June 18, 2012
Andrew D. Mew
Accounting Branch Chief
Office of the Chief Accountant
United States Securities and Exchange Commission
100 F Street, N. E.
Washington, D.C. 20549
Re: | Atlas Energy, L.P. |
Form 10-K for the Fiscal Year Ended December 31, 2011
Filed February 28, 2012
Form 10-Q for the Quarterly Period Ended March 31, 2012
Filed May 9, 2012
File No. 1-32953
Atlas Pipeline Partners, L.P.
Form 10-K for the Fiscal Year Ended December 31, 2011
Filed February 24, 2012
Form 10-Q for the Quarterly Period Ended March 31, 2012
Filed May 7, 2012
File No. 1-14998
Dear Mr. Mew:
On behalf of Atlas Energy, L.P. and Atlas Pipeline Partners, L.P., this letter responds to the Staff’s letter of comment, dated June 6, 2012, with respect to the above-referenced filings. For your convenience, we first restate your comments in bold and then provide a response on behalf of both companies.
General
1. | Our review encompassed Atlas Energy, L.P. and Atlas Pipeline Partners, L.P. In the interests of reducing the number of comments, we have not addressed each registrant with a separate comment. Page references related to the Form 10-K of Atlas Energy, L.P. To the extent a comment is applicable to more than one registrant, please address the issue separately. |
Response: The Staff comment is acknowledged.
Letter to Andrew D. Mew
June 18, 2012
Loss on Mark-to-Market Derivatives, page 60
2. | We note from your disclosure in notes 10 and 11 that the estimated fair value of a significant amount of derivatives maturing in fiscal 2012 was based on the use of unobservable inputs. Please disclose within MD&A the manner in which the fair value of such inputs were determined, and how the resulting calculated fair values have affected, or might affect in the future, your results of operations, liquidity, and capital resources. |
Response: Atlas Energy, L.P. proposes to revise the disclosure within MD&A in its future filings under “Results of Operations” as follows:
“Loss on Mark-to-Market Derivatives
Loss on mark-to-market derivatives principally reflects the change in fair value of APL’s commodity derivatives that will settle in future periods, as APL does not apply hedge accounting to its derivatives. While APL utilizes either quoted market prices or observable market data to calculate the fair value of its natural gas and crude oil derivatives, valuations of APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar geographic locations, and valuations of its NGL options are based on forward price curves developed by third-party financial institutions. The use of unobservable market data for APL’s fixed price swaps and NGL options has no impact on the settlement of these derivatives. However, a change in management’s estimated fair values for these derivatives could impact the Partnership’s net income, though it would have no impact on its liquidity or capital resources. The Partnership recognized $20.6 million, $5.4 million and $13.7 million of mark-to-market loss on derivatives valued upon unobservable inputs for the years ended December 31, 2011, 2010 and 2009, respectively.
Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Loss on mark-to-market derivatives …”
Atlas Pipeline Partners, L.P. also proposes to revise its disclosure within MD&A in future filings in a similar manner.
Critical Accounting Policies and Estimates, page 70
3. | Please provide a quantitative analysis of each of your critical accounting estimates and an analysis of the variability in your financial results resulting from changes in estimates or assumptions. Please also provide an analysis of the variability that is reasonably likely to result from changes in estimates and assumptions in the future. For example, disclose how changes in your oil and gas reserves impact your depletion expense. Additionally, disclose how declining gas prices affect the carrying value of your long-lived assets. Lastly, we note from your disclosure in footnote 12 that a significant portion of your derivative instruments are classified as Level 3 fair value measurements which rely on subjective forward developed price curves. Please quantify |
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how changes in the forward price curves impact the fair value of these derivative instruments. For additional guidance, refer to Item 303 of Regulation S-K as well as section five of the Commission’s Interpretive Release on Management’s Discussion and Analysis of Financial Condition and Results of Operation which is located on our website at: http://www.sec.gov/rules/interp/33-8350.htm. |
Response: Atlas Energy, L.P. proposes to revise its disclosure of Critical Accounting Policies and Estimates within MD&A of its future filings as set forth in Exhibit A.
Atlas Pipeline Partners, L.P. also proposes to revise its disclosure of Critical Accounting Policies and Estimates within MD&A in future filings in a similar manner.
Consolidated Combined Balance Sheets, page 76
4. | Please refer to the Prepaid expenses and other and Accrued liabilities line items on your balance sheet. Please tell us whether any single item is in excess of five percent of total current assets or total current liabilities, respectively. If so, please separately disclose such item consistent with the guidance in Rules 5-02.8 and 5-02.20 of Regulation S-X. |
Response: Atlas Energy, L.P. notes to the Staff that inventory is the only item included within Prepaid expenses and other on its Consolidated Combined Balance Sheets that is in excess of 5% of total current assets, and has been disclosed within Note 2, “Summary of Significant Accounting Policies; Inventory” in its Consolidated Combined Financial Statements within its Form 10-K for December 31, 2011, as required by Rules 5-02.8 and 5-02.20 of Regulation S-X. In addition, Atlas Energy L.P. notes that no single item included within Accrued liabilities on its Consolidated Combined Balance Sheets was in excess of 5% of total current liabilities.
Atlas Pipeline Partners, L.P. also notes that its only item in excess of 5% of total current assets or total current liabilities on its Consolidated Balance Sheets is NGL linefill. APL proposes to add the following to Note 2, “Summary of Significant Accounting Policies” of its Consolidated Financial Statements within its future filings:
“NGL Linefill
The Partnership had $11.5 million and $10.6 million of NGL linefill at December 31, 2011 and 2010, respectively, which was included within prepaid expenses and other on its consolidated balance sheets. The NGL linefill represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then market price.”
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Note 2—Summary of Significant Accounting Policies, page 81
Property, Plant and Equipment, page 83
5. | We note that you capitalize major renewals and improvements that extend the useful lives of your property. Please clarify for us, and disclose, the criteria that you utilize to determine whether capitalization is appropriate. To help us better understand your disclosure and accounting, please identify for us any material capitalized renewals and improvements that have involved significant judgment as to whether capitalization was appropriate. |
Response: Atlas Energy, L.P. notes to the Staff that the amounts it and its subsidiaries capitalize for major renewal and improvement expenditures principally consist of refurbishment of machinery, equipment or similar assets which meet certain criteria, including (i) extend the life of the item for 2 years or more, and (ii) meet certain minimum capitalization thresholds (which range from $2,500 to $10,000, depending upon the asset and subsidiary). In most cases, Atlas Energy, L.P. and its subsidiaries conduct an informal cost/benefit analysis of repairing an existing asset (which causes the asset to continue to perform, but does not replace critical components with new items which extend the life of the asset), a refurbishment (extending the useful life of the asset 2 years or more through the replacement of critical components), and replacement with a new asset. The material assets as to which the management of Atlas Energy, L.P. and its subsidiaries need to exercise significant judgment as to whether to capitalize renewals and improvements are generators, processing plants/units and compressor units.
Atlas Energy, L.P. proposes to revise its disclosure within Note 2, “Summary of Significant Accounting Policies” of its Consolidated Financial Statements within its future filings as follows:
“Property, Plant and Equipment
Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired (see “Principles of Consolidation and Combination”). Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is …”
Atlas Pipeline Partners, L.P. also proposes to revise its disclosure within Note 2, “Summary of Significant Accounting Policies” in future filings in a similar manner.
Note 3—Acquisition from Atlas Energy, Inc., page 91
6. | We note the disclosure on page 92 where you state, “[T]he partnership recognized a non-cash decrease of $261.0 million in partner’s capital ….” Please provide a detailed reconciliation for us supporting this decrease in partner’s capital as a result of the acquisition. |
Response: Atlas Energy, L.P. notes that since the acquisition from Atlas Energy, Inc. was determined by management to constitute a transaction between entities under common control, it recognized the assets acquired and liabilities assumed at historical carrying value at the date of
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acquisition, with the difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on its consolidated combined balance sheet. The table below provides a reconciliation of the $261.0 million decrease recognized in partner’s capital on Atlas Energy, L.P.’s consolidated combined balance sheet related to the excess net book value above the value of the consideration paid to Atlas Energy, Inc.:
Net Book Value of Assets Acquired | ||||||||
Net Book Value of Atlas Energy, Inc. on date of acquisition (per disclosure in Note 3 to consolidated combined financial statements) | $ | 522,874 | ||||||
Less: Contractual Cash Amount received by Atlas Energy, L.P. included within net book value | (118,714 | ) | ||||||
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Equals: Net Book Value of Assets Acquired | 404,160 | |||||||
Consideration Paid for Acquisition | ||||||||
Fair Value of Atlas Energy, L.P. Common Units Issued to Chevron at date of acquisition | 372,200 | |||||||
Cash consideration paid by Atlas Energy, L.P. to Atlas Energy, Inc. | 30,000 | |||||||
Contractual Cash Amount received by Atlas Energy, L.P. from Atlas Energy, Inc. | (118,714 | ) | ||||||
Other cash acquisition adjustment received by Atlas Energy, L.P. from Atlas Energy, Inc. | (22,444 | ) | ||||||
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Net Consideration Paid for Acquisition | 261,042 | |||||||
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Amount of Net Book Value of Assets Acquired in excess of Net Consideration Paid for Acquisition | 143,118 | |||||||
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Reconciliation of Adjustment to Partner’s Capital for Acquisition from Atlas Energy, Inc. | ||||||||
Reversal of Net Book Value of Assets Acquired at date of acquisition | (404,160 | ) | ||||||
Amount of Net Book Value of Assets Acquired in excess of Net Consideration Paid for Acquisition | 143,118 | |||||||
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Net transaction adjustment related to the acquisition of the Transferred Business | $ | (261,042 | ) | |||||
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Executive Compensation, page 132
Role of Compensation Consultant, p. 133
7. | We note your disclosure that Mercer (US) Inc. provided market data for the compensation committee’s use in determining the equity awards to be made to your NEOs. As it appears that you are engaged in benchmarking, please revise your disclosure to identify the components of such benchmarks, including component companies, pursuant to Item 402(b)(2)(xiv) of Regulation S-K. |
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Response: Atlas Energy, L.P. proposes to revise its December 31, 2011 Form 10-K CD&A as follows:
Role of Compensation Consultant
Following the closing of the Chevron Merger, the compensation committee engaged Mercer (US) Inc., an independent compensation consulting firm, to provide market data for equity awards to be made to our NEOs. As our company was essentially reconstituted as a result of the acquisition of AEI’s partnership management business and certain E&P assets, the compensation committee intended the awards to represent multi-year long-term incentive grants competitive with the 75th percentile of the market. In order to assist the compensation committee in assessing the competitiveness of proposed awards, Mercer provided market data for long-term incentive grants from its 2010 oil and gas survey of data from 111 organizations, a survey which comprises the following companies:
Abraxas Petroleum Corporation | Legacy Reserves, LP | |
AGL Resources - Sequent Energy Management | Linn Energy, LLC | |
Altex Energy Corporation | Magellan Midstream Holdings, LP | |
Apache Corporation | Magellan Midstream Holdings, LP - Pipeline/Terminal Division | |
Baker Hughes, Inc. | Magellan Midstream Holdings, LP - Transportation | |
Baker Hughes, Inc. - Baker Atlas | MarkWest Energy Partners LP | |
Baker Hughes, Inc. - Baker Hughes Inteq | MarkWest Energy Partners LP - Gulf Coast Business Unit | |
Basic Energy Services | MarkWest Energy Partners LP - Liberty Business Unit | |
Basic Energy Services - Completion and Remedial Services | MarkWest Energy Partners LP - Northeast Business Unit | |
Baytex Energy USA Ltd. | MarkWest Energy Partners LP - Southwest Business Unit | |
BHP Billiton Petroleum (Americas), Inc. | MDU Resources Group, Inc. - WBI Holdings, Inc. | |
BreitBurn Energy Partners L.P. | Murphy Oil Corporation | |
BreitBurn Energy Partners L.P. - Eastern Division | Newfield Exploration Company | |
BreitBurn Energy Partners L.P. - Orcutt Facility | Nexen Petroleum USA, Inc. | |
BreitBurn Energy Partners L.P. - West Pico Facility | Noble Corporation | |
BreitBurn Energy Partners L.P. - Western Division | Noble Corporation - Noble Drilling Services, Inc. | |
BreitBurn Energy Partners L.P. - Western Division, California Operations | Noble Energy, Inc. | |
BreitBurn Energy Partners L.P. - Western Division, Florida Operations | NuStar Energy LP | |
BreitBurn Energy Partners L.P. - Western Division, Wyoming Operations | OGE Energy Corporation - Enogex | |
Buckeye Partners, L.P. | ONEOK, Inc. |
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Calfrac Well Services Corporation | ONEOK, Inc. - ONEOK Partners | |
Chesapeake Energy Corporation | Parker Drilling Company | |
Chesapeake Energy Corporation - CEMI | Petroleum Development Corporation | |
Chesapeake Energy Corporation - Chesapeake Midstream Partners | Pioneer Natural Resources USA, Inc. | |
Chesapeake Energy Corporation - Diamond Y | Plains Exploration & Production Company | |
Chesapeake Energy Corporation - Great Plains | Precision Drilling Corporation | |
Chesapeake Energy Corporation - Hodges | Pride International | |
Chesapeake Energy Corporation - Midcon | QEP Resources | |
Chesapeake Energy Corporation - Nomac | Questar Corporation - Questar Pipeline | |
CHS Inc. - Energy | Quicksilver Resources Inc. | |
Cimarex Energy Co. | RAM Energy Resources, Inc. | |
Constellation Energy Partners LLC | Regency Energy Partners LP | |
Copano Energy | Regency Energy Partners LP - Contract Compression Segment | |
DCP Midstream, LLC - DCP Midstream Partners, LP | Rowan Companies, Inc. | |
Devon Energy | SandRidge Energy, Inc. | |
Edison Mission Energy - Energy Mission Marketing & Trading | Seneca Resources Corporation | |
El Paso Corporation - Exploration and Production | Seneca Resources Corporation - Bakersfield | |
El Paso Corporation - Pipeline Group | Seneca Resources Corporation - Williamsville | |
Energen Corporation | Southern Union Company | |
Energen Corporation - Energen Resources Corporation | Southern Union Company - Panhandle Energy | |
Enerplus Resources (USA) Corporation | Southern Union Company - Southern Union Gas Services | |
Eni US Operating Company, Inc. | Southwestern Energy Company | |
ENSCO International, Inc. | StatoilHydro - Norsk Hydro Gulf of Mexico, LLC | |
ENSCO International, Inc. - Deepwater Business Unit | Sunoco, Inc. | |
ENSCO International, Inc. - North & South America Business Unit | Talisman Energy Inc. US | |
Enterprise Products Partners L.P. | The Williams Companies, Inc. | |
EOG Resources, Inc. | The Williams Companies, Inc. - E&P | |
Forest Oil Corporation | The Williams Companies, Inc. - Midstream | |
Genesis Energy, LLC | The Williams Companies, Inc. - Williams Gas Pipeline (WGP) |
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Halliburton Company | TransCanada Corporation | |
Halliburton Company - Western Hemisphere | TransCanada Corporation - US Pipeline Central | |
Helmerich & Payne, Inc. | Transocean, Inc. | |
Hess Corporation | Valero Energy Corporation | |
Hess Corporation - Exploration & Production | Venoco, Inc. | |
Husky Energy Inc. | XTO Energy, Inc. | |
Kinder Morgan, Inc. |
In using this broad-based survey, the compensation committee considered only aggregate data and did not select any individual companies for comparison. Mercer provided data with respect to average long-term incentive awards across all positions with a similar base salary in the above-named companies, and calculated long-term incentive awards for our NEOs as a percentage multiple of base salary at the 75th percentile of the survey data. In addition, Mercer advised the compensation committee with respect to current employment agreement practices generally.
Determination of 2011 Compensation Amounts—Long-Term Incentives
Immediately after the Chevron Merger, our compensation committee recognized that the leadership of our NEOs was essential to our company as we established ourselves as a stand-alone entity. It further concluded that strong incentive for our NEOs to remain with us for a significant period of time and their close alignment with our unitholders is critical in attracting and retaining additional key employees. However, the compensation committee further understood that our NEOs had received substantial cash amounts from Chevron in connection with the Chevron Merger, both as a result of the termination payments due under their employment agreements with AEI, which are described under “—Employment Agreements and Potential Payments Upon Termination or Change of Control,” and their equity holdings in AEI, and that could have left our NEOs without the adequate financial incentives to continue employment with us for a significant period of time, which the committee considered important. To provide motivation to the NEOs to give their maximum effort and commitment, we made certain long-term incentive grants under the 2010 Plan to our NEOs in March 2011 as follows: Mr. E. Cohen—300,000 phantom units and 700,000 options; Mr. Dubay—80,000 phantom units and 100,000 options; Mr. McGrath—30,000 phantom units and 35,000 options; Mr. Kalamaras—50,000 phantom units and 70,000 options; Mr. J. Cohen—250,000 phantom units and 500,000 options; Mr. Jones—150,000 phantom units and 200,000 options; and Mr. Kotek—30,000 phantom units and 70,000 options. (Mr. Kotek received an additional grant of 20,000 phantom units in April 2011 which brought his grant in line with the multiples of the other NEO grants described below.) The compensation committee intended the awards to represent long-term incentive grants competitive with the 75th percentile of the market described above under “—Role of Compensation Consultant.” For each of the NEOs, the grants represented between 3.5 to 5.4 times the annual market long-term incentive level from Mercer’s survey. The compensation committee does not anticipate making awards of such size on an annual basis. The awards will vest 25% on the third anniversary of the grant and 75% on the fourth anniversary.
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Atlas Pipeline Partners, L.P. proposes to revise its December 31, 2011 Form 10-K CD&A in a similar manner:
Annual Incentives, page 133
8. | Please disclose the amount of your 2011 distributable cash flow, calculated as set forth on page 133, with a view towards informing investors how you determined the amount of compensation to award to your NEOs under the Annual Incentive Plan. Refer to Item 402(b)(1)(v) of Regulation S-K. |
Response: Atlas Energy, L.P. proposes to revise the sentence in the second paragraph under “Determination of 2011 Compensation Amounts—Annual and Transaction Incentives” in its December 31, 2011 Form 10-K as follows: “In addition, the compensation committee reviewed the calculations of our distributable cash flow and determined that 2011 distributable cash flow was $123,800,000, which exceeded the pre-determined minimum threshold of 80% the budgeted distributable cash flow of $84,498,000.”
Atlas Pipeline Partners, L.P. proposes to revise its December 31, 2011 Form 10-K CD&A in a similar manner.
Form 10-Q for the Quarterly Period Ended March 31, 2012
Liquidity and Capital Resources, page 56
9. | We note from your disclosure on page 21 you had a significant increase in borrowings under your credit facility as of March 31, 2012 as compared to December 31, 2011. Similarly, we noted increased borrowings and repayments of your credit facility on your consolidated combined statements of cash flows for the quarterly period ended March 31, 2012 as compared to the prior quarterly period in fiscal 2011. In this regard, if borrowings during the reporting period are materially different than the period-end amounts recorded in the financial statements, disclosure about the intra-period variations should be provided to facilitate investor understanding of your liquidity position. See Release No. 34-62934, Commission Guidance on Presentation of Liquidity and Capital Resources Disclosures in Management’s Discussion and Analysis. |
Response: Atlas Energy, L.P. notes to the Staff that it duly notes the guidance provided in Release No. 34-62934 and has provided the table below for further analysis of its borrowings and liquidity position from its quarterly periods included within its March 31, 2012 Form 10-Q:
March 31, 2012 | December 31, 2011 | Variance | ||||||||||
Consolidated Combined amount outstanding under revolving credit facilities at period end | $ | 247,000 | $ | 142,000 | $ | 105,000 | ||||||
Three Months Ended March 31, | ||||||||||||
2012 | 2011 | Variance | ||||||||||
Consolidated Combined Borrowings/(repayments) under credit facilities: | ||||||||||||
Borrowings | $ | 336,500 | $ | 178,000 | $ | 158,500 | ||||||
(Repayments) | (231,500 | ) | (248,000 | ) | 16,500 | |||||||
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Net | $ | 105,000 | $ | (70,000 | ) | $ | 175,000 | |||||
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Consolidated Combined Capital Expenditures | $ | 100,125 | $ | 26,065 | $ | 74,060 |
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Atlas Energy, L.P. notes to the Staff that the increase in borrowings from December 31, 2011 to March 31, 2012 was principally related to borrowings by Atlas Pipeline Partners, L.P. to fund its $81.2 million of capital expenditures and Atlas Energy, L.P. and by Atlas Resource Partners, L.P. to fund their $19.0 million of capital expenditures during the period. Atlas Energy, L.P. discloses within “Liquidity and Capital Resources” in the MD&A of its March 31, 2012 Form 10-Q that capital expenditures are funded through borrowings under its credit facility and cash generated from operations.
Atlas Energy, L.P. also notes to the Staff that the disparity between the gross amount of borrowings and repayments under the credit facilities ($336.5 million and $231.5 million, respectively) from the statements of cash flows for the three months ended March 31, 2012 and the net increase in borrowings under the credit facilities ($105.0 million) is a reflection of how Atlas Energy, L.P. and its subsidiaries effectively manage their cash and borrowings under the respective credit facilities to reduce interest expense and other borrowing costs. As is common in their industry, Atlas Energy, L.P. and its subsidiaries collect the vast majority of their trade accounts receivable once a month, while they borrow under the credit facilities on a daily basis to fund capital expenditures and daily operating costs. As such, the statements of cash flows reflect a much larger gross amount of borrowings and repayments under the credit facilities than the actual net increase in borrowings during the period. With regard to Release 34-62934 and the disclosure of intra-period variations, and Atlas Energy, L.P. proposes to include the following disclosure within the description of movements in net cash used in financing activities under “Liquidity and Capital Resources” in the MD&A of its future filings:
“The gross amount of borrowings and repayments under the credit facilities included within net cash used in financing activities in the consolidated combined statements of cash flows, which are generally in excess of net borrowings or repayments during the period or at period end, reflect the timing of cash receipts, which generally occur at specific intervals during the period and are utilized to reduce borrowings under the credit facilities, and payments, which generally occur throughout the period and increase borrowings under the credit facilities, for APL and ARP, which is generally common practice for their industries.”
Atlas Pipeline Partners, L.P. also proposes to revise its disclosure within MD&A in its future filings in a similar manner.
Each of Atlas Energy, L.P. and Atlas Pipeline Partners, L.P. hereby acknowledges that:
• | it is responsible for the adequacy and accuracy of the disclosure in its filings; |
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• | 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 |
• | it 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. |
Sincerely, |
/s/ Sean P. McGrath |
Sean P. McGrath |
Chief Financial Officer |
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Exhibit A
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depletion, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. We summarize our significant accounting policies within our consolidated combined financial statements included in “Item 8: Financial Statements and Supplementary Data”. The critical accounting policies and estimates we have identified are discussed below.
Depreciation and Impairment of Long-Lived Assets and Goodwill
Long-Lived Assets.The cost of property, plant and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively.
Long-lived assets, other than goodwill and intangibles with infinite lives, generally consist of natural gas and oil properties and pipeline, processing and compression facilities and are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset, other than goodwill and intangibles with infinite lives, is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. The undiscounted net cash flows expected to be generated by the asset are based upon our estimates that rely on various assumptions, including natural gas and oil prices, production and operating expenses. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. As discussed in General Trends and Outlook within this section, recent increases in natural gas drilling has driven an increase in the supply of natural gas and put a downward pressure on domestic prices. Further declines in natural gas prices may result in additional impairment charges in future periods.
During the year ended December 31, 2011, the Partnership recognized $7.0 million of asset impairment related to gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in the Niobrara Shale. During the year ended December 31, 2010, the Partnership recognized $50.7 million of asset impairment related to gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in the Chattanooga and Upper Devonian shales. During the year ended December 31, 2009, the Partnership recorded $156.4 million of asset impairment related to gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in the Upper Devonian Shale. These impairments related to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2011, 2010 and 2009. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. In addition, during the year ended December 31, 2009, APL evaluated its long-lived assets for impairment and recognized $10.3 million of impairment related to inactive pipelines and a reduction in estimated useful lives. No impairment charges were recognized by APL for the years ended December 31, 2011 and 2010.
Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under “Item 1A: Risk Factors” in this report.
Goodwill and Intangibles with Infinite Lives. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value.
There were no goodwill impairments recognized by us during the years ended December 31, 2011, 2010 and 2009.
Fair Value of Financial Instruments
We have established a hierarchy to measure our financial instruments at fair value which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:
Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
We use a fair value methodology to value the assets and liabilities for our and APL’s outstanding derivative contracts. Our and APL’s commodity hedges, with the exception of APL’s NGL fixed price swaps and NGL options, are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil and propane prices and therefore are defined as Level 3 fair value measurements. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution and therefore are defined as Level 3 fair value measurements.
Of the $46.4 million and $55.9 million of net derivative assets at December 31, 2011 and 2010, respectively, APL had a $16.5 million net asset and a $1.8 million net liability at December 31, 2011 and 2010, respectively, that were classified as Level 3 fair value measurements which rely on subjective forward developed price curves. Holding all other variables constant, a 10% change in the prices APL utilized in calculating the fair value of derivatives at December 31, 2011 would have resulted in a $17.3 million non-cash decrease to net income for the year ended December 31, 2011.
Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations (“ARO’s”) that are defined as Level 3. Estimates of the fair value of ARO’s are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.
Reserve Estimates
Our estimates of proved natural gas and oil reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures and availability of funds. The accuracy of these reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. As discussed in Item 2: Properties, we engaged Wright and Company, Inc., an independent third-party reserve engineer, to prepare a report of our proved reserves.
Any significant variance in the assumptions utilized in the calculation of our reserve estimates could materially affect the estimated quantity of our reserves. As a result, our estimates of proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect our ability to pay amounts due under our credit facility or cause a reduction in our credit facility. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control. Our reserves and their relation to estimated future net cash flows impact the calculation of impairment and depletion of oil and gas properties. Adjustments to quarterly depletion rates, which are based upon a units of production method, are made concurrently with changes to reserve estimates. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.
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Asset Retirement Obligations
On an annual basis, we and our subsidiaries estimate the cost of future dismantlement, restoration, reclamation and abandonment of our operating assets. We and our subsidiaries also estimate the salvage value of equipment recoverable upon abandonment. As of December 31, 2011 and 2010, the estimate of salvage values was greater than or equal to our estimate of the costs of future dismantlement, restoration, reclamation and abandonment. Projecting future retirement cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of reserves, future labor and equipment rates, future inflation rates and our subsidiaries’ credit adjusted risk free rate. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Since there are many variables in estimating asset retirement obligations, we attempt to limit the impact of management’s judgment on certain of these variables by developing a standard cost estimate based on historical costs and industry quotes updated annually. To the extent future revisions to these assumptions impact the fair value of our existing asset retirement obligation, a corresponding adjustment is made to our gas and oil properties and other property, plant and equipment. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we and our subsidiaries have estimated, or changes in their estimates or costs, could reduce our gross profit from operations.
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