May 16, 2013
Mr. H. Roger Schwall
Assistant Director
Division of Corporation Finance
United States Securities and
Exchange Commission
100 F Street, N.E.
Washington, D.C. 20549-7010
Re: BreitBurn Energy Partners L.P.
Form 10-K for Fiscal Year Ended December 31, 2012
Filed February 28, 2013
File No. 1-33055
Dear Mr. Schwall:
Set forth below are the responses of BreitBurn Energy Partners L.P. (the “Partnership”) 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 March 27, 2013 with respect to the Partnership’s Form 10-K for the fiscal year ended December 31, 2012 (the “2012 Form 10-K”). For your convenience, each response is prefaced by the exact text of the Staff’s comment.
Form 10-K for the Fiscal Year Ended December 31, 2012
Business, page 4
Reserves and Production, page 7
1. | We note the Company does not provide disclosure of natural gas liquids (NGL) reserves or production quantities or the average sales price per unit of NGL produced. The staff considers natural gas liquids to be a separate product type under Item 1202(a)(4) and 1204 of Regulation S-K. Please expand the tables on pages 7, 54 and F-39 to provide that information either by providing a separate column or by providing footnote disclosure. |
Response: We acknowledge the Staff’s comment and note that in Section 1202(a)(4) of Regulation S-K, it requires that registrants disclose separately material reserves for: (i) oil; (ii) natural gas (iii); synthetic oil; (iv) synthetic gas and (v) sales products of other non-renewable natural resources that
Securities and Exchange Commission
May 16, 2013
Page 2
are intended to be upgraded into synthetic oil and gas. At year-end 2012, the Partnership’s NGL reserves represented approximately 4% of its total year end reserves and 2% of its total production. As a result, the Partnership has elected to include its NGL reserve and production volumes with its oil reserve and production volumes as the NGL reserve and production volumes did not represent a material amount of its total reserves or total production for 2012. The Partnership will continue to monitor its NGL reserve and production volumes and will make the necessary separate disclosures in the future should the NGL reserve and production volumes become material.
2. | We note the Company states on page 7 that “as of December 31, 2012, we had no estimated proved undeveloped reserves that have remained undeveloped for more than five years, and we expect to develop all estimated proved undeveloped reserves within the next five years.” For purposes of determining the five year period for development to occur in estimating proved undeveloped reserves, Item 1203(d) of regulation S-K requires that you use the date of the initial disclosure as the starting reference date. Please tell us the extent to which any of the proved undeveloped reserves disclosed as of December 31, 2012 will not be developed within five years since your initial disclosure of those reserves. Please also clarify in your disclosure. |
Response: We acknowledge the Staff’s comment and note that in Item 1203(d) of Regulation S-K, registrants are required to disclose the reasons why material amounts of proved undeveloped reserves that were disclosed remain undeveloped after five years. For clarification, as stated in the disclosure on page 7, the Partnership did not have any proved undeveloped reserves at December 31, 2012 that had previously been disclosed as proved undeveloped reserves for more than five years that would require this disclosure. At December 31, 2012, the Partnership expected to develop its remaining proved undeveloped reserves within the next five years. Additionally, the undeveloped reserve disclosures required by Item 1203 of Regulation S-K are included in the Partnership’s undeveloped reserve disclosure entitled “Conversion of Proved Undeveloped Reserves” on page F-39 of its 2012 Form 10-K. In that disclosure we specify the amount of undeveloped reserves at each year end for 2012, 2011 and 2010, the amount of undeveloped reserves promoted to proved developed reserves during each year as well as the total amount spent to promote the proved undeveloped reserves to proved developed reserves for each of these years. In this disclosure, we also identify other factors contributing to the changes in undeveloped reserves each year such as property acquisitions and economic revisions. The Partnership believes it has met the disclosure requirements for Item 1203 of Regulation S-K in its 2012 Form 10-K. In future filings beginning with our Form 10-K for the year ended December 31, 2013, the Partnership will cross reference its proved undeveloped reserve disclosures contained in its financial statement notes to its proved undeveloped reserve disclosures contained in the Item 1, Business section.
Securities and Exchange Commission
May 16, 2013
Page 3
3. | We note the Company discloses production information by state for the current year on page 8 and by product for the last three fiscal years on pages 54 and F-39 of Form 10-K. However, it does not appear that you disclose production for each field that contains 15% or more of the Company’s total proved reserves for the last three years. Please expand your disclosure to address the presentation requirements contained in Item 1204(a) of Regulation S-K. Also refer to Comment 1 in providing this disclosure. |
Response: We acknowledge the Staff’s comment and note that in Item 1204(a) of Regulation S-K, registrants are required to disclose production by final product sold, of oil, gas and other products for each of the last three fiscal years for each country and field that contains 15% or more of the registrant’s total proved reserves expressed on an oil-equivalent basis unless prohibited by the country in which the reserves are located. In accordance with ASC 932-360-35-6, we account for the Antrim Shale location in Michigan as a producing field. The Antrim Shale operation was the only producing field that contained 15% or more of the Partnership’s overall total proved reserves on an oil equivalent basis for the last three fiscal years. The required disclosures for oil and natural gas for our Antrim Shale area appear on page 8 of the 2012 Form 10-K in the second paragraph following the reserve table (see response to comment 1 above regarding separate NGL disclosures). In future filings beginning with our Form 10-K for the year ended December 31, 2013, we will add clarifying language for the Antrim Shale area to clearly indicate that it contains 15% of the Partnership’s overall total proved reserves.
Developed and Undeveloped Acreage, page 11
4. | We note from the disclosure on page 11 that a significant percentage of the Company’s net undeveloped acreage will expire in 2013. Please tell us the net amounts by product of your December 31, 2012 proved undeveloped oil and gas reserves assigned to locations on acreage scheduled to expire in 2013. Also tell us if all such proved undeveloped locations are included in a development plan adopted by management as of December 31, 2012 indicating these locations are scheduled to be drilled prior to lease expiration. |
Response: We acknowledge the Staff’s comment and note that of the total 63,928 net acres of undeveloped leases shown on page 11 of our 2012 Form 10-K as scheduled to expire in 2013, only 1,361 of the 9,740 net acres in Michigan and 600 of the 9,342 net acres in Wyoming had proved undeveloped reserves assigned to them at December 31, 2012 (see table below).
For the Michigan leases that had proved undeveloped reserves assigned to them, the leases primarily consisted of proved undeveloped natural gas locations in non-Antrim gas fields located in central Michigan. The Partnership reviewed the potential for the continuation of rising natural gas futures prices at December 31, 2012 and while none of these locations were scheduled to be drilled prior to the lease expiration dates, management determined that it would likely exercise its option to extend the leases where applicable or re-lease the acreage under new lease terms should the rise in natural gas prices continue into 2013.
For Wyoming, the Partnership held one 600 acre lease that had proved undeveloped reserves assigned to it. There was one well location assigned to this lease which was included as part of the Partnership’s approved capital spending program for 2013. The Partnership expects to spud the Wyoming well in May 2013.
Securities and Exchange Commission
May 16, 2013
Page 4
Proved Undeveloped Oil and Gas Reserves at December 31, 2012 | ||||||||
Attached to Leases that are Scheduled to Expire During 2013 | ||||||||
State | Net Reserves | |||||||
Net Acreage | Gas (MMCf) | Oil (MBbl) | Total (MBoe) | |||||
Michigan | 1,361 | 3,130 | 170 | 692 | ||||
Wyoming | 600 | 2,235 | 25 | 398 |
Item 6: Selected Financial Data, page 46
5. | We note that your adjusted EBITDA includes an adjustment related to the net operating cash flow from your acquisitions from the effective date through the closing date of the acquisitions, and that the effective dates of these acquisitions are generally prior to the dates the agreements were signed. For example, the two purchase agreements that closed on July 2, 2012 were entered into by you on May 10, 2012 with the effective dates as of March 1, 2012. Please explain to us why your acquisition agreements contained pre-signed effective dates, why you include the referenced adjustment in your determination of adjusted EBITDA, and why you believe the adjustment is appropriate given the guidance in Regulation S-K Item 10(e)(1)(ii)(A). In addition, please provide us an analysis of whether in substance you are making a pro forma adjustment to arrive at adjusted EBITDA. |
Response: We acknowledge the Staff’s comment and note that we include net operating cash flows from the effective date to the closing date for our acquisitions in the determination of adjusted EBITDA, because the effective date, as is very common in oil and natural gas acquisitions, is the first date that the Partnership is entitled to receive the economic benefits attributable to the operating results of the properties acquired. The effective date is generally set by the seller and usually aligns with the “as of” date of the seller’s reserve runs that are provided to prospective purchasers for their use in evaluating the properties for purchase.
We do not believe that Regulation S-K Item 10(e)(1)(ii)(A) is applicable to our disclosure of the net operating cash flows from the effective date through the closing date of acquisitions in our adjusted EBITDA because they represent the cash operating results of the assets for the period. The Partnership has a right to the cash flow from the net operating revenues less direct operating expenses of the acquired assets, which we believe is more characteristic of operating income. Additionally, by providing separate disclosure for net operating cash flows from the effective date to the closing date for acquisitions in our adjusted EBITDA, we believe that we are providing useful financial information to investors on the net operating results of the assets for the period for which we were entitled to receive those operating cash flows and for which this information is generally not otherwise available.
As noted in Regulation S-X Item 11-02(a), the objective of pro forma financial information is to provide investors with information about the continuing impact of a particular transaction by showing how it might have affected historical financial statements if the transaction had been consummated at an earlier time. Item 11-02(b)(6) of Regulation S-X states that pro forma adjustments related to the pro forma condensed income statement shall be computed assuming the
Securities and Exchange Commission
May 16, 2013
Page 5
transaction was consummated at the beginning of the fiscal year presented and shall include adjustments which give effect to events that are (i) directly attributable to the transaction, (ii) expected to have a continuing impact on the registrant, and (iii) factually supportable. By disclosing the actual net operating cash flows from the effective date to the closing date for our acquisitions, we do not believe that we are making a pro forma disclosure. The net operating cash flows that we included in our adjusted EBITDA were attributable to the actual operating results of the assets acquired for the periods in which we were entitled to receive those economic benefits. We did not include net operating cash flow results in our adjusted EBITDA for any period(s) in which we were not entitled to receive those economic benefits (e.g., there was no effect given to assume the transactions occurred at the beginning of the fiscal year in our adjusted EBITDA). Additionally, we did not make adjustments to adjusted EBITDA to give effect to events that did not occur as we included only the actual net operating cash flows for the assets acquired for the periods in which we were contractually entitled to receive those economic benefits.
As noted on page 46 of our Form 10-K for the year ended December 31, 2012, we use adjusted EBITDA to: assess the financial performance of our assets without regard to financing methods, capital structure or historical costs basis; assess our operating performance and return of capital as compared to those of other companies in our industry, without regard to financing or capital structure; assess the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities; and assess the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness. While we do provide a reconciliation of EBITDA to consolidated net income, we state that adjusted EBITDA is a non-GAAP financial measure and should not be considered as an alternative to GAAP measures - such as net income, operating income, or cash flow from operating activities - or any other GAAP measure of liquidity or financial performance. Adjusted EBITDA is presented because management believes it provides additional information relative to the performance of the Partnership's business that may be useful to some investors.
Securities and Exchange Commission
May 16, 2013
Page 6
Financial Statements
Note 4 – Acquisitions, page F-13
Permian Basin Acquisitions, page F-14
6. | We note that you entered into separate agreements with Element Petroleum, L.P. and CrownRock, L.P. on May 10, 2012 to purchase Permian Basin assets and, as disclosed in your Form 8-K on May 11, 2012, that the acquisitions are “not conditioned upon each other.” We also note from the agreements included in your Form 8-K that the sellers and CrownQuest Operating, L.P. entered into a participation agreement dated as of April 1, 2009. Please provide us an analysis of the participation agreement as it relates to Regulation S-X Rule 3-05(a)(3)(i) and whether these businesses were under common control or management. In addition, provide us analysis of all your 2012 Permian Basin acquisitions under Rule 3-05(a)(3) and identify for us any of the acquisitions that should be treated as “related businesses” under the rule. Lastly, provide us the calculations of significant subsidiary under Rule 1-02(w) of Regulation S-X for these acquisitions. |
Response: We acknowledge the Staff’s comment and note that S-X Rule 3-05(a)(3) requires separate businesses be treated as if they are a single business when they are “related businesses” for purposes of measuring significance. As the analysis of the referenced participation agreement shows below, the acquired properties were not under common control or management. The acquisition purchase and sale agreements provided that each seller waived its rights under Section 7 of the Participation Agreement among Element Petroleum, LP (“Element”), CrownRock, L.P. (“CrownRock”) and CrownQuest Operating, LLC (“CrownQuest”), dated as of April 1, 2009 (the “Participation Agreement”). The Participation Agreement was a joint venture document with respect to certain oil and gas leases, originally owned solely by Element, by which Element sold a 50% interest in those leases to CrownRock. CrownQuest was the operator of the properties. The Participation Agreement also set forth a development and drilling plan. Section 7 of the Participation Agreement provided that each of Element and CrownRock would have the right under certain circumstances to participate in a proposed sale of the other’s interest in the properties covered by the Participation Agreement (the “tag-along rights”). As of May 10, 2012, the date of the purchase and sale agreements, the Participation Agreement had been fully performed except with respect to the tag-along rights. Under the Participation Agreement, each party maintained control and management of its respective business and assets, and consequently, the properties acquired separately by us from Element and CrownRock, were not under common control or management, and the Participation Agreement did not affect our acquisitions. The waiver of each party’s tag-along rights ensured that the acquisitions were not conditioned upon each other. These acquisitions also involved the purchase of additional working interests in oil and gas properties with different well locations from Element than the working interests purchased from CrownRock.
For the three Permian Basin acquisitions that closed in December 2012, each of these acquisitions involved the purchase of discrete working interests in oil and gas properties and each acquisition was negotiated separately with each seller. As these purchases also resulted in the Partnership acquiring each of the sellers’ individual rights and obligations to the oil and gas properties under the applicable joint operating agreements, we do not consider these separate purchases to be related businesses for purposes of Rule 3-05(a)(3). In regards to the two Permian Basin acquisitions we
Securities and Exchange Commission
May 16, 2013
Page 7
purchased from CrownRock that closed on July 2, 2012 and December 28, 2012, these acquisitions involved purchases of working interests in oil and gas properties with different well locations and were not considered to be related businesses for purposes of Rule 3-05(a)(3).
Lastly, we are providing the significant subsidiary calculations for our 2012 Permian Basin acquisitions as requested, each of which was deemed to be individually insignificant:
Significance Tests for 2012 Permian Basin Asset Acquisitions(1) | ||||||||
Date | Investment | Asset | Income | |||||
Acquired | Test % | Test % | Test % | |||||
Element Petroleum | 7/2/2012 | 6.17% | 6.17% | 10.74% | ||||
CrownRock | 7/2/2012 | 2.89% | 2.89% | 10.57% | ||||
CrownRock II | 12/28/2012 | 6.86% | 6.86% | 4.65% | ||||
Lynden | 12/28/2012 | 1.02% | 1.02% | 4.03% | ||||
Piedra | 12/28/2012 | 0.4% | 0.4% | 1.44% | ||||
Aggregate | 17.34% | 17.34% | 31.43% | |||||
(1) Income Test, Investment Test and Asset Test are based on our 2011 Full Year Audited Financial Statements. |
7. | We note that you have not presented pro forma financial information for the Permian Basin and other acquisitions as the impact of these acquisitions individually were not significant. Please explain to us how you have considered FASB ASC 805-10-50-3 when evaluating the disclosure requirements of ASC 805-10-50-2(h)(3). |
Response: We acknowledge the Staff’s comment and note for ASC 805-10-50-3, disclosure requirements are based upon whether an acquisition is considered to be material to the financial statements. The Partnership’s Permian Basin and other acquisitions were evaluated to determine their materiality to the financial statements using several measures (see table below). The Partnership initially reviewed the net income for each acquisition and determined that these amounts were not individually material to the consolidated financial statements, as most amounts were at or less than 5% of the Partnership’s consolidated net income on an individual basis. As the Partnership’s consolidated net loss for 2012 was substantially below the Partnership’s average consolidated net income for the prior five years, we performed our net income review using a 5 year average for the Partnership’s consolidated net income as prescribed in Regulation S-X Item 1.02(w)(3),note (2). In addition to net income, we reviewed the operating revenues for each acquisition and determined that these amounts were also individually not material to the consolidated financial statements, as the amount of operating revenues for each acquisition was less than 3% of the Partnership’s consolidated net revenues for 2012. Lastly, we reviewed the estimated net revenues less direct operating expenses for each acquisition and determined that these amounts were individually not material either to the Partnership’s consolidated cash flows from operating activities or to the Partnership’s adjusted EBITDA as the estimated net revenues less direct operating expenses for each acquisition was less than 5% of the Partnership’s cash flows from operating activities and less than 3% of adjusted EBITDA, respectively, for 2012.
Securities and Exchange Commission
May 16, 2013
Page 8
We also noted that aggregated revenues, aggregated cash flows from operating activities as well as aggregated adjusted EBITDA for the acquisitions were not material to the financial statements as the aggregated estimated net revenues less direct operating expenses for the acquisitions were at or less than 6% of the Partnership’s revenues, 10% of the Partnership’s cash flows from operating activities and 7% of Partnership’s adjusted EBITDA, respectively, for 2012. As noted in our response to comment five above, the Partnership presents adjusted EBITDA as we believe it provides additional information relative to the performance of the Partnership's business that may be useful to some investors. While we do not believe adjusted EBITDA should be considered as an alternative to GAAP measures - such as net income, operating income, or cash flow from operating activities - or any other GAAP measure of liquidity or financial performance, we believe that adjusted EBITDA provides an added measure that may be used by some to evaluate the operations of our business and measure the operating performance of our assets.
2012 Acquisitions(1) - Results of Operations | |||||||||||
% of 2012 Operating Results from 2012 Asset Acquisitions | |||||||||||
Net Cash Flow From Operating Activities | |||||||||||
5 Year Avg. | Adjusted | ||||||||||
Date | Revenue | Net Income | Net Income(2) | EBITDA | |||||||
Acquired | % | % | % | % | % | ||||||
Nimin | 6/28/2012 | 1.31% | (5.98)% | 2.33% | 1.76% | 1.14% | |||||
Element Petroleum | 7/2/2012 | 2.26% | (13.15)% | 5.13% | 4.55% | 2.95% | |||||
CrownRock | 7/2/2012 | 1.47% | (10.22)% | 3.98% | 3.34% | 2.17% | |||||
CrownRock II | 12/28/2012 | 0.07% | (0.58)% | 0.23% | 0.18% | 0.12% | |||||
Lynden | 12/28/2012 | 0.01% | (0.09)% | 0.04% | 0.03% | 0.02% | |||||
Piedra | 12/28/2012 | 0.01% | (0.04)% | 0.02% | 0.01% | 0.01% | |||||
Aggregate | 5.13% | (30.07)% | 11.72% | 9.87% | 6.40% | ||||||
(1) Excludes individually significant acquisitions, for which pro forma financial statements have been filed. | |||||||||||
(2) Our 2012 net income is 10% or more lower than the average for the last five years. As such, we have used the 5 year average income. |
Securities and Exchange Commission
May 16, 2013
Page 9
Note 9: Impairments and Price Related Depletion and Depreciation Adjustments, page F-23
8. | We note in your disclosure that you recorded impairment charges of $12.3 million related to uneconomic proved properties in Michigan, Indiana and Kentucky due to a decrease in expected future natural gas prices and on page F-39 that you had negative revisions of 31% for natural gas. Please clarify for us why the amount of the impairment was not larger when compared to the significance of the revisions and the cost basis for these properties, and why impairment was unnecessary for the related properties and midstream assets. We note that your Michigan, Indiana and Kentucky properties were acquired at the end of 2007 and $1.1 billion was allocated to proved properties, $0.2 billion was allocated to unproved properties, and $0.1 billion was allocated to pipelines and processing facilities. As part of your response, please provide us a summary of the undiscounted and discounted cash flow analyses performed in connection with your impairment testing for the Michigan Antrim Shale reserves. |
Response: We acknowledge the Staff’s comment and note that on page F-39 under the paragraphs entitled “Revisions of Previous Estimates”, we disclose that we had total negative proved reserve revisions of previous estimates amounting to 27.1 MMBoe in 2012 primarily related to a decrease in natural gas prices. The unweighted average first-day-of-the-month natural gas price of $2.76 per MMBtu was used in estimating our proved natural gas reserves as of December 31, 2012 as compared to the unweighted average first-day-of-the-month natural gas price of $4.38 per MMBtu that was used to estimate our proved natural gas reserves at December 31, 2011. Using the December 31, 2012 natural gas price, the related natural gas reserve calculations resulted in a downward volume revision at December 31, 2012 of 185,627 MMcf of natural gas reserves or approximately 31% of our December 31, 2011 natural gas volumes. The volume decrease is primarily due to the negative effect the decrease in natural gas prices had on the Partnership’s Antrim Shale natural gas reserves in Michigan (131,932 MMcf) and on the natural gas reserves for four of its southwestern Wyoming producing fields (55,027) partially offset by a smaller positive natural gas reserve revision in California.
On pages F-10 and F-11 of the Partnership’s Form 10-K for the year ended December 31, 2012, the Partnership discloses in its accounting policy for asset impairment that long-lived assets are tested for impairment periodically and when events and circumstances indicate that the assets’ carrying values may not be recoverable from the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets. The Partnership tests its oil and gas producing properties for impairment on a field by field basis using the undiscounted future cash flows based on total proved and risk-adjusted probable and possible reserves in accordance with ASC 932-360-35-8. Undiscounted cash flows are calculated using NYMEX forward strip prices at the end of the period and escalated along with expense and capital starting at year six and thereafter at 2.5% per year. For the impairment tests that the Partnership conducted at December 31, 2012, the associated properties’ expected future cash flows were discounted using a weighted average cost of capital which approximated 10%. Of the $12.3 million in impairment costs the Partnership recorded in 2012, approximately $6.6 million was related to a natural gas field in Indiana, $3.3 million was related to various non-Antrim gas fields in Michigan and $2.3 was related to an oil and gas field in California.
Securities and Exchange Commission
May 16, 2013
Page 10
Because the five year natural gas strip prices at December 31, 2012 were in excess of an average $4 per MMBtu, the undiscounted proved and risk-adjusted probable and possible reserve cash flows related to the Partnership’s Antrim Shale natural gas operations in Michigan as well as its southwestern Wyoming natural gas operations were all in excess of the assets’ carrying values and did not require impairment during 2012. As a result, we are providing the undiscounted cash flows only since the discounted cash flows did not require consideration in the performance of the impairment tests. Summarized below are the results for the impairment tests performed as of December 31, 2012 for the fields representing the negative proved natural gas reserve revisions as discussed in the preceding paragraphs:
Field Name (1) | Undiscounted Cash Flows ($000) | Net Book Value ($000) | Impairment Required? | |||||||
Antrim | $ | 1,227,710 | $ | 891,421 | No | |||||
WY Field 1 | $ | 57,524 | $ | 24,452 | No | |||||
WY Field 2 | $ | 42,184 | $ | 17,473 | No | |||||
WY Field 3 | $ | 905,833 | $ | 219,820 | No | |||||
WY Field 4 | $ | 10,304 | $ | 6,687 | No | |||||
(1) Wyoming field names have been obscured for competitive reasons. |
Supplemental Information, page F-36
Oil and Natural Gas activities (Unaudited), page F-36
9. | We note the Company states on page F-36 that “the definition of proved reserves incorporates a definition of “reasonable certainty” using the PRMS (Petroleum Resource Management System) standard of “high degree of confidence” for deterministic method estimates or a 90% recovery probability for probabilistic methods used in estimating proved reserves.” As you are disclosing proved reserves based on the definitions contained in Rule 4-10(a) of Regulation S-X, please revise your disclosure to refer to the definition of reasonable certainty as set forth in Rule 4-10(a)(24) of Regulation S-X. |
Response: We acknowledge the Staff’s comment and we will revise our disclosure in the future beginning with our Form 10-K for the year ended December 31, 2013 as follows, “Our proved reserves are estimated by third-party reservoir engineers and in accordance with SEC guidelines. We are reasonably certain that the estimated quantities will equal or exceed the estimates. Reserve estimates are expected to change as economic assumptions change and additional engineering and geoscience data becomes available. For reserve reporting purposes, we use unweighted average first-day-of-the-month pricing for the 12 calendar months prior to the end of the reporting period. Costs are held constant throughout the projected reserve life.”
Securities and Exchange Commission
May 16, 2013
Page 11
Exhibit 99.2
10. | We note the reserves report does not clarify if estimates of proved developed non-producing and proved undeveloped reserves have only been included for properties that have positive present worth discounted at 10 percent. Please advise or ask the engineering firm to provide you with an amended reserves report consistent with the disclosure provided in Exhibit 99.1 to comply with disclosure under Item 1202(a)(8)(v) of regulation S-K. |
Response: We acknowledge the staff’s comment and have confirmed with our reserve engineering firm that they will amend their reserves report in the future beginning with our Form 10-K for the year ended December 31, 2013 to include the following sentence, “As requested, estimates of proved developed non-producing and proved undeveloped reserves have only been included for properties that are economically producible at existing economic conditions.”
Exhibit 99.3
11. | We note the reserve report does not include disclosure of the purpose for which it was prepared, e.g., for inclusion as an exhibit in a filing made with the SEC. Please advise the engineering firm that you will need an amended reserves report to comply with disclosure under Item 1202(a)(8)(i) of regulation S-K. |
Response: We acknowledge the Staff’s comment and have confirmed with our reserves engineering firm that they will amend their reserves report in the future beginning with our Form 10-K for the year ended December 31, 2013 to include a disclosure that states “This report has been prepared for BreitBurn Operating L.P.’s use in filing with the Securities and Exchange Commission.”
The Partnership acknowledges that (1) it is responsible for the content of its filings, including the adequacy and accuracy of the disclosures in its filings, (2) Staff comments or changes to disclosures in response to Staff comments do not foreclose the Commission from taking any action with respect to such filings, and (3) the Partnership 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.
Should you have any questions regarding this response, you may contact the Partnership’s General Counsel, Greg Brown, at (213) 225-0294 or me at (213) 225-0273.
Sincerely,
/s/ James G. Jackson
James G. Jackson
Chief Financial Officer
BreitBurn Energy Partners L.P.
cc: Roberta E. Kass
Lawrence C. Smith