July 11, 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 June 20, 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.
Securities and Exchange Commission
July 11, 2013
Page 2
Form 10-K for the Fiscal Year Ended December 31, 2012
Business, page 4
Reserves and Production, page 7
1. | We have read your response to prior comment 2, including your analysis of the disclosure requirements of Item 1203(d) of Regulation S-K. We note your view is expressed relative to the disclosure of the reasons for material amounts of proved undeveloped reserves that remain undeveloped for five years or more after disclosure. We reissue our prior comment 2 and ask that you 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 these reserves. Please clarify for us the net quantities, if any, and provide an explanation of the circumstances that would justify a time period longer than five years to begin development of those reserves. |
Response: We acknowledge the Staff’s comment and note that as of December 31, 2012 approximately 3.3 MMBoe of proved undeveloped (PUD) reserves, or a little over two percent of our total reserves are scheduled to be developed outside of five years from their initial disclosure (but all are scheduled to be developed within the next five years and within five years of the date of our 2012 Form 10-K). The standardized measure of discounted future cash flows associated with these PUD reserves is approximately $23.6 million or about one percent of the total standardized measure of $1.99 billion as reported for 2012. We consider these amounts to be immaterial to the proved reserve and standardized measure of discounted cash flow disclosures in our 2012 Form 10-K. These PUD reserves were all originally scheduled to be developed within five years from their initial disclosure. However, while progress has been made toward first production, due to changes in circumstances and commodity pricing beyond our control, the projects have been delayed. Pursuant to Staff’s request, listed below are the PUD reserves at year end 2012 that are more than five years from their initial disclosure. Approximately 2.4 MMBoe of PUD reserves are scheduled to be brought online at various times between 2015 and 2017 which is between five and six years of their initial disclosure. The remaining 0.9 MMBoe are scheduled to be brought online between 2016 and 2017 or between six and seven years of their initial disclosure.
Of the 3.3 MMBoe PUD reserves noted above, approximately 3 MMBoe pertains to various non-Antrim oil and gas operations in Michigan and 0.3 MMBoe pertains to oil and gas fields in Wyoming. We discuss below for each project the explanation for the delay in implementation and the current timetable for development.
Michigan PUD Reserves:
1) About 0.9 MMBoe of PUD reserves pertain to a non-Antrim oil and gas field located in central Michigan. This field was acquired in late 2007 as part of our Michigan/Indiana/Kentucky asset acquisition from Quicksilver Resources, Inc. (“the Quicksilver acquisition”). Total capital expenditures for this field as of December 31, 2012 including
Securities and Exchange Commission
July 11, 2013
Page 3
the cost of acquisition were approximately $36 million. The field consists of six producing wells. As a result of favorable drilling results in certain areas of the field, the company began acquiring additional acreage in 2010 contiguous to the field. The Partnership is currently evaluating its acreage position in anticipation of pinpointing delineation well locations. Further development was delayed pending the evaluation and additional acreage acquisition. One infill well and three delineation wells are planned for the field in the years 2015 – 2016. Capital expenditures related to these wells are expected to approximate $15 million gross or $12.3 million net. The Partnership is also reviewing additional lease locations in an effort to increase our adjacent acreage position and working interests in the area for these well locations as well as signing new leases at more favorable terms.
2) Approximately 0.8 MMBoe of PUD reserves pertain to our Beaver Creek/Garfield field complex located in northern lower Michigan. This complex was also acquired in late 2007 as part of the Quicksilver acquisition. Garfield consists of a large oil and gas field that is adjacent to the Beaver Creek field and plant. Total capital expenditures for Garfield including the cost of acquisition were approximately $91 million at December 31, 2012. The field consists of 34 producing wells and two salt water disposal wells. Of the 0.8 MMBoe in proved undeveloped reserves for the Beaver Creek/Garfield complex at December 31, 2012, approximately 0.4MMBoe of PUD reserves were associated with additional drilling planned for 2017 at Garfield. This additional drilling is expected to cost $3.8 million gross, $3.7 million net. Drilling in this and each of the following three Michigan gas projects was delayed and reprioritized in our development plans as a result of significant and sustained decline in natural gas prices. We currently anticipate a rise in natural gas prices due to the improving domestic economy and expect to develop these projects within the time periods indicated.
The Beaver Creek complex consists of a large oil and gas field, a natural gas treatment/product separation plant as well as a 99 mile pipeline that transports production from the Beaver Creek plant to the Monitor sales line in lower eastern Michigan. The field consists of 76 producing wells and two injection wells. Total capital expenditures for the Beaver Creek complex including the cost of acquisition were approximately $177 million through December 31, 2012. Additional drilling and water flood expansion is planned for the Prairie du Chien reservoir underlying the Beaver Creek field for 2016. Of the 0.8 MMBoe in proved undeveloped reserves for the Beaver Creek/Garfield complex at December 31, 2012, the PUD reserves associated with Beaver Creek work was approximately 0.4 MMBoe and is expected to cost $3.8 million gross and $1.82 million net. Capital was spent in 2012 on one PUD water flood location and we are expecting the water flood response by 2016. This well will move from PUD to PDNP (proved developed non-producing) for year end 2013 reserve reposting.
3) Approximately 0.7 MMBoe of PUD reserves pertain to three drilling locations planned for 2015, 2016 and 2017 in the Kawkawlin Field located in lower eastern Michigan. This field was acquired in 2007 as part of the Quicksilver acquisition and total capital expenditures including the cost of acquisition were approximately $6 million at December 31, 2012. The field consists of three producing wells. The three PUD wells in this field were delayed in the development plan as a result of significantly declining natural gas
Securities and Exchange Commission
July 11, 2013
Page 4
prices. We currently anticipate that those prices will sufficiently recover within the specified time frame.
4) Approximately 0.6 MMBoe of PUD reserves pertain to two drilling wells planned for 2016 in the Sherman Field located in northern lower Michigan. This field was acquired in 2007 as part of the Quicksilver acquisition. Total capital expenditures for the Sherman field including the cost of acquisition were approximately $34 million at December 31, 2012. The field consists of four producing wells. The three PUD wells in this field were delayed in the development plan as a result of significantly declining natural gas prices. We currently anticipate that those prices will sufficiently recover within the specified time frame.
Wyoming PUD Reserves:
1) Approximately 0.2 MMBoe of proved undeveloped reserves relate to two wells planned for 2017 in a Southwestern Wyoming oil and gas field that was acquired in late 2011 as part of our acquisition of oil and gas properties from Cabot Oil & Gas Corporation. Costs for these wells are estimated to be $3.6 million gross and $0.8 million net. Total Capital expenditures for this southwest Wyoming field including the cost of acquisition were approximately $54 million at December 31, 2012. One of these PUD locations has a lower working interest and we are attempting to increase our interest before drilling this well. Another operator has permitted two wells that directly offset our other PUD location. This well will target the Dakota and Frontier formations and we are waiting on the results of the other operator to become known before we spud our well, which could be as early as 2013. These PUD locations were also delayed and reprioritized in the development plan as a result of significantly declining and sustained lower natural gas prices.
2) The remaining 0.1 MMBoe of PUD reserves pertain to one well planned for 2015 in Gebo field located in central Wyoming. This field was acquired in 2004 and total expenditures including the cost of acquisition were approximately $34 million as of December 31, 2012. We currently have 44 producing wells and eight injection wells. Four Gebo PUD locations were added to reserves in 2009 of which three PUDs remained on the books as of 2012. Management has adopted a one-well per year drilling program in 2011 that was established with drilling one location in 2012. The location scheduled for 2013 is currently drilling. Management plans to continue with the drilling plan through 2015 which results in the last PUD scheduled for development in March 2015. The one well per year program was built on the idea of gathering sufficient production data for future infill-drills/spacing allowances.
While we continue to be reasonably certain that the foregoing described PUD wells will be drilled within five years, due to the immaterial nature of our reserves which fall within a strict initial five-year test period and in order to avoid future analysis of the reasons for the delay, the Partnership will prospectively apply to our reserves disclosure a strict cut-off of the five year rule. That is, any PUD location where operations are scheduled to begin more than five years from the date of initial disclosure of the PUD location will not be reported as proved undeveloped reserves.
Securities and Exchange Commission
July 11, 2013
Page 5
Developed and Undeveloped Acreage, page 11
2. | We have read your response to prior comment 4 regarding your Michigan proved undeveloped locations. Please tell us if all of the locations are included in a development plan adopted by management as of December 31, 2012 indicating these locations are scheduled to be drilled within five years of their initial disclosure as proved undeveloped reserves. Refer to point (ii) in the definition of undeveloped oil and gas reserves contained in Rule 4-10(a)(31) of regulation S-X and Question 131.04 in the Compliance and Disclosure Interpretations issued October 26, 2009 in formulating your response. |
Response: We acknowledge the Staff’s comment and note that of the Michigan leases scheduled to expire during 2013 that contained PUD reserves at December 31, 2012, approximately 320 MBoe or 46% of the 692 MBoe total PUD reserves associated with these leases are for locations that are scheduled to begin drilling in 2015 or within five years of their initial disclosure. The remaining 54% or 372 MBoe of PUD reserves relate to drilling locations that are scheduled to begin operations in 2016. The 372 MBoe of PUD reserves are included in the 0.9 MMBoe of Michigan PUD reserves located in central Michigan as reported in paragraph 1 under “Michigan PUD Reserves” in response to comment 1 above.
As noted in our response to comment 1 above, one infill well and three delineation wells are scheduled for this field for the years 2015 – 2017. Rule 4-10(a)(31)(i) of Regulation S-X states that Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. While the Partnership has reasonable certainty that these undrilled PUD locations are producible, there are currently other projects in the Partnership’s portfolio that have higher priority. As noted in Rule 4-10(a)(31)(ii) of Regulation S-X, undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Although the operations planned for this field are consistent with what are described in Question 131.06, some of the operations – in particular as they relate to the delineation wells – will be drilled outside of five years from the date of their initial disclosure due to further leasing to increase our working interests and delays in the development plan as a result of significantly declining and sustained lower natural gas prices.
As noted in our response to comment 1, we consider the amount of reserves scheduled to be developed outside of five years from their initial disclosure (but still scheduled to be developed within the next five years) to be immaterial as of December 31, 2012. In future reports, the Partnership will prospectively apply to our reserves disclosure a strict cut-off of the five year rule. That is, any PUD location where operations are scheduled to begin more than five years from the date of initial disclosure of the PUD location will not be reported as proved undeveloped reserves.
Securities and Exchange Commission
July 11, 2013
Page 6
Selected Financial Data, page 46
3. | We have read your response to prior comment 5 and understand that you have included net operating cash flows generated by properties or businesses prior to your ownership in calculating your non-GAAP measure of Adjusted EBITDA, because you had negotiated purchase price adjustments based on activity between the effective and closing dates of these acquisitions. However, since you correlate the activity with your historical results, not as a purchase price adjustment along with other acquisition costs, the result has a pro forma or forward looking quality. You indicate this was not your intent. |
We note that you had no entitlement prior to the closing dates and neither consolidated the acquired properties or businesses nor recorded the economic benefits as of the effective dates. Given the foregoing, we do not see appropriate rationale for presenting as your own activity that of other entities prior to establishing ownership. Please revise your presentation to eliminate these types of adjustments from non-GAAP measures that are correlated with your historical results of operations.
Response: We acknowledge the Staff’s comments and confirm that the net operating cash flows from the effective dates to the closing dates attributable to the oil and gas properties that were acquired by the Partnership in 2012 were recorded in the Partnership’s financial statements as adjustments to the purchase price as required by Generally Accepted Accounting Principles (GAAP) (see FASB ACS 805-10-25-7). However, because those net operating cash flows were characteristic of the asset’s operating performance during periods for which the Partnership was legally entitled to receive value for those cash flows and the Partnership actually received the cash benefits for these amounts, we believe that the inclusion of those cash flows in our non-GAAP measure of Adjusted EBITDA was appropriate. We reiterate that because we did not include net operating cash flows attributable to the assets acquired for periods in which we were not legally entitled to receive value for those cash flows - as is part of the requirements for pro forma disclosures contained in Regulation SX Item 11-02 - we believe this does not constitute a pro forma disclosure.
However, because of the volatility encountered with estimating the amount of time required to effectively negotiate and close our oil and gas transactions as well as further complications associated with identifying and segregating other operating cash flow items attributable to this period that may arise with future acquisitions, effective January 1, 2013, the Partnership will no longer report net operating cash flows from acquisitions from the effective date to the closing date as a component of our Adjusted EBITDA. In future reports, we will also conform our prior period disclosures of Adjusted EBITDA.
Securities and Exchange Commission
July 11, 2013
Page 7
4. | We note that you present realized and unrealized gain or loss on derivatives accounted for at fair value on page 54, with a discussion of the changes on pages 55 and 60, and present within your reconciliation of Adjusted EBITDA, an adjustment to eliminate the unrealized portion of the gain or loss related to commodity derivative instruments. Tell us how you determine the realized and unrealized portions of these gains and losses so that we may understand how your method complies with FASB ASC 815-10-35-2. For example, if realized gains do not reflect only the change in fair value during the period of settlement, identify the specific elements reflected in each measure (e.g., premiums paid, the change in fair value from period-to-period, and settlement proceeds/payments). Please explain your rationale in leaving only the realized portion of derivative gain or loss reflected in your measure of Adjusted EBITDA, given that prior changes in fair value would ordinarily also comprise the overall economics of settlement. |
Response: We acknowledge the Staff's comment and note that the Partnership does not use hedge accounting for financial accounting purposes for its commodity derivative instruments or its financial derivative instruments (derivative instruments) as disclosed in our significant accounting policies on pages 64 and F-12 of our 2012 Form 10-K. All changes in fair value of the Partnership's derivative instruments are reported currently in net income as required by FASB ASC 815-10-35-2. When the Partnership enters into a derivative instrument, the derivative instrument is recorded on the balance sheet as a derivative instrument asset or liability at its fair value which includes any premiums paid. Subsequent increases/decreases in fair value due to changes in the market prices of the underlying item as well as changes in the time value of any option component of the derivative instruments are recognized as unrealized gains or losses on the Partnership's consolidated statement of operations in the period of change as these changes do not involve cash realizations in the current period.
When a derivative instrument ultimately settles, any remaining derivative instrument asset or liability is removed from the balance sheet (with a corresponding unrealized loss or gain equal to the amount of the asset or liability that was remaining on the balance sheet from the prior period before settlement) and a realized gain or loss is recognized based on the settlement amount of the contracts. The realized gain or loss includes amounts to be paid/received for the difference between the contract price and the index price at the time of settlement less deferred contract premiums (if any) that are due at the time of contract settlement. Realized gains/losses also include payments/receipts due to early terminations of our financial derivatives.
Securities and Exchange Commission
July 11, 2013
Page 8
For example -
If a derivative swap contract for December 2012 production which was valued at $0 ($80 contract price was equal to market price) when the contract was entered into on December 31, 2010, had a fair market value (“FMV”) at December 31, 2011 of $10 (market price moved to $70), and the contract settled in December 2012 at $50 (FMV was $30):
At December 31, 2010, there would be no entry as the contract was entered into at market. At December 31, 2011, we would recognize a mark-to-market (“MTM”) change in the derivative asset of $10 and an unrealized gain of $10. At December 31 2012, we would recognize a MTM change in the derivative asset of $20 and an unrealized gain of $20. To record the settlement, we would recognize a realized gain of $30, cash of $30, an unrealized loss of $30 (to reverse the life to date unrealized gain) and a $30 decrease in our derivative asset. Adjusted EBITDA for 2010 and 2011 would not be impacted by this contract. Adjusted EBITDA for 2012 would include the $30 realized gain and exclude the $30 unrealized loss.
As noted on page 46 of our 2012 Form 10-K, one of the ways we use Adjusted EBITDA is to assess the ability of our assets to generate cash sufficient to pay interest cost and support our indebtedness. Therefore we do not include unrealized gains and losses in our Adjusted EBITDA. By including the cash effects attributable to the derivative instruments in the period in which the derivative instruments are actually settled, we are better able to assess the net cash operating requirements for the periods that the Partnership's cash payment obligations are scheduled.
For 2012, we had approximately $0.9 million of pre-paid of amortization related to premiums on contracts that settled in 2012. This amount was included in the unrealized loss recorded in 2012 and was not reported as part of the realized gain. We consider this amount to be immaterial. We did not pay any pre-paid premiums during 2008 through 2011 and did not recognize any amortization of pre-paid premiums during these years.
Securities and Exchange Commission
July 11, 2013
Page 9
Shown below is a summary reconciliation of what was included in our realized and unrealized gains/losses for the period 2008 - 2012. In future reports, we will add a disclosure to our Adjusted EBITDA table indicating the total amount of pre-paid premiums made during the period as well as apportion the amount of pre-paid premiums made in prior periods to the production periods to which those derivative instruments pertain.
Summary of Deferred and Pre-paid Premiums related to contracts settled in 2008-2012 ($ in thousands) | Year Ended December 31, | |||||||||||||||||||
2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||
Realized gain (loss) | ||||||||||||||||||||
Contracts settled excluding deferred premiums | $ | 82,136 | $ | (19,324 | ) | $ | 65,558 | $ | 155,684 | $ | (58,312 | ) | ||||||||
Deferred premiums (paid at settlement) | — | — | (1,820 | ) | (1,116 | ) | (355 | ) | ||||||||||||
Total realized gain (loss) (net cash settlement) | $ | 82,136 | $ | (19,324 | ) | $ | 63,738 | $ | 154,568 | $ | (58,667 | ) | ||||||||
Unrealized gain (loss) | ||||||||||||||||||||
Change in FV of contracts settling in future periods | $ | (76,798 | ) | $ | 98,214 | $ | (33,116 | ) | $ | (213,251 | ) | $ | 370,734 | |||||||
Pre-paid premium amortization on contracts settled during the period | (859 | ) | — | — | — | — | ||||||||||||||
Total unrealized gain (loss) | $ | (77,657 | ) | $ | 98,214 | $ | (33,116 | ) | $ | (213,251 | ) | $ | 370,734 | |||||||
Year Ended December 31, | ||||||||||||||||||||
Premiums paid ($ in thousands) | 2012 | 2011 | 2010 | 2009 | 2008 | |||||||||||||||
Pre-paid premiums paid by year (commodity derivative asset) | $ | 30,043 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Year Ended December 31, | ||||||||||||||||||||
Future years ($ in thousands) | 2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||
Pre-paid premiums paid on contracts to be settled (pertaining to the periods in which the underlying production will be sold (1)) | $ | 734 | $ | 8,390 | $ | 6,673 | $ | 8,495 | $ | 4,893 | ||||||||||
Deferred premiums to be paid at settlement (to be recognized in realized gain/loss) | $ | — | $ | — | $ | — | $ | 657 | $ | 892 | ||||||||||
(1) Assumes constant pricing from premium payment date to contract settlement date. |
Securities and Exchange Commission
July 11, 2013
Page 10
Financial Statements
Note 4 – Acquisitions, page F-13
Permian Basin Acquisitions, page F-14
5. | We have read your response to prior comment 6 pertaining to guidance in Rule 3-05 of regulation S-X, relative to your July 2, 2012 acquisitions and understand that you do not regard these transactions as related because under the May 10, 2012 agreements, each seller waived rights to participate in a proposed sale of the other’s interest, given that these waivers occurred as part of the contemporaneously signed purchase and sale agreements, we do not see why you would not conclude that the provisions had accomplished their objective. In determining whether the transactions are related under Rule 3-05(a)(3) of Regulation S-X, the conditional elements should be evaluated relative to the uncertainty they were intended to address. Unless we have misunderstood the conditional aspects of the tag-along rights prior to securing the May 10, 2012 agreements, it appears you would need to file historical and pro forma financial statements for the property interests acquired in your July 2, 2012 acquisitions to comply with Item 9.01 of form 8-K and Rule 3-05 and Article 11 of regulation S-X. |
Response: We acknowledge the staff’s further inquiry regarding the question of whether our acquisitions of properties from Element Petroleum, LP (“Element”) and the acquisition of property from CrownRock, L.P. (“CrownRock”) and CrownQuest Operating, LLC (“CrownQuest”; together with CrownRock, “Crown”) constituted the acquisition of “related businesses.” Respectfully, we fail to understand how these separate acquisitions could be viewed as conditional on the acquisition of the other on the facts presented. Because these separate acquisitions do not fall within any of the three definitions of related businesses within S-X Rule 3-05(a)(3), the acquisitions were properly treated as not related under the rule. As indicated in our letter dated May 16, 2013, the properties in question were owned by totally separate and independent entities. They were not under common control or management.
The second prong of the S-X Rule 3-05(a)(3) test turns on whether “the acquisition of one business is conditional on the acquisition of the other business.” In the present case, the two separate acquisitions were in no way conditioned on each other. Element originally offered its interests in certain oil wells and related lands for sale. BreitBurn and Element agreed upon the terms of that sale. We became aware during negotiations that Crown had a “tag along” right with respect to Element pursuant to an existing Participation Agreement (described in detail in our May 16, 2013 letter) which would give Crown the option to sell its interests in the same properties being sold by Element but only on the same terms and conditions, including price. During our negotiations with Element, Element repeatedly informed us that Crown would not exercise the “tag along” rights. We had no communication with Crown during this period due to the confidentiality requirements of the transaction. Once we had the material terms of a transaction tentatively agreed with Element, Element disclosed the terms of the transaction to Crown as required under the
Securities and Exchange Commission
July 11, 2013
Page 11
Participation Agreement to give those entities their opportunity to elect to participate. Under the Participation Agreement, Crown would have had the right to sell their interests in the same wells Element was selling to us for a proportionate price. Had Crown exercised their rights under the tag along provision, then the two transactions would have been conditioned on one another and would have been treated as a single transaction. However, quite the opposite happened. Crown declined to exercise their right to join the Element transaction. We were informed that they did not agree with the price being paid to Element and that they had other objections to the Element deal. We were fine with that decision and were prepared to close the original transaction with Element.
However, as a result of the opening of direct discussions between us in the course of Crown reviewing the tag along option, we and Crown began discussing an independent transaction on different terms and for different interests in the area in which we were acquiring interests from Element. As an example of how the two deals were negotiated separately and were not the result of tag along rights, the deals had different prices on interests in the same wells. For example, Crown and Element each had a 50% interest in the Lindsay A5 #4 well. The value of that well set forth in the Element deal was $11.7 MM while the equivalent interest in the Crown deal was $9.1 MM. Obviously the prices would have been the same if the deal was a tag along. Further, we did not acquire all of Crown’s interests in the wells acquired from Element. Many interests were retained by Crown. The Crown transaction also featured provisions providing for Crown to continue to operate certain of the wells they had previously operated. That would not have been the case if they had exercised their tag along rights and sold their interests. In short, had the transactions been linked through the tag along provision, the price and property interests acquired would have been the same. They were not.
We were prepared to close on either or both of the transactions. One was not conditional on the other. It is worth noting that we have done a subsequent standalone transaction with Crown to acquire additional oil interests which they have developed in the same area as was involved in the transactions under discussion here. The subsequent transaction was patterned after and closely resembled the first transaction with Crown. Both of our transactions with Crown are standalone deals and not conditioned on any other acquisition. Staff has inquired concerning the purpose of Crown’s waiver of the tag along provision. Because Crown had in fact waived its tag along rights, we provided in the acquisition agreement the acknowledgment and agreement to expressly terminate that provision so that there would be no question of its applicability in the future. While an argument can be made that the express waiver was not necessary since by implication Crown had waived by entering into a separate transaction, we wanted a clear record so that Crown or its successors would not allege a breach or a continuing right to a future tag along.
Finally, the third and final prong of Rule 3-05(a)(3) is whether the Element and Crown transactions were conditioned on a single common event. As can be seen, this was not the case. Neither was dependent on the closing of the other nor any other common event.
Securities and Exchange Commission
July 11, 2013
Page 12
6. | We have read your response to prior comment 7, including your analysis of FASB ASC 805-10-50-3 and 805-10-50-2(h)(3). We note your view is expressed relative to the 5-year income averaging method of identifying significant subsidiaries pursuant to Rule 1-02(w) of Regulation S-X. However, this definitional guidance has a specific purpose other than use in materiality determination under GAAP. We also note that you have not indicated whether you had evaluated the materiality of the 2011 revenues and earnings of your 2012 acquisitions relative to your 2011 financial statements. |
The financial information included in your response to prior comments 6 and 7 indicates that your 2012 acquisitions may be material collectively or in certain cases, individually, for the purpose of disclosing supplemental financial information. We believe that any transactions that result in an obligation to file financial statements on Form 8-K would ordinarily be material in this context. If you continue to believe pro forma information is not required to be disclosed to comply with FASB ACS 805-10-50-3 then please expand your analysis to address significance beyond your income averaging approach and also encompassing activity relative to your 2011 historical results.
Response: We acknowledge the Staff’s comment and note that as explained in our response to comment 5 above, we continue to be of the opinion that none of our 2012 acquisitions for which we did not file historical audited financial statements requires us to file a Form 8-K containing historical audited financial statements under Rule 3-05 of Regulation S-X. This was outlined in the significant subsidiary test information that was prepared under Rule 1-02(w) of Regulation S-X which was previously provided to you in comment number six of our prior response letter dated May 16, 2013. We also previously provided 2012 information to you regarding our analysis as to whether we believed that any of these same acquisitions were material to the financial statements for purposes of pro forma disclosure under FASB ASC 805-10-50-3. Because the Partnership does not use hedge accounting for its derivative instruments, its net income can vary widely from period to period as evidenced by its reporting a net loss of $40.8 million for 2012 and net income of $110.5 million for 2011. Because of this volatility, we looked at other measures for 2012 in addition to net income including five year income averaging as well as net cash flows from operating activities and Adjusted EBITDA. Of the measures we looked at, we believe that Adjusted EBITDA was more comparable to the acquired assets’ revenues and direct operating expenses as it excludes the volatility of changes in the fair value of derivative instruments from period to period. Revenues and direct operating expenses or lease operating statements are also what sellers typically provide to prospective purchasers to help in evaluating oil and gas properties for purchase. Also, statements of revenues and direct operating expenses are generally what is prepared and audited for acquisitions of oil and gas properties for purposes of filing audited financial statements under Rule 3-05 of Regulation S-X. As noted in our prior response, revenues and Adjusted EBITDA for 2012 for the acquisitions in the aggregate were approximately 5% and 6% respectively and we did not consider these amounts to be material for 2012.
Securities and Exchange Commission
July 11, 2013
Page 13
In regards to whether we considered any of these acquisitions to be material for purposes of FASB ASC 805-10-50-2(h)(3) using 2011 income, we believe that the aggregation of individually immaterial business combinations occurring during the reporting period that are material collectively should be considered for pro forma disclosure in the aggregate if the aggregate amount of revenues, net income, etc. are also material to the current reporting period, and not merely to the prior year comparative period. Nevertheless, looking only at the comparative 2011 period, we have calculated the individual revenue and pro forma net income attributable to our 2012 acquisitions as a percentage of our 2011 audited results as shown below:
Full Year 2011 Historical Operating Results for 2012 BBEP Asset Acquisitions | |||||
% compared to BBEP's Historical 2011 Results | |||||
Date | Revenue | Net Income | |||
Acquired | % | % | |||
Nimin | 6/28/2012 | 4.35% | 2.75% | ||
Element Petroleum | 7/2/2012 | 4.23% | 5.42% | ||
CrownRock | 7/2/2012 | 4.16% | 6.59% | ||
CrownRock II | 12/28/2012 | 1.8% | (2.11)% | ||
Lynden | 12/28/2012 | 1.48% | 3.42% | ||
Piedra | 12/28/2012 | 0.56% | 0.75% | ||
Aggregate | 16.58% | 16.82% | |||
(1) Includes pro forma D&D and pro forma interest expense for acquisition financing. |
In addition to assessing quantitative data for purposes of determining materiality under ASC 805-10-50-3, we also looked at qualitative data for the acquisitions. Of the three acquisitions, acquired near the end of the second quarter, only Nimin’s operations remained relatively consistent year over year. Operations for CrownRock and Element in 2012 were up significantly year over year as both companies focused extensively on drilling new well locations in anticipation of putting their properties up for sale. Because much of the value for these acquired properties was in their ongoing development in 2012, comparisons of their 2011 operations to their 2012 operations are not meaningful. Also because the Partnership completed a major acquisition with significant gas properties in October 2011, the Partnership’s production was up substantially in 2012 as compared to 2011 while its revenues were up only slightly due to the drop off in natural gas prices in 2012 as compared to 2011. This impacts the comparison of the Permian Basin acquisitions’ revenues for 2011 versus 2012 as the Permian Basin properties produce mostly oil/liquids which command a higher price.
As noted above, the CrownRock II, Lynden and Piedra acquisitions were all acquired at the end of the year in 2012. Because a lot of the value for these acquisitions still lies in their future development, the 2012 and 2011 results for these three acquisitions were not material to our 2012 or 2011 operating results.
Securities and Exchange Commission
July 11, 2013
Page 14
Finally, when looking at 2011, none of the 2012 acquisitions listed above would be considered significant on their own or in the aggregate for purposes of Rule 1-02(w) of regulation S-X (i.e., 20% individually or 50% in the aggregate).
Taking into consideration the 2012 reporting period and considering the qualitative and quantitative facts and circumstances noted above, we continue to believe the 2012 acquisitions do not require disclosure under the requirements of ASC 805-10-50-3.
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