UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q/A
Amendment No. 1
x | Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the quarterly period ended March 31, 2013 |
or
o | Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the transition period from ___ to ___ |
Commission File Number 001-33055
BreitBurn Energy Partners L.P.
(Exact name of registrant as specified in its charter)
Delaware | 74-3169953 |
(State or other jurisdiction of | (I.R.S. Employer |
incorporation or organization) | Identification Number) |
515 South Flower Street, Suite 4800 | |
Los Angeles, California | 90071 |
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: (213) 225-5900
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x | Accelerated filer o |
Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No x
As of May 3, 2013 the registrant had 99,679,996 Common Units outstanding.
EXPLANATORY NOTE
BreitBurn Energy Partners L.P. (the “Partnership,” “we,” “us” or “our”) is filing this Amendment No. 1 on Form 10-Q/A (this “Amendment”) to amend its Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013, filed with the Securities and Exchange Commission (the “SEC”) on May 3, 2013 (the “Original 10-Q”).
This Amendment is being filed to amend the Original 10-Q as follows:
(a) Revised the Consolidated Statements of Cash Flows in Part I-Item 1 to remove the row titled “Unrealized loss on derivative instruments” under the header “Adjustments to reconcile to cash flow from operating activities” and replace it by a row titled “Loss on derivative instruments” that combines settled and mark-to-market gains on derivative instruments. Added a new row titled “Derivative instrument settlements” under the same header that includes cash attributable to commodity derivative instruments that settled during the periods.
(b) Part I-Item 1-Note 3 “Financial Instruments” - revised the tables presenting gain and loss on derivative instruments not designated as hedging instruments to remove the “Realized gain (loss)” and “Unrealized gain (loss)” rows and combine these amounts in a new row titled ��Net gain (loss).” Revised the tables setting forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3 to remove the “Realized gain (loss)” and “Unrealized loss” rows and combine these amounts in a new row titled “Loss.”
(c) Part I-Item 1-Note 6 “Acquisitions” - revised the pro forma revenue and net loss table to include aggregated pro forma information for our 2012 insignificant subsidiary acquisitions.
(d) Part I-Item 2-“Results of Operations” - (i) amended the results of operations table to combine “Realized gain on commodity derivatives” and “Unrealized loss on commodity derivatives” into a new row titled “Gain (loss) on commodity derivatives” and to exclude the effect of commodity derivative instruments from the average realized sales prices; (ii) replaced the section titled “Revenues” under “Comparison of Results of Operations” with separate sections titled “Oil, natural gas and NGL sales” and “Gain on commodity derivatives” to discuss sales revenues separately from gain (loss) on commodity derivatives including a discussion of settlements received or paid during the periods presented; and (iii) amended the section titled “Interest expense, net of amounts capitalized” and added “Loss on interest rate swaps” to discuss interest expense separately from loss on interest rate swaps.
This Amendment includes new certifications by our Principal Executive Officer and Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed as Exhibits 31.1, 31.2, 32.1 and 32.2, hereto. Each certification was true and correct as of the date of the filing of the Original 10-Q.
Pursuant to interpretation 246.14 in the Regulation S-K section of the SEC’s “Compliance & Disclosure Interpretations,” we are filing the Original 10-Q in its entirety as part of this Amendment.
Except as described above, we have not modified or updated other disclosures contained in the Original 10-Q. Accordingly, this Amendment, with the exception of the foregoing, does not reflect events occurring after the date of filing of the Original 10-Q, or modify or update those disclosures affected by subsequent events. Consequently, all other information not affected by the corrections described above is unchanged and reflects the disclosures and other information made at the date of the filing of the Original 10-Q and should be read in conjunction with our filings with the SEC subsequent to the filing of the Original 10-Q, including amendments to those filings, if any.
INDEX
Page No. | ||
PART I | ||
FINANCIAL INFORMATION | ||
PART II | ||
OTHER INFORMATION | ||
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
Forward-looking statements are included in this report and may be included in other public filings, press releases, our website and oral and written presentations by management. Statements other than historical facts are forward-looking and may be identified by words such as “believe,” “estimate,” “impact,” “future,” “affect,” “expect,” “will,” “plan,” “anticipate,” variations of such words and words of similar meaning. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report.
Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are changes in crude oil and natural gas prices; delays in planned or expected drilling; changes in costs and availability of drilling, completion and production equipment, and related services and labor; the discovery of previously unknown environmental issues; the competitiveness of alternate energy sources or product substitutes; technological developments; potential disruption or interruption of our net production due to accidents or severe weather; changes in governmental regulations, including the regulation of derivative instruments and the oil and natural gas industry; the effects of changes in accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; integration and other risks associated with our acquisitions; and the factors set forth under “Cautionary Statement Regarding Forward-Looking Information” and Part I—Item 1A “—Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2012 and in Part II—Item 1A of this report. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.
All forward-looking statements, expressed or implied, included in this report and attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
We undertake no obligation to update the forward-looking statements in this report to reflect future events or circumstances.
1
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Balance Sheets
Thousands | March 31, 2013 | December 31, 2012 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash | $ | 7,610 | $ | 4,507 | ||||
Accounts and other receivables, net | 58,473 | 67,862 | ||||||
Derivative instruments (note 3) | 17,844 | 34,018 | ||||||
Related party receivables (note 4) | 1,147 | 1,413 | ||||||
Inventory (note 5) | 7,465 | 3,086 | ||||||
Prepaid expenses | 1,576 | 2,779 | ||||||
Total current assets | 94,115 | 113,665 | ||||||
Equity investments | 7,133 | 7,004 | ||||||
Property, plant and equipment | ||||||||
Oil and gas properties | 3,411,617 | 3,363,946 | ||||||
Other assets | 15,325 | 14,367 | ||||||
3,426,942 | 3,378,313 | |||||||
Accumulated depletion and depreciation (note 7) | (712,545 | ) | (666,420 | ) | ||||
Net property, plant and equipment | 2,714,397 | 2,711,893 | ||||||
Other long-term assets | ||||||||
Derivative instruments (note 3) | 48,144 | 55,210 | ||||||
Other long-term assets | 25,630 | 27,722 | ||||||
Total assets | $ | 2,889,419 | $ | 2,915,494 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities | ||||||||
Accounts payable | $ | 42,159 | $ | 42,497 | ||||
Derivative instruments (note 3) | 11,691 | 5,625 | ||||||
Revenue and royalties payable | 21,038 | 22,262 | ||||||
Wages and salaries payable | 5,282 | 10,857 | ||||||
Accrued interest payable | 28,344 | 13,002 | ||||||
Accrued liabilities | 27,060 | 20,997 | ||||||
Total current liabilities | 135,574 | 115,240 | ||||||
Credit facility (note 8) | 85,000 | 345,000 | ||||||
Senior notes, net (note 8) | 755,697 | 755,696 | ||||||
Deferred income taxes (note 10) | 2,466 | 2,487 | ||||||
Asset retirement obligation (note 11) | 99,792 | 98,480 | ||||||
Derivative instruments (note 3) | 4,421 | 4,393 | ||||||
Other long-term liabilities | 4,576 | 4,662 | ||||||
Total liabilities | 1,087,526 | 1,325,958 | ||||||
Commitments and contingencies (note 12) | ||||||||
Equity | ||||||||
Partners' equity (note 13) | 1,801,893 | 1,589,536 | ||||||
Total liabilities and equity | $ | 2,889,419 | $ | 2,915,494 | ||||
Common units issued and outstanding | 99,680 | 84,668 |
See accompanying notes to consolidated financial statements.
2
BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Operations
Three Months Ended | ||||||||
March 31, | ||||||||
Thousands of dollars, except per unit amounts | 2013 | 2012 | ||||||
Revenues and other income items | ||||||||
Oil, natural gas and natural gas liquid sales | $ | 120,362 | $ | 94,007 | ||||
Loss on commodity derivative instruments, net (note 3) | (24,176 | ) | (36,005 | ) | ||||
Other revenue, net | 758 | 1,145 | ||||||
Total revenues and other income items | 96,944 | 59,147 | ||||||
Operating costs and expenses | ||||||||
Operating costs | 52,153 | 43,261 | ||||||
Depletion, depreciation and amortization | 47,790 | 38,281 | ||||||
General and administrative expenses | 14,863 | 13,674 | ||||||
(Gain) loss on sale of assets | (9 | ) | 125 | |||||
Total operating costs and expenses | 114,797 | 95,341 | ||||||
Operating loss | (17,853 | ) | (36,194 | ) | ||||
Interest expense, net of capitalized interest | 18,419 | 13,800 | ||||||
Loss on interest rate swaps (note 3) | — | 494 | ||||||
Other income, net | (2 | ) | (4 | ) | ||||
Loss before taxes | (36,270 | ) | (50,484 | ) | ||||
Income tax expense (benefit) (note 10) | 30 | (559 | ) | |||||
Net loss | (36,300 | ) | (49,925 | ) | ||||
Less: Net income attributable to noncontrolling interest | — | (45 | ) | |||||
Net loss attributable to the partnership | $ | (36,300 | ) | $ | (49,970 | ) | ||
Basic net loss per unit (note 13) | $ | (0.38 | ) | $ | (0.76 | ) | ||
Diluted net loss per unit (note 13) | $ | (0.38 | ) | $ | (0.76 | ) |
See accompanying notes to consolidated financial statements.
3
BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Cash Flows
Three Months Ended | ||||||||
March 31, | ||||||||
Thousands of dollars | 2013 | 2012 | ||||||
Cash flows from operating activities | ||||||||
Net loss | $ | (36,300 | ) | $ | (49,925 | ) | ||
Adjustments to reconcile to cash flow from operating activities: | ||||||||
Depletion, depreciation and amortization | 47,790 | 38,281 | ||||||
Unit-based compensation expense | 4,808 | 5,591 | ||||||
Loss on derivative instruments | 24,176 | 36,499 | ||||||
Derivative instrument settlements | 5,158 | 16,933 | ||||||
Income from equity affiliates, net | (129 | ) | 154 | |||||
Deferred income taxes | (21 | ) | (779 | ) | ||||
(Gain) loss on sale of assets | (9 | ) | 125 | |||||
Other | 905 | 809 | ||||||
Changes in net assets and liabilities | ||||||||
Accounts receivable and other assets | 11,455 | 30,670 | ||||||
Inventory | (4,379 | ) | (4,505 | ) | ||||
Net change in related party receivables and payables | 266 | 2,085 | ||||||
Accounts payable and other liabilities | 5,132 | (4,639 | ) | |||||
Net cash provided by operating activities | 58,852 | 71,299 | ||||||
Cash flows from investing activities | ||||||||
Capital expenditures | (38,143 | ) | (14,054 | ) | ||||
Proceeds from sale of assets | 9 | 507 | ||||||
Property acquisitions | (2,503 | ) | — | |||||
Net cash used in investing activities | (40,637 | ) | (13,547 | ) | ||||
Cash flows from financing activities | ||||||||
Issuance of common units | 285,152 | 166,155 | ||||||
Distributions | (40,602 | ) | (28,130 | ) | ||||
Proceeds from long-term debt | 72,000 | 310,885 | ||||||
Repayments of long-term debt | (332,000 | ) | (498,000 | ) | ||||
Change in bank overdraft | 338 | (2,097 | ) | |||||
Debt issuance costs | — | (5,513 | ) | |||||
Net cash used in financing activities | (15,112 | ) | (56,700 | ) | ||||
Increase in cash | 3,103 | 1,052 | ||||||
Cash beginning of period | 4,507 | 5,328 | ||||||
Cash end of period | $ | 7,610 | $ | 6,380 |
See accompanying notes to consolidated financial statements.
4
Notes to Consolidated Financial Statements
1. Organization and Basis of Presentation
The accompanying unaudited consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the year ended December 31, 2012 (the “Annual Report”). The financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. In the opinion of management, all adjustments considered necessary for a fair statement of our financial position at March 31, 2013, our operating results for the three months ended March 31, 2013 and 2012, and our cash flows for the three months ended March 31, 2013 and 2012, have been included. Operating results for the three months ended March 31, 2013 are not necessarily indicative of the results that may be expected for the year ended December 31, 2013. The consolidated balance sheet at December 31, 2012 has been derived from the audited consolidated financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements. For further information, refer to the consolidated financial statements and notes thereto presented in our Annual Report.
We follow the successful efforts method of accounting for oil and gas activities. Depletion, depreciation and amortization of proved oil and gas properties is computed using the units-of-production method, net of any estimated residual salvage values.
Amendment Explanatory Note
We have revised our financial statements to amend the presentation of the items described below. The revisions, which we determined are not material, had no impact on the financial statements or footnotes except as described below:
(a) Revised the Consolidated Statements of Cash Flows in Part I-Item 1 to remove the row titled “Unrealized loss on derivative instruments” under the header “Adjustments to reconcile to cash flow from operating activities” and replace it by a row titled “Loss on derivative instruments” that combines settled and mark-to-market gains on derivative instruments. Added a new row titled “Derivative instrument settlements” under the same header that includes cash attributable to commodity derivative instruments that settled during the periods. The revisions to the cash flow presentation had no impact on “Net cash provided by operating activities,” “Net cash used in investing activities” or “Net cash provided by (used in) financing activities.”
(b) Part I-Item 1-Note 3 “Financial Instruments” - revised the tables presenting gain and loss on derivative instruments not designated as hedging instruments to remove the “Realized gain (loss)” and “Unrealized gain (loss)” rows and combine these amounts in a new row titled “Net gain (loss).” Revised the tables setting forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3 to remove the “Realized gain (loss)” and “Unrealized loss” rows and combine these amounts in a new row titled “Loss.”
(c) Part I-Item 1-Note 6 “Acquisitions” - revised the pro forma revenue and net loss table to include aggregated pro forma information for our 2012 insignificant subsidiary acquisitions. The impact of the revision on pro forma revenue and net income for the three months ended March 31, 2012 was $24.2 million and $9.0 million, respectively.
Except as described above, we have not modified the presentation of the financial statements or updated any other part of the notes thereto.
2. Accounting Standards
In December 2011, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that requires companies to disclose information about financial instruments that have been offset and related arrangements to enable users of a company’s financial statements to understand the effect of those arrangements on its financial position. We are required to provide both net (offset amounts) and gross information in the notes to the financial statements for relevant assets and liabilities that are offset. This update was effective January 1, 2013 and requires retrospective application. We adopted this ASU, which expanded our financial statement disclosures, but did not have an impact on our financial position, results of operations or cash flows.
5
3. Financial Instruments
Our risk management programs are intended to reduce our exposure to commodity prices and interest rates and to assist with stabilizing cash flows and distributions. Routinely, we utilize derivative financial instruments to reduce this volatility. To the extent we have hedged a significant portion of our expected production through commodity derivative instruments and the cost for goods and services increases, our margins would be adversely affected.
Commodity Activities
The derivative instruments we utilize are based on index prices that may and often do differ from the actual crude oil and natural gas prices realized in our operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges under FASB Accounting Standards. Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial reporting purposes, and instead we recognize changes in fair value immediately in earnings.
We had the following commodity derivative contracts in place at March 31, 2013:
Year | |||||||||||||||||||
2013 | 2014 | 2015 | 2016 | 2017 | |||||||||||||||
Oil Positions: | |||||||||||||||||||
Fixed Price Swaps - NYMEX WTI | |||||||||||||||||||
Hedged Volume (Bbl/d) | 5,270 | 4,814 | 5,189 | 2,611 | 1,472 | ||||||||||||||
Average Price ($/Bbl) | $ | 91.45 | $ | 93.07 | $ | 94.67 | $ | 89.60 | $ | 86.32 | |||||||||
Fixed Price Swaps - ICE Brent | |||||||||||||||||||
Hedged Volume (Bbl/d) | 4,200 | 4,800 | 3,300 | 4,300 | 298 | ||||||||||||||
Average Price ($/Bbl) | $ | 97.57 | $ | 98.88 | $ | 97.73 | $ | 95.17 | $ | 97.50 | |||||||||
Collars - NYMEX WTI | |||||||||||||||||||
Hedged Volume (Bbl/d) | 500 | 1,000 | 1,000 | — | — | ||||||||||||||
Average Floor Price ($/Bbl) | $ | 77.00 | $ | 90.00 | $ | 90.00 | $ | — | $ | — | |||||||||
Average Ceiling Price ($/Bbl) | $ | 103.10 | $ | 112.00 | $ | 113.50 | $ | — | $ | — | |||||||||
Collars - ICE Brent | |||||||||||||||||||
Hedged Volume (Bbl/d) | — | — | 500 | 500 | — | ||||||||||||||
Average Floor Price ($/Bbl) | $ | — | $ | — | $ | 90.00 | $ | 90.00 | $ | — | |||||||||
Average Ceiling Price ($/Bbl) | $ | — | $ | — | $ | 109.50 | $ | 101.25 | $ | — | |||||||||
Puts - NYMEX WTI | |||||||||||||||||||
Hedged Volume (Bbl/d) | 1,000 | 500 | 500 | 1,000 | — | ||||||||||||||
Average Price ($/Bbl) | $ | 90.00 | $ | 90.00 | $ | 90.00 | $ | 90.00 | $ | — | |||||||||
Total: | |||||||||||||||||||
Hedged Volume (Bbl/d) | 10,970 | 11,114 | 10,489 | 8,411 | 1,770 | ||||||||||||||
Average Price ($/Bbl) | $ | 93.00 | $ | 95.17 | $ | 94.74 | $ | 92.52 | $ | 88.20 | |||||||||
Gas Positions: | |||||||||||||||||||
Fixed Price Swaps - MichCon City-Gate | |||||||||||||||||||
Hedged Volume (MMBtu/d) | 37,000 | 7,500 | 7,500 | 7,000 | — | ||||||||||||||
Average Price ($/MMBtu) | $ | 6.50 | $ | 6.00 | $ | 6.00 | $ | 4.51 | $ | — | |||||||||
Fixed Price Swaps - Henry Hub | |||||||||||||||||||
Hedged Volume (MMBtu/d) | 21,100 | 38,600 | 43,200 | 20,700 | 5,571 | ||||||||||||||
Average Price ($/MMBtu) | $ | 4.76 | $ | 4.80 | $ | 4.83 | $ | 4.24 | $ | 4.51 | |||||||||
Puts - Henry Hub | |||||||||||||||||||
Hedged Volume (MMBtu/d) | — | 6,000 | 1,500 | — | — | ||||||||||||||
Average Price ($/MMBtu) | $ | — | $ | 5.00 | $ | 5.00 | $ | — | $ | — | |||||||||
Total: | |||||||||||||||||||
Hedged Volume (MMBtu/d) | 58,100 | 52,100 | 52,200 | 27,700 | 5,571 | ||||||||||||||
Average Price ($/MMBtu) | $ | 5.87 | $ | 4.99 | $ | 5.00 | $ | 4.31 | $ | 4.51 | |||||||||
Calls - Henry Hub | |||||||||||||||||||
Hedged Volume (MMBtu/d) | 30,000 | 15,000 | — | — | — | ||||||||||||||
Average Price ($/MMBtu) | $ | 8.00 | $ | 9.00 | $ | — | $ | — | $ | — | |||||||||
Deferred Premium ($/MMBtu) | $ | 0.08 | $ | 0.12 | $ | — | $ | — | $ | — |
See Note 15 for a discussion of commodity derivative contracts entered into subsequent to March 31, 2013.
6
Interest Rate Activities
We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. In order to mitigate our interest rate exposure, we have entered into interest rate swaps, indexed to 1-month LIBOR, to fix a portion of floating LIBOR-based debt under our credit facility. As of December 31, 2011, we had an interest rate swap covering January 1, 2012 to December 20, 2012 for $100 million at a fixed rate of 1.1550% and an interest rate swap covering January 20, 2012 to January 20, 2014 for $100 million at 2.4800%. The first contract expired in December 2012. In the fourth quarter of 2012, we terminated the second contract and realized a loss of $2.5 million. As of December 31, 2012 and March 31, 2013, we had no interest rate swaps in place. We did not designate these interest rate derivative instruments as hedges for financial accounting purposes.
Fair Value of Financial Instruments
The following table presents the fair value of derivative instruments not designated as hedging instruments:
Balance sheet location, thousands of dollars | Oil Commodity Derivatives | Natural Gas Commodity Derivatives | Commodity Derivatives Netting (a) | Total Financial Instruments | ||||||||||||
As of March 31, 2013 | ||||||||||||||||
Assets | ||||||||||||||||
Current assets - derivative instruments | $ | 2,571 | $ | 29,329 | $ | (14,056 | ) | $ | 17,844 | |||||||
Other long-term assets - derivative instruments | 36,329 | 26,456 | (14,641 | ) | 48,144 | |||||||||||
Total assets | 38,900 | 55,785 | (28,697 | ) | 65,988 | |||||||||||
Liabilities | ||||||||||||||||
Current liabilities - derivative instruments | (24,241 | ) | (1,506 | ) | 14,056 | (11,691 | ) | |||||||||
Long-term liabilities - derivative instruments | (15,890 | ) | (3,172 | ) | 14,641 | (4,421 | ) | |||||||||
Total liabilities | (40,131 | ) | (4,678 | ) | 28,697 | (16,112 | ) | |||||||||
Net assets (liabilities) | $ | (1,231 | ) | $ | 51,107 | $ | — | $ | 49,876 | |||||||
As of December 31, 2012 | ||||||||||||||||
Assets | ||||||||||||||||
Current assets - derivative instruments | $ | 4,270 | $ | 46,724 | $ | (16,976 | ) | $ | 34,018 | |||||||
Other long-term assets - derivative instruments | 38,919 | 33,443 | (17,152 | ) | 55,210 | |||||||||||
Total assets | 43,189 | 80,167 | (34,128 | ) | 89,228 | |||||||||||
Liabilities | ||||||||||||||||
Current liabilities - derivative instruments | (21,665 | ) | (936 | ) | 16,976 | (5,625 | ) | |||||||||
Long-term liabilities - derivative instruments | (18,769 | ) | (2,776 | ) | 17,152 | (4,393 | ) | |||||||||
Total liabilities | (40,434 | ) | (3,712 | ) | 34,128 | (10,018 | ) | |||||||||
Net assets | $ | 2,755 | $ | 76,455 | $ | — | $ | 79,210 |
(a) Represents counterparty netting under derivative master agreements. The agreements allow for netting of oil and natural gas commodity derivative instruments. These derivative instruments are reflected net on the balance sheet.
7
The following table presents gains and losses on derivative instruments not designated as hedging instruments:
Thousands of dollars | Oil Commodity Derivatives (a) | Natural Gas Commodity Derivatives (a) | Interest Rate Derivatives (b) | Total Financial Instruments | ||||||||||||
Three Months Ended March 31, 2013 | ||||||||||||||||
Net loss | $ | (11,314 | ) | $ | (12,862 | ) | $ | — | $ | (24,176 | ) | |||||
Three Months Ended March 31, 2012 | ||||||||||||||||
Net gain (loss) | $ | (68,651 | ) | $ | 32,646 | $ | (494 | ) | $ | (36,499 | ) |
(a) Included in loss on commodity derivative instruments, net on the consolidated statements of operations.
(b) Included in loss on interest rate swaps on the consolidated statements of operations.
FASB Accounting Standards define fair value, establish a framework for measuring fair value and establish required disclosures about fair value measurements. They also establish a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are. We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third-party market participants. We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements. The fair value hierarchy gives the highest priority of Level 1 to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 to unobservable inputs. We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are. The three levels of inputs are described further as follows:
Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2 – Inputs other than quoted prices that are included in Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. We consider the over-the-counter (“OTC”) commodity and interest rate swaps in our portfolio to be Level 2. Level 3 – Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Certain OTC derivative instruments that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. As of March 31, 2013 and December 31, 2012, our Level 3 derivative assets and liabilities consisted entirely of OTC commodity put and call options.
Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data. We had no transfers in or out of Levels 1, 2 or 3 during the three months ended March 31, 2013 and March 31, 2012. Our policy is to recognize transfers between levels as of the end of the period.
Our Treasury/Risk Management group calculates the fair value of our commodity and interest rate swaps and options. We compare these fair value amounts to the fair value amounts we receive from counterparties on a monthly basis. Any differences are resolved and any required changes are recorded prior to the issuance of our financial statements.
The model we utilize to calculate the fair value of our commodity derivative instruments is a standard option pricing model. Inputs to the option pricing model include fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity forward price curves, volatility, interest rate factors and time to expiry. Model inputs are obtained from our counterparties and third-party data providers and are verified against published data when available (e.g., NYMEX). Additional inputs to our Level 3 derivative instruments include option volatility, forward commodity prices and risk-free interest rates for present value discounting. We use the standard swap contract valuation method to value our interest rate derivative instruments, and inputs include LIBOR forward interest rates, 1-month LIBOR rates and risk-free interest rates for present value discounting.
Assumed credit risk adjustments, based on published credit ratings and credit default swap rates, are applied to our derivative instruments.
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Our assessment of the significance of an input to its fair value measurement requires judgment and can affect the valuation of the assets and liabilities as well as the category within which they are classified. Financial assets and liabilities carried at fair value on a recurring basis are presented in the following table:
Thousands of dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
As of March 31, 2013 | ||||||||||||||||
Assets (liabilities) | ||||||||||||||||
Crude Oil | ||||||||||||||||
Crude oil swaps | $ | — | $ | (13,015 | ) | $ | — | $ | (13,015 | ) | ||||||
Crude oil collars | — | — | 3,837 | 3,837 | ||||||||||||
Crude oil puts | — | — | 7,947 | 7,947 | ||||||||||||
Natural Gas | ||||||||||||||||
Natural gas swaps | — | 49,681 | — | 49,681 | ||||||||||||
Natural gas calls | — | — | (1,287 | ) | (1,287 | ) | ||||||||||
Natural gas puts | — | — | 2,713 | 2,713 | ||||||||||||
Net Assets | $ | — | $ | 36,665 | $ | 13,210 | $ | 49,876 | ||||||||
As of December 31, 2012 | ||||||||||||||||
Assets (liabilities) | ||||||||||||||||
Crude Oil | ||||||||||||||||
Crude oil swaps | $ | — | $ | (12,413 | ) | $ | — | $ | (12,413 | ) | ||||||
Crude oil collars | — | — | 4,024 | 4,024 | ||||||||||||
Crude oil calls | — | — | 11,144 | 11,144 | ||||||||||||
Natural Gas | ||||||||||||||||
Natural gas swaps | — | 74,782 | — | 74,782 | ||||||||||||
Natural gas collars | — | — | (1,489 | ) | (1,489 | ) | ||||||||||
Natural gas calls | — | — | 3,162 | 3,162 | ||||||||||||
Net Assets | $ | — | $ | 62,369 | $ | 16,841 | $ | 79,210 |
The following table sets forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3:
Three Months Ended March 31, | ||||||||||||||||
2013 | 2012 | |||||||||||||||
Thousands of dollars | Oil | Natural Gas | Oil | Natural Gas | ||||||||||||
Assets (a): | ||||||||||||||||
Beginning balance | $ | 15,169 | $ | 1,672 | $ | 8,509 | $ | 37,049 | ||||||||
Loss (b)(c) | (3,385 | ) | (246 | ) | (3,336 | ) | (5,467 | ) | ||||||||
Ending balance | $ | 11,784 | $ | 1,426 | $ | 5,173 | $ | 31,582 |
(a) We had no changes in fair value of our derivative instruments classified as Level 3 related to sales, issuances or purchases.
(b) For the three months ended March 31, 2013 and 2012, includes cash settlements received on crude oil derivatives instruments of $0 and $1.7 million, respectively, and cash settlements (paid) received on natural gas derivative instruments of $(0.2) million and $10.9 million, respectively.
(c) Included in loss on commodity derivative instruments, net on the consolidated statement of operations.
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For Level 3 derivative instruments measured at fair value on a recurring basis as of March 31, 2013, the significant unobservable inputs used in the fair value measurements were as follows:
Fair Value at | Valuation | |||||||||
Thousands of dollars | March 31, 2013 | Technique | Unobservable Input | Range | ||||||
Oil Options | $ | 11,784 | Option Pricing Model | Oil forward commodity prices | $86.20/Bbl - $100.34/Bbl | |||||
Oil volatility | 16.57% - 19.12% | |||||||||
Own credit risk | 5% | |||||||||
Natural Gas Options | 1,426 | Option Pricing Model | Gas forward commodity prices | $3.98/MMBtu - $4.54/MMBtu | ||||||
Gas volatility | 21.49% - 28.83% | |||||||||
Own credit risk | 5% | |||||||||
Total | $ | 13,210 |
Credit and Counterparty Risk
Financial instruments that potentially subject us to concentrations of credit risk consist primarily of derivative instruments and accounts receivable. Our derivative instruments expose us to credit risk from counterparties. As of March 31, 2013, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, U.S Bank National Association, Royal Bank of Canada and Toronto-Dominion Bank. We periodically obtain credit default swap information on our counterparties. As of March 31, 2013, each of these financial institutions had an investment grade credit rating. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default. As of March 31, 2013, our largest derivative asset balances were with Credit Suisse Energy LLC, Wells Fargo Bank National Association and Citibank, N.A., which accounted for approximately 21%, 20% and 15% of our derivative asset balances, respectively.
4. Related Party Transactions
BreitBurn Management Company, LLC (“BreitBurn Management”), our wholly-owned subsidiary, operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management.
BreitBurn Management also provides administrative services to Pacific Coast Energy Company L.P., formerly named BreitBurn Energy Company L.P. (“PCEC”), our predecessor, under an administrative services agreement, in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses, including incentive compensation plan costs and direct payroll and administrative costs related to PCEC properties and operations. For the first three months of 2013, the monthly fee paid by PCEC for indirect expenses was $700,000. The current monthly fee will be in effect through August 31, 2014 and, to the extent the term of the administrative services agreement is renewed, will be redetermined biannually thereafter.
At March 31, 2013 and December 31, 2012, we had current receivables of $1.0 million and $1.2 million, respectively, due from PCEC related to the administrative services agreement, employee-related costs and oil and gas sales made by PCEC on our behalf from certain properties. For the three months ended March 31, 2013 and 2012, the monthly charges to PCEC for indirect expenses totaled $2.1 million and $1.7 million, respectively, and charges for direct expenses including direct payroll and administrative costs totaled $2.1 million and $2.0 million, respectively.
At March 31, 2013 and December 31, 2012, we had receivables of $0.1 million and $0.2 million, respectively, due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf.
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5. Inventory
Our crude oil inventory from our Florida operations was $7.5 million at March 31, 2013 and $3.1 million at December 31, 2012. In the three months ended March 31, 2013, we sold 115 gross MBbls and produced 204 gross MBbls of crude oil from our Florida operations. Crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter. Crude oil inventory additions are valued at the lower of cost or market, with cost based on our actual production costs. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded to inventory.
Note 6. Acquisitions
AEO Acquisition
On November 30, 2012, we completed the acquisition of principally oil properties from American Energy Operations, Inc. (“AEO”) located in the Belridge Field in Kern County, California (the “AEO Acquisition”), with an effective date of November 1, 2012, for approximately $38 million in cash and 3 million Common Units. The preliminary purchase price of $38 million in cash and $56 million in Common Units was allocated to the assets acquired and liabilities assumed as follows:
Thousands of dollars | AEO | |||
Oil and gas properties | $ | 97,814 | ||
Asset retirement obligation | (4,014 | ) | ||
Net assets acquired | $ | 93,800 |
We will finalize the purchase price allocation within one year of the acquisition date.
Permian Basin Acquisitions
On July 2, 2012, we completed acquisitions of oil and natural gas properties located in the Permian Basin in Texas from Element Petroleum, LP and CrownRock, L.P for approximately $148 million and $70 million, respectively. On December 28, 2012, we completed the acquisition of additional oil and natural gas properties, additional net working interests and interests in undeveloped drilling locations in the Permian Basin in Texas from CrownRock, L.P., Lynden USA Inc. and Piedra Energy I, LLC for approximately $167 million, $25 million and $10 million, respectively. These purchase prices are subject to customary post-closing adjustments. The preliminary purchase prices for the 2012 Permian Basin acquisitions (the “Permian Basin Acquisitions”) were primarily allocated to oil and gas properties, and included $52.5 million of unproved oil and gas properties. We will finalize the purchase price allocations within one year of the acquisition dates.
NiMin Acquisition
On June 28, 2012, we completed the acquisition of oil properties located in Park County in the Big Horn Basin of
Wyoming from Legacy Energy, Inc., a wholly-owned subsidiary of NiMin (the “NiMin Acquisition”). The final purchase price for this acquisition was approximately $95 million in cash, which was primarily allocated to oil and gas properties (including $36.2 million in unproved properties) and included $1.7 million of ARO.
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2012 Acquisitions Pro Forma
The following unaudited pro forma financial information presents a summary of our combined statement of operations for the three months ended March 31, 2012, assuming the AEO Acquisition, the Nimin Acquisition and the 2012 acquisitions from Element Petroleum, LP, CrownRock, L.P., Piedra Energy I, LLC and Lynden USA Inc. had been completed on January 1, 2011. The pro forma results reflect the results of combining our statement of operations with the results of operations from all of our 2012 acquisitions, adjusted for (1) the assumption of ARO and accretion expense for the properties acquired, (2) depletion and depreciation expense applied to the adjusted purchase price of the properties acquired, and (3) interest expense on additional borrowings necessary to finance the acquisitions, including the amortization of debt issuance costs. The pro forma financial information is not necessarily indicative of the results of operations if these acquisitions had been effective January 1, 2011.
Pro Forma | ||||
Thousands of dollars, except per unit amounts | Three Months Ended March 31, 2012 | |||
Revenues | $ | 90,747 | ||
Net loss attributable to partnership | (37,203 | ) | ||
Net loss per unit: | ||||
Basic | $ | (0.44 | ) | |
Diluted | $ | (0.44 | ) |
7. Impairments
We assess our developed and undeveloped oil and gas properties and other long-lived assets for possible impairment periodically and whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.
Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for market supply and demand conditions for crude oil and natural gas. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves, and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2.5% per year. For impairment charges, the associated property’s expected future net cash flows are discounted using an estimated weighted average cost of capital that approximated 10%. We consider the inputs for our impairment calculations to be Level 3 inputs. The impairment reviews and calculations are based on assumptions that are consistent with our business plans.
During the three months ended March 31, 2013, we recorded no impairments. During the three months ended March 31, 2012, we recorded approximately $8.3 million related to uneconomic proved properties primarily in Michigan, Indiana and Kentucky due to decreases in natural gas prices.
An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable, given the number of assumptions involved in these estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.
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8. Long-Term Debt
Credit Facility
BreitBurn Operating L.P. (“BOLP”), as borrower, and we and our wholly-owned subsidiaries, as guarantors, have a $1.5 billion revolving credit facility with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (as amended, the “Second Amended and Restated Credit Agreement”) with a maturity date of May 9, 2016.
In February 2013, we entered into the Seventh Amendment to the Second Amended and Restated Credit Agreement, which increased the percentage of expected oil and gas production volume that we are permitted to hedge under the terms of the credit facility.
As of March 31, 2013 and December 31, 2012, our borrowing base was $1 billion, and the aggregate commitment of all lenders was $900 million. We expect that our next borrowing base redetermination will be finalized in May 2013.
As of March 31, 2013 and December 31, 2012, we had $85 million and $345 million, respectively, in indebtedness outstanding under our credit facility. At March 31, 2013, the 1-month LIBOR interest rate plus an applicable spread was 1.9535% on the 1-month LIBOR portion of $85 million.
Borrowings under the Second Amended and Restated Credit Agreement are secured by first-priority liens on and security interests in substantially all of our and certain of our subsidiaries’ assets, representing not less than 80% of the total value of our oil and gas properties.
The Second Amended and Restated Credit Agreement contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders or repurchase units (including the restriction on our ability to make distributions unless, after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.
The Second Amended and Restated Credit Agreement also permits us to terminate derivative contracts without obtaining the consent of the lenders in the credit facility, provided that the net effect of such termination plus the aggregate value of all dispositions of oil and gas properties made during such period, together, does not exceed 5% of the borrowing base, and the borrowing base will be automatically reduced by an amount equal to the net effect of the termination.
The events that constitute an Event of Default (as defined in the Second Amended and Restated Credit Agreement) include: payment defaults, misrepresentations, breaches of covenants, cross-default and cross-acceleration to certain other indebtedness, adverse judgments against us in excess of a specified amount, changes in management or control, loss of permits, certain insolvency events and assertion of certain environmental claims.
As of March 31, 2013 and December 31, 2012, we were in compliance with the credit facility’s covenants.
Senior Notes
We have $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the “2020 Senior Notes”), which had a carrying value of $301.2 million, net of unamortized discount of $3.8 million as of March 31, 2013. In addition, we have $450 million in aggregate principal amount of 7.875% Senior Notes due 2022 (the “2022 Senior Notes”), which had a carrying value of $454.5 million, net of unamortized premium of $4.5 million as of March 31, 2013.
Interest on our senior notes is payable twice a year in April and October.
As of March 31, 2013, the fair value of the 2020 Senior Notes and 2022 Senior Notes was estimated to be $336.8 million and $482.3 million, respectively, based on prices quoted from third-party financial institutions. We consider the inputs to the valuation of our senior notes to be Level 2, as fair value was estimated based on prices quoted from third-party financial institutions.
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As of March 31, 2013 and December 31, 2012, we were in compliance with the covenants on our senior notes.
Interest Expense
Our interest expense is detailed as follows:
Three Months Ended | ||||||||
March 31, | ||||||||
Thousands of dollars | 2013 | 2012 | ||||||
Credit agreement (including commitment fees) | $ | 1,769 | $ | 1,760 | ||||
Senior notes | 15,436 | 10,788 | ||||||
Amortization of discount and deferred issuance costs | 1,238 | 1,252 | ||||||
Capitalized interest | (24 | ) | — | |||||
Total | $ | 18,419 | $ | 13,800 |
9. Condensed Consolidating Financial Statements
We and BreitBurn Finance Corporation as co-issuers, and certain of our subsidiaries as guarantors, issued the 2020 Senior Notes and the 2022 Senior Notes. Effective April 1, 2012, we and PCEC agreed to dissolve BEPI. With the dissolution of BEPI, all but one of our subsidiaries have guaranteed our senior notes and our only remaining non-guarantor subsidiary, BreitBurn Collingwood Utica LLC, is a minor subsidiary.
In accordance with Rule 3-10 of Regulation S-X, we are not presenting condensed consolidating financial statements as we have no independent assets or operations; BreitBurn Finance Corporation, the subsidiary co-issuer that does not guarantee our senior notes, is a 100% owned finance subsidiary; all of our material subsidiaries are 100% owned, have guaranteed our senior notes, and all of the guarantees are full, unconditional, joint and several.
Each guarantee of each of the 2020 Senior Notes and the 2022 Senior Notes is subject to release in the following customary circumstances:
(1) | a disposition of all or substantially all the assets of the guarantor subsidiary (including by way of merger or consolidation) to a third person, provided the disposition complies with the applicable indenture, |
(2) | a disposition of the capital stock of the guarantor subsidiary to a third person, if the disposition complies with the applicable indenture and as a result the guarantor subsidiary ceases to be our subsidiary, |
(3) | the designation by us of the guarantor subsidiary as an Unrestricted Subsidiary as defined in the applicable indenture, |
(4) | legal or covenant defeasance of such series of senior notes or satisfaction and discharge of the related indenture, |
(5) | the liquidation or dissolution of the guarantor subsidiary, provided no default under the applicable indenture exists, or |
(6) | the guarantor subsidiary ceases both (a) to guarantee any other indebtedness of ours or any other guarantor subsidiary and (b) to be an obligor under any bank credit facility. |
10. Income Taxes
We, and all of our subsidiaries, with the exception of Phoenix Production Company (“Phoenix”), Alamitos Company, BreitBurn Management and BreitBurn Finance Corporation, are partnerships or limited liability companies treated as partnerships for federal and state income tax purposes. Essentially all of our taxable income or loss, which may differ considerably from the net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our partners. As such, we have not recorded any federal income tax expense for those pass-through entities.
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Our deferred income tax liability was $2.5 million at each of March 31, 2013 and December 31, 2012, respectively. The following table presents our income tax expense (benefit) for the three months ended March 31, 2013 and 2012:
Three Months Ended | ||||||||
March 31, | ||||||||
Thousands of dollars | 2013 | 2012 | ||||||
Federal income tax expense (benefit) | ||||||||
Current | $ | 2 | $ | 176 | ||||
Deferred (a) | (21 | ) | (779 | ) | ||||
State income tax expense (b) | 49 | 44 | ||||||
Total | $ | 30 | $ | (559 | ) |
(a) Related to Phoenix, a tax-paying corporation and our wholly-owned subsidiary.
(b) Primarily in California and Texas.
11. Asset Retirement Obligation
Our asset retirement obligation is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities together with our estimate of the future timing of the costs to be incurred. Payments to settle asset retirement obligations occur over the operating lives of the assets, estimated to be from less than one year to 50 years. Estimated cash flows have been discounted at our credit-adjusted risk-free rate of 7% and adjusted for inflation using a rate of 2%. Our credit-adjusted risk-free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk.
We consider the inputs to our asset retirement obligation valuation to be Level 3, as fair value is determined using discounted cash flow methodologies based on standardized inputs that are not readily observable in public markets.
Changes in the asset retirement obligation for the period ended March 31, 2013 and the year ended December 31, 2012 are presented in the following table:
Three Months Ended | Year Ended | |||||||
Thousands of dollars | March 31, 2013 | December 31, 2012 | ||||||
Carrying amount, beginning of period | $ | 98,480 | $ | 82,397 | ||||
Acquisitions | — | 6,279 | ||||||
Liabilities incurred | — | 2,468 | ||||||
Liabilities settled | (325 | ) | (86 | ) | ||||
Revisions | — | 1,553 | ||||||
Accretion expense | 1,637 | 5,869 | ||||||
Carrying amount, end of period | $ | 99,792 | $ | 98,480 |
12. Commitments and Contingencies
Surety Bonds and Letters of Credit
In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At March 31, 2013 and December 31, 2012, we had surety bonds for $16.7 million and $16.2 million, respectively. At each of March 31, 2013 and December 31, 2012, we had approximately $0.3 million in letters of credit outstanding.
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13. Partners’ Equity
In February 2013, we sold 14.95 million of our common units representing limited partner interests in us (“Common Units”) at a price to the public of $19.86 per Common Unit, resulting in proceeds net of underwriting discount and offering expenses of $285.0 million.
During the first three months of 2013, we issued less than 0.1 million Common Units to employees and non-employee directors for Convertible Phantom Units (“CPUs”) and Restricted Phantom Units (“RPUs”) that vested in January 2013.
At March 31, 2013 and December 31, 2012, we had approximately 99.7 million and 84.7 million Common Units outstanding, respectively. At March 31, 2013 and December 31, 2012, there were approximately 2.0 million and 0.9 million, respectively, of units outstanding under our Long-term Incentive Plan (“LTIP”) that were eligible to be paid in Common Units upon vesting.
Cash Distributions
On February 14, 2013, we paid a cash distribution of approximately $39.8 million to our common unitholders of record as of the close of business on February 11, 2013. The distribution that was paid to unitholders was $0.4700 per Common Unit.
During the three months ended March 31, 2013, we also paid $0.8 million in cash at a rate equal to the distributions paid to our common unitholders to holders of outstanding unvested RPUs issued under our LTIP.
On February 14, 2012, we paid a cash distribution of approximately $27.0 million to our common unitholders of record as of the close of business on February 6, 2012. The distribution that was paid to unitholders was $0.4500 per Common Unit.
During the three months ended March 31, 2012, we also paid $1.2 million in cash at a rate equal to the distributions paid to our common unitholders to holders of outstanding unvested RPUs.
Earnings per Unit
FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of common unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested RPUs and CPUs participate in distributions on an equal basis with Common Units. Accordingly, the presentation below is prepared on a combined basis and is presented as net income (loss) per common unit.
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The following is a reconciliation of net loss attributable to the partnership and weighted average units for calculating basic net loss per common unit and diluted net loss per common unit.
Three Months Ended | ||||||||
March 31, | ||||||||
Thousands, except per unit amounts | 2013 | 2012 | ||||||
Net loss attributable to the partnership | $ | (36,300 | ) | $ | (49,970 | ) | ||
Distributions on participating units not expected to vest | — | — | ||||||
Net loss attributable to common unitholders and participating securities | $ | (36,300 | ) | $ | (49,970 | ) | ||
Weighted average number of units used to calculate basic and diluted net loss per unit: | ||||||||
Common Units | 94,530 | 66,010 | ||||||
Participating securities (a) | — | — | ||||||
Denominator for basic earnings per common unit | 94,530 | 66,010 | ||||||
Dilutive units (b) | — | — | ||||||
Denominator for diluted earnings per common unit | 94,530 | 66,010 | ||||||
Net loss per common unit | ||||||||
Basic | $ | (0.38 | ) | $ | (0.76 | ) | ||
Diluted | $ | (0.38 | ) | $ | (0.76 | ) |
(a) The three months ended March 31, 2013 and 2012 exclude 1,523 and 2,427, respectively, of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.
(b) The three months ended March 31, 2013 and 2012 exclude 305 and 56, respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit.
14. Unit and Other Valuation-Based Compensation Plans
Unit-based compensation expense for the three months ended March 31, 2013 and March 31, 2012 was $4.8 million and $5.6 million, respectively.
During the three months ended March 31, 2013, the board of directors of BreitBurn GP, LLC (our “General Partner”) approved the grant of approximately 1.1 million CPUs and RPUs to employees of BreitBurn Management under our LTIP. Our non-employee directors were issued less than 0.1 million RPUs under our LTIP during the three months ended March 31, 2013. The fair market value of the RPUs granted during 2013 for computing compensation expense under FASB Accounting Standards averaged $20.98 per unit.
During the three months ended March 31, 2013 and 2012, we paid $0.6 million and $0, respectively, for taxes withheld on RPUs vested during the period.
As of March 31, 2013, we had $36.1 million of total unrecognized compensation costs for all outstanding awards. This amount is expected to be recognized over the period from April 1, 2013 to December 31, 2014. For detailed information on our various compensation plans, see Note 17 to the consolidated financial statements included in our Annual Report.
15. Subsequent Events
On April 25, 2013, we announced a cash distribution to common unitholders for the first quarter of 2013 at the rate of $0.4750 per Common Unit, to be paid on May 14, 2013 to our common unitholders of record as of the close of business on May 6, 2013.
In April 2013, we entered into a Henry Hub natural gas fixed price swap contract for 4,000 MMBtu/d for July 1, 2013 through September 30, 2013 at $4.28 per MMbtu and a Henry Hub natural gas fixed price swap contract for 6,000 MMBtu/d for October 1, 2013 through December 31, 2013 at $4.37 per MMBtu.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis in conjunction with Management’s Discussion and Analysis in Part II—Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2012 (the “Annual Report”) and the consolidated financial statements and related notes therein. Our Annual Report contains a discussion of other matters not included herein, such as disclosures regarding critical accounting policies and estimates and contractual obligations. You should also read the following discussion and analysis together with Part II—Item 1A “—Risk Factors” of this report, the “Cautionary Statement Regarding Forward-Looking Information” in this report and in our Annual Report and Part I—Item 1A “—Risk Factors” of our Annual Report.
Overview
We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States. Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders. Our assets consist primarily of producing and non-producing crude oil and natural gas reserves located primarily in:
• the Antrim Shale and several non-Antrim formations in Michigan;
• the Evanston, Green River, Wind River, Big Horn and Powder River Basins in Wyoming;
• the Los Angeles and San Joaquin Basins in California;
• the Permian Basin in Texas;
• the Sunniland Trend in Florida; and
• the New Albany Shale in Indiana and Kentucky.
Our core investment strategy includes the following principles:
• | acquire long-lived assets with low-risk exploitation and development opportunities; |
• | use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery; |
• | reduce cash flow volatility through commodity price derivative instruments; and |
• | maximize asset value and cash flow stability through our operating and technical expertise. |
Consistent with our long-term business strategy, we intend to continue to actively pursue oil and natural gas acquisition opportunities in 2013.
2013 Highlights
In February 2013, we sold approximately 14.95 million Common Units at a price to the public of $19.86, resulting in proceeds net of underwriting discounts and estimated offering expenses of $285.0 million, which we used to repay outstanding debt under our credit facility.
On February 14, 2013, we paid a cash distribution of approximately $39.8 million to our common unitholders of record as of the close of business on February 11, 2013. The distribution that was paid to unitholders was $0.4700 per Common Unit.
On April 25, 2013, we announced a cash distribution to common unitholders for the first quarter of 2013 at the rate of $0.4750 per Common Unit, to be paid on May 14, 2013 to our common unitholders of record as of the close of business on May 6, 2013.
Operational Focus and Capital Expenditures
In the first three months of 2013, our oil and natural gas capital expenditures totaled $45 million, compared to approximately $16 million in the first three months of 2012. We spent approximately $20 million in Texas, $15 million in California, $5 million in Wyoming, $4 million in Florida and $1 million in Michigan. In the first three months of 2013, we drilled and completed nine wells in Texas, four wells in California and three wells in Wyoming and performed workovers on four wells in California, four wells in Wyoming and two wells in Michigan.
In 2013, our crude oil and natural gas capital program, excluding acquisitions, is expected to be approximately $261 million. This compares with approximately $153 million in 2012. We plan to principally target oil projects and expect to
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spend approximately 84% of the capital budget in California, Florida and Texas and approximately 16% in Michigan, Wyoming, Indiana and Kentucky. We anticipate that 89% of our total capital spending will be focused on drilling and rate-generating projects that are designed to increase or add to production or reserves. Without considering potential acquisitions, we expect our 2013 production to be approximately 9.8 MMboe.
Commodity Prices
In the first quarter of 2013, the NYMEX WTI spot price averaged $94 per barrel, compared with approximately $103 per barrel in the first quarter of 2012. The average NYMEX WTI spot price in April 2013 was approximately $92 per barrel and in the first four months of 2013, the NYMEX WTI spot price ranged from a low of $87 to a high of $98. In 2012, the NYMEX WTI spot price averaged approximately $94 per barrel.
In the first quarter of 2013, the Henry Hub natural gas spot price averaged $3.49 per MMBtu compared with approximately $2.44 per MMBtu in the first quarter of 2012. The Henry Hub natural gas spot price in April 2013 averaged approximately $4.16 per MMBtu. In 2012, the Henry Hub natural gas spot price averaged $2.75 per MMBtu and ranged from a low of $1.82 per MMBtu to a high of $3.77 per MMBtu.
BreitBurn Management
BreitBurn Management, our wholly-owned subsidiary, operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management.
BreitBurn Management also manages the operations of PCEC, our predecessor, and provides administrative services to PCEC under an administrative services agreement. These services include operational functions, such as exploitation and technical services, petroleum and reserves engineering and executive management, and administrative services, such as accounting, information technology, audit, human resources, land, business development, finance and legal. These services are provided in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses, including incentive compensation plan costs and direct payroll and administrative costs related to PCEC properties and operations. For the first three months of 2013, the monthly fee paid by PCEC for indirect expenses was $700,000. The monthly fee of $700,000 will be in effect through August 31, 2014 and, to the extent the term of the administrative services agreement is renewed, will be redetermined biannually thereafter.
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Results of Operations
The table below summarizes certain of the results of operations for the periods indicated. The data for the periods reflect our results as they are presented in our unaudited consolidated financial statements included elsewhere in this report.
Three Months Ended March 31, | Increase/ | ||||||||||||||
Thousands of dollars, except as indicated | 2013 | 2012 | Decrease | % | |||||||||||
Total production (MBoe) | 2,346 | 1,987 | 359 | 18 | % | ||||||||||
Oil and NGLs (MBoe) | 1,206 | 859 | 347 | 40 | % | ||||||||||
Natural gas (MMcf) | 6,844 | 6,769 | 75 | 1 | % | ||||||||||
Average daily production (Boe/d) | 26,070 | 21,835 | 4,235 | 19 | % | ||||||||||
Sales volumes (MBoe) | 2,270 | 1,899 | 371 | 20 | % | ||||||||||
Average realized sales price (per Boe) (a) (b) | $ | 52.96 | $ | 49.42 | $ | 3.54 | 7 | % | |||||||
Oil and NGLs (per Boe) (a) (b) | 84.61 | 96.37 | (11.76 | ) | (12 | )% | |||||||||
Natural gas (per Mcf) (b) | 3.61 | 2.90 | 0.71 | 24 | % | ||||||||||
Oil, natural gas and NGLs sales | $ | 120,362 | $ | 94,007 | $ | 26,355 | 28 | % | |||||||
Loss on commodity derivative instruments | (24,176 | ) | (36,005 | ) | 11,829 | (33 | )% | ||||||||
Other revenues, net | 758 | 1,145 | (387 | ) | (34 | )% | |||||||||
Total revenues | 96,944 | 59,147 | 37,797 | 64 | % | ||||||||||
Lease operating expenses before taxes (c) | 45,561 | 38,073 | 7,488 | 20 | % | ||||||||||
Production and property taxes (d) | 9,383 | 7,573 | 1,810 | 24 | % | ||||||||||
Total lease operating expenses | 54,944 | 45,646 | 9,298 | 20 | % | ||||||||||
Purchases and other operating costs | 318 | 370 | (52 | ) | (14 | )% | |||||||||
Change in inventory | (3,109 | ) | (2,755 | ) | (354 | ) | n/a | ||||||||
Total operating costs | $ | 52,153 | $ | 43,261 | $ | 8,892 | 21 | % | |||||||
Lease operating expenses before taxes per Boe | $ | 19.42 | $ | 19.16 | $ | 0.26 | 1 | % | |||||||
Production and property taxes per Boe | 4.00 | 3.81 | 0.19 | 5 | % | ||||||||||
Total lease operating expenses per Boe | 23.42 | 22.97 | 0.45 | 2 | % | ||||||||||
Depletion, depreciation and amortization (DD&A) | $ | 47,790 | $ | 38,281 | $ | 9,024 | 24 | % | |||||||
DD&A per Boe | 20.37 | 19.27 | 0.89 | 5 | % | ||||||||||
(a) Includes crude oil purchases. | |||||||||||||||
(b) Excludes the effect of commodity derivative settlements. | |||||||||||||||
(c) Includes lease operating expenses, district expenses, transportation expenses and processing fees. | |||||||||||||||
(d) Includes ad valorem and severance taxes. |
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Comparison of Results for the Three Months Ended March 31, 2013 and 2012
The variances in our results were due to the following components:
Production
For the three months ended March 31, 2013, production was 2,346 MBoe compared to 1,987 MBoe for the three months ended March 31, 2012, primarily due to 331 MBoe from our Texas properties, acquired in July 2012 and December of 2012, 86 MBoe higher California production (78 MBoe from our properties in the San Joaquin Basin acquired in November 2012 and an increase in production from our legacy properties primarily as a result of our drilling program partially offset by a reduction in our ownership of two California fields) and 35 MBoe higher Wyoming oil production from our properties in Northern Wyoming acquired in June 2012, partially offset by a decrease of 62 MBoe in Michigan production and a 22 MBoe decrease in Wyoming natural gas production, primarily due to natural field declines.
Oil, natural gas and NGL sales
Total oil, natural gas liquids (“NGLs”) and natural gas sales revenues increased $26.4 million for the three months ended March 31, 2013 compared to the three months ended March 31, 2012. Crude oil and NGLs revenues increased $21.3 million due to higher sales volumes, primarily due to oil production from our recently acquired properties in Texas, California and Wyoming. Natural gas revenues increased $5.1 million primarily due to higher natural gas prices and higher natural gas production primarily from our recently acquired Texas properties.
Realized prices for crude oil and NGLs, excluding the effect of derivative instruments, decreased $11.76 per Boe, or 12%, in the three months ended March 31, 2013 compared to the three months ended March 31, 2012. Realized prices for natural gas, excluding the effect of derivative instruments, increased $0.71 per Mcf, or 24%, in the three months ended March 31, 2013 compared to the three months ended March 31, 2013.
Loss on commodity derivative instruments
Loss on commodity derivative instruments for the three months ended March 31, 2013 was $24.2 million compared to $36.0 million during the three months ended March 31, 2012. Commodity derivative instrument settlements received for the three months ended March 31, 2013 and 2012 were $5.2 million and $17.6 million, respectively, which primarily reflects lower natural gas settlements received due to increased natural gas prices and lower average natural gas hedge prices, as well as higher settlements paid for oil due to lower average crude oil hedge prices compared to the prior year.
Lease operating expenses
Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the three months ended March 31, 2013 increased $7.5 million compared to the three months ended March 31, 2012. The increase in pre-tax lease operating expenses primarily reflects our recently acquired Texas, California and Wyoming properties. On a per Boe basis, pre-tax lease operating expenses were $19.42 per Boe for the three months ended March 31, 2013 compared to $19.16 per Boe for the three months ended March 31, 2012. The per Boe increase was primarily attributable to higher Florida lease operating expenses driven by higher fuel and utility costs.
Production and property taxes for the three months ended March 31, 2013 totaled $9.4 million, which was $1.8 million higher than the three months ended March 31, 2012, primarily due to higher production taxes from our recently acquired Texas and Wyoming properties. On a per Boe basis, production and property taxes for the three months ended March 31, 2013 were $4.00 per Boe, which was 5% higher than the three months ended March 31, 2012.
Change in inventory
In Florida, our crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter. Sales occur on average every six to eight weeks. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are credited to operating costs through the change in inventory account. Production expenses are charged to operating costs through the change in inventory account when they are sold.
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For the three months ended March 31, 2013 and 2012, the change in inventory account amounted to a credit of $3.1 million and a credit of $2.8 million, respectively. The credits to inventory during the three months ended March 31, 2013 and March 31, 2012 reflect higher volume of crude oil produced than sold during the periods due to the timing of Florida sales.
Depletion, depreciation and amortization
Depletion, depreciation and amortization expense (“DD&A”) totaled $47.8 million, or $20.37 per Boe, during the three months ended March 31, 2013, an increase of approximately 5% per Boe from the same period a year ago. The first quarter of 2012 included $8.3 million in impairments related to uneconomic proved properties in Michigan, Indiana and Kentucky. DD&A per Boe was 35% higher in the first quarter of 2013 when compared to DD&A, excluding impairments, of $15.07 per Boe in the first quarter of 2012. The increase in DD&A per Boe compared to last year was primarily due to higher rates from our recently acquired properties in Texas and Wyoming and higher Michigan DD&A rates.
General and administrative expenses
Our general and administrative (“G&A”) expenses totaled $14.9 million and $13.7 million for the three months ended March 31, 2013 and 2012, respectively. This included $4.8 million and $5.6 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans. G&A expenses, excluding non-cash unit-based compensation, were $10.1 million and $8.1 million for the three months ended March 31, 2013 and 2012, respectively. The increase was primarily due to additional employee costs attributable to our acquisitions and higher acquisition evaluation related costs. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $4.29 and $4.07 for the three months ended March 31, 2013 and 2012, respectively.
Interest expense, net of amounts capitalized
Our interest expense totaled $18.4 million and $13.8 million for the three months ended March 31, 2013 and 2012, respectively. The increase in interest expense was primarily due to $4.6 million higher interest related to the 2022 Senior Notes, which were issued in January 2012 and September 2012.
Loss on interest rate swaps
As of March 31, 2013, we had no interest rate derivative contracts in place. We had no loss on interest rate swaps for the three months ended March 31, 2013. Loss on interest rate swaps was $0.5 million for the three months ended March 31, 2012.
Credit and Counterparty Risk
Our derivative financial instruments are exposed to credit risk from counterparties. See Note 3 to the consolidated financial statements within this report for a discussion of our derivative contracts and counterparties.
Liquidity and Capital Resources
Our primary sources of liquidity are cash generated from operations and amounts available under our revolving credit facility. Our primary uses of cash have been for our operating expenses, capital expenditures and cash distributions to unitholders. To fund certain acquisition transactions, we have historically used borrowings under our revolving credit facility, accessed the private placement markets and issued equity as partial consideration for the acquisition of oil and gas properties. As market conditions have permitted, we have also engaged in asset sale transactions and equity and debt offerings. In the future, we intend to access the public and private capital markets to fund certain acquisitions and refinancing transactions.
Equity Offering
In February 2013, we sold 14.95 million of our common units representing limited partner interests in us (“Common Units”) at a price to the public of $19.86 per Common Unit, resulting in proceeds net of underwriting discount and offering expenses of $285.0 million.
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Distributions
On February 14, 2013, we paid a cash distribution of approximately $39.8 million to our common unitholders of record as of the close of business on February 11, 2013. The distribution that was paid to unitholders was $0.4700 per Common Unit. On April 25, 2013, we announced a cash distribution to unitholders for the first quarter of 2013 at the rate of $0.4750 per Common Unit, to be paid on May 14, 2013 to our common unitholders of record as of the close of business on May 6, 2013.
Cash Flows
Operating activities. Our cash flow from operating activities for the three months ended March 31, 2013 was $58.9 million, compared to $71.3 million for the three months ended March 31, 2012. The decrease in cash flow from operating activities was primarily due to the collection of a $10.4 million settlement receivable from our insurance company during the three months ended March 31, 2012 and higher interest expense during the three months ended March 31, 2013, partially offset by higher operating income from our recently acquired properties in Texas, Wyoming and California during the three months ended March 31, 2013.
Investing activities. Net cash used in investing activities during the three months ended March 31, 2013 and March 31, 2012 was $40.6 million and $13.5 million, respectively. During the three months ended March 31, 2013 and 2012, we spent $38.1 million and $14.1 million, respectively, on capital expenditures, primarily for drilling and completion activities. During the three months ended March 31, 2013, we also spent $2.5 million on property acquisitions in California.
Financing activities. Net cash used in financing activities for the three months ended March 31, 2013 and March 31, 2012 was $15.1 million and $56.7 million, respectively. During the three months ended March 31, 2013, we reduced our outstanding borrowings under our credit facility by approximately $260.0 million, primarily using net proceeds from the issuance of Common Units in February 2013. We had total outstanding borrowings, net of unamortized discount on our senior notes, of $840.7 million at March 31, 2013 and $1.1 billion at December 31, 2012. During the three months ended March 31, 2013, we issued $285.2 million in Common Units, made cash distributions of $40.6 million, borrowed $72.0 million and repaid $332.0 million under our credit facility. For the three months ended March 31, 2012, we issued $166.2 million in Common Units, made cash distributions of $28.1 million, borrowed $310.9 million and repaid $498.0 million under our credit facility.
Senior Notes
As of March 31, 2013, we had $305 million in 8.625% Senior Notes due 2020 and $450 million in 7.875% Senior Notes due 2022. See Note 8 for a discussion of our Senior Notes.
Credit Agreement
As of December 31, 2012 and March 31, 2013, we had a $1.5 billion bank credit facility with a maturity date of May 9, 2016 and a borrowing base of $1.0 billion with an aggregate commitment of all lenders of $900 million. We expect that our next borrowing base will be finalized in May 2013.
As of March 31, 2013 and May 3, 2013, we had $85.0 million and [$95.0 million], respectively, in indebtedness outstanding under the Second Amended and Restated Credit Agreement.
As of March 31, 2013, the lending group under the Second Amended and Restated Credit Agreement included 14 banks. Of the $900 million in total commitments under the credit facility, Wells Fargo Bank, National Association held approximately 18.8% of the commitments. Ten banks held between 5% and 8% of the commitments, including Union Bank, N.A., Bank of Montreal, The Bank of Nova Scotia, Houston Branch, Citibank, N.A., Royal Bank of Canada, U.S. Bank National Association, Bank of Scotland plc, Barclays Bank PLC, The Royal Bank of Scotland plc and Credit Suisse AG, Cayman Islands Branch, with each of the remaining lenders holding less than 5% of the commitments. In addition to our relationships with these institutions under the credit facility, from time to time we engage in other transactions with a number of these institutions. Such institutions or their affiliates may serve as underwriter or initial purchaser of our debt and equity securities and/or serve as counterparties to our commodity and interest rate derivative contracts.
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The Second Amended and Restated Credit Agreement contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders or repurchase units; make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.
The Second Amended and Restated Credit Agreement includes a restriction on our ability to make a distribution unless after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility. In addition, the Second Amended and Restated Credit Agreement requires us to maintain a leverage ratio (defined as the ratio of total debt to EBITDAX) as of the last day of each quarter, on a last 12-month basis, of no more than 4.00 to 1.00 and a current ratio, as of the last day of each quarter, of not less than 1.00 to 1.00. As of March 31, 2013, we were in compliance with these covenants.
EBITDAX is not a defined GAAP measure. The Second Amended and Restated Credit Agreement defines EBITDAX as consolidated net income plus exploration expense, interest expense, income tax provision, DD&A, unrealized loss or gain on derivative instruments, non-cash charges, including non-cash unit-based compensation expense, loss or gain on sale of assets (excluding gain or loss on monetization of derivative instruments), cumulative effect of changes in accounting principles, cash distributions received from our unrestricted entities (as defined in the Second Amended and Restated Credit Agreement) and BEPI and excluding income from our unrestricted entities and BEPI.
The events that constitute an Event of Default (as defined in the Second Amended and Restated Credit Agreement) include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain other indebtedness; adverse judgments against us in excess of a specified amount; changes in management or control; loss of permits; certain insolvency events; and assertion of certain environmental claims.
Contractual Obligations
Except for the issuance of Common Units and the pay-down of debt under our credit facility, we had no material changes to our financial contractual obligations during the three months ended March 31, 2013.
Off-Balance Sheet Arrangements
We did not have any off-balance sheet arrangements as of March 31, 2013 and December 31, 2012.
New Accounting Standards
See Note 2 to the consolidated financial statements within this report for a discussion of new accounting standards applicable to us.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Part II—Item 7A in our Annual Report. Also, see Note 3 and Note 15 to the consolidated financial statements within this report for additional discussion related to our financial instruments, including a summary of our derivative contracts as of March 31, 2013.
Changes in Fair Value
The fair value of our outstanding oil and gas commodity derivative instruments was a net asset of approximately $49.9 million and $79.2 million at March 31, 2013 and December 31, 2012, respectively. With a $10.00 per barrel increase in the price of oil, and a corresponding $1.00 per Mcf increase in natural gas, our net commodity derivative instrument asset at March 31, 2013 would have decreased by approximately $198 million. With a $10.00 per barrel decrease in the price of oil, and a corresponding $1.00 per Mcf decrease in natural gas, our net commodity derivative instrument asset at March 31, 2013 would have increased by approximately $202 million.
Price risk sensitivities were calculated by assuming across-the-board increases in price of $10.00 per barrel for oil and $1.00 per Mcf for natural gas regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of actual changes in prompt month prices equal to the assumptions, the fair value of our derivative instrument portfolio would typically change by less than the amounts given due to lower volatility in out-month prices.
Item 4. Controls and Procedures
Controls and Procedures
As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our General Partner's principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our General Partner's principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based upon the evaluation, our General Partner's principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2013 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2013 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.
Item 1A. Risk Factors
There have been no material changes to the Risk Factors disclosed in Part I—Item 1A “—Risk Factors” of our Annual Report.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
There were no sales of unregistered equity securities during the period covered by this report.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
None.
Item 6. Exhibits
NUMBER | DOCUMENT | |
3.1 | First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2006). | |
3.2 | Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008). | |
3.3 | Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2009). | |
3.4 | Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 1, 2009). | |
3.5 | Amendment No.4 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010). | |
3.6 | Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010). | |
3.7 | Amendment No. 1 to the Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC dated as of December 30, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). |
26
NUMBER | DOCUMENT | |
4.1 | Indenture, dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors and U.S. National Bank Association as trustee, in connection with the private placement of the Notes (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010). | |
4.2 | Indenture, dated as of January 13, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and U.S. National Bank Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 13, 2012). | |
10.1 | Form of Restricted Phantom Unit Agreement - Deferred Payment Award | |
10.2 | Form of Convertible Phantom Unit Agreement - Non-Employment Agreement | |
10.3 | Form of Convertible Phantom Unit Agreement - Employment Agreement | |
10.4 | Seventh Amendment to the Second Amended and Restated Credit Agreement of BreitBurn Energy Partners L.P. dated February 26, 2013. | |
31.1* | Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002. | |
31.2* | Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002. | |
32.1** | Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002. | |
32.2** | Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002. | |
101†† | Interactive Data Files. |
* | Filed herewith. | |
** | Furnished herewith. | |
† | Management contract or compensatory plan or arrangement. | |
†† | The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under these sections. |
27
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
BREITBURN ENERGY PARTNERS L.P. | |||
By: | BREITBURN GP, LLC, | ||
its General Partner | |||
Dated: | August 23, 2013 | By: | /s/ Halbert S. Washburn |
Halbert S. Washburn | |||
Chief Executive Officer | |||
Dated: | August 23, 2013 | By: | /s/ James G. Jackson |
James G. Jackson | |||
Chief Financial Officer |
28
INDEX TO EXHIBITS
NUMBER | DOCUMENT | |
3.1 | First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2006). | |
3.2 | Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008). | |
3.3 | Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2009). | |
3.4 | Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 1, 2009). | |
3.5 | Amendment No.4 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010). | |
3.6 | Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010). | |
3.7 | Amendment No. 1 to the Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC dated as of December 30, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). | |
4.1 | Indenture, dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors and U.S. National Bank Association as trustee, in connection with the private placement of the Notes (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010). | |
4.2 | Indenture, dated as of January 13, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and U.S. National Bank Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 13, 2012). | |
10.1 | Form of Restricted Phantom Unit Agreement - Deferred Payment Award | |
10.2 | Form of Convertible Phantom Unit Agreement - Non-Employment Agreement | |
10.3 | Form of Convertible Phantom Unit Agreement - Employment Agreement | |
10.4 | Seventh Amendment to the Second Amended and Restated Credit Agreement of BreitBurn Energy Partners L.P. dated February 26, 2013. | |
31.1* | Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002. | |
31.2* | Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002. | |
32.1** | Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002. | |
32.2** | Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002. | |
101†† | Interactive Data Files. |
* | Filed herewith. | |
** | Furnished herewith. | |
† | Management contract or compensatory plan or arrangement. | |
†† | The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under these sections. |
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