2008, $9.37 per mcf at March 31, 2008 and $6.19 per mcf at December 31, 2007). We did not believe natural gas and oil prices were sustainable at the May 12, 2008 levels. As set forth in our May 1, 2008 Outlook (included in our earnings release furnished as an exhibit to the Form 8-K we filed on May 2, 2008), we were estimating an average 2008 second quarter NYMEX price of $8.53 per mcf. As it happened, the NYMEX spot price reached $13.10 per mcf at June 30, 2008, natural gas and oil prices declined significantly in the second half of 2008, and the fair value of our hedging positions changed accordingly.

Our response to comment #2 discusses the nature of our hedging program, and our response to comment #6 explains how we make hedging decisions. Commodity prices are volatile and hedging reduces our exposure to adverse price changes and assures certainty for a substantial portion of our future revenue and cash flow. Unlike a commodity trader that may not have the underlying physical volumes to offset its derivative contracts, our hedging activities do not result in our liquidity increasing or decreasing in any material way and hedging gains and losses do not have a financially disruptive effect on the normal functioning of the company, notwithstanding the financial reporting of hedging activities required by GAAP. Although gains and losses from our derivative instruments will be substantially offset by prices realized at the time our underlying natural gas and oil reserves are produced, such reserves are required to be accounted for under GAAP using an historical cost convention rather than being marked to current market value. As a result, our financial statements under GAAP do not fully reflect the economic hedge that our derivative program provides against the price volatility experienced in our underlying natural gas and oil reserves from period to period.

10.	We note your disclosure that 35% of your current proved undeveloped reserves were booked prior to 2006. Please tell us the portion of these PUD volumes that you booked at year-end 2003 or earlier. If this portion is significant, explain the reason(s) for its continuing undeveloped status.

Response: Proved undeveloped ("PUD") reserves as of December 31, 2008 totaled 3,960 bcfe. Of this total, 315.5 bcfe of PUDs was booked at year-end 2003 or earlier, which represented 8.0% of our total PUD volume. The total proved reserve volume (all categories) as of December 31, 2008 was 12,051 bcfe. The PUD reserves booked at year-end 2003 or earlier represented 2.6% of our total proved reserves at year-end 2008. We do not view either of these percentages as significant.

While not significant, we do intend to develop these PUDs. We have the industry's most active drilling program and in 2008 drilled 3,676 gross (1,733 net) wells. By comparison, there are 761 gross (384 net) locations associated with the 315.5 bcfe of PUDs booked at or prior to year-end 2003. Our drilling program is carefully managed to consider many factors, such as leasehold expirations, rates of return, infrastructure, field development plans, etc., and drilling schedules are frequently revised. If we decide not to develop PUDs, we cease to carry them as proved reserves. Please see our response to comment #13 below.

Response: We note the Staff’s request for additional disclosure concerning any material undeveloped acreage subject to expiration in each of the next three years. The company believes that its undeveloped acreage disclosures provided on page 12 of the 2008 Form 10-K fully comply with the requirements of paragraph 5 of SEC Industry Guide 2. In particular, and relevant to the Staff's request, as of year-end 2008 we did not believe we had any material undeveloped acreage that would expire over the next three years prior to development. Our drilling schedule takes into account our lease holdings and the timing of expiring leases. With our fleet of nearly 100 rigs, we are able to accelerate drilling, if necessary, to establish production prior to a desirable lease expiring. In addition, the terms of most leases provide for renewal after expiration of the primary lease term. The primary terms of leases generally range from two years to ten years pursuant to varying option elections.

Performance revisions occurred in each of our areas of operation. The largest positive performance revisions occurred in our Barnett (875 bcfe), Fayetteville (144 bcfe) and Appalachian operating areas (183 bcfe). Areas where overall performance revisions were negative included the East Texas/Gulf Coast (-143 bcfe) and the Permian Basin (-47 bcfe). Please note that these by-area performance revisions exclude changes due to price. They are the summed total of new PUDs, new PDPs, deletions and revisions to previously booked reserves.

	Audited Revision Volume (bcfe)	% of Total Revision Volume
Netherland, Sewell & Associates, Inc.	873	70.0%
Ryder Scott Company, L.P	67	5.3
Data and Consulting Services, a Division of Schlumberger Technology Corporation	60	4.8
LaRoche Petroleum Consultants, Ltd.	25	2.0
Lee Keeling and Associates, Inc.	7	0.6
Total	1,032	82.7%

13.	Please explain to us the process you employ to ensure that PUD reserves booked prior to the current year have been estimated with current year-end capital and production costs. Tell us the portion of your 2007 PUD reserves that were debooked due to year-end 2008 economics.

Response: At year end, our Operations Engineering department personnel update PUD capital costs for each PUD location on our books. The Operations Engineering personnel consider location, depth and target intervals of the PUDs. Then, using current AFEs and actual cost data collected from bids, accounting information and other sources resultant from our drilling program (we are the most active driller in the U.S. and are therefore exposed to extensive current market data), the Operations Engineering personnel provide our Reservoir Engineering department an updated assessment of the capital required to drill and complete the PUD locations. The Reservoir Engineering department uses this updated capital cost information to run its year-end reserve estimates.

To update production costs for year-end reserve estimates, we retrieve the actual lease operating expense data from accounting records from our extensive operations for the period preceding the reserve estimation date. Each well is then evaluated based on the actual expenses incurred. For PUD reserves, costs for similar wells in the area are averaged to give a production cost estimate for economic evaluation purposes.

14.

Price related negative revisions, 298 BCFE, comprise 3% of your beginning 2008 proved reserves adjusted for 2008 production. Your 2008 year-end average gas price declined by 17% from 2007 ($5.12/MCF from $6.19/MCF) and your 2008 production expenses increased by 17% over 2007 figures ($1.05/MCFE from $.90/MCFE). These changes would appear to increase the economic limit production rate by about 40% if all other factors remain unchanged. Please provide to us technical support for representative negative revisions from year-end 2007 to year-end 2008.

Response: Though price and cost related volume changes at December 31, 2008 were 3%, changes in economic conditions negatively impacted the PV-10 value of the 2008 year-end reserves by $6.5 billion, or 32%. Changes in price and cost impact value to a much larger extent than they do reserve volumes.

As referenced in our response to comment #13, 158 bcfe of PUD reserves did not achieve proved status at year-end 2008 due to changes in current economic conditions. Proved undeveloped reserves are more sensitive than proved producing reserves to changes in price and cost. Paying out the initial capital required to develop these reserves is a higher economic hurdle than generating revenue in excess of monthly operating expenses later in the life of a producing well. The reserves for the undeveloped wells that do not meet the economic threshold are completely de-booked and removed from the reserve report.

For developed reserves, changes in economic conditions affect the end of a well’s producing life and only remove the remaining reserves between the new economic limit and the previous economic limit. In either economic limit case, this occurs at low rates and has a limited effect on the reserves.

Our reserves portfolio consists largely of tight gas reservoirs. Production from these formation types typically follows a hyperbolic decline profile, causing reserve volumes to be predominantly produced in the early years of production. Thus, changes in reserves associated with the proved developed producing properties are not directly proportional to economic limit calculations.

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) 935-9229 or me at (405) 935-9232, or you may contact our outside counsel Connie Stamets at (214) 758-1622 at Bracewell & Giuliani LLP.

Attention:		Mr. H. Roger Schwall, Assistant Director
		Mr. Chris White, Branch Chief
		Mr. Gary Newberry
		Mr. Ronald Winfrey, Petroleum Engineer

		Revision Volume
New PUDs booked on proved acreage		864
New PDP wells drilled on proved acreage		502
Reserves determined inconsistent with development plan		(181)
Revisions of previously booked proved reserves		63
Total		1,248

		Very truly yours,

		/s/ MARCUS C. ROWLAND
		Marcus C. Rowland
		Executive Vice President and Chief Financial Officer

	Filed March 2, 2009
	File No. 1-13726