UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x | Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the quarterly period ended September 30, 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 November 5, 2013, the registrant had 99,679,860 Common Units outstanding.
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,” “intend,” “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, as amended by Amendment No 1. to our Annual Report on Form 10-K for the year December 31, 2012 (our “2012 Annual Report”), in Part II—Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, as amended by Amendment No. 1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, our quarterly report on form 10-Q for the quarter ended June 30, 2013 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
Consolidated Balance Sheets
(Unaudited)
Thousands | September 30, 2013 | December 31, 2012 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash | $ | 2,818 | $ | 4,507 | ||||
Accounts and other receivables, net | 115,931 | 67,862 | ||||||
Derivative instruments (note 4) | 16,558 | 34,018 | ||||||
Related party receivables (note 5) | 530 | 1,413 | ||||||
Inventory (note 6) | 11,118 | 3,086 | ||||||
Prepaid expenses | 3,071 | 2,779 | ||||||
Intangibles, net (note 3) | 6,554 | — | ||||||
Total current assets | 156,580 | 113,665 | ||||||
Equity investments | 7,126 | 7,004 | ||||||
Property, plant and equipment | ||||||||
Oil and gas properties | 4,409,806 | 3,363,946 | ||||||
Other assets | 15,986 | 14,367 | ||||||
4,425,792 | 3,378,313 | |||||||
Accumulated depletion and depreciation (note 7) | (813,713 | ) | (666,420 | ) | ||||
Net property, plant and equipment | 3,612,079 | 2,711,893 | ||||||
Other long-term assets | ||||||||
Intangibles, net (note 3) | 6,693 | — | ||||||
Derivative instruments (note 4) | 71,085 | 55,210 | ||||||
Other long-term assets | 46,893 | 27,722 | ||||||
Total assets | $ | 3,900,456 | $ | 2,915,494 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities | ||||||||
Accounts payable | $ | 50,653 | $ | 42,497 | ||||
Derivative instruments (note 4) | 12,388 | 5,625 | ||||||
Revenue and royalties payable | 26,576 | 22,262 | ||||||
Wages and salaries payable | 12,154 | 10,857 | ||||||
Accrued interest payable | 29,467 | 13,002 | ||||||
Accrued liabilities | 36,645 | 20,997 | ||||||
Total current liabilities | 167,883 | 115,240 | ||||||
Credit facility (note 8) | 1,090,000 | 345,000 | ||||||
Senior notes, net (note 8) | 755,699 | 755,696 | ||||||
Deferred income taxes (note 10) | 2,739 | 2,487 | ||||||
Asset retirement obligations (note 11) | 111,642 | 98,480 | ||||||
Derivative instruments (note 4) | 1,775 | 4,393 | ||||||
Other long-term liabilities | 4,431 | 4,662 | ||||||
Total liabilities | 2,134,169 | 1,325,958 | ||||||
Commitments and contingencies (note 12) | ||||||||
Equity | ||||||||
Partners' equity (note 13) | 1,766,287 | 1,589,536 | ||||||
Total liabilities and equity | $ | 3,900,456 | $ | 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
Consolidated Statements of Operations
(Unaudited)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
Thousands of dollars, except per unit amounts | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Revenues and other income items | ||||||||||||||||
Oil, natural gas and natural gas liquid sales | $ | 197,413 | $ | 111,700 | $ | 467,061 | $ | 300,688 | ||||||||
(Loss) gain on commodity derivative instruments, net (note 4) | (54,765 | ) | (69,418 | ) | (11,948 | ) | 1,865 | |||||||||
Other revenue, net | 737 | 796 | 2,197 | 2,848 | ||||||||||||
Total revenues and other income items | 143,385 | 43,078 | 457,310 | 305,401 | ||||||||||||
Operating costs and expenses | ||||||||||||||||
Operating costs | 68,502 | 50,048 | 181,889 | 142,203 | ||||||||||||
Depletion, depreciation and amortization | 60,125 | 37,270 | 154,456 | 109,068 | ||||||||||||
General and administrative expenses | 16,116 | 13,721 | 44,695 | 40,321 | ||||||||||||
Loss on sale of assets | 77 | 68 | 139 | 222 | ||||||||||||
Total operating costs and expenses | 144,820 | 101,107 | 381,179 | 291,814 | ||||||||||||
Operating (loss) income | (1,435 | ) | (58,029 | ) | 76,131 | 13,587 | ||||||||||
Interest expense, net of capitalized interest | 23,548 | 15,362 | 60,387 | 43,231 | ||||||||||||
Loss on interest rate swaps (note 4) | — | 242 | — | 926 | ||||||||||||
Other expense (income), net | 4 | 17 | (5 | ) | 36 | |||||||||||
(Loss) income before taxes | (24,987 | ) | (73,650 | ) | 15,749 | (30,606 | ) | |||||||||
Income tax expense (benefit) (note 10) | 24 | (647 | ) | 628 | (201 | ) | ||||||||||
Net (loss) income | (25,011 | ) | (73,003 | ) | 15,121 | (30,405 | ) | |||||||||
Less: Net income attributable to noncontrolling interest | — | — | — | (62 | ) | |||||||||||
Net (loss) income attributable to the partnership | $ | (25,011 | ) | $ | (73,003 | ) | $ | 15,121 | $ | (30,467 | ) | |||||
Basic net (loss) income per common unit (note 13) | $ | (0.25 | ) | $ | (1.00 | ) | $ | 0.15 | $ | (0.44 | ) | |||||
Diluted net (loss) income per common unit (note 13) | $ | (0.25 | ) | $ | (1.00 | ) | $ | 0.15 | $ | (0.44 | ) |
See accompanying notes to consolidated financial statements.
3
BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statements of Cash Flows
(Unaudited)
Nine Months Ended | ||||||||
September 30, | ||||||||
Thousands of dollars | 2013 | 2012 | ||||||
Cash flows from operating activities | ||||||||
Net income (loss) | $ | 15,121 | $ | (30,405 | ) | |||
Adjustments to reconcile to cash flows from operating activities: | ||||||||
Depletion, depreciation and amortization | 154,456 | 109,068 | ||||||
Unit-based compensation expense | 14,700 | 16,855 | ||||||
Loss (gain) on derivative instruments | 11,948 | (939 | ) | |||||
Derivative instrument settlements | 3,633 | 62,877 | ||||||
Prepaid premiums on derivative instruments | — | (13,303 | ) | |||||
Income from equity affiliates, net | (122 | ) | 356 | |||||
Deferred income taxes | 252 | (503 | ) | |||||
Loss on sale of assets | 139 | 222 | ||||||
Other | 3,989 | 3,366 | ||||||
Changes in net assets and liabilities | ||||||||
Accounts receivable and other assets | (62,882 | ) | 2,878 | |||||
Inventory | (8,032 | ) | 1,208 | |||||
Net change in related party receivables and payables | 883 | 2,329 | ||||||
Accounts payable and other liabilities | 32,857 | 12,267 | ||||||
Net cash provided by operating activities | 166,942 | 166,276 | ||||||
Cash flows from investing activities | ||||||||
Property acquisitions | (861,601 | ) | (313,404 | ) | ||||
Capital expenditures | (191,472 | ) | (77,699 | ) | ||||
Proceeds from sale of assets | 226 | 863 | ||||||
Net cash used in investing activities | (1,052,847 | ) | (390,240 | ) | ||||
Cash flows from financing activities | ||||||||
Issuance of common units | 285,011 | 370,504 | ||||||
Distributions | (137,447 | ) | (93,734 | ) | ||||
Proceeds from long-term debt | 1,381,000 | 1,066,885 | ||||||
Repayments of long-term debt | (636,000 | ) | (1,109,000 | ) | ||||
Change in bank overdraft | (316 | ) | (2,299 | ) | ||||
Debt issuance costs | (8,032 | ) | (9,346 | ) | ||||
Net cash provided by financing activities | 884,216 | 223,010 | ||||||
Decrease in cash | (1,689 | ) | (954 | ) | ||||
Cash beginning of period | 4,507 | 5,328 | ||||||
Cash end of period | $ | 2,818 | $ | 4,374 |
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 included in our 2012 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 September 30, 2013, our operating results for the three months and nine months ended September 30, 2013 and 2012, and our cash flows for the nine months ended September 30, 2013 and 2012 have been included. Operating results for the three months ended September 30, 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 notes required by GAAP for complete financial statements. For further information, refer to the consolidated financial statements and notes thereto included in our 2012 Annual Report.
We follow the successful efforts method of accounting for oil and gas activities. Depletion, depreciation and amortization (“DD&A”) of proved oil and natural gas properties is computed using the units-of-production method, net of any estimated residual salvage values.
2. New 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 ASU requires retrospective application. We adopted this ASU effective January 1, 2013, and expanded our financial statement disclosures. The adoption of this ASU did not have an impact on our financial position, results of operations or cash flows.
3. Acquisitions
We account for acquisitions using the acquisition method of accounting. The initial accounting applied to our acquisitions at the time of the purchase may not be complete and adjustment to provisional accounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date prior to concluding on the final purchase price of an acquisition.
Our purchase price allocations are based on discounted cash flows, quoted market prices and estimates made by management, and the most significant assumptions are those related to the estimated fair values assigned to oil and natural gas properties with proved reserves. To estimate the fair values of acquired properties, estimates of oil and natural gas reserves are prepared by management in consultation with independent engineers. We apply estimated future prices to the estimated reserve quantities acquired, and estimate future operating and development costs to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted average cost of capital.
We conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions are expensed as incurred.
The fair value measurements of oil and natural gas properties and asset retirement obligations (“ARO”) are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and ARO were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and are subject to change.
5
Oklahoma Panhandle Acquisitions
On July 15, 2013, we completed the acquisition of certain oil and natural gas and midstream assets located in Oklahoma, New Mexico and Texas, certain carbon dioxide (“CO2”) supply contracts, certain crude oil swaps and interests in certain entities from Whiting Oil and Gas Corporation (“Whiting”) for approximately $833 million in cash (the “Whiting Acquisition”). We used borrowings under our credit facility to fund this acquisition. The preliminary purchase price for this acquisition was allocated to the assets acquired and liabilities assumed as follows:
Thousands of dollars | |||
Oil and gas properties - proved | $765,390 | ||
Oil and gas properties - unproved | 52,585 | ||
Derivative assets - current | 15 | ||
Intangibles | 14,739 | ||
Derivative assets - long-term | 16,183 | ||
Other long-term assets | 1,032 | ||
Derivative liabilities - current | (6,347 | ) | |
Accrued liabilities | (2,000 | ) | |
Asset retirement obligations | (8,219 | ) | |
$833,378 |
Thousands of dollars | |||
Purchase price paid | $832,247 | ||
Estimated pending post-closing adjustments | 1,131 | ||
$833,378 |
Whiting novated to us derivative contracts, with a counterparty that is a participant in our current credit facility, consisting of NYMEX West Texas Intermediate (“WTI”) fixed price crude oil swaps covering a total of approximately 5.4 million barrels of future production in 2013 through 2016 at a weighted average hedge price of $95.44 per Bbl, which were valued as a net asset of $9.9 million at the acquisition date. The preliminary purchase price allocation also included finite-lived intangibles valued at $14.7 million relating to two CO2 purchase contracts that we received in the acquisition. We will be amortizing the contracts based on the amount of CO2 purchases made in each period over the contracts’ respective lives, with the first one expiring in December 2014, and the second one expiring in September 2023. In each of the three months and nine months ended September 30, 2013, we recorded $1.5 million in amortization for these contracts.
The preliminary purchase price allocation is based on discounted cash flows, quoted market prices and estimates made by management, with the most significant assumptions related to the estimated fair values assigned to oil and natural gas properties with proved reserves. To estimate the fair values of these properties, estimates of oil and natural gas reserves were prepared by management in consultation with independent engineers. We applied estimated future prices to the estimated reserve quantities acquired, and estimated future operating and development costs to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues were discounted using a market-based weighted average cost of capital rate of approximately 10%. We also employed a third-party valuation firm to assist in the valuation of the associated facilities, including pipelines, gathering lines and processing facilities.
We also completed the acquisition of additional interests in certain of the acquired assets in the Oklahoma Panhandle from other sellers for an additional $30 million in July 2013, subject to customary post-closing adjustments (together with the Whiting Acquisition, the “Oklahoma Panhandle Acquisitions”). We used borrowings under our credit facility to fund these acquisitions.
6
Acquisition-related costs for the Oklahoma Panhandle Acquisitions were $2.9 million in the nine months ended September 30, 2013 and were reflected in general and administrative (“G&A”) expenses on the consolidated statements of operations. In each of the three months and nine months ended September 30, 2013, we recorded $52.3 million in sales revenue and $13.4 million in lease operating expenses, including production and property taxes, from our Oklahoma Panhandle Acquisitions.
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 $164 million, $25 million and $10 million, respectively. The final purchase price for each of the 2012 acquisitions in the Permian Basin were primarily allocated to oil and natural gas properties, which included $52.5 million of unproved oil and gas properties, with $44.3 million related to Element Petroleum, LP acquisition and $8.2 million related to the first CrownRock, L.P, acquisition. Acquisition-related costs for the July 2, 2012 acquisitions from Element Petroleum, LP and CrownRock, L.P. were $1.0 million and were recorded in general and administrative expenses on the consolidated statements of operations. Acquisition-related costs for the December 28, 2012 acquisitions from CrownRock, L.P., Lynden USA Inc. and Piedra Energy I, LLC, were $0.5 million and were recorded in general and administrative expenses on the consolidated statements of operations. During the three months and nine months ended September 30, 2013, we recorded $23.7 million and $65.1 million, respectively, in sales revenue and $5.3 million and $15.5 million, respectively, in lease operating expenses, including production and property taxes, from our Permian Basin properties. During the three months and nine months ended September 30, 2012, we recorded $9.2 million and $9.2 million, respectively, in sales revenue and $1.8 million and $1.8 million, respectively, in lease operating expenses, including production and property taxes, from our Permian Basin properties.
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”) for approximately $38 million in cash and 3 million of our common units representing limited partner interests in us (“Common Units”). Of the final purchase price of $38 million in cash and $56 million in Common Units, $97.8 million was allocated to oil and natural gas properties and $4.0 million was allocated to ARO. Acquisition-related costs for the AEO Acquisition were $0.4 million and were recorded in general and administrative expenses on the consolidated statements of operations. Revenues and expenses from the AEO properties are reflected in our consolidated statements of operations beginning December 1, 2012. During the three months and nine months ended September 30, 2013, we recorded $12.7 million and $27.8 million, respectively, in sales revenue and $1.7 million and $4.8 million, respectively, in lease operating expenses, including production and property taxes, from the properties acquired in the AEO Acquisition.
NiMin Acquisition
In June 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 natural gas properties (including $36.2 million in unproved properties) and included $1.7 million of ARO. Acquisition-related costs for the NiMin Acquisition were $0.4 million and were reflected in general and administrative expenses on the consolidated statements of operations. Revenues and expenses from the NiMin properties are reflected in our consolidated statements of operations beginning June 28, 2012. During the three months and nine months ended September 30, 2013, we recorded $4.6 million and $11.9 million, respectively, in sales revenue and $1.7 million and $4.5 million, respectively, in lease operating expenses, including production and property taxes, from our NiMin properties. During the three months and nine months ended September 30, 2012, we recorded $3.2 million and $3.3 million, respectively, in sales revenue and $1.7 million and $1.7 million, respectively, in lease operating expenses, including production and property taxes, from the properties acquired in the NiMin Acquisition.
7
Pro Forma
The following unaudited pro forma financial information presents a summary of our combined statements of operations for the three months and nine months ended September 30, 2013 and 2012, assuming the Whiting Acquisition and additional acquired assets in the Oklahoma Panhandle acquisitions had been completed in January 1, 2012, 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 statements of operations with the results of operations from all of our 2012 and 2013 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, 2012 or 2011.
Pro Forma | ||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
Thousands of dollars, except per unit amounts | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Revenues | $ | 151,994 | $ | 120,938 | $ | 579,766 | $ | 569,004 | ||||||||
Net income (loss) attributable to the partnership | (21,311 | ) | (41,528 | ) | 63,518 | 78,031 | ||||||||||
Net income (loss) per common unit: | ||||||||||||||||
Basic | $ | (0.21 | ) | $ | (0.42 | ) | $ | 0.63 | $ | 0.77 | ||||||
Diluted | $ | (0.21 | ) | $ | (0.42 | ) | $ | 0.62 | $ | 0.77 |
4. Financial Instruments
Our risk management programs are intended to reduce our exposure to commodity price and interest rate volatilities and to assist with stabilizing cash flows and distributions. Routinely, we utilize derivative financial instruments to reduce this volatility. To the extent we have entered into economic hedges for 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 differentials often result in a lack of adequate correlation to enable these derivative instruments to qualify as 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.
8
We had the following commodity derivative contracts in place at September 30, 2013:
Year | |||||||||||||||||||||||
2013 | 2014 | 2015 | 2016 | 2017 | 2018 | ||||||||||||||||||
Oil Positions: | |||||||||||||||||||||||
Fixed Price Swaps - NYMEX WTI | |||||||||||||||||||||||
Hedged Volume (Bbl/d) | 13,016 | 11,314 | 10,189 | 6,711 | 5,471 | 493 | |||||||||||||||||
Average Price ($/Bbl) | $ | 95.26 | $ | 93.67 | $ | 94.71 | $ | 86.97 | $ | 83.38 | $ | 82.20 | |||||||||||
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) | 18,716 | 17,614 | 15,489 | 12,511 | 5,769 | 493 | |||||||||||||||||
Average Price ($/Bbl) | $ | 95.01 | $ | 94.78 | $ | 94.75 | $ | 90.15 | $ | 84.11 | $ | 82.20 | |||||||||||
Gas Positions: | |||||||||||||||||||||||
Fixed Price Swaps - MichCon City-Gate | |||||||||||||||||||||||
Hedged Volume (MMBtu/d) | 37,000 | 7,500 | 7,500 | 17,000 | 10,000 | — | |||||||||||||||||
Average Price ($/MMBtu) | $ | 6.50 | $ | 6.00 | $ | 6.00 | $ | 4.46 | $ | 4.48 | $ | — | |||||||||||
Fixed Price Swaps - Henry Hub | |||||||||||||||||||||||
Hedged Volume (MMBtu/d) | 27,100 | 38,600 | 43,200 | 20,700 | 5,571 | — | |||||||||||||||||
Average Price ($/MMBtu) | $ | 4.68 | $ | 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) | 64,100 | 52,100 | 52,200 | 37,700 | 15,571 | — | |||||||||||||||||
Average Price ($/MMBtu) | $ | 5.73 | $ | 4.99 | $ | 5.00 | $ | 4.34 | $ | 4.49 | $ | — | |||||||||||
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 | $ | — | $ | — | $ | — | $ | — |
During the nine months ended September 30, 2013, we did not enter into any derivative instruments that required pre-paid premiums. During the nine months ended September 30, 2012, we paid $13.3 million in premiums on commodity derivative instruments that related to future periods.
As of September 30, 2013, premiums paid in 2012 related to oil and natural gas derivatives to be settled in the fourth quarter of 2013 and beyond were as follows:
Year | ||||||||||||||||||||||||
Thousands of dollars | 2013 | 2014 | 2015 | 2016 | 2017 | 2018 | ||||||||||||||||||
Oil | $ | 1,233 | $ | 4,479 | $ | 4,683 | $ | 7,438 | $ | 734 | $ | — | ||||||||||||
Natural gas | $ | — | $ | 4,015 | $ | 1,989 | $ | 952 | $ | — | $ | — |
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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 in the past entered, and may in the future enter, into interest rate derivative contracts, indexed to 1-month LIBOR, to fix a portion of floating LIBOR-based debt under our credit facility. As of September 30, 2013 and December 31, 2012, we had no interest rate swaps in place.
Fair Value of Financial Instruments
The following table presents the fair value of our derivative instruments, none of which are 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 September 30, 2013 | ||||||||||||||||
Assets | ||||||||||||||||
Current assets - derivative instruments | $ | 3,210 | $ | 28,370 | $ | (15,022 | ) | $ | 16,558 | |||||||
Other long-term assets - derivative instruments | 53,144 | 26,997 | (9,056 | ) | 71,085 | |||||||||||
Total assets | 56,354 | 55,367 | (24,078 | ) | 87,643 | |||||||||||
Liabilities | ||||||||||||||||
Current liabilities - derivative instruments | (26,685 | ) | (725 | ) | 15,022 | (12,388 | ) | |||||||||
Long-term liabilities - derivative instruments | (10,327 | ) | (504 | ) | 9,056 | (1,775 | ) | |||||||||
Total liabilities | (37,012 | ) | (1,229 | ) | 24,078 | (14,163 | ) | |||||||||
Net assets | $ | 19,342 | $ | 54,138 | $ | — | $ | 73,480 | ||||||||
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.
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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 September 30, 2013 | ||||||||||||||||
Net (loss) gain | $ | (62,770 | ) | $ | 8,005 | $ | — | $ | (54,765 | ) | ||||||
Three Months Ended September 30, 2012 | ||||||||||||||||
Net loss | $ | (53,180 | ) | $ | (16,238 | ) | $ | (242 | ) | $ | (69,660 | ) | ||||
Nine Months Ended September 30, 2013 | ||||||||||||||||
Net (loss) gain | $ | (22,072 | ) | $ | 10,124 | $ | — | $ | (11,948 | ) | ||||||
Nine Months Ended September 30, 2012 | ||||||||||||||||
Net (loss) gain | $ | (7,988 | ) | $ | 9,853 | $ | (926 | ) | $ | 939 |
(a) Included in (loss) gain 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 that are observable other than quoted prices that are included within 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 September 30, 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 and nine months ended September 30, 2013 and 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.
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Assumed credit risk adjustments, based on published credit ratings and credit default swap rates, are applied to our derivative instruments.
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 September 30, 2013 | ||||||||||||||||
Assets (liabilities) | ||||||||||||||||
Crude Oil | ||||||||||||||||
Crude oil swaps | $ | — | $ | 8,799 | $ | — | $ | 8,799 | ||||||||
Crude oil collars | — | — | 3,819 | 3,819 | ||||||||||||
Crude oil puts | — | — | 6,724 | 6,724 | ||||||||||||
Natural Gas | ||||||||||||||||
Natural gas swaps | — | 51,781 | — | 51,781 | ||||||||||||
Natural gas calls | — | — | (868 | ) | (868 | ) | ||||||||||
Natural gas puts | — | — | 3,225 | 3,225 | ||||||||||||
Net Assets | $ | — | $ | 60,580 | $ | 12,900 | $ | 73,480 | ||||||||
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 puts | — | — | 11,144 | 11,144 | ||||||||||||
Natural Gas | ||||||||||||||||
Natural gas swaps | — | 74,782 | — | 74,782 | ||||||||||||
Natural gas calls | — | — | (1,489 | ) | (1,489 | ) | ||||||||||
Natural gas puts | — | — | 3,162 | 3,162 | ||||||||||||
Net Assets | $ | — | $ | 62,369 | $ | 16,841 | $ | 79,210 |
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The following table sets forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3:
Three Months Ended September 30, | ||||||||||||||||
2013 | 2012 | |||||||||||||||
Thousands of dollars | Oil | Natural Gas | Oil | Natural Gas | ||||||||||||
Assets (a): | ||||||||||||||||
Beginning balance | $ | 15,412 | $ | 2,054 | $ | 22,062 | $ | 22,242 | ||||||||
Derivative instrument settlements (b) | (125 | ) | (225 | ) | 3,968 | 10,515 | ||||||||||
Gain (loss) (b)(c) | (4,744 | ) | 528 | (16,499 | ) | (23,173 | ) | |||||||||
Purchases (b)(d) | — | — | — | 1,252 | ||||||||||||
Ending balance | $ | 10,543 | $ | 2,357 | $ | 9,531 | $ | 10,836 | ||||||||
Nine Months Ended September 30, | ||||||||||||||||
2013 | 2012 | |||||||||||||||
Thousands of dollars | Oil | Natural Gas | Oil | Natural Gas | ||||||||||||
Assets (a): | ||||||||||||||||
Beginning balance | $ | 15,169 | $ | 1,672 | $ | 8,509 | $ | 37,049 | ||||||||
Derivative instrument settlements (b) | (125 | ) | (667 | ) | 9,425 | 33,143 | ||||||||||
Gain (loss) (b)(c) | (4,501 | ) | 1,352 | (8,403 | ) | (64,386 | ) | |||||||||
Purchases (b)(d) | — | — | — | 5,030 | ||||||||||||
Ending balance | $ | 10,543 | $ | 2,357 | $ | 9,531 | $ | 10,836 |
(a) We had no changes in fair value of our derivative instruments classified as Level 3 related to sales or issuances.
(b) Included in (loss) gain on commodity derivative instruments, net on the consolidated statements of operations.
(c) Represents gain (loss) on mark-to-market of derivative instruments.
(d) Relates to natural gas put options entered into in June 2012 and crude oil options entered into in August 2012.
For Level 3 derivative instruments measured at fair value on a recurring basis as of September 30, 2013, the significant unobservable inputs used in the fair value measurements were as follows:
Fair Value at | Valuation | |||||||||
Thousands of dollars | September 30, 2013 | Technique | Unobservable Input | Range | ||||||
Oil Options | $ | 10,543 | Option Pricing Model | Oil forward commodity prices | $83.87/Bbl - $102.22/Bbl | |||||
Oil volatility | 16.18% - 22.29% | |||||||||
Own credit risk | 5% | |||||||||
Natural Gas Options | 2,357 | Option Pricing Model | Gas forward commodity prices | $3.50/MMBtu - $4.26/MMBtu | ||||||
Gas volatility | 20.32% - 30.33% | |||||||||
Own credit risk | 5% | |||||||||
Total | $ | 12,900 |
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For Level 3 derivative instruments measured at fair value on a recurring basis as of December 31, 2012, the significant unobservable inputs used in the fair value measurements were as follows:
Fair Value at | Valuation | |||||||||
Thousands of dollars | December 31, 2012 | Technique | Unobservable Input | Range | ||||||
Oil Options | $ | 15,169 | Option Pricing Model | Oil forward commodity prices | $86.78/Bbl - $110.46/Bbl | |||||
Oil volatility | 20.56% - 27.53% | |||||||||
Own credit risk | 5% | |||||||||
Natural Gas Options | 1,672 | Option Pricing Model | Gas forward commodity prices | $3.35/MMBtu - $4.87/MMBtu | ||||||
Gas volatility | 20.55% - 35.88% | |||||||||
Own credit risk | 5% | |||||||||
Total | $ | 16,841 |
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 September 30, 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, Royal Bank of Canada and Toronto-Dominion Bank. We periodically obtain credit default swap information on our counterparties. As of September 30, 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 September 30, 2013, our largest derivative asset balances were with Wells Fargo Bank, National Association, Credit Suisse Energy LLC and Citibank, N.A., which accounted for approximately 31%, 24% and 13% of our net derivative asset balances, respectively.
5. 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 three months and nine months ended September 30, 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 September 30, 2013 and December 31, 2012, we had current receivables of $0.4 million and $1.2 million, respectively, due from PCEC related to the administrative services agreement, employee-related costs and oil and natural gas sales made by PCEC on our behalf from certain properties. For the three months ended September 30, 2013 and 2012, the monthly charges to PCEC for indirect expenses totaled $2.1 million and $2.1 million, respectively, and charges for direct expenses including payroll and administrative costs totaled $2.9 million and $2.3 million, respectively. For the nine months ended September 30, 2013 and 2012, the monthly charges to PCEC for indirect expenses totaled $6.3 million and $5.9 million, respectively, and charges for direct expenses including payroll and administrative costs totaled $7.3 million and $6.3 million, respectively.
At September 30, 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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6. Inventory
Our crude oil inventory from our Florida operations was $11.1 million at September 30, 2013 and $3.1 million at December 31, 2012. In the nine months ended September 30, 2013, we sold 511 gross MBbls and produced 596 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.
7. Impairments
We assess our developed and undeveloped oil and natural gas properties, finite-lived intangibles 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 . For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves, forecasted using five-year NYMEX forward strip prices at the end of the period and escalated, along with expenses and capital, starting from year six forward at 2.5% per year. For impairment charges recorded in 2012, the associated property’s expected future net cash flows were 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.
We assess our developed and undeveloped oil and natural gas properties, other long-lived assets and finite-lived intangibles for possible impairment periodically and whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable.
During the three months and nine months ended September 30, 2013, we recorded impairments of approximately $0.4 million, including $0.2 million for a Florida property and $0.2 million related to a few smaller Michigan properties. During the three months ended September 30, 2012, we recorded no impairments. During the nine months ended September 30, 2012, we recorded non-cash impairment charges of approximately $11.6 million, respectively, primarily related to uneconomic proved properties in Michigan, Indiana and Kentucky due to decreases in natural gas prices. The impairments are reflected in depletion, depreciation and amortization on the consolidated statements of operations and in accumulated depletion and depreciation on the consolidated balance sheets.
An estimate as to the sensitivity to our earnings for these periods had other assumptions been used in impairment reviews and calculations is not practicable, given the range of assumptions involved in these estimates. Favorable changes to some assumptions might have mitigated the need to impair certain assets in these periods, whereas unfavorable changes might have caused an additional unknown number of additional assets to become impaired.
8. Long-Term Debt
Credit Facility
BreitBurn Operating L.P. (“BOLP”), as borrower, and we and our wholly-owned subsidiaries, as guarantors, have a $3.0 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 July 2013, we entered into the Ninth Amendment to the Second Amended and Restated Credit Agreement, which increased our aggregate maximum credit amount from $1.5 billion to $3.0 billion, increased our borrowing base to $1.5 billion and increased the aggregate commitment of all lenders to $1.4 billion. The amendment also increased flexibility for
15
the Total Leverage Ratio (defined as the ratio of total debt to EBITDAX) for the next five quarters and added a new Senior Secured Leverage Ratio (defined as the ratio of senior secured indebtedness to EBITDAX) that will be applied until the earlier of the end of the second quarter of 2014 and our receipt of net cash proceeds from the issuance of Common Units of at least $350 million. The Ninth Amendment provides that we are required to maintain a Total Leverage Ratio as of the last day of each quarter, on a last 12-month basis, of no more than 4.75 to 1.00 through the first quarter of 2014, no more than 4.50 to 1.00 through the second quarter of 2014, no more than 4.25 to 1.00 through the third quarter of 2014 and thereafter no more than 4.00 to 1.00. We also are required to maintain a Senior Secured Leverage Ratio as of the last day of each quarter, on a last 12-month basis, of no more than 3.00 to 1.00 through the fourth quarter of 2013 and no more than 2.75 to 1.00 through the second quarter of 2014. The numerator of each of these ratios automatically decreases by .25 or .50 if we receive net cash proceeds from the issuance of Common Units of, at least, $175 million or, with respect to the Total Leverage Ratio, $350 million, respectively, but in no event will the Total Leverage Ratio be reduced to less than 4.00 to 1.00.
As of September 30, 2013 and December 31, 2012, our borrowing base was $1.5 billion and $1.0 billion, respectively, and the aggregate commitment of all lenders was $1.4 billion and $900 million, respectively.
As of September 30, 2013 and December 31, 2012, we had $1.1 billion and $345 million, respectively, in indebtedness outstanding under our credit facility. At September 30, 2013, the 1-month LIBOR interest rate plus an applicable spread was 2.4306% on the 1-month LIBOR portion of $1,087 million and the prime rate plus an applicable spread was 4.50% on the prime portion of $3 million. At September 30, 2013, we had $15.2 million of unamortized debt issuance costs related to our credit facility.
As of September 30, 2013 and December 31, 2012, we were in compliance with our 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 $301.5 million, net of unamortized discount of $3.5 million, as of September 30, 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 $454.2 million, net of unamortized premium of $4.2 million, as of September 30, 2013. At September 30, 2013, we had $14.7 million of unamortized debt issuance costs related to our Senior Notes.
Interest on our senior notes is payable twice a year in April and October.
As of September 30, 2013, the fair value of our 2020 Senior Notes and 2022 Senior Notes was estimated to be $322.4 million and $450.4 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.
As of September 30, 2013 and December 31, 2012, we were in compliance with the covenants under our senior notes.
Interest Expense
Our interest expense is detailed as follows:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
Thousands of dollars | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Credit agreement (including commitment fees) | $ | 6,313 | $ | 2,804 | $ | 9,718 | $ | 5,846 | ||||||||
Senior notes | 15,436 | 11,557 | 46,308 | 33,843 | ||||||||||||
Amortization of discount and deferred issuance costs | 1,826 | 1,041 | 4,423 | 3,582 | ||||||||||||
Capitalized interest | (27 | ) | (40 | ) | (62 | ) | (40 | ) | ||||||||
Total | $ | 23,548 | $ | 15,362 | $ | 60,387 | $ | 43,231 |
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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 BreitBurn Energy Partners I, L.P. (“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. Additionally, all of our material subsidiaries are 100% owned and 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.
Our deferred federal income tax liability was $2.7 million and $2.5 million at September 30, 2013 and December 31, 2012, respectively. The following table presents our income tax expense (benefit) for the three months and nine months ended September 30, 2013 and 2012:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
Thousands of dollars | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Federal income tax expense (benefit) | ||||||||||||||||
Current | $ | 41 | $ | (65 | ) | $ | 67 | $ | 199 | |||||||
Deferred (a) | (45 | ) | (629 | ) | 252 | (503 | ) | |||||||||
State income tax expense (b) | 28 | 47 | 309 | 103 | ||||||||||||
Total | $ | 24 | $ | (647 | ) | $ | 628 | $ | (201 | ) |
(a) Related to Phoenix, a tax-paying corporation and our wholly-owned subsidiary.
(b) Primarily in California and Texas.
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11. Asset Retirement Obligations
ARO 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 ARO occur over the operating lives of the assets, estimated to range 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 ARO 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 ARO for the period ended September 30, 2013 and the year ended December 31, 2012 are presented in the following table:
Nine Months Ended | Year Ended | |||||||
Thousands of dollars | September 30, 2013 | December 31, 2012 | ||||||
Carrying amount, beginning of period | $ | 98,480 | $ | 82,397 | ||||
Acquisitions | 8,219 | 6,279 | ||||||
Liabilities incurred | 90 | 2,468 | ||||||
Liabilities settled | (430 | ) | (86 | ) | ||||
Revisions | — | 1,553 | ||||||
Accretion expense | 5,283 | 5,869 | ||||||
Carrying amount, end of period | $ | 111,642 | $ | 98,480 |
12. Commitments and Contingencies
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 September 30, 2013 and December 31, 2012, we had surety bonds for $17.1 million and $16.2 million, respectively. At both September 30, 2013 and December 31, 2012, we had approximately $1.0 million and $0.3 million in letters of credit outstanding, respectively.
Purchase Contracts
On July 15, 2013, we completed the acquisition of the Whiting Assets. The Whiting Assets include the Postle Field, which currently has active CO2 enhanced recovery projects, and the Northeast Hardesty Unit, both of which are located in Texas County, Oklahoma. We have a contracted supply of CO2 in the Bravo Dome Field in New Mexico, with step-in rights, for 129,000,000 Mcf over 10 to 15 years, which we expect to provide volumes in excess of those required to produce our estimated proved reserves when coupled with recycled CO2. Under the take-or-pay provisions of these purchase agreements, we are committed to buying certain volumes of CO2 for use in our enhanced recovery project being carried out at the Postle field. We are obligated to purchase a minimum daily volume of CO2 (as calculated on an annual basis) or else pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. The CO2 volumes planned for use in our enhanced recovery projects in the Postle Field currently exceed the minimum daily volumes specified in these agreements. Therefore, we expect to avoid any payments for deficiencies. The table below shows our future minimum commitments under these purchase agreements as of September 30, 2013:
Year Ending December 31, | ||||||||||||||||||||||||||||
Thousands of dollars | 2013 | 2014 | 2015 | 2016 | 2017 | Thereafter | Total | |||||||||||||||||||||
Purchase contracts | $ | 2,434 | $ | 6,930 | $ | 18,539 | $ | 14,638 | $ | 15,663 | $ | 66,841 | $ | 125,045 |
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13. Partners’ Equity
In February 2013, we sold 14.95 million Common Units at a price to the public of $19.86 per Common Unit, resulting in proceeds of $285.0 million (net of underwriting discount and offering expenses).
During the nine months ended September 30, 2013, we issued 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 September 30, 2013 and December 31, 2012, we had approximately 99.7 million and 84.7 million Common Units outstanding, respectively. At September 30, 2013 and December 31, 2012, there were approximately 2.1 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, or $0.4700 per Common Unit. On May 14, 2013, we paid a cash distribution of approximately $47.3 million, or $0.4750 per Common Unit. On August 14, 2013, we paid a cash distribution of approximately $47.8 million, or $0.4800 per Common Unit.
During the three months and nine months ended September 30, 2013, we also paid $0.8 million and $2.4 million, respectively, in cash at a rate equal to the distributions paid to our holders of Common Units to holders of outstanding unvested RPUs issued under our LTIP.
On February 14, 2012, we paid a cash distribution of approximately $27.0 million, or $0.4500 per Common Unit. On May 14, 2012, we paid a cash distribution of approximately $31.5 million, or $0.4550 per Common Unit. On August 14, 2012, we paid a cash distribution of approximately $31.8 million, or $0.4600 per Common Unit.
During the three months and nine months ended September 30, 2012, we also paid $1.2 million and $3.5 million, respectively, in cash at a rate equal to the distributions paid to our holders of Common Units to holders of outstanding unvested RPUs.
Income 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 per common unit.
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The following is a reconciliation of net income loss attributable to the partnership and weighted average units for calculating basic net income loss per common unit and diluted net income loss per common unit.
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
Thousands, except per unit amounts | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Net (loss) income attributable to the partnership | $ | (25,011 | ) | $ | (73,003 | ) | $ | 15,121 | $ | (30,467 | ) | |||||
Distributions on participating units not expected to vest | 4 | — | 15 | — | ||||||||||||
Net (loss) income attributable to holders of Common Units and participating securities | $ | (25,007 | ) | $ | (73,003 | ) | $ | 15,136 | $ | (30,467 | ) | |||||
Weighted average number of units used to calculate basic and diluted net income per unit: | ||||||||||||||||
Common Units | 99,680 | 72,894 | 97,982 | 69,363 | ||||||||||||
Participating securities (a) | — | — | 1,652 | — | ||||||||||||
Denominator for basic income per common unit | 99,680 | 72,894 | 99,634 | 69,363 | ||||||||||||
Dilutive units (b) | — | — | 355 | — | ||||||||||||
Denominator for diluted income per common unit | 99,680 | 72,894 | 99,989 | 69,363 | ||||||||||||
Net (loss) income per common unit | ||||||||||||||||
Basic | $ | (0.25 | ) | $ | (1.00 | ) | $ | 0.15 | $ | (0.44 | ) | |||||
Diluted | $ | (0.25 | ) | $ | (1.00 | ) | $ | 0.15 | $ | (0.44 | ) |
(a) The three months ended September 30, 2013 and 2012 and the nine months ended September 30, 2012 exclude 1,729, 2,557 and 2,513, respectively, of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.
(b) The three months ended September 30, 2013 and 2012 and the nine months ended September 30, 2012 exclude 384, 59 and 57, respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position.
14. Unit and Other Valuation-Based Compensation Plans
Unit-based compensation expense for the three months and nine months ended September 30, 2013 was $4.9 million and $14.7 million, respectively, and for the three months and nine months ended September 30, 2012 was $5.7 million and $16.9 million, respectively. During the nine months ended September 30, 2013, the board of directors of BreitBurn GP, LLC (our “General Partner”) approved the grant of approximately 1.2 million of RPUs and CPUs to employees of BreitBurn Management under our LTIP. Our outside directors were issued less than 0.1 million RPUs under our LTIP during the nine months ended September 30, 2013. The fair market value of the RPUs granted during 2013 for computing compensation expense under FASB Accounting Standards averaged $20.84 per unit.
During the three months and nine months ended September 30, 2013, we paid zero and $0.6 million, respectively, for taxes withheld on RPUs vested during the period. During the three months and nine months ended September 30, 2012, we paid nothing for taxes withheld on RPUs vested during the period.
As of September 30, 2013, we had $27.8 million of total unrecognized compensation costs for all outstanding awards. The majority of this amount is expected to be recognized over the period from October 1, 2013 to December 31, 2015. For detailed information on our various compensation plans, see Note 17 to the consolidated financial statements included in our 2012 Annual Report.
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15. Subsequent Events
Distributions
On October 30, 2013, we announced a cash distribution to holders of Common Units for the third quarter of 2013 at the rate of $0.4875 per Common Unit, to be paid on November 14, 2013 to our holders of Common Units of record as of the close of business on November 11, 2013.
On October 30, 2013, we amended our First Amended and Restated Agreement of Limited Partnership by adopting Amendment No. 5. Amendment No. 5 provides that, at the discretion of our General Partner, we may pay quarterly distributions within 45 days following the end of each quarter or in three installments within 17, 45 and 75 days following the end of each quarter. The Partnership intends to change its distribution payment policy from a quarterly payment schedule to a monthly payment schedule beginning with the distributions relating to the fourth quarter of 2013. The payment of monthly distributions is expected to commence in January 2014.
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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 2012 Annual Report and the consolidated financial statements and related notes therein. Our 2012 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 2012 Annual Report and Part I—Item 1A “—Risk Factors” of our 2012 Annual Report.
Overview
We are an independent oil and natural gas partnership focused on the acquisition, exploitation and development of oil and natural gas properties in the United States. Our objective is to manage our oil and natural gas producing properties for the purpose of generating cash flows 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 Oklahoma Panhandle;
• 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 derivatives; 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 Acquisitions
On July 15, 2013, we completed the acquisition of the Whiting Assets from Whiting. We acquired the Whiting Assets for a preliminary purchase price of approximately $833.4 million in cash. Also, in July 2013, we completed the acquisition of additional interests in certain of the acquired assets in the Oklahoma Panhandle from other sellers for an additional approximately $30.2 million, subject to customary post-closing adjustments. The Whiting Assets include the Postle Field, which currently has active CO2 enhanced recovery projects, and the Northeast Hardesty Unit, both of which are located in Texas County, Oklahoma. We have a contracted supply of CO2 in the Bravo Dome Field in New Mexico, with step-in rights, for 129,000,000 Mcf over 10 to 15 years, which we expect will provide the volumes required to produce our estimated proved reserves when coupled with recycled CO2. The Postle Field includes 227 gross producing wells and 174 gross injectors, and the Northeast Hardesty Unit includes 24 gross producing wells and 17 gross injectors. As part of the acquisition and the purchase of additional interests, we are also the sole owner of the Dry Trails gas plant located in Texas County, Oklahoma and the 120-mile Transpetco Pipeline, a CO2 transportation pipeline delivering product from New Mexico to the Postle Field in Oklahoma. We funded the purchase price for the Whiting Acquisition and the acquisition of additional interests in certain of the acquired assets in the Oklahoma Panhandle with borrowings under our credit facility.
Our management’s review of the estimated proved reserves relating to the Whiting Acquisition indicated estimated proved reserves of 41.4 MMBoe, with an estimated proved reserve life index of approximately 15 years, as of June 30, 2013, which estimated proved reserves were determined using prices of $91.60 per barrel of oil and $3.44 per MMBtu of gas. Such prices were determined using the average of the historical first-day-of-the-month prices for the 12 months ended June 30, 2013 in accordance with Securities and Exchange Commission guidelines. Approximately 95% of these reserves were oil and NGLs, approximately 70% were proved developed and approximately 68% were proved developed producing as of June 30,
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2013. Management’s estimate of the average daily production per day for September 2013 from the Whiting Assets was approximately 7,275 Boe, which was comprised of approximately 83% crude oil, 13% NGLs and 4% natural gas. In 2013 to date, the price per barrel of oil for our production from the Whiting Assets represented an approximately $8 discount to the NYMEX WTI benchmark price. Reserve engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates prepared by one engineer may vary from those prepared by another. Estimates of proved reserves for our recently acquired Oklahoma properties as of December 31, 2013 will be prepared by Cawley, Gillespie & Associates, Inc. using the information available at that time. Upon completion of their review, the estimate of the proved reserves for our oil and natural gas properties as of December 31, 2013 will be different from our management’s estimate of the proved reserves for our Oklahoma oil and natural gas properties as of June 30, 2013 as described above.
2013 Highlights
In February 2013, we sold approximately 14.95 million Common Units at a price to the public of $19.86 per Common Unit, resulting in proceeds of $285.0 million (net of underwriting discounts and estimated offering expenses), 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, or $0.4700 per Common Unit. On May 14, 2013, we paid a cash distribution of approximately $47.3 million, or $0.4750 per Common Unit. On August 14, 2013, we paid a cash distribution of approximately $47.8 million, or $0.4800 per Common Unit. On October 30, 2013, we announced a cash distribution to holders of Common Units for the third quarter of 2013 at the rate of $0.4875 per Common Unit, to be paid on November 14, 2013 to our holders of Common Units of record as of the close of business on November 11, 2013.
In July 2013, we entered into the Ninth Amendment to the Second Amended and Restated Credit Agreement, which increased our aggregate maximum credit amount from $1.5 billion to $3.0 billion, increased our borrowing base to $1.5 billion and increased the aggregate commitment of all lenders to $1.4 billion. The amendment also increased flexibility for the Total Leverage Ratio (defined as the ratio of total debt to EBITDAX) for the next five quarters, absent any refinancing, and added a new Senior Secured Leverage Ratio (defined as the ratio of senior secured indebtedness to EBITDAX) that will be applied through the second quarter of 2014, absent any refinancing.
Operational Focus and Capital Expenditures
In the first nine months of 2013, our oil and natural gas capital expenditures totaled $198 million, compared to approximately $93 million in the first nine months of 2012. We spent approximately $73 million in Texas, $64 million in California, $24 million in Wyoming, $20 million in Florida, $9 million in Oklahoma and $8 million in Michigan. In the first nine months of 2013, we drilled and completed 38 wells in Texas, 40 wells in California, 22 wells in Wyoming, 3 wells in Oklahoma, 3 wells in Michigan and 1 well in Florida. We also performed workovers on 18 wells in Wyoming, 17 wells in Michigan, 12 wells in California and 5 wells in Oklahoma.
In 2013, our crude oil and natural gas capital program is expected to be approximately $271 million. This compares with approximately $153 million in 2012. We plan to principally target oil projects and expect to spend approximately 84% of our capital budget in California, Florida, Texas and Oklahoma and approximately 16% in Michigan, Wyoming, Indiana and Kentucky. We anticipate that approximately 90% of our total capital spending will be focused on drilling and rate-generating projects that are designed to increase production or reserves. Including production from our Oklahoma Panhandle acquisitions and without considering potential future acquisitions, we expect our 2013 production to be approximately 11.0 MMBoe.
Commodity Prices
In the third quarter of 2013, the NYMEX WTI spot price averaged $106 per barrel, compared with approximately $92 per barrel in the third quarter of 2012. In the first nine months of 2013, the WTI spot price averaged $98 per barrel, compared with $96 per barrel a year earlier. The average NYMEX WTI spot price in October was approximately $101 per barrel, and in the first nine months of 2013, the NYMEX WTI spot price ranged from a low of $87 per barrel to a high of $111 per barrel. In 2012, the NYMEX WTI spot price averaged approximately $94 per barrel.
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In the third quarter of 2013, the Henry Hub natural gas spot price averaged $3.55 per MMBtu compared with approximately $2.88 per MMBtu in the third quarter of 2012. In the first nine months of 2013, the Henry Hub natural gas price averaged $3.69 per MMBtu, compared with $2.54 per MMBtu a year earlier. The Henry Hub natural gas spot price in October averaged approximately $3.68 per MMBtu and in the first nine months of 2013, the Henry Hub spot price ranged from a low of $3.08 to a high of $4.38. In 2012, the Henry Hub natural gas spot price averaged approximately $2.75 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 three months and nine months ended September 30, 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 our 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.
Thousands of dollars, except as | Three Months Ended September 30, | Increase/ | Nine Months Ended September 30, | Increase/ | ||||||||||||||||||||||||||
indicated | 2013 | 2012 | Decrease | % | 2013 | 2012 | Decrease | % | ||||||||||||||||||||||
Total production (MBoe) | 3,098 | 2,166 | 932 | 43 | % | 7,897 | 6,106 | 1,791 | 29 | % | ||||||||||||||||||||
Oil and NGL (MBoe) | 1,888 | 973 | 915 | 94 | % | 4,381 | 2,647 | 1,734 | 66 | % | ||||||||||||||||||||
Natural gas (MMcf) | 7,258 | 7,161 | 97 | 1 | % | 21,096 | 20,754 | 342 | 2 | % | ||||||||||||||||||||
Average daily production (Boe/d) | 33,674 | 23,545 | 10,129 | 43 | % | 28,928 | 22,284 | 6,644 | 30 | % | ||||||||||||||||||||
Sales volumes (MBoe) | 3,027 | 2,219 | 808 | 36 | % | 7,825 | 6,131 | 1,694 | 28 | % | ||||||||||||||||||||
Average realized sales price (per Boe) (a)(b) | $ | 65.14 | $ | 50.25 | $ | 14.89 | 30 | % | $ | 59.62 | $ | 48.95 | $ | 10.67 | 22 | % | ||||||||||||||
Oil and NGL (per Boe) (a)(b) | 93.73 | 87.59 | 6.14 | 7 | % | 89.47 | 90.93 | (1.46 | ) | (2 | )% | |||||||||||||||||||
Natural gas (per Mcf) (b) | 3.69 | 3.03 | 0.66 | 22 | % | 3.84 | 2.76 | 1.08 | 39 | % | ||||||||||||||||||||
Oil and NGL sales | $ | 170,597 | $ | 90,036 | $ | 80,561 | 89 | % | $ | 386,083 | $ | 243,504 | $ | 142,579 | 59 | % | ||||||||||||||
Natural gas sales | 26,816 | 21,664 | 5,152 | 24 | % | 80,978 | 57,184 | 23,794 | 42 | % | ||||||||||||||||||||
Oil, natural gas and NGL sales (a) | $ | 197,413 | $ | 111,700 | $ | 85,713 | 77 | % | $ | 467,061 | $ | 300,688 | $ | 166,373 | 55 | % | ||||||||||||||
(Loss) gain on commodity derivative instruments | (54,765 | ) | (69,418 | ) | 14,653 | (21 | )% | (11,948 | ) | 1,865 | (13,813 | ) | n/a | |||||||||||||||||
Other revenues, net | 737 | 796 | (59 | ) | (7 | )% | 2,197 | 2,848 | (651 | ) | (23 | )% | ||||||||||||||||||
Total revenues | 143,385 | 43,078 | 100,307 | 233 | % | 457,310 | 305,401 | 151,909 | 50 | % | ||||||||||||||||||||
Lease operating expenses before taxes (c) | 58,731 | 40,325 | 18,406 | 46 | % | 152,836 | 117,520 | 35,316 | 30 | % | ||||||||||||||||||||
Production and property taxes (d) | 14,476 | 8,574 | 5,902 | 69 | % | 34,925 | 22,672 | 12,253 | 54 | % | ||||||||||||||||||||
Total lease operating expenses | 73,207 | 48,899 | 24,308 | 50 | % | 187,761 | 140,192 | 47,569 | 34 | % | ||||||||||||||||||||
Purchases and other operating costs | 226 | 293 | (67 | ) | (23 | )% | 881 | 1,310 | (429 | ) | (33 | )% | ||||||||||||||||||
Change in inventory | (4,931 | ) | 856 | (5,787 | ) | n/a | (6,753 | ) | 701 | (7,454 | ) | n/a | ||||||||||||||||||
Total operating costs | $ | 68,502 | $ | 50,048 | $ | 18,454 | 37 | % | $ | 181,889 | $ | 142,203 | $ | 39,686 | 28 | % | ||||||||||||||
Lease operating expenses before taxes per Boe | $ | 18.96 | $ | 18.62 | $ | 0.34 | 2 | % | $ | 19.35 | $ | 19.25 | $ | 0.10 | 1 | % | ||||||||||||||
Production and property taxes per Boe | 4.67 | 3.96 | 0.71 | 18 | % | 4.42 | 3.71 | 0.71 | 19 | % | ||||||||||||||||||||
Total lease operating expenses per Boe | 23.63 | 22.58 | 1.05 | 5 | % | 23.77 | 22.96 | 0.81 | 4 | % | ||||||||||||||||||||
Depletion, depreciation and amortization (“DD&A”) | $ | 60,125 | $ | 37,270 | $ | 22,855 | 61 | % | $ | 154,095 | $ | 109,068 | $ | 45,027 | 41 | % | ||||||||||||||
DD&A per Boe | 19.41 | 17.21 | 2.20 | 13 | % | 19.51 | 17.86 | 1.65 | 9 | % | ||||||||||||||||||||
(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 and Nine Months Ended September 30, 2013 and 2012
The variances in our results were due to the following components:
Production
For the three months ended September 30, 2013, total production was 3,098 MBoe compared to 2,166 MBoe for the three months ended September 30, 2012, primarily due to 583 MBoe from our Oklahoma properties acquired in July 2013, a 218 MBoe increase in production from our Texas properties acquired in December of 2012, and 162 MBoe higher California production, including 130 MBoe from our California properties acquired in November 2012, partially offset by 28 MBoe lower Michigan production, primarily due to natural field declines.
For the nine months ended September 30, 2013, total production was 7,897 MBoe compared to 6,106 MBoe for the nine months ended September 30, 2012, primarily due to a 905 MBoe increase in production from our Texas properties acquired in July 2012 and December 2012, 583 MBoe from our Oklahoma properties acquired in July 2013, 395 MBoe higher California production, including 294 MBoe from our California properties acquired in November 2012, and a 52 MBoe increase in Wyoming production, partially offset by 122 MBoe lower Michigan production and 21 MBoe lower Florida production, primarily due to natural field declines.
Oil, natural gas and NGL sales
Total oil, natural gas liquids (“NGL”) and natural gas sales revenues increased $85.7 million in the three months ended September 30, 2013 compared to the three months ended September 30, 2012. Crude oil and NGL revenues increased $80.6 million due to higher oil prices and higher oil sales volumes, primarily due to production from our 2012 Texas and California acquisitions and our 2013 Oklahoma acquisitions. Natural gas revenues increased $5.2 million, primarily due to higher natural gas prices and slightly higher natural gas production.
Realized prices for crude oil and NGLs, excluding the effect of derivative instruments, increased $6.14 per Boe, or 7%, in the three months ended September 30, 2013 compared to the three months ended September 30, 2012. Realized prices for natural gas, excluding the effect of derivative instruments, increased $0.66 per Mcf, or 22%, in the three months ended September 30, 2013 compared to the three months ended September 30, 2012.
Total oil, NGLs and natural gas sales revenues increased $166.4 million for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012. Crude oil and NGLs revenues increased $142.6 million due to higher sales volumes, primarily due to production from our 2012 Texas and California acquisitions and our 2013 Oklahoma acquisitions. Natural gas revenues increased $23.8 million primarily due to higher natural gas prices and slightly higher natural gas production.
Realized prices for crude oil and NGLs, excluding the effect of derivative instruments, decreased $1.46 per Boe, or 2%, in the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012, primarily due to higher crude oil differentials. Realized prices for natural gas, excluding the effect of derivative instruments, increased $1.08 per Mcf, or 39%, in the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012.
Loss on commodity derivative instruments
Loss on commodity derivative instruments for the three months ended September 30, 2013 was $54.8 million compared to a loss of $69.4 million during the three months ended September 30, 2012. Commodity derivative instrument settlement payments net of receipts were $6.3 million for the three months ended September 30, 2013 compared to net receipts of $22.5 million during the same period in 2012, which primarily reflects higher oil settlement payments due to higher average crude oil prices and lower average crude oil hedge prices, as well as lower natural gas settlement receipts due to higher natural gas prices and lower average natural gas hedge prices compared to the prior year.
Loss on commodity derivatives instruments for the nine months ended September 30, 2013 was $11.9 million compared to a gain of $1.9 million during the nine months ended September 30, 2012. Commodity derivative instrument settlement receipts net of payments for the nine months ended September 30, 2013 and 2012 were $3.6 million and $65.2 million, respectively, which primarily reflects higher oil settlement payments due to lower average crude oil hedge prices, as well as lower natural gas settlement receipts due to higher natural gas prices and lower average natural gas hedge prices compared to the prior year.
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Lease operating expenses
Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the three months ended September 30, 2013 increased $18.4 million compared to the three months ended September 30, 2012. The increase in pre-tax lease operating expenses reflects our 2012 acquisitions in Texas and California, and 2013 acquisitions in Oklahoma. On a per Boe basis, pre-tax lease operating expenses were $18.96 per Boe for the three months ended September 30, 2013 compared to $18.62 per Boe for the three months ended September 30, 2012.
Production and property taxes for the three months ended September 30, 2013 totaled $14.5 million, which was $5.9 million higher than the three months ended September 30, 2012, primarily due to higher production and property taxes from our 2012 acquisitions in Texas and California, and 2013 acquisitions in Oklahoma. On a per Boe basis, production and property taxes for the three months ended September 30, 2013 were $4.67 per Boe, which was 18% higher than the three months ended September 30, 2012, primarily due to higher oil production as a percentage of total production and higher oil and natural gas prices.
Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the nine months ended September 30, 2013 increased $35.3 million compared to the nine months ended September 30, 2012. The increase in pre-tax lease operating expenses primarily reflects our 2012 acquisitions in Texas and California, and 2013 acquisitions in Oklahoma. On a per Boe basis, pre-tax lease operating expenses were $19.35 per Boe for the nine months ended September 30, 2013 compared to $19.25 per Boe for the nine months ended September 30, 2012.
Production and property taxes for the nine months ended September 30, 2013 totaled $34.9 million, which was $12.3 million higher than the nine months ended September 30, 2012, primarily due to higher production and property taxes from our 2012 acquisitions in Texas and California, and 2013 acquisitions in Oklahoma. On a per Boe basis, production and property taxes for the nine months ended September 30, 2013 were $4.42 per Boe, which was 19% higher than the nine months ended September 30, 2012, primarily due to higher oil production as a percentage of total production and higher natural gas prices.
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.
For the three months ended September 30, 2013, the change in inventory account amounted to a credit of $4.9 million compared to a charge of $0.9 million during the same period in 2012. The credit to inventory during the three months ended September 30, 2013 reflects a lower volume of crude oil sold than produced while the charge during the three months ended September 30, 2012 reflects a higher volume of crude oil sold than produced during the periods due to the timing of Florida sales.
For the nine months ended September 30, 2013, the change in inventory account amounted to a credit of $6.8 million compared to a charge of $0.7 million during the same period in 2012. The credit to inventory during the nine months ended September 30, 2013 reflects a lower volume of crude oil sold than produced while the charge during the nine months ended September 30, 2012 reflects a higher volume of crude oil sold than produced during the periods due to the timing of Florida sales.
Depletion, depreciation and amortization
DD&A totaled $60.1 million, or $19.41 per Boe, during the three months ended September 30, 2013, an increase of approximately 13% per Boe from the same period a year ago. The increase in DD&A per Boe compared to last year was primarily due to increased production associated with our Texas and California acquisitions that occurred in the fourth quarter of 2012. In addition, DD&A for the three months ended September 30, 2013 included $1.5 million amortization of CO2 contracts acquired in the Whiting Acquisition and $0.4 million related to impairments. DD&A for the three months ended September 30, 2012 included impairments of $0.5 million.
DD&A totaled $154.1 million, or $19.51 per Boe, during the nine months ended September 30, 2013, an increase of approximately 9% per Boe from the same period a year ago. DD&A for the nine months ended September 30, 2013 included $1.5 million amortization of CO2 contracts acquired in the Whiting Acquisition and $0.4 million related to impairments. The first
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nine months of 2012 included $12.2 million in impairments and write-offs related to uneconomic proved properties primarily in Michigan, Indiana and Kentucky due to lower natural gas prices. Excluding impairments and write-offs, DD&A per Boe was 23% higher in the first nine months of 2013 when compared to the first nine months of 2012 DD&A of $15.87 per Boe. The increase in DD&A per Boe compared to last year was primarily due to higher rates associated with our 2012 and 2013 acquisitions and higher Michigan DD&A rates due to lower reserves.
General and administrative expenses
Our G&A expenses totaled $16.1 million and $13.7 million for the three months ended September 30, 2013 and 2012, respectively. This included $4.9 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 $11.2 million and $8.1 million for the three months ended September 30, 2013 and 2012, respectively. The increase was primarily due to higher payroll expense for additional personnel attributable to acquisitions and higher acquisition evaluation and integration costs. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $3.62 and $3.73 for the three months ended September 30, 2013 and 2012, respectively.
Our G&A expenses totaled $44.7 million and $40.3 million for the nine months ended September 30, 2013 and 2012, respectively. This included $14.7 million and $16.9 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans. G&A expenses, excluding non-cash unit-based compensation, were $30.0 million and $23.4 million for the nine months ended September 30, 2013 and 2012, respectively. The increase was primarily due to higher payroll expense for additional personnel attributable to acquisitions and higher acquisition evaluation and integration costs. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $3.80 and $3.84 during for the nine months ended September 30, 2013 and 2012, respectively.
Interest expense, net of amounts capitalized
Our interest expense totaled $23.5 million and $15.4 million for the three months ended September 30, 2013 and 2012, respectively. The increase in interest expense was primarily due to $3.9 million higher interest related to the 2022 Senior Notes, which were issued in September 2012, and increased borrowing under our credit facility. We had no losses and $0.2 million in losses for the three months ended September 30, 2013 and 2012, respectively, relating to our interest rate derivative contracts. As of September 30, 2013 and December 31, 2012, we had no interest rate derivative contracts in place.
Interest expense, including interest rate derivative instrument settlements paid and excluding debt amortization and mark-to-market on interest rate derivatives, totaled $21.7 million and $15.1 million for the three months ended September 30, 2013 and 2012, respectively.
Our interest expense totaled $60.4 million and $43.2 million for the nine months ended September 30, 2013 and 2012, respectively. The increase in interest expense was primarily due to $12.5 million higher interest related to the 2022 Senior Notes, which were issued in September 2012, and increased borrowing under our credit facility. We had no losses and $0.9 million in losses for the nine months ended September 30, 2013 and 2012, respectively, relating to our interest rate derivative contracts.
Interest expense, including interest rate derivative instrument settlements paid and excluding debt amortization and mark-to-market on interest rate derivatives, totaled $56.0 million and $41.9 million for the nine months ended September 30, 2013 and 2012, respectively.
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 September 30, 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, Royal Bank of Canada and Toronto-Dominion Bank. We periodically obtain credit default swap information on our counterparties. As of September 30, 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 September 30, 2013, our largest derivative asset balances were with Wells Fargo Bank, National Association, Credit Suisse Energy LLC and Citibank, N.A., which accounted for approximately 31%, 24% and 13% of our derivative asset balances, respectively.
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Liquidity and Capital Resources
Our primary sources of liquidity are cash generated from operations and amounts available under our 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 credit facility, accessed the private placement markets and issued equity as partial consideration for the acquisition of oil and natural 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 Common Units at a price to the public of $19.86 per Common Unit, resulting in proceeds of $285.0 million (net of underwriting discount and offering expenses).
Distributions
On February 14, 2013, we paid a cash distribution of approximately $39.8 million, or $0.4700 per Common Unit. On May 14, 2013, we paid a cash distribution of approximately $47.3 million, or $0.4750 per Common Unit. On August 14, 2013, we paid a cash distribution of approximately $47.8 million, or $0.4800 per Common Unit. On October 30, 2013, we announced a cash distribution to common unitholders for the third quarter of 2013 at the rate of $0.4875 per Common Unit, to be paid on November 14, 2013 to our common unitholders of record as of the close of business on November 11, 2013.
On October 30, 2013, we amended our First Amended and Restated Agreement of Limited Partnership by adopting Amendment No. 5. Amendment No. 5 provides that, at the discretion of our General Partner, we may pay quarterly distributions within 45 days following the end of each quarter or in three installments within 17, 45 and 75 days following the end of each quarter. The Partnership intends to change its distribution payment policy from a quarterly payment schedule to a monthly payment schedule beginning with the distributions relating to the fourth quarter of 2013. The payment of monthly distributions is expected to commence in January 2014.
Cash Flows
Operating activities. Our cash flows from operating activities for the nine months ended September 30, 2013 were $166.9 million, compared to $166.3 million for the nine months ended September 30, 2012. The increase in cash flows from operating activities was primarily due to higher operating income compared to the same period a year ago and $13.3 million in prepaid premiums on derivative instruments that were paid during the nine months ended September 30, 2012, offset by an increase in trade receivables during the nine months ended September 30, 2013.
Investing activities. Net cash used in investing activities during the nine months ended September 30, 2013 and 2012 was $1,052.8 million and $390.2 million, respectively. During the nine months ended September 30, 2013, we spent $861.6 million on property acquisitions and $191.5 million on capital expenditures, primarily for drilling and completion activities. During the nine months ended September 30, 2012, we spent $313.4 million on property acquisitions and $77.7 million on capital expenditures, primarily for drilling and completion activities.
Financing activities. Net cash provided by financing activities for the nine months ended September 30, 2013 and 2012 was $884.2 million and $223.0 million, respectively. During the nine months ended September 30, 2013, we increased our outstanding borrowings under our credit facility by approximately $745.0 million. We had total outstanding borrowings, net of unamortized discount on our senior notes, of $1,845.7 million at September 30, 2013 and $1,100.7 million at December 31, 2012. During the nine months ended September 30, 2013, we issued $285.0 million in Common Units, made cash distributions of $137.4 million, borrowed $1,381.0 million and repaid $636.0 million under our credit facility. During the nine months ended September 30, 2012, we issued $370.5 million in Common Units, made cash distributions of $93.7 million, borrowed $1,066.9 million and repaid $1,109.0 million under our credit facility.
Senior Notes
As of September 30, 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.
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Credit Agreement
As of September 30, 2013 and December 31, 2012, we had a $3.0 billion and $1.5 billion, respectively, credit facility with a maturity date of May 9, 2016. As of September 30, 2013 and December 31, 2012, our borrowing base was $1.5 billion and $1.0 billion, respectively, and the aggregate commitment of all lenders was $1.4 billion and $900 million, respectively.
As of September 30, 2013 and November 5, 2013, we had $1.1 billion and $1.1 billion, respectively, in indebtedness outstanding under the Second Amended and Restated Credit Agreement.
As of September 30, 2013, the lending group under the Second Amended and Restated Credit Agreement included 22 banks. Of the $1.4 billion in total commitments under our credit facility, Wells Fargo Bank, National Association held approximately 12.1% of the commitments. Fifteen banks held between 3.5% and 6.8% of the commitments, including Bank of Montreal, The Bank of Nova Scotia, Union Bank, N.A., Barclays Bank PLC, Citibank, N.A., Royal Bank of Canada, Sovereign Bank, N.A., The Royal Bank of Scotland plc, U.S. Bank National Association, Compass Bank, Comerica Bank, Credit Suisse AG, Cayman Islands Branch, J.P. Morgan Chase, N.A., Sumitomo Mitsui Banking Group and Toronto Dominion (Texas), LLC, with each of the remaining lenders holding 2.5% of the commitments. In addition to our relationships with these institutions under our 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.
In July 2013, we entered into the Ninth Amendment to the Second Amended and Restated Credit Agreement, which increased our aggregate maximum credit amount from $1.5 billion to $3.0 billion, increased our borrowing base to $1.5 billion and increased the aggregate commitment of all lenders to $1.4 billion. The amendment also increased flexibility for the Total Leverage Ratio (defined as the ratio of total debt to EBITDAX) for the next five quarters and added a new Senior Secured Leverage Ratio (defined as the ratio of senior secured indebtedness to EBITDAX) that will be applied until the earlier of the end of the second quarter of 2014 and our receipt of net cash proceeds from the issuance of Common Units of at least $350 million. The Ninth Amendment provides that we are required to maintain a Total Leverage Ratio as of the last day of each quarter, on a last 12-month basis, of no more than 4.75 to 1.00 through the first quarter of 2014, no more than 4.50 to 1.00 through the second quarter of 2014, no more than 4.25 to 1.00 through the third quarter of 2014 and thereafter no more than 4.00 to 1.00. We also are required to maintain a Senior Secured Leverage Ratio as of the last day of each quarter, on a last 12-month basis, of no more than 3.00 to 1.00 through the fourth quarter of 2013 and no more than 2.75 to 1.00 through the second quarter of 2014. The numerator of each of these ratios automatically decreases by .25 or .50 if we receive net cash proceeds from the issuance of Common Units of, at least, $175 million or, with respect to the Total Leverage Ratio, $350 million, respectively, but in no event will the Total Leverage Ratio be reduced to less than 4.00 to 1.00.
Our borrowing base will be redetermined in November 2013, and the following borrowing base redetermination is scheduled for April 2014.
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 total 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 4.75 to 1.00 as of September 30, 2013 and a current ratio, as of the last day of each quarter, of not less than 1.00 to 1.00. As of September 30, 2013 and November 5, 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 loss or gain on monetization of derivative instruments for the following 12 months), cumulative effect of changes in accounting principles, pro forma results from acquisitions and cash distributions received from our unrestricted entities (as defined in the Second Amended and Restated Credit Agreement) and excluding income from our unrestricted entities.
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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
On July 15, 2013, we completed the acquisition of the Whiting Assets. As part of this acquisition, we assumed the obligation to purchase a minimum daily volume of CO2 over the next 20 years. Under the take-or-pay provisions of these purchase agreements, we are committed to buying certain volumes of CO2 for use in our enhanced recovery project being carried out at the Postle field. See Note 12 to the consolidated financial statements within this report for a discussion of our future minimum commitments under these purchase agreements.
Except for the issuance of Common Units, the amendments to our credit facility, and purchase agreement from the Whiting Acquisition, we had no material changes to our financial contractual obligations during the nine months ended September 30, 2013.
Off-Balance Sheet Arrangements
We did not have any off-balance sheet arrangements as of September 30, 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.
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 2012 Annual Report. Also, see Note 4 to the consolidated financial statements within this report for additional discussion related to our financial instruments, including a summary of our derivative instruments as of September 30, 2013.
Changes in Fair Value
The fair value of our outstanding oil and natural gas commodity derivative instruments was a net asset of approximately $73.5 million and $79.2 million at September 30, 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 September 30, 2013 would have decreased by approximately $256 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 September 30, 2013 would have increased by approximately $259 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.
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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 September 30, 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 September 30, 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 2012 Annual Report and in Part II—Item 1A “—Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2013.
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.
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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). | |
3.8 | Amendment No. 5 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 November 5, 2013). | |
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 (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q (File No. 001-33055) filed on May 3, 2013). | |
10.2 | Form of Convertible Phantom Unit Agreement - Non-Employment Agreement (incorporated herein by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q (File No. 001-33055) filed on May 3, 2013). | |
10.3 | Form of Convertible Phantom Unit Agreement - Employment Agreement (incorporated herein by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q (File No. 001-33055) filed on May 3, 2013). | |
10.4 | Purchase and Sale Agreement, dated June 22, 2013, between Whiting Oil and Gas Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 25, 2013). | |
10.5 | Eighth Amendment to the Second Amended and Restated Credit Agreement of BreitBurn Energy Partners L.P. dated May 22, 2013 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on July 18, 2013). | |
10.6 | Ninth Amendment to the Second Amended and Restated Credit Agreement of BreitBurn Energy Partners L.P. dated July 15, 2013 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on July 18, 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. |
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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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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: | November 6, 2013 | By: | /s/ Halbert S. Washburn |
Halbert S. Washburn | |||
Chief Executive Officer | |||
Dated: | November 6, 2013 | By: | /s/ James G. Jackson |
James G. Jackson | |||
Chief Financial Officer |
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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). | |
3.8 | Amendment No. 5 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 November 5, 2013). | |
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 (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q (File No. 001-33055) filed on May 3, 2013). | |
10.2 | Form of Convertible Phantom Unit Agreement - Non-Employment Agreement (incorporated herein by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q (File No. 001-33055) filed on May 3, 2013). | |
10.3 | Form of Convertible Phantom Unit Agreement - Employment Agreement (incorporated herein by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q (File No. 001-33055) filed on May 3, 2013). | |
10.4 | Purchase and Sale Agreement, dated June 22, 2013, between Whiting Oil and Gas Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 25, 2013). | |
10.5 | Eighth Amendment to the Second Amended and Restated Credit Agreement of BreitBurn Energy Partners L.P. dated May 22, 2013 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on July 18, 2013). | |
10.6 | Ninth Amendment to the Second Amended and Restated Credit Agreement of BreitBurn Energy Partners L.P. dated July 15, 2013 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on July 18, 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. |
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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. |
38