 | Domenic J. Dell’Osso, Jr. Executive Vice President and Chief Financial Officer |
Chesapeake Energy Corporation
6100 North Western Avenue
Oklahoma City, Oklahoma 73118
August 31, 2012
Division of Corporation Finance
Securities and Exchange Commission
100 F Street, NE
Washington, DC 20549-7010
Attention: Mr. H. Roger Schwall, Assistant Director
| Re: | Chesapeake Energy Corporation |
| Form 10-K for Fiscal Year Ended December 31, 2011 |
| Filed February 29, 2012 |
| Form 10-Q for Fiscal Quarter Ended March 31, 2012 |
Filed May 11, 2012
Definitive Proxy Statement on Schedule 14A
Filed May 11, 2012
File No. 1-13726
Ladies and Gentlemen:
This letter sets forth the responses of Chesapeake Energy Corporation (the “Company”) to the comments of the staff (the “Staff”) of the Division of Corporation Finance of the Securities and Exchange Commission (the “Commission”) received by letter dated July 23, 2012. We have repeated below the Staff’s comments and followed each comment with the Company’s response.
Form 10-K for Fiscal Year Ended December 31, 2011
Business, page 2
Production, Sales, Prices and Expenses, page 11
| 1. | We note that your disclosure of liquids production and reserves does not distinguish between crude oil and natural gas liquids volumes and that liquids comprise 16% and 17% of your production and proved reserves, respectively. Item 1202(a)(4) of Regulation S-K requires disclosure by product type and it is the staff’s view that natural gas liquids are a separate product type from crude oil. Please expand your disclosure here and on page 154 to disclose NGL volumes separately from crude oil. See also FASB ASC 932-235-50-4(a). |
Securities and Exchange Commission
August 31, 2012
Page 2 of 30
Response: We acknowledge the Staff’s comment and have been closely monitoring the significance of our natural gas liquids (“NGL”) production and our estimated proved reserves associated with NGL. For the year ended December 31, 2011, our NGL production was 7% of total production, and at year-end 2011 estimated NGL proved reserves were 8% of our estimated total proved reserves. Based on our understanding of reporting trends in our industry and previous comments from the Staff, we believe that the appropriate time to report NGL separately from oil is when our estimated proved NGL reserves equal or exceed 10% of our estimated total proved reserves. Because the Company’s NGL proved reserves as of December 31, 2011 represented less than 10% of total proved reserves, we reported NGL together with oil in our Annual Report on Form 10-K for the year ended December 31, 2011 (the “2011 Form 10-K”). We believe our reporting of crude oil (including NGL) and natural gas in our 2011 Form 10-K complied with the requirement of Item 1204(a)(4) of Regulation S-K for separate product disclosure. Our conclusion is supported by FASB ASC Topic 932-235-50-4(a), which groups crude oil together with condensate and NGL and notes that if “significant,” the reserve quantity information shall be disclosed separately for NGL.
We estimated that NGL proved reserves, as of June 30, 2012, composed approximately 11% of the Company’s estimated total proved reserves. This was the first quarter end that estimated NGL proved reserves exceeded 10% of the Company’s estimated total proved reserves. Accordingly, we included disclosure and discussion of NGL production separate from crude oil production for the three and six months ended June 30, 2012 and 2011 in Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) beginning on page 63 of our Quarterly Report on Form 10-Q for the period ended June 30, 2012 filed on August 9, 2012 (the “Second Quarter Form 10-Q”). We will continue to separately disclose NGL production for current and comparable prior periods in future periodic report filings with the Commission and will also separately disclose estimated NGL proved reserves in future annual reports on Form 10-K.
| 2. | For year-end 2011, please tell us the oil, gas and NGL production volumes associated with the volumetric production payments that you have sold and explain to us your treatment of the associated production costs. Address whether you include these costs in Results of Operations on page 152 and apply these costs to the appropriate individual properties in the estimation of their proved reserves and standardized measure. Illustrate to us the proved reserve negative adjustment made at the corporate level to account for your nine volumetric production payments as described on page 2 of Exhibit 99.1. |
Response: The Company has engaged in sales of natural gas, oil and NGL reserves (i.e., hydrocarbons) through the use of volumetric production payment (“VPP”) transactions since 2007. Each of our VPP transactions results in the sale (and conveyance) of an overriding royalty interest (“ORRI”) in hydrocarbons to the buyer for a limited term. The ORRI is carved out of our working interest in specified leases or well-bores, and it entitles the buyer to receive scheduled production volumes of hydrocarbons if, as and when produced over a period of time from the specified leases or well-bores. Consequently, the reserves attributable to the ORRI conveyed to the VPP buyer are not included in the estimation of our proved reserves and
Securities and Exchange Commission
August 31, 2012
Page 3 of 30
standardized measure. The ORRI interest is conveyed to the buyer free of the expenses of production and we, as seller, are responsible for the operating expenses and production taxes associated with the production attributable to the ORRI. Actual costs incurred were reflected in Results of Operations on page 152, and estimates of future costs were applied to the appropriate individual properties in our estimates of proved reserves and related standardized measure of discounted future net cash flows.
In 2011, we delivered the following scheduled volumes to the respective buyers in connection with the VPPs in effect during the period:
| Natural Gas | 182,952,841 mcf |
| Oil | 1,097,287 barrels |
| NGL | 349,210 barrels |
We have illustrated the proved reserve negative adjustment made at the corporate level to account for VPPs #1 - 9 in our response to this comment provided to the Staff supplementally under separate cover dated August 30, 2012 pursuant to a confidential treatment request under the Freedom of Information Act and 17 C.F.R. § 200.83. The Company has requested the return of these materials following the completion of the Staff's review pursuant to Rule 418(b) of Regulation C.
Natural Gas and Oil Reserves, page 12
| 3. | We note the disclosure here of 12 month average bench mark prices “before price differential adjustments”, the average adjusted prices incorporating such adjustments disclosed by your third party engineers and the fact (page 15) that 23% of your total proved reserves - estimated by your in-house engineering staff - lack disclosure of appropriate average adjusted pricing. Please expand your disclosure to present the average adjusted oil, NGL and natural gas prices used to estimate your company total proved reserves. This comment also applies to the price disclosure on page 156. |
Response: We acknowledge the Staff’s comment. Average adjusted prices for the proved reserves estimated by our Reservoir Engineering Department were $89.60 per bbl of oil, $3.76 per mcf of natural gas and $42.47 per bbl of NGL. Average adjusted prices for total proved reserves were $88.50 per bbl of oil, $3.19 per mcf of natural gas and $40.38 per bbl of NGL. We will expand our disclosure in future filings with the Commission to present the average adjusted natural gas, oil and NGL prices used to estimate the Company’s total proved reserves.
| 4. | Please tell us whether you have PUD reserves that are scheduled for development more than five years after initial booking. See Rule 4-10(a)(31)(ii) of Regulation S-X. |
Response: We do not have proved undeveloped (“PUD”) reserves booked that are scheduled for development beyond five years from their initial booking date. In addition, reference is made to page 13 of our 2011 Form 10-K where we disclosed that there were no PUD reserves that had remained undeveloped for five years or more as of December 31, 2011.
Securities and Exchange Commission
August 31, 2012
Page 4 of 30
| 5. | We note your statement on page 13, “[w]e invested approximately $1.477 billion, net of drilling and completion cost carries, in 2011 to convert 1.076 tcfe of PUDs to proved developed reserves.” Please expand this to disclose the value of these cost carries. If applicable, this comment includes also the drilling and completion, acquisition and divestiture table on page 17. |
Response: On pages 8 and 9 of our 2011 Form 10-K, we provided the value of our 2011 drilling and completion cost carries by operating division. Additionally, on page 52, we provided the total value of our 2011 drilling and completion cost carries as follows:
“During 2011, we invested $6.036 billion in operated wells (using an average of 167 operated rigs) and $1.509 billion in non-operated wells (using an average of 97 non-operated rigs) for total drilling and completing costs on proved and unproved properties of $7.545 billion, net of drilling and completion carries of $2.570 billion.”
Disclosure of $2.570 billion of drilling and completion cost carries received in 2011 is also provided on page 55 (as noted in the Staff’s comment 11) and on page 159. While we believe our 2011 Form 10-K included adequate disclosure of the value of the drilling and completion cost carries we received during 2011, we will provide in future periodic reports the suggested expanded disclosure describing the value of our drilling and completion cost carries related to properties carried as proved undeveloped locations in the prior year’s reported reserves, in addition to our total drilling and completion costs net of carries.
| 6. | We note the statement on page 13, “Chesapeake's developmental drilling schedules are subject to revision and reprioritization throughout the year resulting from unknowable factors…” as well as your intention (page 3) to direct your 2012 capital expenditures to liquids recovery rather than dry gas. With reasonable detail, please explain to us whether you have materially altered your year-end 2011 PUD drilling schedule in view of low dry gas prices. |
Response: Since the adoption and approval of the Company’s year-end 2011 development plan, business conditions have continued to change. Consequently, we have altered some of our field-by-field development schedules, continuing our shift to liquids-focused drilling while reducing natural gas drilling more sharply than originally planned. In some areas, such as the Marcellus Shale, this has resulted in deferring some natural gas PUD drilling from 2012 and 2013 to 2014, 2015 and 2016. In other areas, such as the Barnett Shale and the Haynesville Shale, declining prices have caused the removal of a significant number of our dry natural gas PUDs from our estimated proved reserves as of June 30, 2012.
We monitor and update our PUD development plans quarterly to ensure they are consistent with the Company’s current business decisions and strategic direction. These efforts have helped to minimize the incremental changes to the year-end 2011 development plan that were required to reflect our redirection of capital toward liquids recovery. We disclosed material changes to our estimates of proved reserves that have occurred since December 31, 2011 in our Quarterly Report on Form 10-Q for the period ended March 31, 2012 filed on May 11, 2012 (the “First Quarter Form 10-Q”) and our Second Quarter Form 10-Q in accordance with applicable
Securities and Exchange Commission
August 31, 2012
Page 5 of 30
disclosure requirements. For example, we included the following discussion on pages 64-65 in our Second Quarter Form 10-Q:
“Proved Reserves. Chesapeake began 2012 with estimated proved reserves of 18.789 tcfe and ended the Current Period with 17.392 tcfe, a decrease of 1.397 tcfe, or 7%. The Current Period’s proved reserve movement included 679 bcfe of production, 3.695 tcfe of extensions, 462 bcfe of positive performance revisions and 4.565 tcfe of downward revisions resulting from lower natural gas prices using the average first-day-of-the-month price for the twelve months ended June 30, 2012, compared to the twelve months ended December 31, 2011. During the Current Period, we acquired 9 bcfe of estimated proved reserves and divested 319 bcfe of estimated proved reserves.
In the Current Period, we reduced our estimate of proved reserves by 4.565 tcfe due to the impact of downward natural gas price revisions. Natural gas prices used in estimating proved reserves decreased by $0.97 from $4.12 per mcf for the 12 months ended December 31, 2011 to $3.15 per mcf for the 12 months ended June 30, 2012 using 12-month average prices required by the SEC. The reserve reductions primarily involved the loss of significant proved undeveloped reserves, primarily in the Barnett Shale and the Haynesville Shale plays, for which future development is uneconomic at the natural gas prices used in the reserves estimates. As of June 30, 2012, we were not required to impair the carrying value of our natural gas and oil properties; however, based on the expected natural gas prices we will be required to use to estimate proved reserves for the second half of 2012, we anticipate an impairment resulting from downward natural gas price revisions during the second half of 2012. Any such impairment, a non-cash charge that would not impact our liquidity or our ability to comply with financial covenants under our corporate revolving bank credit facility, is subject to a number of factors which could change, including the impact of oil and natural gas asset sales and other factors. We refer you to the risk factor “Declines in the prices of natural gas and oil could result in a write-down of our asset carrying values” included in Item 1A of our 2011 Form 10-K and the discussion of the full cost method of accounting under Application of Critical Accounting Policies – Natural Gas and Oil Properties in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2011 Form 10-K.”
| 7. | Further to the comment above, please compare for us your year-end 2010 PUD drilling schedule with the historical 2011 results regarding number of wells drilled by each division. As part of your response, tell us the number of gross/net PUD wells scheduled to spud in 2011 by division as well as the number that were drilled with explanation for significant differences. |
Response: Our five-year PUD drilling schedule as of December 31, 2010 included 7,819 locations, of which 1,284 locations were scheduled to be drilled during 2011 (the “2011 Drilling Schedule”). Of that total, 511 locations were included in the Fayetteville Shale assets that we sold in March 2011 to BHP Billiton. Of the remaining 773 locations on the 2011 Drilling Schedule, we removed 484 locations from our estimated proved reserves during 2011 due to
Securities and Exchange Commission
August 31, 2012
Page 6 of 30
changing business conditions, leaving 289 locations on the original 2011 Drilling Schedule. During 2011, we drilled a total of 309 wells that were classified as PUDs as of December 31, 2010.
The table below presents the number of gross/net PUD wells scheduled to be spud in 2011, after giving effect to the changes to the drilling schedule described above, by division and by the number of wells actually drilled:
| Division | Scheduled Gross | Scheduled Net | Initiated Gross | Initiated Net |
| Eastern | 9 | 6 | 10 | 5 |
| Northern | 123 | 84 | 103 | 59 |
| Southern | 148 | 78 | 167 | 85 |
| Western | 9 | 5 | 29 | 18 |
| Total | 289 | 172 | 309 | 167 |
Acres Expiring Table, page 19
| 8. | We note that leases covering 1.08 million net undeveloped acres will expire in 2012. Please tell us the figures, if any, for PUD reserves you have booked on this expiring acreage. Address the remedies you intend to apply to this expiring acreage and the anticipated costs. |
Response: Booked PUD reserves are located on only 746 net acres (or 0.07%) of the total 1.08 million net undeveloped acres subject to leases expiring in 2012. There will not be any material reduction of our estimated total proved reserves as a result of expiring acreage in 2012. Only 17 PUDs are booked on these expiring leases and the total exposure to loss of net reserves is less than 4 bcfe.
We typically apply one of the following remedies to any potentially expiring acreage that we wish to continue to hold:
| 1. | We attempt to spud wells to hold the leases in question by production prior to their expiration; or |
| 2. | We attempt to renew expiring leases that are capable of renewal. Historically, we have been successful at renewing expiring acreage that we believe will be commercially viable for development at a later date. |
Securities and Exchange Commission
August 31, 2012
Page 7 of 30
The costs associated with the renewal of expiring leases vary based on market conditions at the time of renewal, but the costs related to any efforts undertaken to prevent the expiration of the 746 net acres expiring in 2012 will not be material.
Risk Factors, page 34
Our level of indebtedness may limit our financial flexibility, page 35
| 9. | We note that several credit rating agencies, such as Fitch Ratings, Moody’s, and Standard and Poors have downgraded your credit rating. Please revise or add a new risk factor to address the related risks. |
Response: We acknowledge the Staff’s comment; however, we believe that the risks associated with our credit ratings, which primarily relate to our indebtedness, do not require a stand-alone risk factor. We believe those risks are adequately disclosed in the referenced risk factor as follows:
“[A] lowering of the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings will increase the interest rate we pay on our corporate revolving bank credit facility.”
As disclosed on page 65 of our 2011 Form 10-K, our credit facilities do not contain provisions which would trigger an acceleration of amounts due or require us to post additional collateral in the event of a downgrade. Although the applicable interest rates under our corporate credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, the increase in rates resulting from the credit rating downgrade referenced in the Staff’s comment was not material.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 51
Steps Taken in 2011 to Implement Our Business Strategy, page 54
Joint Ventures, page 54
| 10. | Please expand your disclosure here to discuss the terms of the drilling and completion carries to be received under your joint venture agreements. Please address the factors that impact the amount and timing of receipt of these carry amounts, such as whether the drilling carry amounts are to be funded on a predetermined schedule or will be reimbursed to you, as the operator, for your partner’s share of the drilling and completion costs as they are incurred. For example, in some arrangements, such as the February 2011 joint venture with CNOOC Limited, you disclose $697 million in drilling carries will be funded to you for reimbursement of 66.7% of drilling and completion costs as they are incurred, even though CNOOC Limited’s interest in the joint venture is 33.3%. |
Securities and Exchange Commission
August 31, 2012
Page 8 of 30
Response: Under our joint venture agreements, the drilling carry obligations paid by a joint venture partner are for a specified percentage of our drilling and completion cost obligations. In addition, a joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner. For example, in our February 2011 joint venture with CNOOC in the Niobrara Shale, CNOOC agreed to pay (i) 100% of its proportionate share of drilling and completion costs for wells drilled in the Niobrara Shale, and (ii) approximately 67% of our proportionate share of drilling and completion costs for wells drilled in the Niobrara Shale until $697 million has been paid. We bill our joint venture partners for their drilling carry obligations at the same time we bill them and other joint working interest owners for their share of drilling costs as they are incurred.
Although we believe the disclosure in our 2011 Form 10-K complied with applicable requirements, we note that we enhanced our disclosure on page 39 of our Second Quarter Form 10-Q as provided below to further clarify the joint venture carry obligations and, while applicable, will continue to provide similar disclosure in future filings with the Commission (emphasis added):
“As of June 30, 2012, we had entered into seven significant joint ventures with other leading energy companies pursuant to which we sold a portion of our leasehold, producing properties and other assets located in seven different resource plays and received cash of $7.1 billion and commitments for future drilling and completion cost sharing totaling $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all leasing, drilling, completion, operations and marketing activities for the project. The carry obligations paid by a joint venture partner are for a specified percentage of our drilling and completion cost obligations. In addition, a joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner. We bill our joint venture partners for their drilling carry obligations at the same time we bill them and other joint working interest owners for their share of drilling costs as they are incurred. Our joint venture transactions have allowed us to recover much or all of our initial leasehold investments and reduce our ongoing capital costs in these plays. For accounting purposes, initial cash proceeds from these joint venture transactions were reflected as a reduction of natural gas and oil properties with no gain or loss recognized….”
| 11. | On a similar matter, we note you received approximately $2.570 billion and $1.151 billion in drilling carries during fiscal year 2011 and 2010, respectively. We note from your disclosures on pages 7 through 9, that you expect to receive approximately $842 million in drilling carries in fiscal year 2012. You state on page 55 that these drilling and completion carries are “a significant cost advantage that allows us to reduce our future finding costs.” Please expand your disclosure on page 55 to discuss how the reduced amount of drilling carries from your current joint venture agreements will impact your financial statements and the obligation to incur finding costs on these properties. |
Securities and Exchange Commission
August 31, 2012
Page 9 of 30
Response: Although we believe the disclosure in our 2011 Form 10-K complied with applicable requirements, we will provide in future filings disclosure that our net drilling and completion costs will increase once our joint venture carries have been used, assuming our drilling activities remain at the same level. See, for example, the following disclosure that appears on page 69 of our Second Quarter Form 10-Q:
“Our drilling and completion costs for 2012, 2013 and 2014 will continue to be partially offset by the use of the remaining drilling and completion carries associated with our joint venture agreements. Once the remaining carries have been used, we anticipate our net drilling and completion costs to increase.”
Volumetric Production Payment (VPP), page 56
| 12. | We note from your description of the May 2011 VPP monetization of certain of your producing assets in the Mid-Continent that this “transaction included approximately 177 bcfe of proved reserves and approximately 80 mmcfe per day of net production.” Please revise your disclosure to clarify your specific performance obligations under the VPP. In this regard, clarify whether you are legally obligated to provide the purchaser with production from the properties underlying the 177 bcfe of proved reserves over the ten year term of the VPP or alternatively, scheduled, contractually-agreed-upon production amounts per day over the ten year term from the identified reserves. For example, please tell us what obligation, if any, you have to supplement the production from the properties underlying the 177 bcfe of proved reserves, if such production falls below the 80 mmcfe per day. In addition, please clarify whether you are required to deliver a specific product (i.e., natural gas, natural gas liquids or oil) to the purchaser to meet your production obligation. |
Response: The disclosure on page 56 of our 2011 Form 10-K referenced in the Staff’s comment contains a description of the material terms of our May 2011 VPP transaction and refers to the description of all our VPPs appearing on page 160. Accordingly, we believe we have disclosed the material performance obligations for the May 2011 VPP. Also, please see our response to the Staff’s comment 32 for a more detailed discussion regarding our VPPs.
With regard to the Staff’s specific questions concerning our May 2011 VPP transaction, each month we are obligated to deliver the contractually scheduled quantities of hydrocarbons, which consisted of a total of 177 bcfe of proved reserves at the time of sale, from the VPP wellbores
Securities and Exchange Commission
August 31, 2012
Page 10 of 30
conveyed (“Subject Wells”) as, if and when produced. The monthly scheduled delivery quantities decline over the term of the VPP, as set forth in the contract (we disclosed the net production amount of the VPP wells at the time of sale, 80 mmcfe per day, to provide readers a point of reference for the transaction, not to indicate a monthly delivery amount). We have no obligation to supplement the production from the Subject Wells from any other source. If the contractually scheduled volumes exceed the actual volumes produced from the Subject Wells that are attributable to the ORRI conveyed, either the shortfall will be made up from future production from these wellbores through an adjustment mechanism or the initial term of the VPP will be extended until all scheduled volumes, if any, when produced are delivered from the Subject Wells to the buyer, if at all. Although the contractually scheduled volumes are designated between oil and natural gas, production shortfalls from the Subject Wells in one category of hydrocarbon can be made up with production from the Subject Wells of another through the monthly adjustment mechanism.
| 13. | Provide us supplementally with copies of your contracts relating to the May 2011 VPP transaction. |
Response: We have provided copies of these contracts to the Staff supplementally under separate cover dated August 30, 2012 pursuant to a confidential treatment request under the Freedom of Information Act and 17 C.F.R. § 200.83.
| 14. | Provide us supplementally with an explanation of the key terms and provisions of the May 2011 VPP transaction, and explain to us whether and how it differs from your other VPP transactions. |
Response: We have provided the response to this comment to the Staff supplementally under separate cover dated August 30, 2012 pursuant to a confidential treatment request under the Freedom of Information Act and 17 C.F.R. § 200.83.
Liquidity and Capital Resources, page 58
Liquidity Overview, page 58
| 15. | In various parts of your Management’s Discussion and Analysis, you discuss your business strategies (including increasing your liquids production and reduction of natural gas operations), your need for funds (including for capital expenditures) and sources of funds (including asset monetizations, planned asset monetization, VPPs and credit facilities). The interaction of these elements is not clear – specifically, the amounts that will be needed, the amounts that will be available for funding, and how for example asset monetizations may impact cash from operations, debt covenants, etc. Revise your disclosure to present a comprehensive summary that collectively identifies the main categories of sources and uses and their related amounts in one location in your filing. A quantitative summary in tabular format may best present a company-level overview of the various methods of funds raised and used. Please expand your disclosure under this heading to include this summary overview that prefaces your liquidity discussion. You may |
Securities and Exchange Commission
August 31, 2012
Page 11 of 30
| refer to our Interpretive Release No. 33-8350, Section III.A, which discusses tabular presentation of financial or other information to help a reader’s understanding of disclosures within Management’s Discussion and Analysis. |
Response: Although we believe the disclosure in our 2011 Form 10-K complied with applicable requirements, we acknowledge the Staff’s comment and will provide the suggested quantitative summary in tabular format describing the main categories of sources and uses of funds and their related amounts in future filings with the Commission. We note that we included the following summary, which presents our budgeted sources and uses of cash for 2012, on page 71 of our Second Quarter Form 10-Q:
Year Ending December 31, 2012 | ||
| ($ in millions) | ||
| Operating cash flow before changes in assets and liabilities(a) | $3,200 – $3,250 | |
| Drilling and completion costs | ($8,000) – ($8,500) | |
| Acquisition of unproved properties, net | ($2,000) | |
| Investment in oilfield services, midstream and other | ($2,800) – ($3,100) | |
| Subtotal of net investment | ($12,800) – ($13,600) | |
| Asset sales and other transactions | $13,000 – $14,000 | |
| Interest, dividends and cash taxes | ($1,100) – ($1,350) | |
| Total budgeted cash flow surplus | $2,300 |
| (a) | A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities. Assumes NYMEX prices on open contracts of $3.00 to $3.25 per mcf and $90.00 per bbl. |
We also included a summary of the sources and uses of our cash and cash equivalents for the six months ended June 30, 2012 and 2011 on page 72 of our Second Quarter Form 10-Q.
Contractual Obligations and Off-Balance Sheet Arrangements, page 70
| 16. | We note your statement that other than the arrangements and transactions you list on page 70, you “have no off-balance sheet arrangements or transactions that are reasonably likely to materially affect [your] liquidity or availability of or requirements for capital resources.” Please explain to us the analysis you undertook with regard to satisfying the disclosure requirements of Item 303(a)(4) of Regulation S-K. Specifically, we direct your attention to the requirement in subpart (i)(C) of this Item that you must disclose “the nature and amounts of any other obligations or liabilities (including contingent obligations or liabilities) arising from such arrangements that are or are reasonably likely to become material.” |
Response: In analyzing the disclosure requirements of Item 303(a)(4) of Regulation S-K, we considered that the Company’s off-balance sheet arrangements have future commitments associated with them that will be incurred over time in the normal course of business. We also recognized that many of these commitments cannot be accurately estimated due to numerous
Securities and Exchange Commission
August 31, 2012
Page 12 of 30
factors, including the long-term nature of the commitments as well as their dependence on future commodity prices and costs that have yet to be incurred. After determining which of our off-balance sheet arrangements can be accurately estimated, we quantified and disclosed the commitments arising from those arrangements in the table on page 71 of our 2011 Form 10-K. We also provided cross references to the notes to the consolidated financial statements containing general descriptions of our commitments, some of which we could not accurately estimate. We believe this disclosure meets the requirements of Item 303(a)(4) of Regulation S-K.
| 17. | Please explain to us your analysis as to whether you are required to file any contracts relating to these arrangements as material exhibits. |
Response: The arrangements described under “Contractual Arrangements and Off-balance Sheet Arrangements” are governed by the following categories of agreements:
| · | operating lease agreements; |
| · | VPP agreements; |
| · | oil and gas purchase agreements; |
| · | oil and gas delivery agreements; |
| · | drilling agreements; and |
| · | credit agreements and indentures. |
In considering whether to file any or all of the preceding types of agreements as material contracts, we reviewed the exhibit filing requirements in Regulation S-K Item 601(b)(10). Each of the operating lease agreements, purchase agreements, delivery agreements and drilling agreements to which we are a party was entered into in the ordinary course of business. Our business is, primarily, finding, producing and selling natural gas, oil and NGL. We further considered materiality in the context of Item 601(b)(10)(ii)(B) and (C) and found those provisions to be inapplicable. Our business is not substantially dependent upon any of our operating lease agreements, purchase agreements, delivery agreements or drilling agreements, nor do they relate to the acquisition or sale of any property, plant or equipment. In addition, none of our operating leases is of the type described in Item 601(b)(10)(ii)(D).
We also concluded that the substance of each of the VPP transactions was ordinary course business for us because each one involved the sale of hydrocarbons that we produce. No VPP represented more than 2% of the Company’s proved reserves as of the end of the most recent fiscal year before the applicable VPP transaction. We further considered materiality in the context of Item 601(b)(10)(ii)(B) and (C) and found those provisions to be inapplicable. Our business is not substantially dependent upon the VPP agreements, and the sale prices with respect to each of these agreements, which ranged from $180 million to $1.15 billion, were far less than 15% of our natural gas and oil properties as of the end of the most recent fiscal year before the applicable VPP transaction.
Securities and Exchange Commission
August 31, 2012
Page 13 of 30
For these reasons, we concluded that the agreements relating to our contractual arrangements and off-balance sheet arrangements were not “material contracts” as contemplated in Regulation S-K Item 601(b)(10), and therefore did not file them as exhibits to our 2011 Form 10-K.
With respect to debt instruments, we have filed each of the indentures to which the Company is a party, as well as the Company’s corporate credit facility agreement, pursuant to Regulation S-K Item 601(b)(4). We have not filed the agreements for the Company’s midstream credit facility or oilfield services credit facility, as neither facility is material to the Company under Regulation S-K Item 601(b)(10). We note that the midstream credit facility was repaid and terminated in June 2012 and that we plan to file the oilfield services credit facility agreement with a future amendment to the pending Registration Statement on Form S-1 of our wholly owned subsidiary Chesapeake Oilfield Services, Inc.
| 18. | We note from your disclosure that your VPP obligations give rise to an off-balance sheet obligation to pay related lease operating expenses in the future. With a view towards enhanced disclosure, please explain to us the extent to which you are able to quantify the amount of future lease operating expenses related to your VPP obligations in the next twelve months and for the term of each of the VPPs. |
Response: We acknowledge the Staff’s comment and note that we supplemented our disclosures related to our VPP commitments in MD&A on page 82 of our Second Quarter Form 10-Q (and such disclosure is also included in Note 8 of the notes to the condensed consolidated financial statements contained in our Second Quarter Form 10-Q) to include the following (emphasis added):
“As the operator of the properties from which the VPP volumes have been sold, we have the responsibility to bear the cost of producing the reserves attributable to such interests, which we include as a component of production expenses and production taxes in our consolidated statements of operations in the periods such costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining the cost center ceiling for impairment purposes and in determining our standardized measure. Pursuant to SEC guidelines, the estimates used for purposes of determining the cost center ceiling and the standardized measure are based on current costs. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet and the expenses that will apply in the future will depend on the actual production expenses and taxes in effect during the periods in which such production actually occurs, which could differ materially from our current and historical costs.”
Although we are unable to quantify the exact amount of future production expenses and production taxes that will be incurred in connection with these transactions, we included supplemental disclosure regarding the actual costs we incurred in connection with our VPP
Securities and Exchange Commission
August 31, 2012
Page 14 of 30
transactions during the three and six months ended June 30, 2012 and 2011 on pages 85 and 90 of our Second Quarter Form 10-Q. Please see our response to the Staff’s comment 22.
| 19. | Please clarify for us whether your investment obligations related to Clean Energy Fuels Corp. and Sundrop Fuels, Inc. are included within your table of contractual obligations. |
Response: Our investment commitments related to Clean Energy Fuels Corp. (“CLNE”) and Sundrop Fuels, Inc. (“Sundrop”) are not included in the table of contractual obligations on page 71 of our 2011 Form 10-K. We note, however, that following the table of contractual obligations we included a cross reference to Note 4 of the notes to the consolidated financial statements on page 126 of our 2011 Form 10-K where we stated the following:
“In July 2011, we agreed to invest $150 million in newly issued convertible promissory notes of Clean Energy Fuels Corp. (Nasdaq:CLNE), based in Seal Beach, California. The investment is being made in three equal $50 million promissory notes, the first of which was issued on July 11, 2011, with the remaining notes scheduled to be issued in June 2012 and June 2013. The notes bear interest at the annual rate of 7.5%, payable quarterly, and are convertible at our option into shares of Clean Energy’s common stock at a 22.5% conversion premium, resulting in a conversion price of $15.80 per share. See Note 12 for further discussion of this investment.
In July 2011, we agreed to invest $155 million in preferred equity securities of Sundrop Fuels, Inc., a privately held cellulosic biofuels company based in Louisville, Colorado. The first $35 million tranche of our investment was funded in July 2011 and the remaining tranches of preferred equity investment will be scheduled around certain funding and operational milestones that are expected to be reached by July 2013. See Note 12 for further discussion of this investment.”
We believe the foregoing disclosure provided investors with all material information regarding our investments in, and obligations to, CLNE and Sundrop.
We will disclose our CLNE commitments, if still outstanding, in the table of contractual obligations in our Form 10-K for the year ending December 31, 2012 and will continue to disclose such commitments in our future quarterly reports on Form 10-Q filed with the Commission in the Contingencies and Commitments note of the notes to consolidated financial statements. Because our commitments to Sundrop are contingent commitments that will only be paid if certain funding and operational milestones are met, we believe this commitment should not be included in the contractual obligations table.
Results of Operations, page 73
| 20. | Throughout your filing, you have discussed the impact of a low natural gas price environment on your business strategy. We note that as of December 31, 2011, 83% of your proved reserves were held in natural gas. In view of this price |
Securities and Exchange Commission
August 31, 2012
Page 15 of 30
| environment and the relative significance of gas to you, explain the consideration you have given to providing disclosure regarding the uncertainty surrounding future gas prices and the possibility of impairment charges under the full cost rules. For example, explain to us how you have considered providing information regarding the extent to which the cost center ceiling exceeded capitalized costs as of December 31, 2011 and subsequent balance sheet dates. See Item 303(a)(3)(ii) of Regulation S-K. |
Response: We believe we prominently disclosed our exposure to low commodity prices and the corresponding risk of impairment charges in our 2011 Form 10-K. Please see, for example, the risk factors entitled “Natural gas and oil prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business” and “Declines in the prices of natural gas and oil could result in a write-down of our asset carrying values” included in Item 1A of our 2011 Form 10-K, which highlighted our exposure to natural gas and oil prices. The latter risk factor specifically referred to the possibility of impairment charges as a result of continued low natural gas prices, as follows:
“Natural gas prices declined significantly in late 2011 and early 2012 to the lowest level in recent years and continue to trade near historic lows. Although we did not have an impairment of our natural gas and oil properties as of December 31, 2011, sustained low natural gas prices and other factors could cause us to be required to write down our natural gas and oil properties or other assets in the future and incur a non-cash charge against future earnings.”
Additionally, Note 1 of the notes to the consolidated financial statements in the 2011 Form 10-K (page 106) highlighted risks and uncertainties related to low natural gas prices, including the possibility of ceiling test write downs. With respect to our impairment test calculation as of December 31, 2011, our calculated ceiling test cushion as of December 31, 2011 was approximately $3.3 billion. As there is no requirement to disclose the exact amount of the cushion, combined with the fact that the disclosures noted above reference our exposure to low commodity prices and possible resulting impairment charges, we believe our previous disclosures were sufficient.
As natural gas prices continued to drop significantly subsequent to year-end, we included similar disclosure in Note 1 of the notes to the condensed consolidated financial statements in our First Quarter Form 10-Q and our Second Quarter Form 10-Q. The following appeared in the Second Quarter Form 10-Q, beginning on page 8 (emphasis added):
“Risks and Uncertainties
We have a material exposure to low natural gas prices, which reached 10-year lows in the Current Period. Approximately 83% and 72% of our estimated proved reserves volumes as of December 31, 2011 and June 30, 2012 were natural gas, and natural gas represented approximately 84% and 80% of our natural gas, oil and natural gas liquids (NGL) sales volumes for the full year 2011 and the Current Period, respectively. Although our derivative arrangements serve to mitigate a portion of the effect of price
Securities and Exchange Commission
August 31, 2012
Page 16 of 30
volatility on our cash flows, approximately 35% of our 2012 second half natural gas production is currently not protected by derivative instruments against downward price movement. Our use of oil derivatives to partially mitigate the price risk of our oil and NGL (collectively “liquids”) production is subject to basis risk to the extent oil and NGL prices do not remain highly correlated.
In response to low natural gas prices and, by comparison, strong oil prices, we have shifted our strategy to building a more liquids-focused portfolio, and an increasing amount of our revenue is now derived from liquids production (65% of total natural gas, oil and NGL revenue before the effects of hedging in the Current Period). Sustained low natural gas prices, and volatile natural gas, oil and NGL prices in general, however, could have a material adverse effect on our financial position, results of operations and cash flows, which could adversely impact our ability to comply with financial covenants under our corporate revolving bank credit facility and further limit our ability to fund our planned capital expenditures. In addition, sustained low natural gas, oil and NGL prices could result in a reduction in the estimated quantity of proved reserves we report and in the estimated future net cash flows expected to be generated from our proved reserves. As a result, we may be required to write down the carrying value of our natural gas and oil properties, and such amounts could be material.
In the Current Period, we reduced our estimate of proved reserves by 4.6 tcfe due to the impact of downward natural gas price revisions. Natural gas prices used in estimating proved reserves decreased by $0.97 from $4.12 per mcf for the 12 months ended December 31, 2011 to $3.15 per mcf for the 12 months ended June 30, 2012 using 12-month average prices required by the SEC. The reserve reductions primarily involved the loss of significant proved undeveloped reserves, primarily in the Barnett Shale and the Haynesville Shale plays, for which future development is uneconomic at the natural gas prices used in the reserves estimates. As of June 30, 2012, we were not required to impair the carrying value of our natural gas and oil properties; however, based on the expected natural gas prices we will be required to use to estimate proved reserves for the second half of 2012, we anticipate an impairment resulting from downward natural gas price revisions during the second half of 2012. Any such impairment, a non-cash charge that would not impact our liquidity or our ability to comply with financial covenants under our corporate revolving bank credit facility, is subject to a number of factors which could change, including the impact of oil and natural gas asset sales and other factors.”
| 21. | Provide us, as supplemental information, a summary of your ceiling test calculations as of December 31, 2011 and March 31, 2012. The summary should show capitalized costs, less accumulated amortization and related deferred income taxes, as well as the amounts calculated under Rule 4-10(c)(4)(i)(A) through Rule 4-10(c)(4)(i)(D) of Regulation S-X. |
Response: We provided the response to this comment to the Staff supplementally under separate cover dated August 30, 2012 pursuant to a confidential treatment request under the Freedom of Information Act and 17 C.F.R. § 200.83.
Securities and Exchange Commission
August 31, 2012
Page 17 of 30
| 22. | Expand your disclosure under this section to include a more detailed discussion of the impact of the VPP obligations on your results of operations for all periods presented. Your revised disclosure should address, but not necessarily be limited to, quantities produced under the VPP obligations, the costs to produce those quantities, and where those costs are reported in your consolidated statements of operations. |
Response: We acknowledge the Staff’s comment and, although we believe the disclosure in our 2011 Form 10-K complied with applicable requirements, we will enhance our disclosures about the impact of the VPPs on our results operations in future periodic reports. We note that we supplemented our disclosures related to the effect of VPP costs on our results of operations in our Second Quarter Form 10-Q, as set forth below. Also, please see our response to the Staff’s comment 2, which provides the quantities produced under our VPPs in 2011.
Page 85, Second Quarter Form 10-Q (emphasis added):
“Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $335 million in the Current Quarter and $262 million in the Prior Quarter. On a unit-of-production basis, production expenses were $0.97 per mcfe in the Current Quarter compared to $0.94 per mcfe in the Prior Quarter. The per unit expense increase in the Current Quarter was primarily the result of an overall increase in field rates and the lifting costs associated with VPP production for VPP #10 and #9 completed in March 2012 and May 2011, respectively. Production expenses in the Current Quarter and Prior Quarter included approximately $58 million and $56 million, or $0.17 and $0.20 per mcfe, respectively, associated with VPP production volumes.
Production Taxes. Production taxes were $41 million in the Current Quarter compared to $46 million in the Prior Quarter. On a unit-of-production basis, production taxes were $0.12 per mcfe in the Current Quarter compared to $0.17 per mcfe in the Prior Quarter. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when natural gas and oil prices are higher. The $5 million decrease in production taxes in the Current Quarter was primarily due to a decrease in the average realized sales price of natural gas and liquids of $1.40 per mcfe (excluding gains or losses on derivatives), which was offset by an increase in production of 69 bcfe. Production taxes in the Current Quarter and Prior Quarter included approximately $5 million and $8 million, or $0.01 and $0.03 per mcfe, respectively, associated with VPP production volumes.”
Page 90, Second Quarter Form 10-Q (emphasis added):
“Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $685 million in the Current Period and $500 million in the Prior Period. On a unit-of-production basis, production expenses were $1.01 per mcfe in the Current Period compared to $0.90 per mcfe in the Prior Period. The per unit expense increase in the Current Period was primarily the result of a new fee retroactively imposed in Pennsylvania on spud wells, which had a $17 million, or $0.02 per mcfe effect, an overall
Securities and Exchange Commission
August 31, 2012
Page 18 of 30
increase in field rates and the lifting costs associated with VPP production for VPP #10 and #9 completed in March 2012 and May 2011, respectively. Production expenses in the Current Period and Prior Period included approximately $117 million and $110 million, or $0.17 and $0.20 per mcfe, respectively, associated with VPP production volumes.
Production Taxes. Production taxes were $89 million in the Current Period compared to $91 million in the Prior Period. On a unit-of-production basis, production taxes were $0.13 per mcfe in the Current Period compared to $0.16 per mcfe in the Prior Period. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when natural gas and oil prices are higher. The $2 million decrease in production taxes in the Current Period was primarily due to a decrease in the average realized sales price of natural gas and liquids of $1.00 per mcfe (excluding gains or losses on derivatives), which was offset by an increase in production of 122 bcfe. Production taxes in the Current Period and Prior Period included approximately $11 million and $15 million, or $0.02 and $0.03 per mcfe, respectively, associated with Current Period and Prior Period VPP production volumes.”
Consolidated Financial Statements, page 95
Notes to Consolidated Financial Statements, page 105
Note 1. Basis of Presentation and Summary of Significant Accounting Policies, page 105
Natural Gas and Oil Properties, page 107
| 23. | With regard to the ceiling test you perform on a quarterly basis, please clarify your disclosure to indicate whether you include the future production expenses attributable to your VPPs when calculating the part of the cost center ceiling referenced in Rule 4-10(c)(4)(i)(A) of Regulation S-X. |
Response: We confirm that we consider the future production expenses associated with our VPPs in calculating our quarterly ceiling test. Reference is made to our response to the Staff’s comment 18 where we reproduced disclosure to this effect appearing in Note 8 of the notes to the condensed consolidated financial statements in our Second Quarter Form 10-Q on page 40. We will continue to provide similar disclosure in our future periodic reports filed with the Commission.
Note 4. Contingencies and Commitments, page 121
Commitments, page 123
Natural Gas and Oil Purchase Obligations, page 125
| 24. | We note your statement that you “have also committed to purchase any natural gas and oil associated with certain volumetric production payment transactions.” Please provide us with additional information concerning these arrangements, including quantitative information about the size of these commitments. |
Securities and Exchange Commission
August 31, 2012
Page 19 of 30
| Please provide us with additional information concerning these arrangements, including quantitative information about the size of these commitments. |
Response: Because it is often impracticable for royalty interest, non-operating working interest and ORRI owners in oil and natural gas properties to independently market their share of hydrocarbons, and because the number of these interest owners in a given well can be numerous, it is common practice in the oil and natural gas industry for these interest owners to contract with the operating interest owner to market their share of the hydrocarbons. Consequently, our VPP agreements include provisions for an affiliate of the Company to purchase from ORRI owners any hydrocarbons attributable to their interests in produced quantities based on market prices at the time of production, and the Company affiliate subsequently resells the purchased natural gas and liquids at market prices. As described in greater detail in our response to the Staff’s comment 33, due to the nature of the ORRI conveyed, each VPP buyer’s right to receive the scheduled quantities, and our commitment to purchase those quantities from the VPP buyer, is conditioned upon the sufficiency of the hydrocarbons produced from the subject leases or wellbores.
Note 6. Related Party Transactions, page 130
| 25. | In light of the recent articles published regarding the existence of significant personal loans obtained by your CEO, Aubrey K. McClendon, to meet his obligations under the Founder Well Participation Program (“FWPP”), please address the following: |
| · | Disclose the risks and/or financial impact to you in the event Mr. McClendon is unable to meet his funding obligations under the FWPP. In addition, address what recourse, if any, you have with regard to the working interests owned by Mr. McClendon under this program in the event of such non-performance. Alternatively, tell us why such disclosure is not required. |
| · | In this regard, we note that Mr. McClendon has obtained personal loans from lenders that have direct business relationships with you to meet his funding obligations under the FWPP. If material, disclose any risks and/or potential financial impact to you in the event Mr. McClendon were to default on the personal loans related to his involvement in the FWPP. |
Response: As explained in Note 6 to the notes to the consolidated financial statements in our 2011 Form 10-K, under the FWPP, Mr. McClendon has the right to participate in either all or none of the wells spudded by or on behalf of the Company during each calendar year. Prior to the beginning of each year, Mr. McClendon must provide written notice to the members of the Compensation Committee of his election to participate in the FWPP and his proposed working interest percentage for that year. His working interest percentage may not exceed a 2.5% working interest in a well and is not effective for any well where the Company’s working interest after Mr. McClendon’s participation election would be reduced to below 12.5%. Subject to these limitations, if Mr. McClendon elects to participate in the FWPP, he must participate in all wells
Securities and Exchange Commission
August 31, 2012
Page 20 of 30
spudded by or on behalf of the Company during the given calendar year and cannot elect to participate on a well-by-well basis. Mr. McClendon pays the Company for lease operating expenses and capital expenditures related to his FWPP interests promptly upon receipt of each invoice. As noted in the Staff's comment, Mr. McClendon has mortgaged his interests acquired under the FWPP to fund well costs under the FWPP.
The financial risk to the Company of non-payment by Mr. McClendon, or any other non-operating working interest owner, is insignificant to the Company (although not to Mr. McClendon) due to the legal and structural protections that have developed in the oil and gas industry. At a minimum, Mr. McClendon’s interest is no different than the interest of other working interest owners even before consideration of the additional protections put in place under the FWPP. In addition, the FWPP provides additional protection to the Company to avoid loss from any non-performance by Mr. McClendon. The principal protections under the FWPP are summarized below:
| · | The FWPP, the Model Form Joint Operating Agreement (the “JOA”) for each well under the FWPP and applicable law require Mr. McClendon and the applicable Founder Affiliates (as defined in the FWPP) to pay the Company for the costs of acquiring, drilling and operating the wells developed under the FWPP. Mr. McClendon’s obligation to pay his proportionate share of drilling and operating costs of the wells in which he acquires an interest is identical to the obligations of other non-operating working interest owners in the Company’s wells. |
| · | Mr. McClendon is required to pay all joint interest billings on receipt, which provides additional protection to the Company by eliminating the period that normally exists between when a joint interest billing is sent and payment is made. So unlike other participants in the Company’s wells, any non-payment will be apparent immediately and any necessary action can be taken without delay. In addition, the Company disburses Mr. McClendon’s revenue on Company operated wells so the Company has a right of set off against the revenue to satisfy any obligations under the FWPP. Because revenue is distributed by the Company to working interest owners several months after joint interest bill payments are due from working interests owners, including for all the wells drilled under the FWPP over time, that revenue serves as significant collateral to the Company for Mr. McClendon’s obligations. |
| · | In most, if not all, jurisdictions the Company has the right to enforce against Mr. McClendon’s working interests, liens under statutes similar to or identical to mechanics and materialmens liens. To provide additional protection and standard remedies to the Company, the JOA for each well drilled under the FWPP grants the Company, as operator, a lien and mortgage on Mr. McClendon’s working interest in such well to secure the performance of his obligations. The assignments to Mr. McClendon specifically reference and are made subject to this JOA, and a Ratification and Memorandum of Joint Operating Agreement filed of record after the assignment of the base leasehold perfects the lien. In addition, the preparation of the FWPP assignment typically occurs after all drilling and completion costs for a well have been incurred and paid by Mr. McClendon, thereby |
Securities and Exchange Commission
August 31, 2012
Page 21 of 30
| eliminating the risk that a mortgage could prejudice the Company’s ability to enforce Mr. McClendon’s obligations. As a result, the Company's liens have priority over the mortgages granted to secure other indebtedness of Mr. McClendon or any Founder Affiliate. |
If Mr. McClendon were to default on any of his personal loans, the lenders would have no recourse against the Company. The lender’s rights are limited to foreclosing their liens on the working interests owned by Mr. McClendon (subject to any prior or senior claims, including those of the Company as operator in the case of non-performance) or pursuing Mr. McClendon for payment of the obligations. The mechanisms discussed above protect the Company’s interests such that when a working interest owner defaults on a personal loan, the Company will be paid any outstanding obligations owed by the working interest owner (provided funds are available) before the lender can recover its secured interests. Accordingly, we do not believe that a default by Mr. McClendon on his personal loans would increase or exacerbate any material risk or cost for the Company.
Given the strong protections that exist to prevent any loss to the Company, we believe additional disclosure is not required.
Note 10. Supplemental Disclosures About Natural Gas and Oil Producing Activities (Unaudited), page 150
Costs Incurred in Natural Gas and Oil Drilling and Completion, Acquisitions and Divestitures, page 151
| 26. | Please clarify for us whether the amounts you report for development and exploration costs are net of funds received from your joint venture drilling carries. In this regard, we note your disclosure on page 159 that “During 2011, 2010 and 2009, our drilling and completion costs included the benefit of approximately $2.570 billion, $1.151 billion and $1.153 billion, respectively, in drilling and completion carries paid by our joint venture partners, CNOOC, TOT, STO, BP and PXP.” If applicable, please disclose the amounts by which reported development and exploration costs have been reduced. |
Response: The drilling and completion costs reported within the table appearing on page 151 of our 2011 Form 10-K are net of the benefit of approximately $2.570 billion, $1.151 billion and $1.153 billion in drilling and completion carries paid on our behalf by our joint venture partners for the years 2011, 2010 and 2009, respectively. In our future periodic reports filed with the Commission, we will include supplemental footnote disclosure to the Costs Incurred Table to quantify and clarify that amounts reported are net of joint venture drilling carries.
| 27. | We note your disclosure under this heading includes separate line items for “Asset retirement obligation and other” and “Proceeds from divestitures.” Please revise your presentation to reflect the disclosure specifically required by FASB ASC 932-235-50-18 and reflected in Example 3 in 932-235-55-4. |
Securities and Exchange Commission
August 31, 2012
Page 22 of 30
Response: We acknowledge the Staff’s comment and will revise future filings with the Commission to reflect the disclosure specifically required by FASB ASC 932-235-50-18 and reflected in Example 3 in 932-235-55-4.
Results of Operations from Natural Gas and Oil Producing Activities, page 152
| 28. | Please clarify whether the costs to produce quantities sold under your VPP arrangements have been included in this table for all periods presented. |
Response: We confirm that the costs to produce the quantities sold under our VPP transactions are included in our reported Results of Operations from Natural Gas and Oil Producing Activities for all periods presented.
Natural Gas and Oil Reserve Quantities, page 152
| 29. | Please expand your table on page 154 to include the net quantities of your proved undeveloped reserves as of the beginning and the end of the year as required by FASB ASC 932-235-50-4 and Example 1 in 932-235-55-2. |
Response: The table presented on page 154 discloses total proved reserves and total proved developed reserves. Proved undeveloped reserves can be determined by calculating the difference between proved reserves and proved developed reserves. Accordingly, the information required by FASB ASC 932-235-50-4 is available to investors within the table. We will expand the table appearing on page 154 of the 2011 Form 10-K as requested in future annual reports on Form 10-K filed with the Commission.
| 30. | Please provide us with the amalgamated petroleum engineering report – incorporating your in-house and four third party reports - you used as the basis for your December 31, 2011 proved reserves disclosures. You may furnish these materials on digital media such as flash drive or compact disk. |
The report should include:
a) One-line recaps in spread sheet format for each property sorted by field within each proved reserve category including the development costs, dates of first booking and estimated first production for your proved undeveloped properties;
b) Total company summary income forecast schedules for total proved, proved developed producing, proved developed non-producing and proved undeveloped reserves;
c) Summary income forecasts for each proved reserve category in each of the Barnett, Haynesville and Marcellus areas;
d) Engineering/geological exhibits (e.g. maps, rate/time plots, volumetric calculations, analogy well performance) for each of the three shale plays
Securities and Exchange Commission
August 31, 2012
Page 23 of 30
in line item c) above that support your PUD reserve attribution beyond one offset from productive wells as described on page 14. Please ensure that the decline parameters, EURs and cumulative production figures are presented on all rate/time plots.
If you would like to have these supplemental materials returned to you, please comply with the provisions of Rule 418(b) of Regulation C, which provides for the return supplemental information subject to certain conditions.
If you wish to request confidential treatment of those materials while they are in our possession, please follow the procedures set forth in Rule 83 of the Freedom of Information Act.
Please direct these engineering items to:
U.S. Securities and Exchange Commission
100 F Street NE
Washington, DC 20549-4628
Attn: Ronald M. Winfrey
Response: We have provided the referenced report to the Staff supplementally under separate cover dated August 30, 2012 pursuant to a confidential treatment request under the Freedom of Information Act and 17 C.F.R. § 200.83. The Company has requested the return of these materials following the completion of the Staff’s review pursuant to Rule 418(b) of Regulation C.
Standardized Measure of Discounted Future Net Cash Flows, page 155
| 31. | Please add footnote disclosure that clarifies whether your standardized measure of discounted future net cash flows includes any future cash inflows or outflows attributable to your VPP obligations. |
Response: We confirm that the standardized measure of discounted future net cash flows does not include estimated future cash inflows attributable to future production of VPP volumes sold and does include estimated future cash outflows attributable to the costs of future production of VPP volumes sold. Reference is made to our response to the Staff’s comment 18 where we reproduced disclosure to this effect appearing in Note 8 of the notes to the condensed consolidated financial statements of our Second Quarter Form 10-Q on page 40. We will add footnote disclosure to the standardized measure table in our future annual reports on Form 10-K filed with the Commission to clarify the treatment of future cash inflows and outflows attributable to VPPs.
Securities and Exchange Commission
August 31, 2012
Page 24 of 30
Note 11. Acquisitions and Divestitures, page 157
Volumetric Production Payments, page 160
| 32. | Please disclose, in reasonable detail, the key terms of each VPP that you have entered into since 2007. For each VPP, this disclosure should clarify: |
| · | Quantity of proved reserves by product type; |
| · | The specific performance obligations as they relate to what the purchaser is entitled to receive in scheduled production volumes, including whether the purchaser is entitled to receive a minimum quantity of production volume over the specified term; |
| · | Whether the VPPs are structured in the manner outlined by the definition provided in items (i) through (v) on page 160 or whether there are fundamental differences that should be described; |
| · | The estimated production and development costs to meet your VPP obligations over the related terms; |
| · | Whether you may cease production on any of the properties subject to a VPP if you determine that production would not be economical and the ramifications, if applicable, of such a decision; and, |
| · | Whether your strategy to reduce your exposure to natural gas, as compared to liquids, will impact your ability to fulfill your VPP obligations. |
Response: We believe we have disclosed in reasonable detail the key terms for each of our VPPs in our prior filings with the Commission. Each of our 10 VPP transactions is structured in the manner outlined on page 160 of our 2011 Form 10-K as follows:
“From time to time, we have sold certain of our producing assets which are located in more mature producing regions through the sale of volumetric production payments (VPPs). A VPP is a limited-term overriding royalty interest in natural gas and oil reserves that (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser's only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain the remaining reserves, if any, after the scheduled production volumes have been delivered. We retain drilling rights on the properties below currently producing intervals and outside of producing well bores. We also retain all production beyond the specified volumes sold in the transaction.”
Securities and Exchange Commission
August 31, 2012
Page 25 of 30
In addition, the foregoing description is followed by a table that quantifies proved reserves sold, among other key terms for each VPP. In this presentation, we believe we have disclosed the material terms of our VPPs, including the fact that in each case the VPP entitles the purchaser to receive scheduled hydrocarbons from specific lease or wellbore interests (as defined in each transaction’s conveyance agreement), and that the conveyances are otherwise non-recourse to the Company as the seller. The production payments are non-operating, non-expense-bearing interests of limited duration in specified lease interests or well-bores (as applicable), and convey to the buyer ownership of the hydrocarbons as, if and when they are produced.
Although our VPP transactions were separately negotiated and contain certain terms and provisions that differ from one another, we believe that we have described the fundamental differences between our VPPs in our filings with the Commission. We note that, as described in detail in response to the Staff’s comment 18, we supplemented our disclosures related to our VPP commitments throughout our Second Quarter Form 10-Q and will continue to provide similar disclosure in our future filings with the Commission. We have also provided the Staff with a summary of terms and provisions of our VPP transactions supplementally pursuant to a confidential treatment request under the Freedom of Information Act and 17 C.F.R. § 200.83, which includes quantity of proved reserves sold by type.
Our strategy to reduce our exposure to natural gas, as compared to liquids, will not impact our ability to fulfill our VPP commitments, primarily because our VPP commitments are met with production from existing wells and any capital expenditures shifted away from natural gas development toward liquids development will not impact existing wells.
With regard to uneconomic production, under each of our VPPs we are contractually required to act as a reasonably prudent oil and gas operator would act under the same or similar circumstances as if it were acting with respect to its own properties, disregarding the existence of the VPP burdening such properties. As such, we may abandon and cease production from any of the relevant wells if we determine it is no longer capable of producing hydrocarbons in paying quantities and it would not be economical to secure, restore or otherwise obtain the production of hydrocarbons (without regard to the VPP burden) from such well.
Volumetric Production Payments, page 160
| 33. | Please expand this disclosure to fulfill the requirements of Item 1207 of Regulation S-K. |
Response: The Company does not have a fixed and determinable obligation to deliver the scheduled quantities to the VPP buyers in the near future under an existing contract or agreement; therefore, Item 1207 of Regulation S-K is not applicable. The ORRIs held by VPP buyers are similar to the ownership interests held by the Company in that they are real property interests, which entitle the holder to the underlying hydrocarbons as, if and when produced. Each VPP buyer’s right to the scheduled quantities is conditioned upon the sufficiency of the hydrocarbons produced from the burdened leases or wellbores.
Securities and Exchange Commission
August 31, 2012
Page 26 of 30
As disclosed in Note 4 of the notes to the consolidated financial statements in our 2011 Form 10-K on page 125, we have committed to market the produced quantities attributable to the ORRIs held by VPP buyers on their behalf, at market prices as such quantities are produced.
Exhibit 99.1
| 34. | We note the statement on page 2 of the third party report, “As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and $220 per well per month, which is Chesapeake's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties; these overhead expenses are not included in the determination of the economic limits for the properties.” Pursuant to FASB ASC 932-235-50-26, “… some expenses incurred at an entity's central administrative office may not be general corporate expenses, but rather may be operating expenses of oil- and gas-producing activities, and therefore shall be reported as such. The nature of an expense rather than the location of its incurrence shall determine whether it is an operating expense.” Please explain to us the justification for excluding the operated property production overhead from determination of the economic production. Tell us whether you followed this procedure for all your operated properties. With reasonable detail, illustrate the effect of including the $220/well overhead charge in the economic producing limit for all operated properties’ proved reserve estimate. |
Response: We acknowledge the Staff’s comment. The expenses associated with the portion of our headquarters general and administrative overhead expenses necessary to operate our properties were not included in the determination of the economic limits for our properties; however, if such expenses were included, they would not have had a material impact on the economic producing limit for our estimated total proved reserves. The effect of including the $220/well overhead expense would have been a 243 bcfe, or 1.4%, reduction in our estimated total proved reserves as of December 31, 2011. We will include overhead expenses in the determination of the economic limits for all properties in our future filings with the Commission.
Exhibit 99.3
| 35. | Please file a third party reserve report that presents the average adjusted product prices used in determining total proved reserves. |
Response: We have provided a copy of this comment to, and discussed it with, our principal contact at Lee Keeling and Associates, Inc. (“Keeling”). We will ensure that any reserve report prepared by Keeling and included with our future filings with the Commission will present the average adjusted product prices used in determining total proved reserves substantially in the form as provided below:
Securities and Exchange Commission
August 31, 2012
Page 27 of 30
Oil Income
Income from the sale of oil was estimated using a reference price of $95.973 per barrel based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2011, which was then adjusted for state severance and ad valorem taxes and for the historical difference between the actual field price received and the reference price. These prices were provided by the staff of Chesapeake. The average adjusted price, $87.012 per barrel, was held constant throughout the economic life determined for each well.
Gas Income
Income from the sale of gas was also estimated using a reference price of $4.118 per million cubic feet based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2011, which was then adjusted for state severance and ad valorem taxes and for the historical difference between the actual field price received and the reference price. These prices were provided by the staff of Chesapeake. The average adjusted price, $2.862 per million cubic feet, was held constant throughout the economic life determined for each well.
NGL Income
Income from the sale of natural gas liquids (NGL) was estimated using the oil reference price noted above as adjusted for any state severance and ad valorem taxes and the historical difference between actual field price received and the reference price. These prices were provided by the staff of Chesapeake. The average adjusted price of $32.793 per barrel, which represents approximately thirty-four percent (34%) of the oil reference price noted above, was held constant throughout the economic life determined for each well.
Form 10-Q for Fiscal Quarter Ended March 31, 2012
General
| 36. | To the extent applicable to the disclosure in your Form 10-Q, please address the comments above concerning your Form 10-K. |
Response: We acknowledge the Staff’s comment and will address the comments above to the extent they are applicable to our next Form 10-Q filing. As discussed above, we note that we have addressed the Staff’s comments 1, 6, 10, 11, 15, 18, 20, 22, 23, 31 and 32 in our Second Quarter Form 10-Q.
Securities and Exchange Commission
August 31, 2012
Page 28 of 30
Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 52
Liquidity and Capital Resources, page 57
Contractual Obligations and Off-Balance Sheet Arrangements, page 66
| 37. | Provide us supplementally with copies of your contracts relating to the March 2012 VPP transaction. |
Response: We have provided copies of these contracts to the Staff supplementally under separate cover dated August 30, 2012 pursuant to a confidential treatment request under the Freedom of Information Act and 17 C.F.R. § 200.83.
| 38. | Provide us supplementally with an explanation of the key terms and provisions of the March 2012 VPP transaction, and explain to us whether and how it differs from your other VPP transactions. |
Response: We have provided the response to this comment to the Staff supplementally under separate cover dated August 30, 2012 pursuant to a confidential treatment request under the Freedom of Information Act and 17 C.F.R. § 200.83.
Results of Operations – Three Months Ended March 31, 2012 vs. March 31, 2011, page 66
Production Expenses, page 68
| 39. | We note your disclosure that your per unit expense increase was primarily the result of several factors including “the effect of VPP transactions in which [you] are still burdened by production expenses.” Please quantify the increase that was attributable to each factor. |
Response: Reference is made to our responses to the Staff’s comments in 18 and 22. We supplemented our disclosures related to our VPP commitments in our Second Quarter Form 10-Q on page 40 to include a more thorough discussion of the impact of our VPP commitments in Note 8 of the notes to the condensed consolidated financial statements, and on pages 85 and 90 to discuss the impact of our VPPs on our results of operations in MD&A. We will continue to provide similar disclosure in our future periodic reports filed with the Commission.
Risk Factors, page 81
| 40. | Your filing discloses recent developments that may have a material impact on your operating results or financial condition. For example, we note your disclosure with respect to the proposed initial public offering of Chesapeake Oilfield Services, Inc. on page 57. We also note recent press reports of undisclosed liabilities associated with your volumetric production payments. Please add new risk factors related to any material changes from those in your Form 10-K. Refer to Item 1A of Form 10-Q. |
Securities and Exchange Commission
August 31, 2012
Page 29 of 30
Response: As part of the preparation of each Form 10-Q, we review our existing risk factors included in our most recent Form 10-K to determine whether any new risk factors reflecting material changes to disclosures in our most recent Form 10-K are required. We determined that no new risk factors were required to be included in Part II, Item 1A of our First Quarter Form 10-Q or our Second Quarter Form 10-Q. We will continue to review our risk factors as we draft future Form 10-Q filings with the Commission, and will include new risk factors or amend existing risk factors in such filings to the extent necessary to address any material changes to our disclosures.
Definitive Proxy Statement on Schedule 14A filed May 11, 2012
Transactions with Related Persons, page 14
| 41. | We note recent media reports concerning a special unit of the company called “AKM Operations” that allegedly provides approximately $3 million of services to Mr. McClendon each year. We note your disclosure on pages 15, 27 and 32 concerning certain accounting and engineering support services provided to Mr. McClendon. Please quantify the aggregate amount of services that you provided to Mr. McClendon as well as the amount that was reimbursed to you by Mr. McClendon. Refer to Item 404 of Regulation S-K. |
Response: In 2011, the Company provided Mr. McClendon with accounting and engineering services pursuant to his employment agreement in an aggregate amount of $3,482,199.00. Mr. McClendon reimbursed the Company on a monthly basis throughout 2011, which resulted in his aggregate reimbursement to the Company of $3,232,199.00. In accordance with Instruction 5 of Item 404 of Regulation S-K, disclosure of these transactions was reported pursuant to Item 402 of Regulation S-K in the All Other Compensation Table on page 32 of our proxy statement for the 2012 Annual Meeting of Shareholders, which is reproduced in relevant part below.
| Name | Year | Other Perquisites and Benefits(c) | Total |
| Aubrey K. McClendon | 2011 | $375,770 | $1,314,520 |
| 2010 | 375,702 | 1,314,452 | |
| 2009 | 691,361 | 1,576,096 |
(c) This column represents the value of other benefits provided to the named executive officers. Included are amounts for supplemental life insurance premiums for all named executive officers and, other than Mr. McClendon, amounts for financial advisory services and monthly country club dues (reimbursement for such dues by the Company was eliminated beginning in 2012). The amounts reported in this column for Mr. McClendon in 2011 include (i) $250,000 for the costs related to personal accounting support provided to Mr. McClendon by our employees, net of reimbursement, and (ii) $121,570 for personal security provided to Mr. McClendon. Personal accounting support costs for Mr. McClendon include the following with respect to personnel providing such support: (i) cash compensation; (ii) equity compensation; (iii) Company matching contributions under the 401(k) Plan and deferred compensation plan; (iv) Company-
Securities and Exchange Commission
August 31, 2012
Page 30 of 30
paid life insurance premiums; and (v) overhead (utilities, office equipment, health and welfare benefit plans, etc.). The named executive officers also receive benefits for which there is no incremental cost to the Company, such as tickets to certain sporting events.
* * * * *
Should any member of the Staff have a question regarding our responses to the comments set forth above, or need additional information, please do not hesitate to call Mike Johnson, our Chief Accounting Officer, at (405) 935-9229 or me at (405) 935-6125, or you may contact our outside counsel Connie Stamets at (214) 758-1622 at Bracewell & Giuliani LLP. For any future written correspondence sent by email, please use the following addresses: nick.dellosso@chk.com, mike.johnson@chk.com and connie.stamets@bgllp.com.
As you requested in the comment letter, we acknowledge that:
| · | the Company is responsible for the adequacy and accuracy of the disclosure in the filing; |
| · | Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and |
| · | the Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. |
| Very truly yours, | |||
| /s/ Domenic J. Dell’Osso, Jr. | |||
| Domenic J. Dell’Osso, Jr. | |||
| Executive Vice President and Chief Financial Officer | |||