Legacy Reserves LP
303 W. Wall Street, Suite 1800
Midland, Texas 79701
September 16, 2013
Via EDGAR
Brad Skinner
Senior Assistant Chief Accountant
United States Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549
Re: Legacy Reserves LP
Form 10-K for Fiscal Year Ended
December 31, 2012
Filed February 27, 2013
Form 8-K filed August 6, 2013
File No. 001-33249
Dear Mr. Skinner:
Set forth below are the responses of Legacy Reserves LP, a Delaware limited partnership (“Legacy,” “we,” “us,” or “our”), to the comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated September 4, 2013, with respect to (i) Legacy’s Form 10-K for the Fiscal Year ended December 31, 2012 filed with the Commission on February 27, 2013, File No. 001-33249 (our “Form 10-K”), and (ii) Legacy’s Form 8-K filed August 6, 2013, File No. 001-33249 (our “Form 8-K”).
For the Staff’s convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold, italicized text.
Form 10-K for Fiscal Year Ended December 31, 2012
Item 1 Business, page 1
Development Activities, page 3
1. Please revise your disclosure to present the dollar amounts of the capital expenditures made during the year to convert proved undeveloped reserves to proved developed reserves. Refer to Item 1203(c) of Regulation S-K.
Mr. Brad Skinner
September 16, 2013
Page 2
We acknowledge the Staff’s comment and note our disclosure on page F-34 of our Form 10-K, stating that we invested approximately $67.6 million in development costs during our Fiscal Year ended December 31, 2012. Of this $67.6 million in development costs, $41.1 million was incurred to convert proved undeveloped reserves (“PUDs”) to proved developed reserves. We also incurred an additional $5.0 million in development costs to begin converting PUDs to proved developed reserves during the Fiscal Year ended December 31, 2012 that were still in the process of being developed as of December 31, 2012 and therefore disclosed as PUDs in our Form 10-K. These amounts equate to 60.1% of total development costs incurred with total drilling costs, inclusive of uncompleted drilling projects, amounting to 68.2% of total development costs incurred.
In future filings, we will include in the discussion of development costs expanded disclosure that states what portion of our development cost were incurred to convert PUDs to proved developed reserves such as the text underlined in the following:
Summary of Development Projects
We are currently pursuing an active development strategy. For the year ended December 31, 2012, we invested approximately $67.6 million in implementing our development strategy, including $46.1 million related to the development of proved undeveloped reserves. We estimate that our capital expenditures for the year ending December 31, 2013 will be approximately $90 million for development drilling, re-completions and fracture stimulation and other development related projects to implement this strategy. All of these development projects are located in the Permian Basin, Wyoming and the East Binger field in Oklahoma. We will consider adjustments to this capital program based on our assessment of additional development opportunities that are identified during the year and the cash available to invest in our development projects.
Item 2 Properties, page 28
Developed and Undeveloped Acreage, page 35
2. Please expand your disclosure to present the expiration dates relating to material amounts of your undeveloped acreage. Refer to Item 1208(b) of Regulation S-K.
As stated in footnote (b) to the Developed and Undeveloped Acreage table on page 35 our Form 10-K, all of our proved undeveloped locations are located on acreage currently held by production. As shown in our Form 10-K, as of December 31, 2012, we held 70,108 net undeveloped acres, of this total, only 7,953 net acres is acreage with a corresponding book basis (approximately $9.0 million as of December 31, 2012), which is immaterial to Legacy. The remaining gross and net undeveloped acres are acreage positions we obtained during various acquisitions of proved developed producing properties. Based on our internal measurement of fair value upon acquisition as prescribed by ASC 820-10, we did not assign any value to these undeveloped acres as the economic viability of any potential oil and natural gas development is remote or non-existent. As such, we do not anticipate pursuing a development program with respect to this acreage and therefore the minimum remaining terms of leases, or concessions relating to such undeveloped acreage, is not material. Consequently, we respectfully submit that the requirement in Item 1208(b) of Regulation S-K to disclose minimum
Mr. Brad Skinner
September 16, 2013
Page 3
remaining terms of material leases is not applicable. In future filings, to the extent such information is material, we will add disclosure describing the minimum remaining terms of material leases.
Exhibit 99.1
3. The reserve report refers to additional information not included in Exhibit 99.1 such as:
· summary economic projections of reserves and cash flow for each reserve category, and
· one-line summaries of basic economic data and reserves for each property evaluated.
Please obtain and file a revised report to include the referenced supplemental information. Alternatively, remove these references if you do not intend to include this supplemental information in Exhibit 99.1. For additional information about the content of the third party report, please refer to paragraph 3(e) on page 72 of section IV in the Adopting Release contained in the Modernization of Oil and Gas Reporting; Final Rule. The Adopting Release may be found at http://www.sec.gov/rules/final/2008/33-8995.pdf.
We acknowledge the Staff’s comment and note that certain of the additional information specified in the Staff’s comment is included in Exhibit 99.1 under the table provided on page one of Exhibit 99.1. The summary economic projections of reserves and cash flow for each reserve category is included in Exhibit 99.1, but the one-line summaries of basic economic data and reserves for each property evaluated, upon which such projections were based, were not. In future filings, we will not reference any items not included in Exhibit 99.1.
Form 8-K filed August 6, 2013
Non-GAAP Financial Measures
4. We note your disclosure of the non-GAAP measure adjusted EBITDA, as presented here and in your periodic Exchange Act filings, excludes the unrealized gain / loss on oil and natural gas derivatives. Please tell us why this non-GAAP measure excludes the unrealized gain / loss, but includes the realized gain / loss on your oil and natural gas derivatives. If it is your intent for this non-GAAP measure to reflect the cash flows associated with oil and natural gas derivatives settled during the period, please revise your reconciliation to include two separate line items: one for the total gain / loss recognized and another for the net cash received / paid for oil and natural gas derivatives not designated as hedging instruments which were settled during the period.
We acknowledge the Staff’s comment and our intent for adjusted EBITDA is to reflect the cash flows associated with oil and natural gas derivatives settled during the period. As such, the line item “Unrealized (gains) losses on oil and natural gas derivatives” provided in the reconciliation of “Net income (loss)” to “Adjusted EBITDA” provided an adjustment to “Net income (loss)” for the unrealized portion of the net gains on
Mr. Brad Skinner
September 16, 2013
Page 4
commodity derivatives of $32.5 million for the fiscal year ended December 31, 2012 as the total unrealized and realized gain on commodity derivatives of $38.5 million was already included in “Net Income (loss)” and therefore we did not have a separate line item for realized portion of our gain on commodity derivatives. As shown below, adding the requested separate line items would not have changed Adjusted EBITDA for any period presented. Please also note that all of Legacy’s commodity derivatives have been costless, and we currently have no intention to pay any premiums for commodity derivatives in the future and have therefore not provided separate line-item disclosure related to such costs. In future filings we will provide the two separate line items (italicized below) requested by the Staff as follows:
|
|
|
Year Ended |
| |
|
|
|
December 31, |
| |
|
|
|
2012 |
| |
|
Net Income |
|
$ |
68,637 |
|
|
Plus: |
|
|
| |
|
Interest Expense |
|
20,260 |
| |
|
Income Taxes |
|
1,096 |
| |
|
Depletion, depreciation, amortization and accretion |
|
102,144 |
| |
|
Impairment of long-lived assets |
|
37,066 |
| |
|
(Gain) loss on disposal of assets |
|
(2,496 |
) | |
|
Equity in income of partnership |
|
(111 |
) | |
|
Unit based compensation expense |
|
3,546 |
| |
|
Realized and unrealized net (gains) losses on commodity derivatives |
|
(38,493 |
) | |
|
Realized net gains (losses) on commodity derivatives |
|
5,902 |
| |
|
Adjusted EBITDA |
|
$ |
197,551 |
|
5. We note that beginning in the quarter ended March 31, 2013 you began deducting maintenance capital expenditures instead of total development capital expenditures in the computation of distributable cash flow. Please tell us about your basis for making this change and explain how the revised measure provides information that is comparatively more useful to an investor. Your response should identify the types of costs that are now being included as part of distributable cash flow.
We acknowledge the Staff’s comment and note that Legacy is a master limited partnership (“MLP”), and in accordance with our partnership agreement we are required to distribute 100% of our available cash as such term is defined by our partnership agreement (“Available Cash”). In order to provide investors meaningful disclosure related to such distributions of Available Cash, many MLPs provide Distributable Cash Flow (“DCF”), a Non-GAAP metric, as an approximation of Available Cash prior to the establishment of any cash reserves by the MLP’s governing body. DCF, as an approximation of Available Cash, allows investors to approximate an MLP’s Distribution Coverage, the ratio of DCF or Available Cash to the amount of cash needed to fund the MLP’s distribution for the corresponding period. As we note in our Form 8-K, we believe DCF is useful to investors because this measure is used by most MLPs as a measure of operating and financial performance, and is commonly employed by financial analysts and others to evaluate the operating and financial performance of Legacy from period to period and to compare it with the performance of other MLPs. As such, our
Mr. Brad Skinner
September 16, 2013
Page 5
decision to provide an adjustment for maintenance capital expenditures rather than total capital expenditures was driven by a desire to provide a more meaningful and clear metric when comparing Legacy to its investment class peers rather than providing a metric that is not comparable to those of our peers.
We believe MLPs are viewed as an investment class based on our direct interaction with investors and the market’s frequent reference to the Alerian Index. According to a sampling of 98 MLPs’ calculation of DCF, 89 companies use maintenance capital expenditures, 6 companies do not provide any reference to capital expenditures and 3 companies utilize total capital expenditures. Since our initial public offering in January 2007, we have had investors and equity research analysts repetitively request that we provide our estimated maintenance capital expenditures so that they could compare our DCF and Distribution Coverage relative to other MLPs. Further, of the 12 other MLPs primarily focused on the exploration and production of oil and natural gas (“Upstream MLPs”), 11 calculate DCF using maintenance capital expenditures. We believe our change from total development capital expenditures to maintenance capital expenditures improves the comparability of our financial performance relative to other MLPs, and Upstream MLPs in particular.
For Legacy, maintenance capital expenditures is the estimated amount of capital required to hold production flat on a long-term basis. On an annual basis we examine the long-term compound annual production decline rate of our existing reserves based on our third-party prepared reserve report and calculate the amount of production to be offset. We then use the estimated weighted average productivity of our budgeted capital expenditures based on what we have achieved on capital expenditure projects in the past. With our estimated production to-be-replaced and our estimated capital productivity, we then estimate the amount of capital that we define as maintenance capital expenditures. If we make a material acquisition, we update our analysis to include the estimated production decline of the newly acquired properties.
Given that we use our past performance of capital productivity, our estimated maintenance capital includes capital expenditures related to development drilling, re-completion, workover and other costs to improve production rates or increase reserves, both from operated and non-operated properties.
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Legacy acknowledges the following:
· Legacy 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
· Legacy 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.