UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
x | Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 2011
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 No.) |
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
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | |
Common Units Representing Limited Partner Interests | The NASDAQ Stock Market LLC |
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Indicate by check mark whether 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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 Act). Yes o No x
The aggregate market value of the Common Units held by non-affiliates was approximately $967.9 million on June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, based on $19.46 per unit, the last reported sales price on such date.
As of February 28, 2012, there were 69,144,046 Common Units outstanding.
Documents Incorporated By Reference: Certain information called for in Items 10, 11, 12, 13 and 14 of Part III are incorporated by reference from the registrant’s definitive proxy statement for the 2012 annual meeting of unitholders to be held on June 21, 2012.
BREITBURN ENERGY PARTNERS L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
Page | ||
No. | ||
PART I | ||
PART II | ||
PART III | ||
PART IV | ||
GLOSSARY OF OIL AND GAS TERMS, DESCRIPTION OF REFERENCES
The following is a description of the meanings of some of the oil and gas industry terms that may be used in this report. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(6), (22) and (31) of Regulation S-X.
API gravity scale: A gravity scale devised by the American Petroleum Institute.
Bbl: One stock tank barrel, or 42 U.S. gallons of liquid volume, of crude oil or other liquid hydrocarbons.
Bbl/d: Bbl per day.
Bcf: One billion cubic feet of natural gas.
Bcfe: One billion cubic feet equivalent, determined using the ratio of one Bbl of crude oil to six Mcf of natural gas.
Boe: One barrel of oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of oil equivalent for natural gas is significantly less than the price for a barrel of oil.
Boe/d: Boe per day.
Btu: British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
development well: A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
dry hole or well: A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
economically producible: A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
exploitation: A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
exploratory well: A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is not a development well.
field: An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
gross acres or gross wells: The total acres or wells, as the case may be, in which a working interest is owned.
LIBOR: London Interbank Offered Rate.
MBbls: One thousand barrels of crude oil or other liquid hydrocarbons.
MBoe: One thousand barrels of oil equivalent.
MBoe/d: One thousand barrels of oil equivalent per day.
Mcf: One thousand cubic feet of natural gas.
Mcf/d: One thousand cubic feet of natural gas per day.
Mcfe: One thousand cubic feet of natural gas equivalent, determined using the ratio of one Bbl of crude oil to six Mcf of
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natural gas.
MichCon: Michigan Consolidated Gas Company.
MMBbls: One million barrels of crude oil or other liquid hydrocarbons.
MMBoe: One million barrels of oil equivalent.
MMBtu: One million British thermal units.
MMBtu/d: One million British thermal units per day.
MMcf: One million cubic feet of natural gas.
MMcfe: One million cubic feet of natural gas equivalent, determined using the ratio of one Bbl of crude oil to six Mcf of natural gas.
MMcfe/d: One million cubic feet of natural gas equivalent per day, determined using the ratio of one Bbl of crude oil to six Mcf of natural gas.
net acres or net wells: The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
NYMEX: New York Mercantile Exchange.
oil: Crude oil, condensate and natural gas liquids.
productive well: A well that is producing or that is mechanically capable of production.
proved developed reserves: Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. This definition of proved developed reserves has been abbreviated from the applicable definition contained in Rule 4-10(a)(6) of Regulation S-X.
proved reserves: The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically producible in future years from known reservoirs under existing economic and operating conditions and government regulations. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. This definition of proved reserves has been abbreviated from the applicable definition contained in Rule 4-10(a)(22) of Regulation S-X.
proved undeveloped reserves or PUDs: Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(31) of Regulation S-X.
recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
reserve: Estimated remaining quantities of mineral deposits anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.
reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
standardized measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the
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timing of future net revenue. Standardized measure does not give effect to derivative transactions.
undeveloped acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
West Texas Intermediate ("WTI"): Light, sweet crude oil with high API gravity and low sulfur content used as the benchmark for U.S. crude oil refining and trading. WTI is deliverable at Cushing, Oklahoma to fill NYMEX futures contracts for light, sweet crude oil.
working interest: The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.
workover: Operations on a producing well to restore or increase production.
_____________________________________
References in this report to "the Partnership," "we," "our," "us" or like terms refer to BreitBurn Energy Partners L.P. and its subsidiaries. References in this filing to "PCEC" or the "Predecessor" refer to Pacific Coast Energy Company LP, formerly named BreitBurn Energy Company L.P., our predecessor, and its predecessors and subsidiaries. References in this filing to "BreitBurn GP" or the "General Partner" refer to BreitBurn GP, LLC, our general partner and our wholly owned subsidiary. References in this filing to "BreitBurn Corporation" refer to BreitBurn Energy Corporation, a corporation owned by Randall Breitenbach and Halbert Washburn, the President and Chief Executive Officer, respectively, of our general partner. References in this filing to "BreitBurn Management" refer to BreitBurn Management Company, LLC, our administrative manager and wholly owned subsidiary. References in this filing to "BOLP" or "BreitBurn Operating" refer to BreitBurn Operating L.P., our wholly owned operating subsidiary. References in this filing to "BOGP" refer to BreitBurn Operating GP, LLC, the general partner of BOLP. References in this filing to "Quicksilver" refer to Quicksilver Resources Inc. from whom we acquired oil and gas properties and facilities in Michigan, Indiana and Kentucky on November 1, 2007. References in this filing to "BEPI" refer to BreitBurn Energy Partners I, L.P. References in this filing to "Utica" refer to BreitBurn Collingwood Utica LLC, our wholly owned subsidiary formed September 17, 2010. References in this filing to "Cabot" refer to Cabot Oil & Gas Corporation from whom we acquired oil and gas properties primarily located in Wyoming on October 6, 2011.
_____________________________________
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PART I
Item 1. Business.
Cautionary Statement Regarding Forward-Looking Information
Certain statements and information in this Annual Report on Form 10-K ("this report") may constitute "forward-looking statements." The words "believe," "expect," "anticipate," "plan," "intend," "foresee," "should," "would," "could" or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those described in (1) Part I—Item 1A "—Risk Factors" and elsewhere in this report, and (2) our Quarterly Reports on Form 10-Q and Current Reports on Form 8-K filed with the Securities and Exchange Commission ("SEC").
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.
Overview
We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States. Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders. Our assets consist primarily of producing and non-producing crude oil and natural gas reserves located primarily in:
• | the Antrim Shale and other non-Antrim formations in Michigan; |
• | the Evanston and Green River Basins in southwestern Wyoming; |
• | the Wind River and Big Horn Basins in central Wyoming; |
• | the Powder River Basin in eastern Wyoming; |
• | the Los Angeles Basin in California; |
• | the Sunniland Trend in Florida; and |
• | the New Albany Shale in Indiana and Kentucky. |
Our assets are characterized by stable, long-lived production and proved reserve life indexes averaging greater than 18 years. Our fields generally have long production histories, with some fields producing for over 100 years. We have high net revenue interests in our properties.
We are a Delaware limited partnership formed on March 23, 2006. We completed our initial public offering in October 2006. Our general partner is BreitBurn GP, a Delaware limited liability company, also formed on March 23, 2006, and our wholly owned subsidiary since June 17, 2008. The board of directors of our General Partner (the "Board") has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly owned subsidiary, BOLP, and BOLP’s general partner, BOGP. We own all of the ownership interests in BOLP and BOGP.
In 2008, we acquired BreitBurn Management and its interest in the General Partner, resulting in BreitBurn Management and the General Partner becoming our wholly owned subsidiaries. BreitBurn Management manages our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. See Note 6 to the consolidated financial statements in this report for more information regarding our relationship with BreitBurn Management.
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Available Information
Our internet website address is www.breitburn.com. We make available, free of charge at the "Investor Relations" portion of our website, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC. The information contained on our website does not constitute part of this report.
The SEC maintains an internet website that contains these reports at www.sec.gov. Any materials that the Company files with the SEC may be read or copied at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room may be obtained by calling the SEC at (800) 732-0330.
Structure
The following diagram depicts our organizational structure as of December 31, 2011:
As of December 31, 2011, we had 59.9 million Common Units outstanding.
In January 2012, we issued less than 0.1 million Common Units to outside directors for phantom units and distribution equivalent rights that were granted in 2009 and 2011 and vested in January 2012.
In February 2012, we sold approximately 9.2 million Common Units at a price to the public of $18.80, resulting in proceeds net of underwriting discounts and estimated offering expenses of $165.9 million, which we used to repay outstanding debt under our credit facility.
These issuances increased our outstanding Common Units to 69.1 million as of February 28, 2012.
Long-Term Business Strategy
Our long-term goals are to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders. In order to meet these objectives, we plan to continue to follow our core investment strategy, which 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 and interest rate derivatives; and |
• | Maximize asset value and cash flow stability through our operating and technical expertise. |
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2012 Outlook
We expect our full year 2012 crude oil and natural gas capital spending program to be approximately $68 million, excluding acquisitions, compared with approximately $75 million in 2011, and anticipate spending approximately 60% principally on oil projects in California and Florida and approximately 40% principally on oil projects in Michigan, Wyoming, Indiana and Kentucky. We anticipate 77% of our total capital spending will be focused on drilling and rate generating projects that are designed to increase or add to production or reserves. We expect to fund these capital expenditures primarily with cash flow from operations. Based on the continuing decline of natural gas prices, we will continue to evaluate our capital spending program throughout 2012. Without considering potential acquisitions, we expect our 2012 production to be approximately 8.1 MMBoe.
Commodity hedging remains an important part of our strategy to reduce cash flow volatility. We use swaps, collars and options for managing risk relating to commodity prices.
As of February 28, 2012, we had approximately 75% of our expected 2012 production hedged. For 2012, we had 7,516 Bbl/d of oil and 54,257 MMBtu/d of natural gas hedged at average prices of approximately $101.00 and $7.12, respectively. For 2013, we had 6,980 Bbl/d of oil and 56,000 MMBtu/d of natural gas hedged at average prices of approximately $92.05 and $5.96 respectively. For 2014, we had 6,000 Bbl/d of oil and 30,500 MMBtu/d of natural gas hedged at average prices of approximately $93.58 and $5.43, respectively. For 2015, we had 5,000 Bbl/d of oil and 30,500 MMBtu/d of natural gas hedged at average prices of approximately $96.41 and $5.55, respectively.
Consistent with our long-term business strategy, we intend to continue to actively pursue oil and natural gas acquisition opportunities in 2012.
Properties
Our properties include natural gas, oil and midstream assets in Michigan, Indiana and Kentucky, including fields in the Antrim Shale in Michigan and the New Albany Shale in Indiana and Kentucky, transmission and gathering pipelines, three gas processing plants and four NGL recovery plants. Our properties also include fields in the Evanston and Green River Basins in southwestern Wyoming, the Wind River and Big Horn Basins in central Wyoming, the Powder River Basin in eastern Wyoming, the Los Angeles Basin in California, including a limited partnership interest in a partnership that owns the East Coyote and Sawtelle fields in the Los Angeles Basin, and fields in Florida’s Sunniland Trend.
In connection with our initial public offering, our Predecessor contributed to our wholly owned subsidiaries certain fields in the Los Angeles Basin in California, including its interests in the Santa Fe Springs, Rosecrans and Brea Olinda fields, substantially all of its oil and gas assets, liabilities and operations located in the Wind River and Big Horn Basins in central Wyoming and certain other assets and liabilities. In 2007, we completed seven acquisitions totaling approximately $1.7 billion, the largest of which was our acquisition of assets in Michigan, Indiana and Kentucky for approximately $1.46 billion.
In 2011, we completed the acquisition of crude oil properties in the Powder River Basin in eastern Wyoming (the "Greasewood Acquisition") for approximately $57 million in cash. We also completed the acquisition of oil and gas properties located primarily in the Evanston and Green River Basins in southwestern Wyoming (the "Cabot Acquisition") for approximately $281 million in cash, subject to ordinary adjustments. The assets acquired in the Cabot Acquisition (the "Cabot Assets") also include limited acreage and non-operated oil and gas interests in Colorado and Utah. The Cabot Assets are approximately 95% natural gas.
BreitBurn Management manages all of our properties and employs production and reservoir engineers, geologists and other specialists, as well as field personnel. On a net production basis, we operate approximately 87% of our production. As operator, we design and manage the development of wells and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate. We engage independent contractors to provide all the equipment and personnel associated with these activities.
Reserves and Production
As of December 31, 2011, our total estimated proved reserves were 151.1 MMBoe, of which approximately 65% was natural gas and 35% was crude oil. As of December 31, 2010, our total estimated proved reserves were 118.9 MMBoe, of which approximately 65% was natural gas and 35% was crude oil. Our total estimated reserve additions in 2011 of 39.2 MMBoe were partially offset by the 7.0 MMBoe of production resulting in a net gain of 32.2 MMBoe over 2010. The increase in 2011 was primarily the result of 32.2 MMBoe of reserve acquisitions. Additionally, drilling, recompletions, workovers,
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addition of new drilling locations, economic factors and revised estimates of existing reserves contributed to the increase. The primary economic factor for the increase in estimated proved reserves relating to oil producing properties was an increase in oil prices. The unweighted average first-day-of-the-month crude oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2011 were $95.97 per Bbl of oil for Michigan, California and Florida, $76.79 per Bbl of oil for Wyoming and $4.12 per MMBtu of gas, compared to $79.40 per Bbl of oil for Michigan, California and Florida, $65.36 per Bbl of oil for Wyoming and $4.38 per MMBtu of gas in 2010.
The following table summarizes our estimated proved developed and undeveloped oil and gas reserves based on average 2011 prices:
Summary of Oil and Gas Reserves as of December 31, 2011 | |||||||||
Total (MMBoe)(a) | Oil (MMBbl) | Gas (Bcf) | |||||||
Proved | |||||||||
Developed | 131.5 | 47.8 | 501.9 | ||||||
Undeveloped | 19.6 | 4.9 | 88.6 | ||||||
Total proved | 151.1 | 52.7 | 590.5 | ||||||
(a) Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a Bbl of oil equivalent for natural gas is significantly less than the price for a Bbl of oil. |
During 2011, we incurred $15.4 million in capital expenditures and drilled 28 wells related to the conversion of estimated proved undeveloped to estimated proved developed reserves. During 2011, we converted 614 MBbl of oil and 2.5 Bcf of natural gas from estimated proved undeveloped to estimated proved developed reserves. As of December 31, 2011, we had no material estimated proved undeveloped reserves that have remained undeveloped for more than five years and we expect to develop all material estimated proved undeveloped reserves within the next five years.
As of December 31, 2011, proved undeveloped reserves were 19.6 MMBoe compared to 10.6 MMBoe as of December 31, 2010. The Cabot and Greasewood acquisitions added 10.3 MMBoe and 1.9 MMBoe of proved undeveloped reserves, respectively.
As of December 31, 2011, the total standardized measure of discounted future net cash flows was $1.66 billion. During 2011, we filed estimates of oil and gas reserves as of December 31, 2010 with the U.S. Department of Energy, which were consistent with the reserve data as of December 31, 2010 as reported in Note A in the supplemental information to the consolidated financial statements in this report.
The following table summarizes estimated proved reserves and production for our properties by state:
As of December 31, 2011 | 2011 | ||||||||||||||
Estimated Proved Reserves (MMBoe) | Percent of Total Estimated Proved Reserves | Estimated Proved Developed Reserves (MMBoe) | Production (MBoe) (a) | Average Daily Production (Boe/d) (a) | |||||||||||
Michigan | 74.8 | 49.5 | % | 68.6 | 3,772 | 10,336 | |||||||||
Wyoming | 44.4 | 29.4 | % | 31.5 | 1,222 | 6,951 | |||||||||
California | 20.6 | 13.7 | % | 20.1 | 1,168 | 3,200 | |||||||||
Florida | 9.9 | 6.5 | % | 9.9 | 663 | 1,815 | |||||||||
Indiana/Kentucky | 1.4 | 0.9 | % | 1.4 | 212 | 582 | |||||||||
Total | 151.1 | 100.0 | % | 131.5 | 7,037 | 22,884 | |||||||||
(a) For properties acquired during 2011, includes production and average daily production from acquisition date to December 31, 2011. |
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See "Results of Operations" in Part II—Item 7 "—Management’s Discussion and Analysis of Financial Condition and Results of Operations" in this report for oil, NGL and natural gas production, average sales price per Boe and per Mcf and average production cost per Boe for 2011, 2010 and 2009.
The Antrim Shale, which accounted for 42% of our total estimated proved reserves at December 31, 2011, accounted for 38%, 40% and 44% of our total production and 70%, 76% and 81% of our natural gas production for 2011, 2010 and 2009, respectively. Realized prices per Mcfe for our Antrim Shale production were $4.21, $4.58 and $4.23 for 2011, 2010 and 2009, respectively. Lease operating expenses per Mcfe for our Antrim Shale production were $1.60, $1.46 and $1.55 for 2011, 2010 and 2009, respectively.
Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices or development and production expenses, may require revision of such estimates. Accordingly, oil and gas quantities ultimately recovered will vary from reserve estimates. See Part I—Item 1A "—Risk Factors" in this report for a description of some of the risks and uncertainties associated with our business and reserves.
The information in this report relating to our estimated oil and gas proved reserves is based upon reserve reports prepared as of December 31, 2011. Estimates of our proved reserves were prepared by Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services, independent petroleum engineering firms. Netherland, Sewell & Associates, Inc. prepares reserve data for our California, Wyoming and Florida properties, and Schlumberger Data & Consulting Services prepares reserve data for our Michigan, Kentucky and Indiana properties. The reserve estimates are reviewed and approved by members of our senior engineering staff and management. The process performed by Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services to prepare reserve amounts included their estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue. Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services also prepared estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a)(22) and subsequent SEC staff interpretations and guidance. In the conduct of their preparation of the reserve estimates, Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their work, something came to their attention which brought into question the validity or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their questions relating thereto.
The technical person primarily responsible for overseeing preparation of the reserves estimates and the third party reserve reports is Mark L. Pease, the Executive Vice President and Chief Operating Officer of our General Partner. Mr. Pease received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines in 1979. Prior to joining our General Partner, Mr. Pease was Senior Vice President, E&P Technology & Services for Anadarko Petroleum Corporation. Mr. Pease has over 30 years of experience working in various capacities in the energy industry, including acquisition analysis, reserve estimation, reservoir engineering and operations engineering. Mr. Pease consults with Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services during the reserve estimation process to review properties, assumptions and relevant data.
See exhibits 99.1 and 99.2 to this report for the estimates of proved reserves provided by Netherland, Sewell & Associates, Inc. and exhibit 99.3 to this report for the estimates of proved reserves provided by Schlumberger Data & Consulting Services. We only employ large, widely known, highly regarded, and reputable engineering consulting firms. Not only the firms, but the technical persons that sign and seal the reports are licensed and certify that they meet all professional requirements. Licensing requirements formally require mandatory continuing education and professional qualifications.
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Michigan
As of December 31, 2011, our Michigan operations comprised approximately 49% of our total estimated proved reserves. As of December 31, 2011, approximately 93% of our Michigan total estimated proved reserves were natural gas. For the year ended December 31, 2011, our average production was 10.3 MBoe/d or 62.0 MMcfe/d. Estimated proved reserves attributable to our Michigan properties as of December 31, 2011 were 74.8 MMBoe. Our integrated midstream assets enhance the value of our Michigan properties as gas is sold at MichCon City-Gate prices, and we have no significant reliance on third party transportation. We have interests in 3,284 productive wells in Michigan.
In 2011, we drilled 20 wells and completed 40 well optimization projects (recompletions and workovers). Our capital spending in Michigan for the year ended December 31, 2011 was approximately $22 million.
The Antrim Shale underlies a large percentage of our Michigan acreage; wells tend to produce relatively predictable amounts of natural gas in this reservoir. On average, Antrim Shale wells have a proved reserve life of more than 20 years. Since reserve quantities and production levels over a large number of wells are fairly predictable, maximizing per well recoveries and minimizing per unit production costs through a sizable well-engineered drilling program are the keys to profitable Antrim Shale development. Growth opportunities include infill drilling and recompletions, horizontal drilling and bolt-on acquisitions.
Our non-Antrim interests are located in several reservoirs including the Prairie du Chien, Richfield, Detroit River Zone III and Niagaran pinnacle reefs.
Wyoming
On July 28, 2011, we completed the Greasewood Acquisition to acquire crude oil properties in the Powder River Basin in eastern Wyoming with an effective date of July 1, 2011 (the "Greasewood Field"). The Greasewood Field is 100% oil and produced approximately 605 Bbl/d in the fourth quarter of 2011. Our estimated proved reserves in the Greasewood Field as of December 31, 2011 were 2.9 MMBoe, of which 35% was proved developed.
On October 6, 2011, we completed the Cabot Acquisition to acquire oil and gas properties located primarily in the
Evanston and Green River Basins in southwestern Wyoming for approximately $281 million in cash. The Cabot Assets also include limited acreage and non-operated oil and gas interests in Colorado and Utah. These properties are 95% natural gas. The Cabot Assets produced approximately 25.7 MMcfe/d net in the fourth quarter of 2011. Estimated proved reserves for the Cabot Assets as of December 31, 2011 were 28.7 MMBoe, of which 64% was proved developed.
Our other Wyoming properties consist primarily of fields in the Wind River and Big Horn Basins in central Wyoming including Gebo, North Sunshine, Black Mountain, Hidden Dome, Sheldon Dome, Rolff Lake in Fremont County, Lost Dome in Natrona County (outside the Wind River and Big Horn Basin), West Oregon Basin and Half Moon.
For the year ended December 31, 2011, our average production from our Wyoming fields was approximately 7.0 MBoe/d, including average daily production from acquisition date to December 31, 2011 for properties acquired during 2011. Our Wyoming estimated proved reserves as of December 31, 2011 totaled 44.4 MMBoe. As of December 31, 2011, approximately 62% of our Wyoming total estimated proved reserves were natural gas. In 2011, we drilled nine new productive development wells and three recompletions of existing productive wells in Wyoming. Additionally, one workover was performed in Wyoming during 2011. Our capital spending in Wyoming for the year ended December 31, 2011 was approximately $10 million.
In total, we have interests in 920 productive wells and 49 fields in Wyoming.
California
Our operations in California are concentrated in several large, complex oil fields within the Los Angeles Basin. For the year ended December 31, 2011, our average California production was approximately 3.2 MBoe/d. Our California estimated proved reserves as of December 31, 2011 totaled 20.6 MMBoe. As of December 31, 2011, approximately 98% of our California total estimated proved reserves were crude oil. Our California fields include the Santa Fe Springs, East Coyote, Sawtelle, Rosecrans and Brea Olinda fields, the Alamitos lease of the Seal Beach Field and the Recreation Park lease of the Long Beach Field. In 2011, we drilled three productive wells and completed seven well optimization projects (recompletions and workovers) in California. Our capital spending in California for the year ended December 31, 2011 was approximately $9 million.
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Florida
We operate five Florida fields with 15 actively producing wells as of December 31, 2011. Production is from the Cretaceous Sunniland Trend of the South Florida Basin. Each of our Florida fields is 100% oil. As of December 31, 2011, we had estimated proved reserves of approximately 9.9 MMBbls. In 2011, our average production from our Florida fields was approximately 1.8 MBbl/d. Production from the Raccoon Point field currently accounts for more than half of our Florida production. In 2011, we drilled three productive wells in Florida. Our capital spending in Florida for the year ended December 31, 2011 was approximately $34 million.
Indiana/Kentucky
Our operations in the New Albany Shale of southern Indiana and northern Kentucky include 21 miles of high pressure gas pipeline that interconnects with the Texas Gas Transmission interstate pipeline. The New Albany Shale has over 100 years of production history.
We operate 254 producing wells in Indiana and Kentucky and hold a 100% working interest. In 2011, our production for our Indiana and Kentucky operations was 0.6 MBoe/d or 3.5 MMcf/d. Our estimated proved reserves in Indiana and Kentucky as of December 31, 2011 were 1.4 MMBoe or 8.2 Bcf. Our capital spending in Indiana and Kentucky for the year ended December 31, 2011 was less than $1 million.
Productive Wells
The following table sets forth information for our properties as of December 31, 2011 relating to the productive wells in which we owned a working interest. Productive wells consist of producing wells and wells capable of production. Gross wells are the total number of productive wells in which we have an interest, and net wells are the sum of our fractional working interests owned in the gross wells. None of our productive wells have multiple completions.
Oil Wells | Gas Wells | |||||||||||
Gross | Net | Gross | Net | |||||||||
Operated | 694 | 663 | 2,275 | 1,687 | ||||||||
Non-operated | 92 | 64 | 1,710 | 620 | ||||||||
786 | 727 | 3,985 | 2,307 |
Developed and Undeveloped Acreage
The following table sets forth information for our properties as of December 31, 2011 relating to our leasehold acreage. Developed acres are acres spaced or assigned to productive wells. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas or oil, regardless of whether such acreage contains proved reserves. Gross acres are the total number of acres in which a working interest is owned. Net acres are the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
Developed Acreage | Undeveloped Acreage | Total Acreage | ||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||
Michigan | 462,171 | 218,153 | 44,306 | 40,186 | 506,477 | 258,339 | ||||||||||||
Wyoming | 161,109 | 87,212 | 61,225 | 32,474 | 222,334 | 119,686 | ||||||||||||
Indiana | 46,856 | 46,117 | 48,165 | 47,464 | 95,021 | 93,581 | ||||||||||||
Florida | 34,402 | 33,322 | 2,707 | 1,245 | 37,109 | 34,567 | ||||||||||||
Colorado | 14,292 | 13,198 | — | — | 14,292 | 13,198 | ||||||||||||
Kentucky | 3,148 | 3,148 | 7,719 | 6,944 | 10,867 | 10,092 | ||||||||||||
California | 2,713 | 2,515 | — | — | 2,713 | 2,515 | ||||||||||||
Utah | 1,740 | 529 | — | — | 1,740 | 529 | ||||||||||||
726,431 | 404,194 | 164,122 | 128,313 | 890,553 | 532,507 |
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The following table lists the net undeveloped acres as of December 31, 2011, the net acres expiring in the years ending December 31, 2012, 2013 and 2014, and, where applicable, the net acres expiring that are subject to extension options.
2012 Expirations | 2013 Expirations | 2014 Expirations | |||||||||||||||||||
Net Undeveloped Acreage | Net Acreage | Net Acreage with Ext. Opt. | Net Acreage | Net Acreage with Ext. Opt. | Net Acreage | Net Acreage with Ext. Opt. | |||||||||||||||
Michigan | 40,186 | 1,270 | — | 9,411 | 608 | 611 | — | ||||||||||||||
Wyoming | 32,474 | 8,249 | — | 8,741 | — | 1,607 | — | ||||||||||||||
Indiana | 47,464 | 3,053 | — | 41,753 | — | 1,963 | — | ||||||||||||||
Florida | 1,245 | — | — | — | — | — | — | ||||||||||||||
Kentucky | 6,944 | 3,190 | — | 3,357 | — | 175 | — | ||||||||||||||
128,313 | 15,762 | — | 63,262 | 608 | 4,356 | — |
We hold more than 130,000 net acres in the developing Collingwood-Utica shale play in Michigan. Approximately 85% of this acreage is held by production.
Drilling Activity
Drilling activity and production optimization projects are on lower risk, development properties. The following table sets forth information for our properties with respect to wells completed during the years ended December 31, 2011, 2010 and 2009. Productive wells are those that produce commercial quantities of oil and gas, regardless of whether they produce a reasonable rate of return. No exploratory wells were drilled during the periods presented.
Year Ended December 31, | |||||||||
2011 | 2010 | 2009 | |||||||
Gross development wells: | |||||||||
Productive | 79 | 50 | 23 | ||||||
Dry | 2 | 2 | 3 | ||||||
81 | 52 | 26 | |||||||
Net development wells: | |||||||||
Productive | 69 | 48 | 21 | ||||||
Dry | 2 | 2 | 3 | ||||||
71 | 50 | 24 |
Included in the table above for 2011 are 38 recompletions in Michigan, four recompletions in California and three recompletions in Wyoming. We drilled one dry development well in Florida and one dry development well in Wyoming during 2011. We had two gross and net wells in progress as of December 31, 2011, one in Florida and one in Wyoming.
Delivery Commitments
As of December 31, 2011, we had a delivery commitment with a purchaser of our southwestern Wyoming natural gas for 22,500 MMBtu/d through March 31, 2013. Approximately 100% of our current natural gas production in southwestern Wyoming is available to be used as source gas for this delivery commitment. Based on our estimated proved reserves as of December 31, 2011, approximately 23.6 MMcf/d and 28.2 MMcf/d will be available as source gas from these fields in 2012 and 2013, respectively.
Sales Contracts
We have a portfolio of crude oil and natural gas sales contracts with large, established refiners and utilities. Our sales contracts are sold at market-sensitive or spot prices. Because commodity products are sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. During 2011, our largest purchasers were ConocoPhillips in California and Michigan, which accounted for approximately 30% of net sales revenues, Plains Marketing & Transportation LLC in Florida, which accounted for approximately 16% of net sales revenues, Marathon Oil Company in
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Wyoming, which accounted for approximately 15% of net sales revenues and Sunoco Partners Marketing and Terminals L.P. in Michigan, which accounted for approximately 9% of net sales revenues.
Crude Oil and Natural Gas Prices
We analyze the prices we realize from sales of our oil and gas production and the impact on those prices of differences in market-based index prices and the effects of our derivative activities. We market our oil and natural gas production to a variety of purchasers based on regional pricing. The WTI price of crude oil is a widely used benchmark in the pricing of domestic and imported oil in the United States. The relative value of crude oil is mainly determined by its quality and location. In the case of WTI pricing, the crude oil is light and sweet, meaning that it has a higher specific gravity (lightness) measured in degrees API (a gravity scale devised by the American Petroleum Institute) and low sulfur content, and is priced for delivery at Cushing, Oklahoma. In general, higher quality crude oils (lighter and sweeter) with fewer transportation requirements result in higher realized pricing for producers.
Our California crude oil is generally medium gravity crude. Because of its proximity to the extensive Los Angeles refining market, it has traded at only a minor discount to NYMEX WTI in the past. Historically, WTI oil prices and IPE Brent oil prices have fluctuated together, but recently WTI and IPE Brent oil prices have diverged. Management believes that IPE Brent pricing will better correlate with local California prices we receive in the future. In 2011, IPE Brent prices were higher than WTI, and our California production traded at a premium to WTI. Our Wyoming crude oil, while generally of similar quality to our Los Angeles Basin crude oil, trades at a significant discount to NYMEX WTI because of its distance from a major refining market and the fact that our central Wyoming production is priced relative to the Bow River benchmark for Canadian heavy sour crude oil and our eastern Wyoming production is priced relative to Flint Hills Resources Wyoming Sweet posting, both of which have historically traded at a significant discount to NYMEX WTI. Our Florida crude oil also traded at a significant discount to NYMEX primarily because of its low gravity and other characteristics as well as its distance from a major refining market.
In 2011, the NYMEX WTI spot price averaged approximately $95 per barrel, compared with about $79 a year earlier. Monthly average NYMEX WTI spot prices during 2011 ranged from a low of $86 per barrel for September to a high of $110 per barrel for April. During 2011, the average differentials per barrel to NYMEX WTI spot prices were a $13.88 premium for our California-based production, a $15.42 discount for our Wyoming-based production and a $14.46 discount for our Florida-based production, including approximately $7.50 in transportation costs.
Our Michigan properties have favorable natural gas supply/demand characteristics as the state has been importing an increasing percentage of its natural gas. This supply/demand situation has allowed us to sell our natural gas production at a slight premium to Henry Hub spot prices. Our Wyoming natural gas generally trades at a discount to Henry Hub due to its relative location and the regional supply/demand market balances. Prices for natural gas have historically fluctuated widely and in many regional markets are aligned with supply and demand conditions in regional markets and with the overall U.S. market. Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the inventory in underground storage relative to customer demand. U.S. natural gas prices are also typically higher during the winter period when demand for heating is greatest. During 2011, the average Henry Hub spot price ranged from a low of $3.17 per MMBtu for December to a high of $4.54 per MMBtu for June. During 2011, the average differentials per Mcf to the Henry Hub spot price were a $0.27 premium for our Michigan-based production and a $0.01 discount for our Wyoming-based production. See Part I—Item 1A "—Risk Factors" — "Risks Related to Our Business — A deterioration of the economy and continued depressed natural gas prices could limit our ability to obtain funding in the capital and credit markets on terms we find acceptable, obtain additional or continued funding under our current credit facility or obtain funding at all" in this report.
Our operating expenses are responsive to changes in commodity prices. We experience pressure on operating expenses that is highly correlated to oil prices for specific expenditures such as lease fuel, electricity, drilling services and severance and property taxes.
Derivative Activity
Our revenues and net income are sensitive to oil and natural gas prices. We enter into various derivative contracts intended to achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas. We currently maintain derivative arrangements for a significant portion of our oil and gas production. Currently, we use a combination of fixed price swap and option arrangements to economically hedge NYMEX and IPE Brent crude oil prices and NYMEX natural gas prices. By removing the price volatility from a significant portion of our crude oil and natural gas production, we have mitigated, but not eliminated, the potential effects of changing crude oil and natural gas prices on our cash flow from operations for those periods. While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant
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portion of our expected production and the cost for goods and services increases, our margins would be adversely affected. For a more detailed discussion of our derivative activities, see Part II—Item 7A "—Quantitative and Qualitative Disclosures About Market Risk" and Note 5 to the consolidated financial statements included in this report.
Competition
The oil and gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in all aspects of our business, including acquiring properties and oil and gas leases, marketing oil and gas, contracting for drilling rigs and other equipment necessary for drilling and completing wells and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit.
In regards to the competition we face for drilling rigs and the availability of related equipment, the oil and gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel in the past, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program. Competition is also strong for attractive oil and gas producing properties, undeveloped leases and drilling rights, which may affect our ability to compete satisfactorily when attempting to make further acquisitions. See Item 1A "—Risk Factors" — "Risks Related to Our Business — We may be unable to compete effectively with other companies in the oil and gas industry, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders" in this report.
Title to Properties
As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing oil leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. Under our credit facility, we have granted the lenders a lien on substantially all of our oil and gas properties. Our properties are also subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.
Some of our oil and gas leases, easements, rights-of-way, permits, licenses and franchise ordinances require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained sufficient third-party consents, permits and authorizations for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that the failure to obtain these consents, permits or authorizations have no material adverse effect on the operation of our business.
Seasonal Nature of Business
Seasonal weather conditions, especially freezing conditions in Michigan, and lease stipulations can limit our drilling activities and other operations in certain of the areas in which we operate and, as a result, we seek to perform the majority of our drilling during the summer months. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.
Environmental Matters and Regulation
General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:
• | require the acquisition of various permits before exploration, drilling or production activities commence; |
• | prohibit some or all of the operations of facilities deemed in non-compliance with regulatory requirements; |
• | restrict the types, quantities and concentration of various substances that can be released into the environment in |
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connection with oil and natural gas drilling, production and transportation activities;
• | limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and |
• | require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits, plug abandoned wells, and restore drilling sites. |
These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the United States Congress ("Congress"), state legislatures, and federal and state agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.
The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.
Waste Handling. The Resource Conservation and Recovery Act ("RCRA"), and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the U.S. Environmental Protection Agency ("EPA"), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes.
Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, ("CERCLA"), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by us. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.
Water Discharges. The Federal Water Pollution Control Act (the "Clean Water Act") and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The Clean Water Act also imposes spill prevention, control, and countermeasure requirements, including requirements for appropriate containment berms and similar structures, to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
The primary federal law for oil spill liability is the Oil Pollution Act ("OPA") which establishes a variety of requirements pertaining to oil spill prevention, containment, and cleanup. OPA applies to vessels, offshore facilities and onshore facilities,
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including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, are required to develop and implement plans for preventing and responding to oil spills and, if a spill occurs, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from the spill.
Air Emissions. The Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. For example, on July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA's proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds ("VOCs") and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. EPA's proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. EPA is currently considering comments submitted on the proposed rules and has indicated that it expects to adopt final rules by April 3, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. States can impose air emissions limitations that are more stringent than the federal standards imposed by the EPA, and California air quality laws and regulations are in many instances more stringent than comparable federal laws and regulations. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Regulatory requirements relating to air emissions are particularly stringent in Southern California.
Global Warming and Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2012 for emissions occurring after January 1, 2011, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2013 for emissions occurring in 2012.
In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. California has been one of the leading states in adopting greenhouse gas emission reduction requirements, and California’s initial cap and trade program will begin in 2012. Producers and distributors of liquid fuels and natural gas are not subject to emission limits until 2015.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
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Pipeline Safety. Some of our pipelines are subject to regulation by the U.S. Department of Transportation ("DOT") under the Pipeline Safety Improvement Act of 2002, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The DOT, through the Pipeline and Hazardous Materials Safety Administration ("PHMSA"), has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect "high consequence areas." "High consequence areas" are currently defined to include areas with specified population densities, buildings containing populations with limited mobility, areas where people may gather along the route of a pipeline (such as athletic fields or campgrounds), environmentally sensitive areas and commercially navigable waterways. Under the DOT’s regulations, integrity management programs are required to include baseline assessments to identify potential threats to each pipeline segment, implementation of mitigation measures to reduce the risk of pipeline failure, periodic reassessments, reporting and record keeping. In two steps taken in 2008 and 2010, PHMSA extended its integrity management program requirements to hazardous liquid gathering lines located in "unusually sensitive areas," such as locations containing sole-source drinking water aquifers, endangered species or other protected ecological resources. Fines and penalties may be imposed on pipeline operators that fail to comply with PHMSA requirements, and such operators may also become subject to orders or injunctions restricting pipeline operations. We have had fines and penalties imposed or threatened based on claimed paperwork and documentation omissions.
OSHA and Other Laws and Regulation. We are subject to the requirements of the federal Occupational Safety and Health Act, ("OSHA"), and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.
We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2011. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2012. However, accidental spills or releases may occur in the course of our operations, and we cannot assure you that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. In addition, we expect to be required to incur remediation costs for property, wells and facilities at the end of their useful lives. Moreover, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our business, financial condition and results of operations or ability to make distributions to our unitholders.
Other Regulation of the Oil and Gas Industry
The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.
Production Regulation. Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate, also regulate one or more of the following:
• | the location of wells; |
• | the method of drilling and casing wells; |
• | the surface use and restoration of properties upon which wells are drilled; |
• | the plugging and abandoning of wells; and |
• | notice to surface owners and other third parties. |
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The various states regulate the drilling for, and the production of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Wyoming currently imposes a severance tax on oil and gas producers at the rate of 6% of the value of the gross product extracted. Wyoming wells that reside on Indian or federal land are subject to an additional tax of 8.5%. Florida currently imposes a severance tax on oil producers of up to 8% and Michigan currently imposes a severance tax on oil producers at the rate of 7.6% and on gas producers at the rate of 6.0%. In Wyoming, Florida and Michigan, reduced rates may apply to certain types of wells and production methods, such as new wells, renewed wells, stripper production and tertiary production. California does not currently impose a severance tax but taxes minerals in place. Attempts by California to impose a similar tax have been introduced in the past.
States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowances from oil and gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill. Our Los Angeles Basin properties are located in urbanized areas, and certain drilling and development activities within these fields require local zoning and land use permits obtained from individual cities or counties. These permits are discretionary and, when issued, usually include mitigation measures which may impose significant additional costs or otherwise limit development opportunities.
Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act ("NGA") exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission ("FERC") as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Though our natural gas gathering facilities are not subject to regulation by FERC as natural gas companies under the NGA, our gathering facilities may be subject to certain FERC annual natural gas transaction reporting requirements and daily scheduled flow and capacity posting requirements depending on the volume of natural gas transactions and flows in a given period. See the discussion below of "FERC Market Transparency Rules."
Our natural gas gathering operations are subject to regulation in the various states in which we operate. The level of such regulation varies by state. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.
Transportation Pipeline Regulation. Our sole interstate pipeline is an 8.3 mile pipeline in Kentucky that connects with the Texas Gas Transmission interstate pipeline. That pipeline is subject to a limited jurisdiction FERC certificate, and we are not currently required to maintain a tariff at FERC. Our intrastate natural gas transportation pipelines are subject to regulation by applicable state regulatory commissions. The level of such regulation varies by state. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.
Though our natural gas intrastate pipelines are not subject to regulation by FERC as natural gas companies under the NGA, our intrastate pipelines may be subject to certain FERC annual natural gas transaction reporting requirements and daily scheduled flow and capacity posting requirements depending on the volume of natural gas transactions and flows in a given period. See below the discussion of "FERC Market Transparency Rules."
Natural Gas Processing Regulation. Our natural gas processing operations are not presently subject to FERC regulation. However, pursuant to Order No. 704, we are required to annually report to FERC information regarding natural gas sale and purchase transactions transacted by some of our processing operations. See below the discussion of "FERC Market Transparency Rules." There can be no assurance that our processing operations will continue to be exempt from other FERC regulation in the future.
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Our processing facilities are affected by the availability, terms and cost of pipeline transportation. The price and terms of access to pipeline transportation can be subject to extensive federal and in state regulation. FERC is continually proposing and implementing new rules and regulations affecting the interstate transportation of natural gas, and to a lesser extent, the interstate transportation of NGLs. These initiatives also may indirectly affect the intrastate transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of these regulatory changes to our processing operations.
The ability of our processing facilities and pipelines to deliver natural gas into third party natural gas pipeline facilities is directly impacted by the gas quality specifications required by those pipelines. On June 15, 2006, FERC issued a policy statement on provisions governing gas quality and interchangeability in the tariffs of interstate gas pipeline companies and a separate order declining to set generic prescriptive national standards. FERC strongly encouraged all natural gas pipelines subject to its jurisdiction to adopt, as needed, gas quality and interchangeability standards in their FERC gas tariffs modeled on the interim guidelines issued by a group of industry representatives, headed by the Natural Gas Council (the "NGC+ Work Group"), or to explain how and why their tariff provisions differ. We do not believe that the adoption of the NGC+ Work Group’s gas quality interim guidelines by a pipeline that either directly or indirectly interconnects with our facilities would materially affect our operations. We have no way to predict, however, whether FERC will approve of gas quality specifications that materially differ from the NGC+ Work Group’s interim guidelines for such an interconnecting pipeline.
Regulation of Sales of Natural Gas and NGLs. The price at which we buy and sell natural gas and NGLs is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical purchases and sales of these energy commodities and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission ("CFTC"). See below the discussion of "Energy Policy Act of 2005." Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.
Our sales of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation can be subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting the interstate transportation of natural gas, and to a lesser extent, the interstate transportation of NGLs. These initiatives also may indirectly affect the intrastate transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of these regulatory changes to our natural gas and NGL marketing operations, and we do not believe that we would be affected by any such FERC action materially differently than other natural gas and NGL marketers with whom we compete.
Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005 ("EPAct 2005"). EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. With respect to regulation of natural gas transportation, EPAct 2005 amended the NGA and the Natural Gas Policy Act ("NGPA") by increasing the criminal penalties available for violations of each Act. EPAct 2005 also added a new section to the NGA, which provides FERC with the power to assess civil penalties of up to $1,000,000 per day for each violation of the NGA and increased FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in FERC-jurisdictional transportation and the sale for resale of natural gas in interstate commerce. EPAct 2005 also amended the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of EPAct 2005, and subsequently denied rehearing. The rules make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which they were made, not misleading; or (3) engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any entity. The new anti-market manipulation rule does not apply to activities that relate only to non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction, including the annual reporting requirements under Order No. 704 and the daily scheduled flow and capacity posting requirements under Order No. 720. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s enforcement authority. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. The natural gas industry historically has been heavily regulated. Accordingly, we cannot assure you that present policies pursued by FERC and Congress
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will continue.
FERC Market Transparency Rules. On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing ("Order No. 704"). Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers, and natural gas producers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.
On November 20, 2008, FERC issued a final rule on the daily scheduled flow and capacity posting requirements ("Order No. 720"), which was modified on January 21, 2010 ("Order No. 720-A") and July 21, 2010 ("Order No. 720-B"). Under Order Nos. 720, 720-A and 720-B, major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of natural gas over the previous three calendar years, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu/d.
Employees
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. As of December 31, 2011, BreitBurn Management had 395 full time employees. BreitBurn Management provides services to us as well as to our Predecessor. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are satisfactory.
Offices
BreitBurn Management's principal executive offices are located at 515 S. Flower St., Suite 4800, Los Angeles, California 90071. BreitBurn Management leases office space in the JP Morgan Chase Tower at 600 Travis Street, Houston, Texas 77002, where our regional office is located. In addition to the offices in Los Angeles and Houston, BreitBurn Management maintains field offices in Gaylord, Michigan and Cody, Wyoming.
Financial Information
We operate our business as a single segment. Additionally, all of our properties are located in the United States and all of the related revenues are derived from purchasers located in the United States. Our financial information is included in the consolidated financial statements and the related notes beginning on page F-1.
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Item 1A. Risk Factors.
An investment in our securities is subject to certain risks described below. If any of these risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the distributions on our Common Units, the trading price of our Common Units could decline and you could lose part or all of your investment.
Risks Related to Our Business
Oil and natural gas prices and differentials are highly volatile. In the past, declines in commodity prices have adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flow, access to the capital markets and ability to grow. A decline in our cash flow could force us to reduce our distributions or cease paying distributions altogether in the future.
The oil and natural gas markets are highly volatile, and we cannot predict future oil and natural gas prices. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
• | domestic and foreign supply of and demand for oil and natural gas; |
• | market prices of oil and natural gas; |
• | level of consumer product demand; |
• | weather conditions; |
• | overall domestic and global political and economic conditions; |
• | political and economic conditions in oil and natural gas producing countries, including those in the Middle East, Russia, South America and Africa; |
• | actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls; |
• | impact of the U.S. dollar exchange rates on oil and natural gas prices; |
• | technological advances affecting energy consumption and energy supply; |
• | domestic and foreign governmental regulations and taxation; |
• | the impact of energy conservation efforts; |
• | the capacity, cost and availability of oil and natural gas pipelines, processing, gathering and other transportation facilities, and the proximity of these facilities to our wells; |
• | an increase in imports of liquid natural gas in the United States; and |
• | the price and availability of alternative fuels. |
Oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because natural gas accounted for approximately 65% of our estimated proved reserves as of December 31, 2011 and is a substantial portion of our current production on an Mcfe basis, our financial results will be more sensitive to movements in natural gas prices.
In the past, prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2011, the monthly average NYMEX WTI spot price ranged from a low of $86 per barrel in September 2011 to a high of $110 per barrel in April 2011 while the monthly average Henry Hub natural gas price ranged from a low of $3.17 per MMBtu in December to a high of $4.54 per MMBtu in June.
Price discounts or differentials between NYMEX WTI prices and what we actually receive are also historically very volatile. For instance, during calendar year 2011, the average quarterly premium to NYMEX WTI for our California production varied from $5.86 to $20.30 per barrel, with the differential percentage of the total price per barrel ranging from 6% to 22%. For Wyoming crude oil, our average quarterly price discount from NYMEX WTI varied from $9.40 to $21.44, with the discount percentage ranging from 10% to 23% of the total price per barrel. Our crude oil produced from our Florida properties also traded at a significant discount to NYMEX WTI primarily because of its low gravity and other characteristics as well as its distance from a major refining market. For Florida crude oil, our average quarterly discount to NYMEX WTI varied from $10.13 to $16.12 including transportation expenses of approximately $7.50 per barrel, with the discount percentage ranging from 11% to 18% of the total price per barrel.
Our revenue, profitability and cash flow depend upon the prices and demand for oil and natural gas, and a drop in prices could significantly affect our financial results and impede our growth. In particular, continuance of the current low natural gas price environment, further declines in natural gas prices, lack of natural gas storage or a significant decline in crude oil prices will negatively impact:
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• | our ability to pay distributions; |
• | the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically; |
• | the amount of cash flow available for capital expenditures; |
• | our ability to replace our production and future rate of growth; |
• | our ability to borrow money or raise additional capital and our cost of such capital; |
• | our ability to meet our financial obligations; and |
• | the amount that we are allowed to borrow under our credit facilities. |
Historically, higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services. Accordingly, continued high costs could adversely affect our ability to pursue our drilling program and our results of operations.
In the past, we have raised our distribution levels on our Common Units in response to increased cash flow during periods of relatively high commodity prices. However, we were not able to sustain those distribution levels during subsequent periods of lower commodity prices. For example, our initial distribution rate was $1.65 on an annual basis for the fourth quarter of 2006. The distribution made to our unitholders on February 13, 2009 for the fourth quarter of 2008 was $2.08 on an annual basis. As a result of the reduction in our borrowing base in April 2009, we were restricted from declaring a distribution on our Common Units and did not pay a distribution from February 2009 until May 2010. Although distributions were reinstated in 2010, a decline in our cash flow may force us to reduce our distributions or cease paying distributions again altogether in the future.
Natural gas prices have declined substantially in the last year, and are expected to remain depressed for the foreseeable future. Approximately 54% of our 2011 production, on an MBoe basis, is natural gas. Sustained depressed prices of natural gas will adversely affect our assets, development plans, results of operations and financial position, perhaps materially.
Natural gas prices have declined from a monthly average price for Henry Hub of $4.49 per MMBtu in January 2011 to $2.67 per MMBtu in January 2012 and $2.48 for the first three weeks of February 2012. The reduction in prices has been caused by many factors, including recent increases in gas production from non-conventional (shale) reserves, warmer than normal weather and high levels of natural gas in storage. We have hedged more than 65% of our natural gas production in 2012 and 2013 at prices higher than those currently prevailing. However, if prices for natural gas remain depressed for long periods, we may be required to write down the value of our oil and gas properties and/or revise our development plans which may cause certain of our undeveloped well locations to no longer be deemed to be proved. In addition, sustained low prices for natural gas will reduce the amounts we would otherwise have available to pay expenses, make distributions to our unitholders and to service our indebtedness.
The continuing decline of natural gas prices and concern about the global financial markets could limit our ability to obtain funding in the capital and credit markets on terms we find acceptable, obtain additional or continued funding under our current credit facility or obtain funding at all.
Following the 2008 economic downturn, global financial markets, economic conditions and commodity prices were disrupted and volatile. In addition, the debt and equity capital markets were slow to recover. A continued decline in natural gas prices and concern about the global financial markets could make it challenging to obtain funding in the capital and credit markets in the future. During 2011 and the first quarter of 2012, we were able to access the debt and equity capital markets. However, the continuing decline of natural gas prices could significantly increase the cost of obtaining money from the capital and credit markets and limit our ability to access those markets as a source of funding.
Historically, we have used our cash flow from operations, borrowings under our credit facility and issuance of senior notes and additional partnership units to fund our capital expenditures and acquisitions. The continuing decline of natural gas prices could ultimately decrease our net revenue and profitability. The recent natural gas price declines have negatively impacted our revenues and cash flows.
These events affect our ability to access capital in a number of ways, which include the following:
• | Our ability to access new debt or credit markets on acceptable terms may be limited and this condition may last for an unknown period of time. |
• | Our current credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. |
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• | We may be unable to obtain adequate funding under our current credit facility because our lenders may simply be unwilling or unable to meet their funding obligations. |
• | The operating and financial restrictions and covenants in our credit facility limit (and any future financing agreements likely will limit) our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions. |
Due to these factors, we cannot be certain that funding will be available, if needed and to the extent required, on acceptable terms. If funding is not available when needed, or if funding is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our development plans, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues, results of operations, financial condition or ability to pay distributions. Moreover, if we are unable to obtain funding to make acquisitions of additional properties containing proved oil or natural gas reserves, our total level of proved reserves may decline as a result of our production, and we may be limited in our ability to maintain our level of cash distributions.
Even if we are able to pay quarterly distributions on our Common Units under the terms of our credit facility, we may not elect to pay quarterly distributions on our Common Units because we do not have sufficient cash flow from operations following establishment of cash reserves, reduction of debt and payment of fees and expenses.
Our credit facility limits the amounts we can borrow to a borrowing base amount, which is determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. For example, in April 2009, our borrowing base was decreased from $900 million to $760 million as a result of a scheduled borrowing base redetermination and further decreased to $732 million as a result of an asset sale and derivative contract monetization. In October 2011, our borrowing base was increased to $850 million and in January 2012 reduced to $788 million as a result of our issuance of $250 million in aggregate principal amount of unsecured 7.875% senior notes maturing April 15, 2022 (the “2022 Senior Notes”). As a result of the reduction in our borrowing base in April 2009, we were restricted from declaring a distribution on our Common Units and did not pay a distribution from February 2009 until May 2010. While we currently are not restricted by our credit facility from declaring a distribution as we were in April 2009, we may again be restricted from paying a distribution in the future. Our credit facility restricts our ability to make distributions to unitholders or repurchase units unless after giving effect to such distribution or repurchase, we remain in compliance with all terms and conditions of our credit facility.
Even if we are able to pay quarterly distributions on our Common Units under the terms of our credit facility, we may not have sufficient available cash each quarter to pay quarterly distributions on our Common Units. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses, debt reduction and the amount of any cash reserve amounts that our General Partner establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. In the future, we may reserve a substantial portion of our cash generated from operations to develop our oil and natural gas properties and to acquire additional oil and natural gas properties in order to maintain and grow our level of oil and natural gas reserves.
The amount of cash we actually generate will depend upon numerous factors related to our business that may be beyond our control, including among other things:
• | the amount of oil and natural gas we produce; |
• | demand for and prices at which we sell our oil and natural gas; |
• | the effectiveness of our commodity price derivatives; |
• | the level of our operating costs; |
• | prevailing economic conditions; |
• | our ability to replace declining reserves; |
• | continued development of oil and natural gas wells and proved undeveloped reserves; |
• | our ability to acquire oil and natural gas properties from third parties in a competitive market and at an attractive price; |
• | the level of competition we face; |
• | fuel conservation measures; |
• | alternate fuel requirements; |
• | government regulation and taxation; and |
• | technical advances in fuel economy and energy generation devices. |
In addition, the actual amount of cash that we will have available for distribution will depend on other factors, including:
• | our ability to borrow under our credit facility to pay distributions; |
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• | debt service requirements and restrictions on distributions contained in our credit facility or future debt agreements; |
• | the level of our capital expenditures; |
• | sources of cash used to fund acquisitions; |
• | fluctuations in our working capital needs; |
• | general and administrative expenses; |
• | cash settlement of hedging positions; |
• | timing and collectability of receivables; and |
• | the amount of cash reserves established for the proper conduct of our business. |
For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read Part II-Item 7 "-Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources."
If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.
Our ability to grow and to increase distributions to unitholders depends in part on our ability to make acquisitions that result in an increase in pro forma available cash per unit. We may be unable to make such acquisitions because:
• | we cannot identify attractive acquisition candidates or negotiate acceptable purchase contracts with them; |
• | we cannot obtain financing for these acquisitions on economically acceptable terms; |
• | we are outbid by competitors; or |
• | our Common Units are not trading at a price that would make the acquisition accretive. |
If we are unable to acquire properties containing proved reserves, our total level of estimated proved reserves may decline as a result of our production, and we may be limited in our ability to increase or maintain our level of cash distributions.
Any acquisitions that we complete are subject to substantial risks that could reduce our ability to make distributions to our unitholders. The integration of the oil and natural gas properties that we acquire may be difficult, and could divert our management's attention away from our other operations.
If we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:
• | the validity of our assumptions about reserves, future production, revenues and costs, including synergies; |
• | an inability to integrate successfully the businesses we acquire; |
• | a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions; |
• | a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; |
• | the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate; |
• | the diversion of management's attention from other business concerns; |
• | an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; |
• | the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges; |
• | unforeseen difficulties encountered in operating in new geographic areas; and |
• | customer or key employee losses at the acquired businesses. |
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.
Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.
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Drilling for and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.
The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce enough oil and natural gas to be commercially viable after drilling, operating and other costs. Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
• | high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services; |
• | unexpected operational events and drilling conditions; |
• | reductions in oil and natural gas prices; |
• | limitations in the market for oil and natural gas; |
• | problems in the delivery of oil and natural gas to market; |
• | adverse weather conditions; |
• | facility or equipment malfunctions; |
• | equipment failures or accidents; |
• | title problems; |
• | pipe or cement failures; |
• | casing collapses; |
• | compliance with environmental and other governmental requirements; |
• | environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases; |
• | lost or damaged oilfield drilling and service tools; |
• | unusual or unexpected geological formations; |
• | loss of drilling fluid circulation; |
• | pressure or irregularities in formations; |
• | fires, blowouts, surface craterings and explosions; |
• | natural disasters; and |
• | uncontrollable flows of oil, natural gas or well fluids. |
If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.
We may be unable to compete effectively with other companies in the oil and gas industry, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.
The oil and gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major independent oil and gas companies, and possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Factors that affect our ability to acquire properties include availability of desirable acquisition targets, staff and resources to identify and evaluate properties and available funds. Many of our larger competitors not only drill for and produce oil and gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the oil and gas industry. Other companies may have a greater ability to continue drilling activities during periods of low oil and gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with other companies could have a material adverse effect on our business activities, financial condition and results of operations.
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Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.
As of February 28, 2012, we had approximately $88.0 million in borrowings outstanding under our credit facility. Our credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. The borrowing base is redetermined semi-annually and the available borrowing amount could be further decreased as a result of such redeterminations. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements or regulations or certain other circumstances. In October 2011, our borrowing base was increased to $850 million from $735 million and in January 2012 was reduced to $788 million as a result of our issuance of the 2022 Senior Notes. Our next borrowing base redetermination will be in April 2012. As a result of the continuing decline in natural gas prices, our borrowing base could be decreased by the lenders under our credit facility. A future decrease in our borrowing base could be substantial and could be to a level below our outstanding borrowings at that time. Outstanding borrowings in excess of the borrowing base are required to be repaid in five equal monthly payments, or we are required to pledge other oil and natural gas properties as additional collateral, within 30 days following notice from the administrative agent of the new or adjusted borrowing base. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our credit facility or sell assets or debt or Common Units. We may not be able to obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to make the required repayment could result in a default under our credit facility, which could adversely affect our business, financial condition and results of operations.
The operating and financial restrictions and covenants in our credit facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions. Our credit facility restricts, and any future credit facility likely will restrict, our ability to:
• | incur indebtedness; |
• | grant liens; |
• | make certain acquisitions and investments; |
• | lease equipment; |
• | make capital expenditures above specified amounts; |
• | redeem or prepay other debt; |
• | make distributions to unitholders or repurchase units; |
• | enter into transactions with affiliates; and |
• | enter into a merger, consolidation or sale of assets. |
Our credit facility restricts our ability to make distributions to unitholders or repurchase Common Units unless after giving effect to such distribution or repurchase, we remain in compliance with all terms and conditions of our credit facility. While we currently are not restricted by our credit facility from declaring a distribution as we were in April 2009, we may again be restricted from paying a distribution in the future.
We also are required to comply with certain financial covenants and ratios under the credit facility. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. In light of persistent weak economic conditions and the deterioration of natural gas prices, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited and our lenders' commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders can seek to foreclose on our assets.
See Part II-Item 7 "-Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources" for a discussion of our credit facility covenants.
Restrictive covenants under our indenture governing our senior notes may adversely affect our operations.
The indentures governing our $305 million unsecured 8.625% senior notes maturing October 15, 2020 (the "2020 Senior Notes") and our 2022 Senior Notes (together the “Senior Notes”) contain, and any future indebtedness we incur may contain, a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:
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• | sell assets, including equity interests in our restricted subsidiaries; |
• | pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt; |
• | make investments; |
• | incur or guarantee additional indebtedness or issue preferred units; |
• | create or incur certain liens; |
• | enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; |
• | consolidate, merge or transfer all or substantially all of our assets; |
• | engage in transactions with affiliates; |
• | create unrestricted subsidiaries; and |
• | engage in certain business activities. |
As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
A failure to comply with the covenants in the indenture governing our senior notes or any future indebtedness could result in an event of default under the indenture governing the Senior Notes or the future indebtedness, which, if not cured or waived, could have a material adverse affect on our business, financial condition and results of operations. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.
Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.
As of February 28, 2012, our long-term debt totaled $643 million. Our existing and future indebtedness could have important consequences to us, including:
• | our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on terms acceptable to us; |
• | covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities; |
• | our access to the capital markets may be limited; |
• | our borrowing costs may increase; |
• | we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and |
• | our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally. |
Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.
We will require substantial capital expenditures to replace our production and reserves, which will reduce our cash available for distribution. We may be unable to obtain needed capital due to our financial condition, which could adversely affect our ability to replace our production and estimated proved reserves.
To fund our capital expenditures, we will be required to use cash generated from our operations, additional borrowings or the issuance of additional partnership interests, or some combination thereof. In 2012, our oil and gas capital spending program is expected to be approximately $68 million, compared to approximately $75 million in 2011 and approximately $70 million in 2010. Based on the continuing decline of natural gas prices, we will continue to evaluate our capital spending program throughout 2012. We expect to use cash generated from operations to fund future capital expenditures, which will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or to access the capital and credit markets for future equity or debt offerings to fund future capital expenditures was limited in 2009 because of the credit crisis and turmoil in the financial markets. In the future, our ability to borrow and to access the capital and credit markets may be limited by our financial condition at the time of any such financing or offering and the covenants in our debt agreements, as well as by oil and natural gas prices, the value and performance of our equity securities, and adverse market conditions resulting from, among
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other things, general economic conditions and contingencies and uncertainties that are beyond our control. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, results of operations, financial condition and ability to pay distributions. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution, thereby increasing the aggregate amount of cash required to maintain the then-current distribution rate, which could have a material adverse effect on our ability to pay distributions at the then-current distribution rate.
Our inability to replace our reserves could result in a material decline in our reserves and production, which could adversely affect our financial condition. We are unlikely to be able to sustain or increase distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base.
Producing oil and natural gas reservoirs are characterized by declining production rates that vary based on reservoir characteristics and other factors. The rate of decline of our reserves and production included in our reserve report at December 31, 2011 will change if production from our existing wells declines in a different manner than we have estimated and may change when we drill additional wells, make acquisitions and under other circumstances. Our future oil and natural gas reserves and production and our cash flow and ability to make distributions depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution.
We are unlikely to be able to sustain or increase distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution. Because the timing and amount of these capital expenditures fluctuate each quarter, we expect to reserve cash each quarter to finance these expenditures over time. We may use the reserved cash to reduce indebtedness until we make the capital expenditures.
Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions. If we do not make sufficient growth capital expenditures, we will be unable to sustain our business operations and therefore will be unable to maintain our current level of distributions. With our reserves decreasing, if we do not reduce our distributions, then a portion of the distributions may be considered a return of part of your investment in us as opposed to a return on your investment. Also, if we do not make sufficient growth capital expenditures, we will be unable to expand our business operations and will therefore be unable to raise the level of future distributions.
Future oil and natural gas price declines may result in a write-down of our asset carrying values.
Declines in oil and natural gas prices in 2008 resulted in us having to make substantial downward adjustments to our estimated proved reserves resulting in increased depletion and depreciation charges. Accounting rules require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties in the event we have impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write-down. For example, as a result of the dramatic declines in oil and gas prices in the second half of 2008 and related reserve reductions, we recorded non-cash charges of $51.9 million for total impairments and $34.5 million for price related adjustments to depletion and depreciation expense for the year ended December 31, 2008. We also may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit facility, which in turn may adversely affect our ability to make cash distributions to our unitholders.
Our derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders. To the extent we have hedged a significant portion of our expected production and actual production is lower than expected or the costs of goods and services increase, our profitability would be adversely affected.
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently and may in the future enter into derivative arrangements for a significant portion of our expected oil and natural gas production that could result in both realized and unrealized hedging losses. As of February 28, 2012, we had hedged, through swaps, options (including collar instruments) and physical contracts, approximately 75% of our 2012 production.
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The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we utilize are primarily based on IPE Brent, NYMEX WTI and MichCon City-Gate-Inside FERC prices, which may differ significantly from the actual crude oil and natural gas prices we realize in our operations. Furthermore, we have adopted a policy that requires, and our credit facility also mandates, that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we will continue to have direct commodity price exposure on the portion of our production volumes not covered by these derivative transactions.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution in our profitability and liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.
In addition, our derivative activities are subject to the following risks:
• | we may be limited in receiving the full benefit of increases in oil and natural gas prices as a result of these transactions; |
• | a counterparty may not perform its obligation under the applicable derivative instrument or seek bankruptcy protection; |
• | there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and |
• | the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. |
As of February 28, 2012, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, U.S Bank National Association and Toronto-Dominion Bank. We periodically obtain credit default swap information on our counterparties. As of December 31, 2011 and February 28, 2012, each of these financial institutions had an investment grade credit rating. Although we currently do not believe that we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default. As of December 31, 2011, our largest derivative asset balances were with JP Morgan Chase Bank N.A., Union Bank N.A and Wells Fargo Bank National Association which accounted for approximately 37%, 10% and 10% of our derivative asset balances, respectively. As of December 31, 2011, our largest derivative liability balances were with BNP Paribas, The Royal Bank of Scotland plc and Citibank, N.A. which accounted for approximately 34%, 31% and 22% of our derivative liability balances, respectively.
The adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
Congress adopted comprehensive financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank") that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Partnership, that participate in that market. Dodd-Frank was signed into law by the President on July 21, 2010 and requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In December 2011, the CFTC extended temporary exemptive relief from certain swap regulation provisions of the legislation until July 16, 2012. In its rulemaking under Dodd-Frank, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or derivative instruments would be exempt from these position limits. It is not possible at this time to predict when the CFTC will make these regulations effective. Dodd-Frank may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. Dodd-Frank may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as credit worthy as the current counterparty. Dodd-Frank and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less credit worthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more
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volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and make distributions to our unitholders. Finally, this legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of Dodd-Frank and any new regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, our results of operations and our ability to make distributions to unitholders.
Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves.
It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. Our independent reserve engineers do not independently verify the accuracy and completeness of information and data furnished by us. In estimating our level of oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:
• | future oil and natural gas prices; |
• | production levels; |
• | capital expenditures; |
• | operating and development costs; |
• | the effects of regulation; |
• | the accuracy and reliability of the underlying engineering and geologic data; and |
• | the availability of funds. |
If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly. For example, if the SEC prices used for our December 31, 2011 reserve report had been $10.00 less per Bbl and $1.00 less per MMBtu, respectively, then the standardized measure of our estimated proved reserves as of December 31, 2011 would have decreased by $423.9 million, from $1,659.3 million, to $1,235.4 million.
Our standardized measure is calculated using unhedged oil prices and is determined in accordance with SEC rules and regulations. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.
The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures.
The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of the estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:
• | the actual prices we receive for oil and natural gas; |
• | our actual operating costs in producing oil and natural gas; |
• | the amount and timing of actual production; |
• | the amount and timing of our capital expenditures; |
• | supply of and demand for oil and natural gas; and |
• | changes in governmental regulations or taxation. |
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the FASB Accounting Standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
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Our actual production could differ materially from our forecasts.
From time to time, we provide forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production from existing wells. In addition, our forecasts assume that none of the risks associated with our oil and gas operations summarized in this Item 1A occur, such as facility or equipment malfunctions, adverse weather effects, or significant declines in commodity prices or material increases in costs, which could make certain production uneconomical.
In 2011, we depended on four customers for a substantial amount of our sales. If these customers reduce the volumes of oil and natural gas that they purchase from us, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production. In addition, if the parties to our purchase contracts default on these contracts, we could be materially and adversely affected.
In 2011, four customers accounted for approximately 70% of our net sales revenues. If these customers reduce the volumes of oil and natural gas that they purchase from us and we are not able to find new customers for our production, our revenue and cash available for distribution will decline. In 2011, ConocoPhillips in California and Michigan accounted for approximately 30% of our net sales revenues, Plains Marketing & Transportation LLC in Florida accounted for approximately 16% of our net sales revenues, Marathon Oil Company in Wyoming accounted for approximately 15% of our net sales revenues and Sunoco Partners Marketing and Terminals L.P. in Michigan accounted for approximately 9% of our net sales revenues. In 2010, ConocoPhillips accounted for approximately 30% of our net sales revenues, Marathon Oil Company accounted for approximately 16% of our net sales revenues, Plains Marketing & Transportation LLC accounted for approximately 12% of our net sales revenues and Sunoco Partners Marketing and Terminals L.P. accounted for approximately 10% of our net sales revenues.
Natural gas purchase contracts account for a significant portion of revenues relating to our Michigan, Indiana and Kentucky properties. We cannot assure you that the other parties to these contracts will continue to perform under the contracts. If the other parties were to default after taking delivery of our natural gas, it could have a material adverse effect on our cash flows for the period in which the default occurred. A default by the other parties prior to taking delivery of our natural gas could also have a material adverse effect on our cash flows for the period in which the default occurred depending on the prevailing market prices of natural gas at the time compared to the contractual prices.
We have limited control over the activities on properties we do not operate.
On a net production basis, we operate approximately 87% of our production as of December 31, 2011. We have limited ability to influence or control the operation or future development of the non-operated properties in which we have interests or the amount of capital expenditures that we are required to fund for their operation. The success and timing of drilling development or production activities on properties operated by others depend upon a number of factors that are outside of our control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, approval of other participants, and selection of technology. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns on capital or lead to unexpected future costs.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
There are a variety of operating risks inherent in our wells, gathering systems, pipelines and other facilities, such as leaks, explosions, fires, mechanical problems and natural disasters including earthquakes and tsunamis, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.
We currently possess property and general liability insurance at levels that we believe are appropriate; however, we are not fully insured for these items and insurance against all operational risk is not available to us. We are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be
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available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and recent natural disasters have made it more difficult for us to obtain certain types of coverage. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you.
If third-party pipelines and other facilities interconnected to our wells and gathering and processing facilities become partially or fully unavailable to transport natural gas, oil or NGLs, our revenues and cash available for distribution could be adversely affected.
We depend upon third party pipelines and other facilities that provide delivery options to and from some of our wells and gathering and processing facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third-party pipelines and other facilities become partially or fully unavailable to transport natural gas, oil or NGLs, or if the gas quality specifications for the natural gas gathering or transportation pipelines or facilities change so as to restrict our ability to transport natural gas on those pipelines or facilities, our revenues and cash available for distribution could be adversely affected.
For example, in Florida, there are a limited number of alternative methods of transportation for our production, and substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in us having to find transportation alternatives, increased transportation costs, or involuntary curtailment of our oil production in Florida, which could have a negative impact on our future consolidated financial position, results of operations or cash flows.
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.
Our oil and natural gas exploration, production, gathering and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, in California, there have been proposals at the legislative and executive levels in the past two years for tax increases which have included a severance tax as high as 12.5% on all oil production in California. Although the proposals have not passed the California Legislature, the financial crisis in the State of California could lead to a severance tax on oil being imposed in the future. We have significant oil production in California and while we cannot predict the impact of such a tax without having more specifics, the imposition of such a tax could have severe negative impacts on both our willingness and ability to incur capital expenditures in California to increase production, could severely reduce or completely eliminate our California profit margins and would result in lower oil production in our California properties due to the need to shut-in wells and facilities made uneconomic either immediately or at an earlier time than would have previously been the case. On the local level, the City of Los Angeles placed an initiative on the March 2011 ballot proposing to increase the city's tax on oil production in the City of Los Angeles to $1.44 per barrel which was defeated. There also is currently proposed federal legislation in three areas (tax legislation, climate change and hydraulic fracturing) that if adopted could significantly affect our operations. The following are brief descriptions of the proposed laws:
• | Tax Legislation. The Fiscal Year 2013 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of such U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our Common Units. |
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• | Climate Change Legislation and Regulation. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA's rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011. |
In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. California has been one of the leading states in adopting greenhouse gas emission reduction requirements, and California's initial cap and trade program will begin in 2012. Producers and distributors of liquid fuels and natural gas are not subject to emission limits until 2015.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
• | Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. |
In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and
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final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms. Significant restrictions on hydraulic fracturing activities could eventually reduce the amount of oil and natural gas that we are able to produce from our reserves.
• | A change in the jurisdictional characterization of our gathering assets by federal, state or local regulatory agencies or a change in policy by those agencies with respect to those assets may result in increased regulation of those assets. |
Failure to comply with federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production of, oil and natural gas could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you. Please read Part I-Item 1 "-Business-Environmental Matters and Regulation" and "-Business-Other Regulation of the Oil and Gas Industry" for a description of the laws and regulations that affect us.
Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.
We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas exploration and production activities. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.
Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to make distributions to you could be adversely affected. Please read Part I-Item 1 "Business-Environmental Matters and Regulation" for more information.
We depend on our General Partner's executive officers, who would be difficult to replace.
We depend on the performance of our General Partner's executive officers, Randall Breitenbach and Halbert Washburn. We do not maintain key person insurance for Mr. Breitenbach or Mr. Washburn. The loss of either or both of Mr. Breitenbach or Mr. Washburn could negatively impact our ability to execute our strategy and our results of operations.
Risks Related to Our Structure
We may issue additional Common Units without your approval, which would dilute your existing ownership interests.
We may issue an unlimited number of limited partner interests of any type, including Common Units, without the approval of our unitholders, including in connection with potential acquisitions of oil and gas properties or the reduction of debt, which would dilute your existing ownership interests. For example, in 2007, we issued a total of 45 million Common Units (or 67% of our outstanding Common Units) in connection with our acquisitions of oil and natural gas properties, in February 2011, we issued 4.9 million Common Units (or approximately 9% of our outstanding Common Units at issuance) and in February 2012, we issued 9.2 million Common Units (or approximately 15% of our outstanding Common Units at issuance).
The issuance of additional Common Units or other equity securities may have the following effects:
• | your proportionate ownership interest in us may decrease; |
• | the amount of cash distributed on each Common Unit may decrease; |
• | the relative voting strength of each previously outstanding Common Unit may be diminished; |
• | the market price of the Common Units may decline; and |
• | the ratio of taxable income to distributions may increase. |
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Our partnership agreement limits our General Partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
• | provides that our General Partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were in the best interests of the Partnership; |
• | generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the Board and not involving a vote of unitholders will not constitute a breach of our partnership agreement or of any fiduciary duty if they are on terms no less favorable to us than those generally provided to or available from unrelated third parties or are "fair and reasonable" to us and that, in determining whether a transaction or resolution is "fair and reasonable," our General Partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; |
• | provides that in resolving conflicts of interest where approval of the conflicts committee of the Board is not sought, it will be presumed that in making its decision the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and |
• | provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or those other persons acted in bad faith or engaged in fraud or willful misconduct. |
Unitholders are bound by the provisions of our partnership agreement, including the provisions described above.
Certain of the directors and officers of our General Partner, including our Chief Executive Officer, our President and other members of our senior management, own interests in PCEC, which is managed by our subsidiary, BreitBurn Management. Conflicts of interest may arise between PCEC, on the one hand, and us and our unitholders, on the other hand. Our partnership agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.
Certain of the directors and officers of our General Partner, including our Chief Executive Officer, our President and other members of our senior management, own interests in PCEC, which is managed by our subsidiary, BreitBurn Management. Conflicts of interest may arise between PCEC, on the one hand, and us and our unitholders, on the other hand. We have entered into an Omnibus Agreement with PCEC to address certain of these conflicts. However, these persons may face other conflicts between their interests in PCEC and their positions with us. These potential conflicts include, among others, the following situations:
• | Our General Partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayments of indebtedness, issuances of additional partnership securities, cash reserves and expenses. Although we have entered into a new Omnibus Agreement with PCEC, which addresses the rights of the parties relating to potential business opportunities, conflicts of interest may still arise with respect to the pursuit of such business opportunities. We have agreed in the Omnibus Agreement that PCEC and its affiliates will have a preferential right to acquire any third party upstream oil and natural gas properties that are estimated to contain less than 70% proved developed reserves. |
• | Currently and historically some officers of our General Partner and many employees of BreitBurn Management have also devoted time to the management of PCEC. This arrangement will continue under the Second Amended and Restated Administrative Services Agreement and this will continue to result in material competition for the time and effort of the officers of our General Partner and employees of BreitBurn Management who provide services to PCEC and who are officers and directors of the sole member of the general partner of PCEC. If the officers of our General Partner and the employees of BreitBurn Management do not devote sufficient attention to the management and operation of our business, our financial results could suffer and our ability to make distributions to our unitholders could be reduced. |
See "BreitBurn Management" in Part II—Item 7 "—Management’s Discussion and Analysis of Financial Condition and
Results of Operations" in this report for a discussion of Pacific Coast Oil Trust.
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Our partnership agreement limits the liability and reduces the fiduciary duties of our General Partner and its directors and officers, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing Common Units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our Common Units.
Our partnership agreement restricts unitholders' voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board, cannot vote on any matter. In addition, solely with respect to the election of directors, our partnership agreement provides that (x) our General Partner and the Partnership will not be entitled to vote their units, if any, and (y) if at any time any person or group beneficially owns 20% or more of the outstanding Partnership securities of any class then outstanding and otherwise entitled to vote, then all Partnership securities owned by such person or group in excess of 20% of the outstanding Partnership securities of the applicable class may not be voted, and in each case, the foregoing units will not be counted when calculating the required votes for such matter and will not be deemed to be outstanding for purposes of determining a quorum for such meeting. Such Common Units will not be treated as a separate class of Partnership securities for purposes of our partnership agreement. Notwithstanding the foregoing, the Board may, by action specifically referencing votes for the election of directors, determine that the limitation set forth in clause (y) above will not apply to a specific person or group. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders' ability to influence the manner or direction of management.
Our partnership agreement has provisions that discourage takeovers.
Certain provisions of our partnership agreement may have the effect of delaying or preventing a change in control. Our directors are elected to staggered terms. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove our General Partner. The provisions contained in our partnership agreement, alone or in combination with each other, may discourage transactions involving actual or potential changes of control.
Unitholders who are not "Eligible Holders" will not be entitled to receive distributions on or allocations of income or loss on their Common Units and their Common Units will be subject to redemption.
In order to comply with U.S. laws with respect to the ownership of interests in oil and gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our Common Units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof and only for so long as the alien is not from a country that the United States federal government regards as denying similar privileges to citizens or corporations of the United States. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder will not be entitled to receive distributions or allocations of income and loss on their units and they run the risk of having their units redeemed by us at the lower of their purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner.
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions to you.
We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries. As a result, our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.
Unitholders may not have limited liability if a court finds that unitholder action constitutes participation in control of our business.
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The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could have unlimited liability for our obligations if a court or government agency determined that:
• | we were conducting business in a state but had not complied with that particular state's partnership statute; or |
• | your right to act with other unitholders to elect the directors of our General Partner, to remove or replace our General Partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted participation in "control" of our business. |
Unitholders may have liability to repay distributions.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the "Delaware Act"), we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of Common Units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the Partnership that are known to such purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.
Tax Risks to Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If we were to be treated as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.
The anticipated after-tax economic benefit of an investment in our Common Units depends largely on us being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service ("IRS") with respect to our treatment as a partnership for federal income tax purposes.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit would flow through to you. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, treatment of us as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and, therefore, result in a substantial reduction in the value of our units.
Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Imposition of such a tax on us by any such state will reduce the cash available for distribution to our unitholders.
The tax treatment of publicly traded partnerships or an investment in our Common Units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our Common Units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of
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Congress have considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the legislation considered would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Common Units.
If the IRS contests the federal income tax positions we take, the market for our Common Units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our Common Units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our cash available for distribution.
You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.
Because you will be treated as a partner in us for federal income tax purposes we will allocate a share of our taxable income to you, and you will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive a cash distribution from us. You may not receive a cash distribution from us equal to your share of our taxable income or even equal to the actual tax liability which results from your share of our taxable income.
Tax gain or loss on the disposition of our Common Units could be more or less than expected because prior distributions in excess of allocations of income will decrease your tax basis in your Common Units.
If you sell any of your Common Units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those Common Units. Prior distributions to you in excess of the total net taxable income you were allocated for a Common Unit, which decreased your tax basis in that Common Unit, will, in effect, become taxable income to you if the Common Unit is sold at a price greater than your tax basis in that Common Unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you due to potential recapture of depreciation deductions. In addition, because the amount realized will include your share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our Common Units that may result in adverse tax consequences to them.
Investment in units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Our partnership agreement generally prohibits non-U.S. persons from owning our units. However, if non-U.S. persons own our units, distributions to such non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and such non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our Common Units.
We will treat each purchaser of our Common Units as having the same tax benefits without regard to the Common Units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Common Units.
Due to a number of factors including our inability to match transferors and transferees of Common Units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of Common Units and could have a negative impact on the value of our Common Units or result in audits of and adjustments to our unitholders' tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the
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date a particular Common Unit is transferred. The IRS may challenge this treatment, and, if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS, were to successfully challenge this method or new Treasury Regulations were issued, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax it ems among transferor and transferee unitholders. Although existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued.
A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have constructively terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest are counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders receiving two Schedules K-1) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder's taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to its unitholders for the tax year in which the termination occurs.
For example, in 2011 as a result of Quicksilver selling approximately 15.7 million of our Common Units together with normal trading activity by other unitholders, greater than 50% of our Common Units traded within a twelve month period and caused a technical termination of the Partnership for federal income tax purposes. This technical termination required the closing of our taxable year for all unitholders on November 30, 2011, and brought about two taxable periods for 2011: January 1, 2011, to November 30, 2011 and December 1, 2011, to December 31, 2011. We will be required to file two tax returns and, unless relief is granted by the IRS, issue two Schedules K-1 to each unitholder. See Note 12 to the consolidated financial statements in this report for further details about this technical termination that occurred in 2011.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
The Fiscal Year 2013 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress which would implement many of these proposals. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and
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development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our Common Units.
You may be subject to state and local taxes and return filing requirements.
In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not reside in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We currently conduct business and own property in California, Florida, Indiana, Kentucky, Michigan, and Wyoming. Each of these states other than Wyoming and Florida currently imposes a personal income tax on individuals, and all of these states impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. Some of the states may require us, or we may elect to withhold a percentage of income from amounts to be distributed to a common unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular common unitholder's income tax liability to the state, generally does not relieve a nonresident common unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to common unitholders for purposes of determining the amounts distributed by us. It is the responsibility of each unitholder to file all U.S. federal, state and local returns that may be required of such unitholder.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
The information required to be disclosed in this Item 2 is incorporated herein by reference to Part I—Item 1 "—Business."
Item 3. 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 pending legal proceedings or know of any such procedures contemplated by government authorities. 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 statues to which we are subject.
Item 4. Mine Safety Disclosures.
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
Our Common Units trade on the NASDAQ Global Select Market under the symbol "BBEP." As of December 31, 2011, based upon information received from our transfer agent and brokers and nominees, we had approximately 40,000 common unitholders of record.
The following table sets forth high and low sales prices per Common Unit and cash distributions to common unitholders for the periods indicated. The last reported sales price for our Common Units on the NASDAQ on February 28, 2012 was $19.24 per unit.
Price Range | Cash Distribution | Date | ||||||||||||
Period | High | Low | Per Common Unit | Paid | ||||||||||
First Quarter, 2010 | $ | 15.98 | $ | 10.80 | $ | 0.3750 | 5/14/2010 | |||||||
Second Quarter, 2010 | 15.94 | 13.12 | 0.3825 | 8/13/2010 | ||||||||||
Third Quarter, 2010 | 18.31 | 14.25 | 0.3900 | 11/12/2010 | ||||||||||
Fourth Quarter, 2010 | 20.89 | 18.20 | 0.4125 | 2/11/2011 | ||||||||||
First Quarter, 2011 | 23.14 | 19.50 | 0.4175 | 5/13/2011 | ||||||||||
Second Quarter, 2011 | 22.69 | 19.01 | 0.4225 | 8/12/2011 | ||||||||||
Third Quarter, 2011 | 20.00 | 15.00 | 0.4350 | 11/14/2011 | ||||||||||
Fourth Quarter, 2011 | 19.17 | 15.75 | 0.4500 | 2/14/2012 |
We intend to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our credit agreement restricts us from making cash distributions unless, after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility. See Item 7 "—Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility" and Note 10 to the consolidated financial statements in this report.
For the quarters for which we declare a distribution, distributions of available cash are made within 45 days after the end of the quarter to unitholders of record on the applicable record date. Available cash, as defined in our partnership agreement, generally is all cash on hand, including cash from borrowings, at the end of the quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs.
Equity Compensation Plan Information
See Part III—Item 12 "—Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters" for information regarding securities authorized for issuance under equity compensation plans.
Unregistered Sales of Equity Securities and Use of Proceeds
There were no unregistered sales of equity securities during the fourth quarter of 2011.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
There were no purchases of our Common Units by us or any affiliated purchasers during the fourth quarter of 2011.
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Common Unit Performance Graph
The graph below compares our cumulative total unitholder return on our Common Units over the past five years, with the cumulative total returns over the same period of the Russell 2000 index and the Alerian MLP index. The graph assumes that the value of the investment in our Common Units, in the Russell 2000 index, and in the Alerian MLP index was $100 on December 31, 2006. Cumulative return is computed assuming reinvestment of dividends.
Comparison of Cumulative Total Return among the Partnership, the Russell 2000 Index and the Alerian MLP Index
The information in this report appearing under the heading "Common Unit Performance Graph" is being furnished pursuant to Item 2.01(e) of Regulation S-K and shall not be deemed to be "soliciting material" or to be "filed" with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.
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Item 6. Selected Financial Data.
Set forth below is selected historical consolidated financial data for the past five years.
The selected consolidated financial data presented is derived from our audited financial statements. In 2007, we completed seven acquisitions totaling approximately $1.7 billion, the largest of which was the Quicksilver Acquisition for approximately $1.46 billion. In 2008, we acquired Provident’s interest in BreitBurn Management, BreitBurn Corporation contributed its interest in BreitBurn Management to us, and BreitBurn Management contributed its interest in the General Partner to us, resulting in BreitBurn Management and the General Partner becoming our wholly owned subsidiaries. In 2009, we completed the sale of the Lazy JL field for $23 million in cash. In 2011, we completed the Greasewood Acquisition on July 28, 2011, with an effective date of July 1, 2011, for approximately $57 million and the Cabot Acquisition on October 6, 2011 with an effective date of September 1, 2011, for approximately $281 million.
You should read the following selected financial data in conjunction with Part II—Item 7 "—Management’s Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and related notes appearing elsewhere in this report.
The selected financial data table presents a non-GAAP financial measure, "Adjusted EBITDA," which we use in our business. This measure is not calculated or presented in accordance with generally accepted accounting principles ("GAAP"). We reconcile this measure to the most directly comparable financial measure calculated and presented in accordance with GAAP.
We believe the presentation of Adjusted EBITDA provides useful information to investors to evaluate the operations of our business excluding certain items and for the reasons set forth below. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.
We use Adjusted EBITDA to assess:
• | the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
• | our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; |
• | the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities; and |
• | the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness. |
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Selected Financial Data
Year Ended December 31, | ||||||||||||||||||||
Thousands of dollars, except per unit amounts | 2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||
Oil, natural gas and natural gas liquid sales | $ | 394,393 | $ | 317,738 | $ | 254,917 | $ | 467,381 | $ | 184,372 | ||||||||||
Gain (loss) on commodity derivative instruments net | 81,667 | 35,112 | (51,437 | ) | 332,102 | (110,418 | ) | |||||||||||||
Other revenue, net | 4,310 | 2,498 | 1,382 | 2,920 | 1,037 | |||||||||||||||
Total revenue | 480,370 | 355,348 | 204,862 | 802,403 | 74,991 | |||||||||||||||
Operating income (loss) | 153,809 | 63,743 | (82,811 | ) | 429,354 | (55,348 | ) | |||||||||||||
Net income (loss) | 110,698 | 34,913 | (107,257 | ) | 378,424 | (60,266 | ) | |||||||||||||
Less: Net income attributable to noncontrolling interest | (201 | ) | (162 | ) | (33 | ) | (188 | ) | (91 | ) | ||||||||||
Net income (loss) attributable to the partnership | $ | 110,497 | $ | 34,751 | $ | (107,290 | ) | $ | 378,236 | $ | (60,357 | ) | ||||||||
Basic net income (loss) per unit | $ | 1.80 | $ | 0.61 | $ | (2.03 | ) | $ | 6.29 | $ | (1.83 | ) | ||||||||
Diluted net income (loss) per unit | $ | 1.79 | $ | 0.61 | $ | (2.03 | ) | $ | 6.28 | $ | (1.83 | ) | ||||||||
Cash Flow Data: | ||||||||||||||||||||
Net cash provided by operating activities | $ | 128,543 | $ | 182,022 | $ | 224,358 | $ | 226,696 | $ | 60,102 | ||||||||||
Net cash used in investing activities | (414,573 | ) | (68,286 | ) | (6,229 | ) | (141,039 | ) | (1,020,110 | ) | ||||||||||
Net cash provided by (used in) financing activities | 287,728 | (115,872 | ) | (214,909 | ) | (89,040 | ) | 965,844 | ||||||||||||
Balance Sheet Data (at period end): | ||||||||||||||||||||
Cash | $ | 5,328 | $ | 3,630 | $ | 5,766 | $ | 2,546 | $ | 5,929 | ||||||||||
Other current assets | 167,492 | 121,674 | 136,675 | 138,020 | 91,834 | |||||||||||||||
Net property, plant and equipment | 2,072,759 | 1,722,295 | 1,741,089 | 1,840,341 | 1,864,487 | |||||||||||||||
Other assets | 85,270 | 82,568 | 87,499 | 235,927 | 24,306 | |||||||||||||||
Total assets | $ | 2,330,849 | $ | 1,930,167 | $ | 1,971,029 | $ | 2,216,834 | $ | 1,986,556 | ||||||||||
Current liabilities | 89,889 | 101,317 | 91,890 | 79,990 | 90,684 | |||||||||||||||
Long-term debt | 820,613 | 528,116 | 559,000 | 736,000 | 370,400 | |||||||||||||||
Other long-term liabilities | 93,133 | 91,477 | 91,338 | 47,413 | 100,120 | |||||||||||||||
Partners' equity | 1,326,764 | 1,208,803 | 1,228,373 | 1,352,892 | 1,424,808 | |||||||||||||||
Noncontrolling interest | 450 | 454 | 428 | 539 | 544 | |||||||||||||||
Total liabilities and partners' equity | $ | 2,330,849 | $ | 1,930,167 | $ | 1,971,029 | $ | 2,216,834 | $ | 1,986,556 | ||||||||||
Cash dividends declared per unit outstanding: | $ | 1.6875 | $ | 1.1475 | $ | 0.5200 | $ | 1.9925 | $ | 1.6765 |
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The following table presents a reconciliation of Adjusted EBITDA to net income (loss) attributable to the partnership, our most directly comparable GAAP financial performance measure, for each of the periods indicated.
Year Ended December 31, | ||||||||||||||||||||
Thousands of dollars | 2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||
Reconciliation of consolidated net income (loss) to Adjusted EBITDA: | ||||||||||||||||||||
Net income (loss) attributable to the partnership | $ | 110,497 | $ | 34,751 | $ | (107,290 | ) | $ | 378,236 | $ | (60,357 | ) | ||||||||
Unrealized (gain) loss on commodity derivative instruments | (97,734 | ) | 39,713 | 219,120 | (388,048 | ) | 103,862 | |||||||||||||
Depletion, depreciation and amortization expense (a) | 107,503 | 102,758 | 106,843 | 179,933 | 29,422 | |||||||||||||||
Write-down of crude oil inventory | — | — | — | 1,172 | — | |||||||||||||||
Interest expense and other financing costs | 42,422 | 35,639 | 31,942 | 31,868 | 6,258 | |||||||||||||||
Unrealized (gain) loss on interest rate derivatives | (480 | ) | (6,597 | ) | (5,869 | ) | 17,314 | — | ||||||||||||
(Gain) loss on sale of commodity derivative instruments | 36,779 | — | (70,587 | ) | — | — | ||||||||||||||
(Gain) loss on sale of assets | (111 | ) | 14 | 5,965 | — | — | ||||||||||||||
Income tax expense (benefit) | 1,188 | (204 | ) | (1,528 | ) | 1,939 | (1,229 | ) | ||||||||||||
Amortization of intangibles | — | 495 | 2,771 | 3,131 | 2,174 | |||||||||||||||
Non-cash unit based compensation | 22,002 | 20,331 | 13,619 | 7,481 | 5,133 | |||||||||||||||
Net operating cash flow from acquisitions, effective date through closing date | 2,886 | — | — | — | — | |||||||||||||||
Adjusted EBITDA | $ | 224,952 | $ | 226,900 | $ | 194,986 | $ | 233,026 | $ | 85,263 | ||||||||||
(a) 2011 includes impairments of $0.6 million related to Michigan properties. 2010 includes impairments of $6.3 million related to Eastern region properties. 2008 includes impairments and price related depletion, depreciation and amortization expense adjustments of $86.4 million. |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in conjunction with the "Selected Financial Data" and the financial statements and related notes included elsewhere in this report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are discussed in "Risk Factors" contained in Part I—Item 1A of this report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See "Cautionary Statement Regarding Forward-Looking Information" in the front of this report.
Executive Overview
We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States. Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders. Our assets consist primarily of producing and non-producing crude oil and natural gas reserves located primarily in the Antrim Shale and other non-Antrim formations in Michigan, the Evanston and Green River Basins in southwestern Wyoming, the Wind River and Big Horn Basins in central Wyoming, the Powder River Basin in eastern Wyoming, the Los Angeles Basin in California, 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 and interest rate derivatives; and |
• | Maximize asset value and cash flow stability through operating and technical expertise. |
Acquisitions
On July 28, 2011, we completed the Greasewood Acquisition to acquire crude oil properties in Niobrara County, Wyoming with a July 1, 2011 effective date. The purchase price for the acquisition was approximately $57 million in cash. The properties produced approximately 605 Bbl/d of crude oil in the fourth quarter of 2011.
On October 6, 2011, we completed the Cabot Acquisition to acquire oil and gas properties located primarily in the Evanston and Green River Basins in southwestern Wyoming with a September 1, 2011 effective date for approximately $281 million in cash, subject to ordinary adjustments. The Cabot Assets also include limited acreage and non-operated oil and gas interests in Colorado and Utah. The properties produced approximately 25.7 MMcfe/d in the fourth quarter of 2011 and are 95% natural gas.
We used borrowings under our credit facility to fund both the Greasewood and Cabot Acquisitions.
Highlights
On February 11, 2011, we sold approximately 4.9 million Common Units at a price to the public of $21.25, resulting in proceeds net of underwriting discount and expenses of $100 million, which we used to repay outstanding debt under our credit facility.
On February 11, 2011, we paid a cash distribution to unitholders for the fourth quarter of 2010 at the rate of $0.4125 per Common Unit. On May 13, 2011, we paid a cash distribution to unitholders for the first quarter of 2011 at the rate of $0.4175 per Common Unit. On August 12, 2011, we paid a cash distribution to unitholders for the second quarter of 2011 at the rate of $0.4225 per Common Unit. On November 14, 2011, we paid a cash distribution to unitholders for the third quarter of 2011 at the rate of $0.4350 per Common Unit. On February 14, 2012, we paid a cash distribution to unitholders for the fourth quarter of 2011 at the rate of $0.4500 per Common Unit.
In 2011, our oil and natural gas capital expenditures totaled approximately $75 million, compared with approximately $70 million in 2010. We spent approximately $34 million in Florida, $22 million in Michigan, Indiana and Kentucky, $10 million in Wyoming and $9 million in California. We drilled and completed 20 new wells, 38 recompletions and two workovers in Michigan. We drilled and completed nine new wells and four well optimization projects in Wyoming. We drilled and completed
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six new wells and seven well optimization projects in California and Florida. Primarily as a result of our 2011 acquisitions and our capital spending, our 2011 production was 7,037 MMBoe, which was 5% higher than 2010.
During 2011, Quicksilver sold 15.7 million of our Common Units, representing its total ownership in the Partnership. As a result of Quicksilver selling 15.7 million of our Common Units together with normal trading activity by other unitholders, greater than 50% of our Common Units traded within a twelve month period and caused a technical termination of the Partnership for federal income tax purposes. This technical termination required the closing of our taxable year for all unitholders on November 30, 2011, and brought about two taxable periods for 2011: January 1, 2011 to November 30, 2011 and December 1, 2011 to December 31, 2011. We will be required to file two tax returns and, unless relief is granted by the IRS, issue two Schedules K-1 to each unitholder. See Note 12 to the consolidated financial statements in this report for further details about this technical termination that occurred in 2011.
In January 2012, we and BreitBurn Finance Corporation, and certain of our subsidiaries, as guarantors, issued $250 million in aggregate principal amount of 7.875% senior notes due 2022 at a price of 99.154%. We received net proceeds of approximately $242.3 million and used the proceeds to repay amounts outstanding under our credit facility.
In February 2012, we sold approximately 9.2 million Common Units at a price to the public of $18.80, resulting in proceeds net of underwriting discounts and estimated offering expenses of $165.9 million, which we used to repay outstanding debt under our credit facility.
Outlook
In 2012, our crude oil and natural gas capital spending program, excluding acquisitions, is expected to be approximately $68 million, compared with approximately $75 million in 2011. We anticipate spending approximately 60% principally on oil projects in California and Florida and approximately 40% principally on oil projects in Michigan, Wyoming, Indiana and Kentucky. We anticipate 77% of our total capital spending will be focused on drilling and rate generating projects that are designed to increase or add to production or reserves. Without considering potential acquisitions, we expect our 2012 production to be approximately 8.1 MMBoe. Based on the continuing decline of natural gas prices, we will continue to evaluate our capital spending program throughout 2012.
Commodity hedging remains an important part of our strategy to reduce cash flow volatility. We use swaps, collars and options for managing risk relating to commodity prices. As of February 28, 2012, we had approximately 75% of our expected 2012 production hedged. For 2012, we had 7,516 Bbl/d of oil and 54,257 MMBtu/d of natural gas hedged at average prices of approximately $101.00 and $7.12, respectively. For 2013, we had 6,980 Bbl/d of oil and 56,000 MMBtu/d of natural gas hedged at average prices of approximately $92.05 and $5.96 respectively. For 2014, we had 6,000 Bbl/d of oil and 30,500 MMBtu/d of natural gas hedged at average prices of approximately $93.58 and $5.43, respectively. For 2015, we had 5,000 Bbl/d of oil and 30,500 MMBtu/d of natural gas hedged at average prices of approximately $96.41 and $5.55, respectively.
Consistent with our long-term business strategy, we intend to continue to actively pursue oil and natural gas acquisition opportunities in 2012.
Operational Focus
We use a variety of financial and operational measures to assess our performance. Among these measures are the following: volumes of oil and natural gas produced; reserve replacement; realized prices and operating and general and administrative expenses.
As of December 31, 2011, our total estimated proved reserves were 151.1 MMBoe, of which approximately 65% was natural gas and 35% was crude oil. As of December 31, 2010, our total estimated proved reserves were 118.9 MMBoe, of which approximately 65% was natural gas and 35% was crude oil.
We had estimated reserves revisions and purchase additions of 39.2 MMBoe in 2011, which were partially offset by 7.0 MMBoe of production. The increase in 2011 was primarily the result of 32.2 MMBoe of reserve acquisitions. Additionally, drilling, recompletions, workovers, addition of new drilling locations, economic factors and revised estimates of existing reserves contributed to the increase. The primary economic factor for the increase in estimated proved reserves relating to our oil producing properties was an increase in oil prices. The unweighted average first-day-of-the-month crude oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2011 were $95.97 per Bbl of oil for Michigan, California and Florida, $76.79 per Bbl of oil for Wyoming and $4.12 per MMBtu of gas, compared to $79.40 per Bbl of oil for Michigan, California and Florida, $65.36 per Bbl of oil for Wyoming and $4.38 per MMBtu of gas in 2010. The unweighted
46
average first-day-of-the-month crude oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2009 were $61.18 per Bbl of oil for Michigan, California and Florida, $51.29 per Bbl of oil for Wyoming and $3.87 per MMBtu of gas.
Of our total estimated proved reserves as of December 31, 2011, 49% were located in Michigan, 29% in Wyoming, 14% in California and 7% in Florida, with the remaining 1% in Indiana and Kentucky. On a net production basis, we operate approximately 87% of our production.
Our revenues and net income are sensitive to oil and natural gas prices. Our operating expenses are highly correlated to oil prices, and as oil prices rise and fall, our operating expenses will directionally rise and fall. Significant factors that will impact near-term commodity prices include global demand for oil and natural gas, political developments in oil producing countries, including, without limitation, the extent to which members of the OPEC and other oil exporting nations are able to manage oil supply through export quotas and variations in key North American natural gas and refined products supply and demand indicators.
In 2011, the NYMEX WTI spot price averaged approximately $95 per barrel, compared with approximately $79 per barrel a year earlier. In 2011, crude oil prices ranged from a monthly average low of $86 per barrel for September to a monthly average high of $110 per barrel for April. In 2010, prices ranged from a monthly average low of $74 per barrel for May to a monthly average high of $89 per barrel for December.
Prices for natural gas have historically fluctuated widely and in many markets are aligned both with supply and demand conditions in their respective regional markets and with the overall U.S. market. U.S. natural gas prices are also typically higher during the winter period when demand for heating is greatest. Since January 2009, monthly average natural gas spot prices at Henry Hub ranged from a low of $2.99 per MMBtu for September 2009 to a high of $5.83 per MMBtu for January 2010. During 2011, the natural gas spot price at Henry Hub ranged from a low of $2.84 per MMBtu to a high of $4.92 per MMBtu, with the monthly average ranging from a low of $3.17 per MMBtu for December to a high of $4.54 per MMBtu for June, and averaged approximately $4.00 per MMBtu for the year. During 2010, the natural gas spot price at Henry Hub ranged from a low of $3.18 per MMBtu to a high of $7.51 per MMBtu, and averaged approximately $4.37 per MMBtu. In January 2012, The natural gas spot price at Henry Hub averaged $2.67 per MMBtu in January 2012 and $2.48 per MMBtu for the first three weeks of February 2012.
Excluding the effect of derivatives, our realized average oil and NGL price for 2011 increased $19.21 per Boe to $89.92 per Boe as compared to $70.71 per Boe in 2010. Including the effects of derivative instruments but excluding the effects of hedge terminations, our realized average oil and NGL price increased $5.49 per Boe to $79.80 per Boe as compared to $74.31 per Boe in 2010, primarily due to the increase in crude oil prices. Our realized natural gas price for 2011 decreased $0.39 per Mcf to $4.18 per Mcf as compared to $4.57 per Mcf in 2010. Including the effects of derivative instruments, our realized natural gas price decreased $0.99 per Mcf to $6.58 per Mcf compared to $7.57 per Mcf in 2010, primarily due to the decrease in natural gas prices.
While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected.
In evaluating our production operations, we frequently monitor and assess our operating and general and administrative expenses per Boe produced. These measures allow us to better evaluate our operating efficiency and are used in reviewing the economic feasibility of a potential acquisition or development project.
Operating expenses are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses. A majority of our operating cost components are variable and increase or decrease along with our levels of production. For example, we incur power costs in connection with various production related activities such as pumping to recover oil and gas, separation and treatment of water produced in connection with our oil and gas production, and re-injection of water produced into the oil producing formation to maintain reservoir pressure. Although these costs typically vary with production volumes, they are driven not only by volumes of oil and gas produced but also volumes of water produced. Consequently, fields that have a high percentage of water production relative to oil and gas production, also known as a high water cut, will experience higher levels of power costs for each Boe produced. Certain items, however, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased expenses in periods during which they are performed. Our operating expenses are highly correlated to oil prices and
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we experience upward or downward pressure on material and service costs depending on how oil prices change. These costs include specific expenditures such as lease fuel, electricity, drilling services and severance and property taxes. Lease operating expenses, including processing fees, were $18.64 per Boe in 2011 and $17.68 per Boe in 2010. The increase in per Boe lease operating expenses was primarily due to an increase in crude oil prices, higher Florida production costs related to new wells as well as higher well services, compression repairs and maintenance.
Production taxes vary by state. All states in which we operate impose ad valorem taxes on our oil and gas properties. Various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Currently, Wyoming, Michigan, Indiana, Kentucky and Florida impose severance taxes on oil and gas producers at rates ranging from 1% to 8% of the value of the gross product extracted. Wyoming wells that reside on Indian or federal land are subject to an additional tax of 8.5%. California does not currently impose a severance tax; rather it imposes an ad valorem tax based in large part on the value of the mineral interests in place. See Part I—Item 1A "—Risk Factors" — "Risks Related to Our Business — We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations" in this report.
General and administrative expenses ("G&A"), excluding unit based compensation, were $4.45 per Boe in 2011 and $3.65 per Boe in 2010. The increase in per Boe G&A, excluding unit based compensation, was primarily due to acquisition and integration related costs and an increase in employee related expenses due to new hires.
BreitBurn Management
BreitBurn Management 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 operates the assets of PCEC, our Predecessor. In 2008, BreitBurn Management entered into a five year Administrative Services Agreement to manage our Predecessor's properties. In 2008, we also entered into an Omnibus Agreement with our Predecessor detailing rights with respect to business opportunities and providing us with a right of first offer with respect to the sale of PCEC assets.
In addition to a monthly fee for indirect expenses, BreitBurn Management charges PCEC for all direct expenses including incentive plan costs and direct payroll and administrative costs related to PCEC properties and operations. The monthly fee for indirect expenses is contractually based on an annual projection of anticipated time spent by each employee who provides services to both us and PCEC during the ensuing year and is subject to renegotiation annually by the parties during the term of the agreement. See Note 6 to the consolidated financial statements in this report for a discussion of the process for determining the monthly fee.
The monthly fee in effect for 2011, 2010 and 2009 was determined to be $481,000, $456,000 and $500,000, respectively. In 2012, we expect the monthly fee for indirect costs to be approximately $571,000. The increase in the monthly fee for indirect expenses in 2012 primarily reflects additional anticipated services related to PCEC oil field development programs.
On January 6, 2012, Pacific Coast Oil Trust (the "Trust"), which was formed by PCEC, filed a registration statement on Form S-1 with the SEC in connection with an initial public offering (the "Trust Offering") by the Trust. Immediately prior to the closing of the Trust Offering, PCEC intends to convey net profits interests in its oil and natural gas production from certain of its properties to the Trust in exchange for Trust units. PCEC's assets consist primarily of producing and non-producing crude oil reserves located in Santa Barbara, Los Angeles and Orange Counties in California, including certain interests in the East Coyote and Sawtelle Fields. PCEC operates the Sawtelle and East Coyote Fields for the benefit of itself and the Partnership. The Partnership currently owns the non-operated interests in the East Coyote and Sawtelle Fields and pays an operating fee to PCEC. The annual operating fee in 2011 was $0.9 million. PCEC currently holds an average working interest of approximately 5.0% in the East Coyote and Sawtelle Fields. PCEC holds a reversionary interest in both of these fields, and its average working interest will increase to approximately 37.6% once certain payment milestones are achieved, which is currently expected to occur in the second quarter of 2012. The Partnership has no direct or indirect ownership interest in PCEC or the Trust.
The expected 2012 monthly fee charged by BMC to PCEC for indirect costs of $571,000 could change in connection with the Trust Offering. For more information on potential conflicts between us and PCEC, see Part I—Item 1A "—Risk Factors"— "Risks Related to Our Structure — Certain of the directors and officers of our General Partner, including our Chief Executive Officer, our President and other members of our senior management, own interests in PCEC, which is managed by our subsidiary, BreitBurn Management. Conflicts of interest may arise between PCEC, on the one hand, and us and our unitholders, on the other hand. Our partnership agreement limits the remedies available to you in the event you have a claim relating to
48
conflicts of interest."
See Note 6 to the consolidated financial statements in this report for more information regarding our relationship with BreitBurn Management and PCEC.
Results of Operations
The table below summarizes certain of the results of operations and period-to-period comparisons attributable to our operations for the periods indicated. These results are presented for illustrative purposes only and are not indicative of our future results. The data reflect our results as they are presented in our consolidated financial statements.
Year Ended December 31, | Increase / decrease % | |||||||||||||||||
Thousands of dollars, except as indicated | 2011 | 2010 | 2009 | 2011-2010 | 2010-2009 | |||||||||||||
Total production (MBoe) (a) | 7,037 | 6,699 | 6,517 | 5 | % | 3 | % | |||||||||||
Oil and NGL (MBoe) | 3,255 | 3,157 | 2,990 | 3 | % | 6 | % | |||||||||||
Natural gas (MMcf) | 22,697 | 21,251 | 21,161 | 7 | % | — | % | |||||||||||
Average daily production (Boe/d) | 19,281 | 18,354 | 17,856 | 5 | % | 3 | % | |||||||||||
Sales volumes (MBoe) | 7,106 | 6,663 | 6,465 | 7 | % | 3 | % | |||||||||||
Average realized sales price (per Boe) (b) (c) | ||||||||||||||||||
Including realized gain (loss) on derivative instruments | $ | 58.33 | $ | 58.94 | $ | 54.60 | (1 | )% | 8 | % | ||||||||
Oil and NGL (per Boe) (b) (c) | 79.80 | 74.31 | 66.27 | 7 | % | 12 | % | |||||||||||
Natural gas (per Mcf) (b) | 6.58 | 7.57 | 7.48 | (13 | )% | 1 | % | |||||||||||
Excluding realized gain (loss) on derivative instruments (c) | $ | 55.41 | $ | 47.71 | $ | 39.58 | 16 | % | 21 | % | ||||||||
Oil and NGL (per Boe) (c) | 89.92 | 70.71 | 56.80 | 27 | % | 24 | % | |||||||||||
Natural gas (per Mcf) | 4.18 | 4.57 | 4.21 | (9 | )% | 9 | % | |||||||||||
Oil, natural gas and NGL sales (d) | $ | 394,393 | $ | 317,738 | $ | 254,917 | 24 | % | 25 | % | ||||||||
Realized gain (loss) on derivative instruments (e) | (16,067 | ) | 74,825 | 167,683 | (121 | )% | (55 | )% | ||||||||||
Unrealized gain (loss) on derivative instruments (e) | 97,734 | (39,713 | ) | (219,120 | ) | n/a | n/a | |||||||||||
Other revenues, net | 4,310 | 2,498 | 1,382 | 73 | % | 81 | % | |||||||||||
Total revenues | $ | 480,370 | $ | 355,348 | $ | 204,862 | 35 | % | 73 | % | ||||||||
Lease operating expenses including processing fees | $ | 131,188 | $ | 118,454 | $ | 118,405 | 11 | % | — | % | ||||||||
Production and property taxes (f) | 26,599 | 20,510 | 19,433 | 30 | % | 6 | % | |||||||||||
Total lease operating expenses | $ | 157,787 | $ | 138,964 | $ | 137,838 | 14 | % | 1 | % | ||||||||
Transportation expenses | 5,253 | 4,058 | 3,825 | 29 | % | 6 | % | |||||||||||
Purchases and other operating costs | 961 | 328 | 172 | 193 | % | 91 | % | |||||||||||
Change in inventory | 1,968 | (825 | ) | (3,337 | ) | n/a | n/a | |||||||||||
Total operating costs | $ | 165,969 | $ | 142,525 | $ | 138,498 | 16 | % | 3 | % | ||||||||
Lease operating expenses pre-taxes per Boe (g) | $ | 18.64 | $ | 17.68 | $ | 17.90 | 5 | % | (1 | )% | ||||||||
Production and property taxes per Boe | 3.78 | 3.06 | 2.98 | 23 | % | 3 | % | |||||||||||
Total lease operating expenses per Boe | 22.42 | 20.74 | 20.88 | 8 | % | (1 | )% | |||||||||||
Depletion, depreciation and amortization (DD&A) | $ | 107,503 | $ | 102,758 | $ | 106,843 | 5 | % | (4 | )% | ||||||||
(a) Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a Bbl of oil equivalent for natural gas is significantly less than the price for a Bbl of oil. | ||||||||||||||||||
(b) Excludes the effect of the early termination of commodity derivative contracts terminated in 2011 for a cost of $36,779 and commodity derivative contracts monetized in 2009 for a gain of $70,587. | ||||||||||||||||||
(c) 2010 and 2009 exclude the per Boe price effect of amortization of an intangible asset related to crude oil sales contracts. Includes the per Boe price effect of crude oil purchases. | ||||||||||||||||||
(d) 2010 and 2009 include $495 and $1,040, respectively, of amortization of an intangible asset related to crude oil sales contracts. | ||||||||||||||||||
(e) Includes the effects of the early termination of commodity derivative contracts terminated in 2011 for a cost of $36,779 and commodity derivative contracts monetized in 2009 for a gain of $70,587. | ||||||||||||||||||
(f) Includes ad valorem and severance taxes. | ||||||||||||||||||
(g) Includes lease operating expenses, district expenses and processing fees. 2009 excludes amortization of intangible asset related to the Quicksilver Acquisition. |
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Comparison of Results of Operations for the Years Ended December 31, 2011, 2010 and 2009
The variances in our results of operations were due to the following components:
Production
For the year ended December 31, 2011 compared to the year ended December 31, 2010, production volumes increased by 338 MBoe, or 5%, primarily due to 368 MBoe from our southwestern Wyoming properties acquired on October 6, 2011, 88 MBoe from our eastern Wyoming properties acquired on July 28, 2011 and 41 MBoe higher Florida production from new wells partially offset by 129 MBoe lower Michigan natural gas production due to natural field declines. In 2011, natural gas, crude oil and natural gas liquids accounted for 54%, 44% and 2% of our production, respectively.
For the year ended December 31, 2010 compared to the year ended December 31, 2009, production volumes increased by 182 MBoe, or 3%, primarily due to 118 MBoe higher Florida production from the new Raccoon Point well, 100 MBoe higher Eastern region production from the capital work program and 13 MBoe higher California crude oil production, partially offset by the sale of the Lazy JL Field effective July 1, 2009, which produced 44 MBoe in 2009. In 2010, natural gas, crude oil and natural gas liquids accounted for 53%, 45% and 2% of our production, respectively.
Revenues
Total revenues increased by $125.0 million for the year ended December 31, 2011 compared to the year ended December 31, 2010. Realized losses from commodity derivative instruments were $16.1 million in 2011 compared to realized gains of $74.8 million in 2010. Unrealized gains from commodity derivative instruments for the year ended December 31, 2011 were $97.7 million primarily reflecting a decrease in crude oil and natural gas futures prices during 2011. The effect of $36.8 million net loss on hedge contracts terminated in the fourth quarter of 2011 is reflected in realized and unrealized gains and losses on commodity derivative instruments for the year ended December 31, 2011. Unrealized losses from commodity derivative instruments for the year ended December 31, 2010 were $39.7 million primarily reflecting an increase in crude oil futures prices partially offset by a decrease in natural gas futures prices during 2010. For 2011 compared to 2010, higher commodity prices increased total sales revenues by approximately $56 million and higher sales volumes increased total sales revenues by approximately $21 million.
Total revenues increased by $150.5 million for the year ended December 31, 2010 compared to the year ended December 31, 2009. Realized gains from commodity derivative instruments were $74.8 million in 2010 compared to realized gains of $167.7 million in 2009. Unrealized losses from commodity derivative instruments for the year ended December 31, 2010 were $39.7 million reflecting an increase in crude oil futures prices partially offset by a decrease in natural gas futures prices during 2010. Unrealized losses from commodity derivative instruments for the year ended December 31, 2009 were $219.1 million reflecting the increase in both crude oil and natural gas futures prices during 2009. The effect of net proceeds of $45.6 million in hedge contracts monetized in January 2009 and $25.0 million in June 2009 are reflected in realized and unrealized gains and losses on commodity derivative instruments for the year ended December 31, 2009. For 2010 compared to 2009, higher commodity prices increased total sales revenues by approximately $55.0 million and higher sales volumes increased total sales revenues by approximately $7.8 million.
Lease operating expenses
Pre-tax lease operating expenses, including processing fees, for the year ended December 31, 2011 totaled $131.2 million or $18.64 per Boe, which was 5% higher per Boe than 2010. The increase was primarily attributable to an increase in crude oil prices, higher Florida production costs related to new wells as well as higher well services, compression repairs and maintenance. For the year ended December 31, 2011, $13.6 million or $1.93 per Boe of regional management costs were included in lease operating expenses compared to $12.9 million or $1.93 per Boe for the year ended December 31, 2010. The increase in regional management costs was primarily due to an increase in our short-term incentive compensation expense.
Production and property taxes for the year ended December 31, 2011 totaled $26.6 million, or $3.78 per Boe, which was 23% higher per Boe than the year ended December 31, 2010. The per Boe increase in production and property taxes compared to 2010 was primarily due to higher commodity prices in 2011.
Pre-tax lease operating expenses, including processing fees, for the year ended December 31, 2010 totaled $118.5 million or $17.68 per Boe, which was 1% lower per Boe than 2009. The decrease was primarily due to higher production volumes during 2010 compared to 2009. For the year ended December 31, 2010, $12.9 million or $1.93 per Boe of regional management costs were included in lease operating expenses compared to $10.9 million or $1.68 per Boe for the year ended
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December 31, 2009. The increase in regional management costs was primarily due to an increase in our short-term incentive compensation expense.
Production and property taxes for the year ended December 2010 totaled $20.5 million, or $3.06 per Boe, which was 3% higher per Boe than the year ended December 31, 2009. The per Boe increase in production and property taxes compared to 2009 was primarily due to higher commodity prices in 2010.
Transportation expenses
In Florida, our crude oil is transported from the field by trucks and pipelines and then transported by barge to the sales point. Transportation costs incurred in connection with such operations are reflected in operating costs on the consolidated statements of operations. Transportation expenses for the years ended December 31, 2011 and 2010 were $5.3 million and $4.1 million, respectively. The increase in transportation expenses was primarily due to higher Florida sales volumes in 2011 as compared to 2010.
Transportation expenses for the years ended December 31, 2010 and 2009 were $4.1 million and $3.8 million, respectively. The increase in transportation expenses was primarily due to higher Florida sales volumes in 2010 as compared to 2009.
Change in inventory
In Florida, our crude oil sales are a function of the number and size of crude oil shipments in each year and thus crude oil sales do not always coincide with volumes produced in a given year. 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. In 2011 the change in inventory account amounted to a charge of $2.0 million reflecting the higher amount of barrels sold than produced during the year, compared to credits of $0.8 million in 2010 and $3.3 million in 2009, reflecting the higher amount of barrels produced than sold during the periods.
Depletion, depreciation and amortization
Depletion, depreciation and amortization ("DD&A") expense totaled $107.5 million, or $15.28 per Boe, for the year ended December 31, 2011, which was in line with DD&A of $15.34 per Boe for the year ended December 31, 2010. Included in DD&A for the year ended December 31, 2011 are $0.6 million in impairments related to uneconomic proved properties in Michigan. Included in DD&A for the year ended December 31, 2010 are $6.3 million in impairments related to our Eastern region properties, including a $4.2 million write-down of uneconomic proved properties and a $2.1 million write-down of expired unproved lease properties. Excluding the impact of impairments, DD&A per Boe for 2011 and 2010 was $15.18 and $14.40, respectively. The increase in DD&A excluding impairments was primarily due to higher DD&A rates reflecting lower natural gas reserves as a result of a decrease in natural gas prices, and investment additions related to new wells in Florida.
DD&A expense totaled $102.8 million, or $15.34 per Boe, for the year ended December 31, 2010, a decrease of approximately 6% per Boe from the year ended December 31, 2009. The decrease in DD&A compared to 2009 was primarily due to the effect that higher 2010 commodity prices had on DD&A rates. Included in DD&A for the year ended December 31, 2010 are impairments of approximately $6.3 million related to our Eastern region properties, including a $4.2 million write-down of uneconomic proved properties and a $2.1 million write-down of expired unproved lease properties. Excluding the impact of the impairments for 2010, DD&A per Boe for 2010 was $14.40 or 12% lower than 2009.
General and administrative expenses
Our general and administrative ("G&A") expenses totaled $53.3 million and $44.9 million in 2011 and 2010, respectively. This included $22.0 million and $20.4 million, respectively, in unit-based compensation expense related to employee incentive plans. The increase in non-cash unit-based compensation expense was primarily due to new equity awards granted in the first quarter of 2011. For 2011, G&A expenses, excluding unit-based compensation, were $31.3 million, which was $6.8 million higher than 2010. The increase was primarily due to acquisition and integration costs related to the Cabot and Greasewood Acquisitions, higher employee related costs and higher short-term incentive compensation expense.
G&A expenses totaled $44.9 million and $36.4 million in 2010 and 2009, respectively. This included $20.4 million and $12.7 million, respectively, in unit-based compensation expense related to employee incentive plans. The increase in non-cash unit-based compensation expense was primarily due to new equity awards granted in the first quarter of 2010. For 2010, G&A expenses, excluding unit-based compensation, were $24.5 million, which was $0.8 million higher than 2009. The increase was
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primarily due to higher short-term incentive compensation expense.
Unreimbursed litigation costs
In 2010, we recorded $1.4 million for unreimbursed litigation costs and legal fees related to the Quicksilver lawsuit that we did not expect to get reimbursed from our insurance companies. In 2011, we reduced the previously recorded $1.4 million provision by $0.1 million in anticipation of an insurance recovery, which we received in January 2012.
(Gain) loss on sale of assets
There was no material gain or loss on sale of assets for the years ended December 31, 2011 and 2010. The loss on sale of assets of $6.0 million for the year ended December 31, 2009 primarily reflects the $5.5 million loss on sale of the Lazy JL Field in Texas, which was sold in July 2009.
Interest expense, net of amounts capitalized
Our interest expense totaled $39.2 million for the year ended December 31, 2011, net of $0.1 million of capitalized interest, an increase of $14.6 million from 2010. This increase in interest expense was primarily attributable to an additional $19.9 million in interest expense associated with our 2020 Senior Notes, partially offset by $4.8 million lower interest expense on our credit facility due to a lower credit facility debt balance and $0.7 million lower amortization of debt issuance costs.
We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. See Part II—Item 7A "—Quantitative and Qualitative Disclosures About Market Risk" within this report for a discussion of our interest rate swaps. We had realized losses of $3.3 million for the year ended December 31, 2011, compared to realized losses of $11.1 million for the year ended December 31, 2010 and unrealized gains of $0.5 million for the year ended December 31, 2011 compared to unrealized gains of $6.6 million for the year ended December 31, 2010, relating to our interest rate swaps. Interest expense, including realized losses on interest rate derivative contracts and excluding debt amortization and unrealized gains or losses on interest rate derivative contracts, totaled $37.7 million and $30.2 million for the years ended December 31, 2011 and 2010, respectively.
Our interest expense totaled $24.6 million for the year ended December 31, 2010, net of $0.3 million of capitalized interest, an increase of $5.8 million from 2009. This increase in interest expense was primarily attributable to $6.3 million related to the 2020 Senior Notes and the write-off of $1.5 million of debt issuance costs related to the borrowing base reduction of our credit facility resulting from the issuance of the 2020 Senior Notes. These increases were partially offset by lower interest rates and a lower debt balance under our credit facility.
We had realized losses of $11.1 million for the year ended December 31, 2010, compared to realized losses of $13.1 million for the year ended December 31, 2009 and unrealized gains of $6.6 million for the year ended December 31, 2010 compared to unrealized gains of $5.9 million for the year ended December 31, 2009, relating to our interest rate swaps. Interest expense, including realized losses on interest rate derivative contracts and excluding debt amortization and unrealized gains or losses on interest rate derivative contracts, totaled $30.2 million and $28.6 million for the years ended December 31, 2010 and 2009, respectively.
Liquidity and Capital Resources
Our primary sources of liquidity are cash generated from operations, amounts available under our revolving credit facility and cash from the issuance of unsecured long-term debt and partnership units. Historically, our primary uses of cash have been for our operating expenses, capital expenditures, cash distributions to unitholders and unit repurchase transactions. To fund certain acquisition transactions, we have also sourced the private placement markets and have issued equity as partial consideration for the acquisition of oil and gas properties. As market conditions have permitted, we have also engaged in asset sale transactions.
Natural gas prices have declined substantially in the last year from a monthly average Henry Hub price of $4.49 per MMBtu in January 2011 to $2.67 per MMBtu in January 2012 and $2.48 for the first three weeks of February 2012. We have hedged more than 65% of our natural gas production in 2012 and 2013 at average prices of $7.12 and $5.96, respectively. As of February 28, 2012, we had approximately $88.0 million in borrowings outstanding under our credit facility and a borrowing base of $787.5 million. However, sustained low prices for natural gas may reduce the amounts we would otherwise have available to pay expenses, make distributions to our unitholders and to service our indebtedness.
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In 2012, our crude oil and natural gas capital spending program excluding acquisitions is expected to be approximately $68 million. Based on the continuing decline of natural gas prices, we will continue to evaluate our capital spending program throughout 2012.
Senior Notes
On October 6, 2010, we and BreitBurn Finance Corporation, and certain of our subsidiaries, as guarantors, issued $305 million in aggregate principal amount of 8.625% senior notes due 2020 at a price of 98.358%. We received net proceeds of approximately $291.2 million (after deducting estimated fees and offering expenses) and used $290 million of the net proceeds to repay amounts outstanding under our credit facility.
On January 13, 2012, we and BreitBurn Finance Corporation, and certain of our subsidiaries, as guarantors, issued $250 million in aggregate principal amount of 7.875% senior notes due 2022 at a price of 99.154%. We received net proceeds of approximately $242.3 million, after deducting estimated fees and offering expenses, and used the proceeds to repay amounts outstanding under our credit facility.
The use of proceeds from the issuance of these senior notes to repay amounts outstanding under our credit facility increased the borrowing availability under our credit facility, which gives us additional flexibility to finance future acquisitions.
Equity Offerings
In February 2011, we sold approximately 4.9 million Common Units at a price to the public of $21.25, resulting in proceeds net of underwriting discounts and expenses of $100 million. In February 2012, we sold approximately 9.2 million Common Units at a price to the public of $18.80, resulting in proceeds net of underwriting discounts and estimated offering expenses of $165.9 million. We used the proceeds from these offerings to repay outstanding debt under our credit facility.
Credit Facility
As of December 31, 2010, we had a $1.5 billion bank credit facility (the "Second Amended and Restated Credit Agreement") with a maturity date of May 7, 2014 and a borrowing base of $658.8 million.
On May 9, 2011, we entered into the Second Amendment to the Second Amended and Restated Credit Agreement (the "Second Amendment"), which increased our borrowing base to $735 million and extended the maturity date to May 9, 2016. The Second Amendment also revised certain covenants in the credit facility, which included: eliminating the interest coverage ratio and the "borrowing base availability" test (applied prior to making distributions to unitholders or making other restricted payments); increasing the maximum leverage coverage ratio to 4.00 to 1.00 from 3.75 to 1.00; increasing our ability to incur or guaranty an additional $350 million of unsecured senior notes (subject to our borrowing base being reduced by 25% of the original stated principal amount of such new debt), and adjusting the pricing grid by decreasing the applicable margins (as defined in the Second Amended and Restated Credit Agreement) by 25 basis points.
On August 3, 2011, we entered into the Third Amendment (the "Third Amendment") to the Second Amended and Restated Credit Agreement, which permits us to hedge oil and gas volumes for properties for which we have entered into a purchase agreement prior to closing the transaction. The Third Amendment also provides that such hedges must be terminated in the event that the acquisition does not close within 90 days of the execution of such purchase agreement.
On October 5, 2011, in connection with the completion of the Cabot Acquisition, we entered into the Fourth Amendment (the "Fourth Amendment") to the Second Amended and Restated Credit Agreement. The Fourth Amendment provides for an increase in the volume of permitted gas imbalances under the Second Amended and Restated Credit Agreement from 300 MMcf to 1,000 MMcf.
In October 2011, our borrowing base was redetermined at $850 million, primarily as a result of an increase in oil and natural gas reserves due to the re-evaluation of existing reserves and the additional reserves associated with the Greasewood Acquisition. In January 2012, in connection with the issuance of senior notes, our borrowing base was reduced to $787.5 million. Our next semi-annual borrowing base redetermination is scheduled for April 2012.
We had outstanding borrowings under our credit facility of $520.0 million as of December 31, 2011 and $88.0 million as of February 28, 2012. Our borrowing base was $850 million as of December 31, 2011 and $787.5 million as of February 28, 2012.
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As of December 31, 2011, the lending group under the Second Amended and Restated Credit Agreement included 15 banks. Of the $850 million in total commitments under the credit facility, Wells Fargo Bank National Association held approximately 12.4 % of the commitments. Eleven banks held between 5% and 7.5% of the commitments, including Union Bank, N.A., Bank of Montreal, The Bank of Nova Scotia, Houston Branch, BNP Paribas, Citibank, N.A., Royal Bank of Canada, U.S. Bank National Association, Bank of Scotland plc, Barclays Bank PLC, The Royal Bank of Scotland plc and Credit Suisse AG, Cayman Islands Branch, with each of the remaining lenders holding less than 5% of the commitments. In addition to our relationships with these institutions under the credit facility, from time to time we engage in other transactions with a number of these institutions. Such institutions or their affiliates may serve as underwriter or initial purchaser of our debt and equity securities and/or serve as counterparties to our commodity and interest rate derivative agreements.
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 the restriction on our ability to make distributions unless after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility. In addition, the Second Amended and Restated Credit Agreement requires us to maintain a leverage ratio (defined as the ratio of total debt to EBITDAX) as of the last day of each quarter, on a last twelve month basis of no more than 4.00 to 1.00 and a current ratio as of the last day of each quarter, of not less than 1.00 to 1.00. As of December 31, 2011, 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, depletion, depreciation and amortization, unrealized loss or gain on derivative instruments, non-cash charges, including non-cash unit based compensation expense, loss or gain on sale of assets (excluding gain or loss on monetization of derivative instruments), cumulative effect of changes in accounting principles, cash distributions received from our unrestricted entities (as defined in the Second Amended and Restated Credit Agreement) and BEPI and excluding income from our unrestricted entities and BEPI.
The events that constitute an Event of Default (as defined in the Second Amended and Restated Credit Agreement) include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain other indebtedness; adverse judgments against us in excess of a specified amount; changes in management or control; loss of permits; certain insolvency events; and assertion of certain environmental claims.
Please see Part I—Item 1A "—Risk Factors"— "Risks Related to Our Business — Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions" in this report, for more information on the effect of an event of default under the Second Amended and Restated Credit Facility.
Distributions
Our credit facility limits the amounts we can borrow to a borrowing base amount determined by the lenders in their sole discretion based on their evaluation of our proved reserves and their internal criteria. In April 2009, as a result of a redetermination of our credit facility borrowing base from $900 million to $760 million and the terms of our credit facility then in effect, we were restricted from making distributions to our unitholders and suspended distributions for the first quarter of 2009.
Although we were not restricted from making distributions under the terms of our credit facility for the second, third and fourth quarters of 2009, we elected not to declare distributions in light of total leverage levels and other factors. We began reducing our outstanding bank debt in 2009 by applying the proceeds from monetization of derivative contracts, a portion of the cash flow from operations for 2009 and the proceeds from the July 2009 sale of the Lazy JL Field. In total, we reduced our outstanding borrowings under our credit facility by approximately $177 million in 2009.
In May 2010, we reinstated quarterly cash distributions to our unitholders, by paying a distribution for the first quarter of 2010. On May 14, 2010, we paid a cash distribution for the first quarter totaling $20.0 million, which was $0.375 per Common Unit, to our common unitholders of record as of the close of business on May 10, 2010. On August 13, 2010, we paid a cash distribution for the second quarter totaling $20.4 million, which was $0.3825 per Common Unit, to our common unitholders of record as of the close of business on August 9, 2010. On November 12, 2010, we paid a cash distribution for the third quarter totaling $20.8 million, which was $0.39 per Common Unit, to our common unitholders of record as of the close of business on November 9, 2010.
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On February 11, 2011, we paid a cash distribution to unitholders for the fourth quarter of 2010 at the rate of $0.4125 per Common Unit. On May 13, 2011, we paid a cash distribution to unitholders for the first quarter of 2011 at the rate of $0.4175 per Common Unit. On August 12, 2011, we paid a cash distribution to unitholders for the second quarter of 2011 at the rate of $0.4225 per Common Unit. On November 14, 2011, we paid a cash distribution to unitholders for the third quarter of 2011 at the rate of $0.4350 per Common Unit. On February 14, 2012, we paid a cash distribution for the fourth quarter of 2011 to our common unitholders of record as of the close of business on February 6, 2012 at the rate of $0.4500 per Common Unit.
Cash Flows
Operating activities. Our cash flow from operating activities for 2011 was $128.5 million compared to $182.0 million in 2010. The decrease in cash flow from operating activities was primarily due to higher operating costs, higher overall cash interest expense and $36.8 million in net payments during 2011 related to the termination of commodity derivative contracts.
Our cash flow from operating activities for 2010 was $182.0 million compared to $224.4 million in 2009. Included in cash flow from operating activities for 2009 were net proceeds of $70.6 million from the monetization of commodity derivative contracts. Excluding the monetization of commodity derivative contracts from our 2009 results, cash flow from operating activities in 2010 was higher than 2009 reflecting the net effect of higher commodity prices and slightly higher sales volumes.
Investing activities. Net cash used in investing activities for the year ended December 31, 2011 was $414.6 million, which was predominantly spent on property acquisitions. The current year results included $280.6 million for the Cabot Acquisition, $57.4 million for the Greasewood Acquisition and $78.1 million for capital expenditures, primarily for drilling and completions. Net cash used in investing activities for the year ended December 31, 2010 was $68.3 million, which was predominantly spent on drilling and completions, including drilling of the Raccoon Point wells in Florida. Property acquisitions of $1.7 million primarily related to a property acquisition in Michigan.
Net cash used in investing activities for the year ended December 31, 2009 was $6.2 million, which included capital expenditures of $29.5 million spent primarily on facility and infrastructure projects and well recompletions. The capital expenditures were partially offset by $23 million in proceeds from the sale of the Lazy JL Field in Texas.
Financing activities. Net cash provided by financing activities for the year ended December 31, 2011 was $287.7 million compared to cash used in financing activities of $115.9 million for the year ended December 31, 2010. Our long-term debt increased by approximately $292.0 million in 2011 compared to a decrease of $26.0 million in 2010. The increase in our debt in 2011 was primarily due to borrowings for property acquisitions. In addition, for the year ended December 31, 2011, we received net cash proceeds from the issuance of Common Units of $99.4 million and made cash distributions of $102.7 million.
Net cash used in financing activities for the year ended December 31, 2010 was $115.9 million compared to $214.9 million for the year ended December 31, 2009. We reduced our long-term debt by approximately $26.0 million in 2010 compared to $177.0 million in 2009. The decrease in our debt reduction in 2010 compared with 2009 was primarily due to higher capital expenditures in 2010 compared to the hedge contract monetizations and sale of the Lazy JL Field in 2009. In addition, for the year ended December 31, 2010, we made cash distributions of $65.2 million compared to $28.0 million in 2009. For the year ended December 31, 2010, we paid $11.9 million in debt issuance costs in connection with the Second Amended and Restated Credit Agreement and $8.8 million in connection with the Senior Notes.
Contractual Obligations
In addition to the credit facility and the Senior Notes described above, on August 26, 2008, BreitBurn Management entered into a five-year Administrative Services Agreement with PCEC that terminates on August 26, 2013. See "BreitBurn Management" under "Executive Overview" above for a discussion of this agreement.
Off-Balance Sheet Arrangements
We did not have any off-balance sheet arrangements as of December 31, 2011.
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Commitments
The following table summarizes our financial contractual obligations as of December 31, 2011. Some of these contractual obligations are reflected in the balance sheet, while others are disclosed as future obligations under accounting principles generally accepted in the United States.
Payments Due by Year | ||||||||||||||||||||||||||||
Thousands of dollars | 2012 | 2013 | 2014 | 2015 | 2016 | after 2016 | Total | |||||||||||||||||||||
Credit facility (a) | $ | — | $ | — | $ | — | $ | — | $ | 520,000 | $ | — | $ | 520,000 | ||||||||||||||
Credit facility commitment fees | 1,671 | 1,671 | 1,672 | 1,672 | 591 | — | 7,277 | |||||||||||||||||||||
Senior Notes (b) | — | — | — | — | — | 305,000 | 305,000 | |||||||||||||||||||||
Estimated interest payments (c) | 42,393 | 41,649 | 39,884 | 39,789 | 31,072 | 99,745 | 294,532 | |||||||||||||||||||||
Operating lease obligations | 3,782 | 2,876 | 2,513 | 2,268 | 1,477 | 1,565 | 14,481 | |||||||||||||||||||||
Asset retirement obligations | — | 102 | 47 | 55 | 540 | 81,653 | 82,397 | |||||||||||||||||||||
Purchase obligations | 183 | 183 | — | — | — | — | 366 | |||||||||||||||||||||
Total | $ | 48,029 | $ | 46,481 | $ | 44,116 | $ | 43,784 | $ | 553,680 | $ | 487,963 | $ | 1,224,053 | ||||||||||||||
(a) Credit facility matures on May 9, 2016. | ||||||||||||||||||||||||||||
(b) Represents 8.625% senior notes due 2020 with a face value of $305,000. | ||||||||||||||||||||||||||||
(c) Based on debt balance and interest rates in effect at December 31, 2011. Includes the impact of interest rate swaps. |
After the January 2012 Senior Note offering, which resulted in net proceeds of approximately $242.3 million, after deducting estimated fees and offering expenses, and the February 2012 equity offering, which resulted in proceeds net of underwriting discounts and estimated offering expenses of $165.9 million, we had outstanding borrowings under our credit facility of $88.0 million and Senior Notes outstanding of $555 million as of February 28, 2012. After consideration of these two transactions, the estimated interest payments reflected in the above table are projected to be $50.8 million, $50.7 million, $49.0 million, $48.9 million, $47.0 million and $203.9 million for 2012, 2013, 2014, 2015, 2016 and after 2016, respectively.
Surety Bonds and Letters of Credit
In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At December 31, 2011, we had obtained various surety bonds for $22.1 million and $0.3 million in letters of credit outstanding. At December 31, 2010, we had $15.1 million in surety bonds and $0.3 million in letters of credit outstanding.
Credit and Counterparty Risk
Financial instruments that potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives are exposed to credit risk from counterparties. As of December 31, 2011 and February 28, 2012, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, U.S Bank National Association and Toronto-Dominion Bank. Our counterparties are all lenders who participate in our Second Amended and Restated Credit Agreement. During 2008 and 2009, there was extreme volatility and disruption in the capital and credit markets. While the market has become more stable in 2010 and 2011, future volatility could adversely affect the financial condition of our derivative counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty's financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. As of December 31, 2011 and February 28, 2012, 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 December 31, 2011, our largest derivative asset balances were with JP Morgan Chase Bank N.A., Union Bank N.A and Wells Fargo Bank National Association which accounted for approximately 37%, 10% and 10% of our derivative asset balances, respectively. As of December 31, 2011, our largest derivative liability balances were with BNP Paribas, The Royal Bank of Scotland plc and Citibank, N.A., which accounted for approximately 34% and 31% and 22% of our derivative liability balances, respectively. See Note 5 to the consolidated financial statements in this report for more information regarding our derivatives.
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Accounts receivable are primarily from purchasers of oil and natural gas products. We have a portfolio of crude oil and natural gas sales contracts with large, established refiners and utilities. Because our products are commodity products sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. During the year ended December 31, 2011, our largest purchasers were ConocoPhillips, Plains Marketing & Transportation LLC, Marathon Oil Company and Sunoco Partners Marketing and Terminals L.P. which accounted for approximately 30%, 16%, 15% and 9% of net sales revenues, respectively.
ConocoPhillips, Plains Marketing & Transportation LLC, Marathon Oil Company, and Lundy Thagard Company each comprised 10% or more of our outstanding trade receivables, and together comprised approximately 54% of our outstanding trade receivables as of December 31, 2011.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. The development, selection and disclosure of each of these policies is reviewed by our audit committee. We believe these accounting policies reflect the more significant estimates and assumptions used in preparation of our financial statements. See Note 2 to the consolidated financial statements in this report for a discussion of additional accounting policies and estimates made by management.
Successful Efforts Method of Accounting
We account for oil and gas properties using the successful efforts method. Under this method of accounting, leasehold acquisition costs are capitalized. Subsequently, if proved reserves are found on unproved property, the leasehold costs are transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.
Depletion, depreciation and amortization of producing oil and gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves.
Geological, geophysical and dry hole costs on oil and gas properties relating to unsuccessful exploratory wells are charged to expense as incurred.
Oil and gas properties are reviewed for impairment periodically and when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. For purposes of performing an impairment test, the undiscounted cash flows are forecast using five-year NYMEX forward strip prices at the end of the period and escalated thereafter at 2.5%. For impairment charges, the associated proved properties’ expected future net cash flows are discounted using a rate of approximately 10%. Unproved properties are assessed for impairment along with proved properties and if considered impaired are charged to expense when such impairment is deemed to have occurred. During the year ended December 31, 2011, we recorded impairments of approximately $0.6 million related to uneconomic proved natural gas properties in Michigan.
During the year ended December 31, 2010, we recorded impairments of approximately $6.3 million related to our Eastern region properties, including a $4.2 million write-down of uneconomic proved properties and a $2.1 million write-down of expired unproved lease properties. In 2009, we had no impairments. Price declines may in the future result in additional impairment charges, which could have a material adverse effect on our results of operations in the period incurred.
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Property acquisition costs are capitalized when incurred.
We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. During 2011 and 2010, interest of $0.1 million and $0.3 million, respectively, was capitalized and included in our capital expenditures. We had no capitalized interest for 2009.
Oil and Gas Reserve Quantities
The estimates of our proved reserves are based on the quantities of oil and gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Annually, Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services prepare reserve and economic evaluations of all our properties on a well-by-well basis.
Estimated proved reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our disclosures for reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firms described above adhere to the same guidelines when preparing their reserve reports. The accuracy of the reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.
Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.
Our estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of oil and gas producing properties for impairment. For example, if the SEC prices used for our December 31, 2010 reserve report had been $10.00 less per Bbl and $1.00 less per MMBtu, respectively, then the standardized measure of our estimated proved reserves as of December 31, 2011 would have decreased by approximately $423.9 million, from $1,659.3 million to $1,235.4 million.
Please see Part I—Item 1A —"Risk Factors" — "Risks Related to Our Business — Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves."
Asset Retirement Obligations
Estimated asset retirement obligation ("ARO") costs are recognized when the asset is placed in service and are amortized over proved reserves using the units of production method. The engineers of BreitBurn Management estimate asset retirement costs using existing regulatory requirements and anticipated future inflation rates. Projecting future ARO cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of future oil and gas reserves, future labor and equipment rates, future inflation rates, and our credit adjusted risk free interest rate. Because of the intrinsic uncertainties present when estimating asset retirement costs as well as asset retirement settlement dates, our ARO estimates are subject to ongoing volatility.
Derivative Instruments
We use derivative financial instruments to achieve more predictable cash flow from our oil and natural gas production by reducing their exposure to price fluctuations. Currently, these instruments include swaps, collars and options. Additionally, we may use derivative financial instruments in the form of interest rate swaps to mitigate interest rate exposure. Derivative instruments (including certain derivative instruments embedded in other contracts) are recorded at fair market value and are
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included in the balance sheet as assets or liabilities. The accounting for changes in the fair market value of a derivative instrument depends on the intended use of the derivative instrument and the resulting designation, which is established at the inception of a derivative instrument. We do not account for our derivative instruments as cash flow hedges for financial accounting purposes and are recognizing changes in the fair value of our derivative instruments immediately in net income. If we do account for our derivative instruments as cash flow hedges, we are required to formally document, at the inception of a hedge, the hedging relationship and our risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment. See Part II—Item 7A "—Quantitative and Qualitative Disclosures About Market Risk" and Note 5 to the consolidated financial statements in this report for additional information related to our financial instruments.
New Accounting Standards
See Note 3 to the consolidated financial statements in this report for a discussion of new accounting standards.
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. See "Cautionary Statement Regarding Forward-Looking Information" in Part I—Item 1 "—Business" in this report.
See Note 5 to the consolidated financial statements in this report for additional information related to our financial instruments, including summaries of our commodity and interest rate derivative contracts at December 31, 2011 and a discussion of credit and counterparty risk.
Commodity Price Risk
Due to the historical volatility of crude oil and natural gas prices, we have entered into various derivative instruments to manage exposure to volatility in the market price of crude oil and natural gas to achieve more predictable cash flows. We use swaps, collars and options for managing risk relating to commodity prices. All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement. While this strategy may result in us having lower revenues than we would otherwise have if we had not utilized these instruments in times of higher oil and natural gas prices, management believes that the resulting reduced volatility of prices and cash flow is beneficial. While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash f low and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected. Please see Part I—Item 1A —"Risk Factors" — "Risks Related to Our Business — Our derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders. To the extent we have hedged a significant portion of our expected production and actual production is lower than expected or the costs of goods and services increase, our profitability would be adversely affected." The use of derivatives also involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.
Our commodity derivative instruments provide for monthly settlement based on the differential between the agreement price and the actual IPE Brent crude oil price, NYMEX WTI crude oil price, NYMEX Henry Hub natural gas price or MichCon City-Gate natural gas price.
We do not currently designate any of our derivative instruments as hedges for financial accounting purposes. In order to qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge effectiveness must be measured, at minimum, on a quarterly basis. Hedge accounting must be discontinued prospectively when a hedge instrument is no longer considered to be highly effective. Many of our commodity derivative instruments would not qualify for hedge accounting due to the ineffectiveness created by variability in our price discounts or differentials.
Our Los Angeles Basin crude oil is generally medium gravity crude. Because of its proximity to the extensive Los Angeles refinery market, it trades at only a minor discount to NYMEX WTI. Historically, WTI oil prices and IPE Brent oil prices have fluctuated together, but recently WTI and IPE Brent oil prices have diverged. Management believes that IPE Brent pricing will better correlate with local California prices we receive in the future. In 2011, IPE Brent prices were higher than WTI, and our California production traded at a premium to WTI. Our Wyoming crude oil, while generally of similar quality to our Los Angeles Basin crude oil, trades at a significant discount to NYMEX WTI because of its distance from a major refining market and the fact that our central Wyoming production is priced relative to the Bow River benchmark for Canadian heavy sour crude oil and our eastern Wyoming production is priced relative to Flint Hills Resources Wyoming Sweet posting, both of which have historically traded at a significant discount to NYMEX WTI. Our Florida crude oil also traded at a significant discount to NYMEX WTI primarily because of its low gravity and other quality characteristics as well as its distance from a major refining market.
Our Michigan properties have favorable natural gas supply/demand characteristics as the state has been importing an increasing percentage of its natural gas. To the extent our production is not hedged, the supply/demand situation has allowed us to sell our natural gas production with little or no discount to industry MichCon City-Gate prices. Our Wyoming natural gas trades at a discount to Henry Hub due to its relative location and the regional supply/demand market balances.
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During 2011, the average differentials per barrel to NYMEX WTI benchmark prices were a $13.88 premium for our California-based oil production, a $15.42 discount for our Wyoming-based oil production and a $14.46 discount for our Florida-based oil production, including approximately $7.50 in transportation costs. During 2011, the average differentials per Mcf to Henry Hub benchmark prices were a $0.27 premium for our Michigan-based natural gas production and a $0.01 discount for our Wyoming-based natural gas production.
During 2010, the average discounts we received for our crude oil production relative to NYMEX WTI benchmark prices per barrel were $0.25 for California-based production, $13.24 for Wyoming-based production, and $16.15 for Florida-based production, including approximately $7.50 in transportation costs. During 2010, the average premium we received for our natural gas production relative to Henry Hub benchmark prices per Mcf was $0.17 for our Michigan-based production.
During 2009, the average discounts we received for our crude oil production relative to NYMEX WTI benchmark prices per barrel were $0.53 and $8.08 for our California and Wyoming-based production, respectively, and $18.71 for our Florida-based production, including approximately $7.50 in transportation costs. During 2009, the average premium we received for our natural gas production relative to Henry Hub benchmark prices per Mcf was $0.21 for our Michigan-based production.
All derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or confirmed by the counterparty. Changes in the fair value of our commodity derivatives were recorded in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations, as a gain of $97.7 million for 2011 and a loss of $39.7 million for 2010.
Interest Rate Risk
We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. We currently do not designate any of our interest rate derivatives as hedges for financial accounting purposes. At December 31, 2011, long-term debt outstanding under our credit facility was $520.0 million. At December 31, 2011, our LIBOR based debt was $518.0 million and our prime based debt was $2.0 million. In order to mitigate our interest rate exposure, we have entered into various interest rate swaps to fix a portion of floating LIBOR based debt under our credit facility. For the year ended December 31, 2011, our weighted average debt balance was $252 million and, if interest rates on the variable interest portion of our LIBOR and prime based debt of $80 million increased or decreased by 1%, our annual interest cost would have increased or decreased by approximately $0.8 million.
Changes in Fair Value
The fair value of our outstanding oil and gas commodity derivative instruments at December 31, 2011 was a net asset of approximately $131.2 million. The fair value of our outstanding oil and gas commodity derivative instruments at December 31, 2010 was a net asset of approximately $33.5 million.
As of December 31, 2011, with a $10 per barrel increase in the price of oil, and a corresponding $1 per Mcf increase in natural gas, our net commodity derivative instrument asset at December 31, 2011 would have decreased by approximately $144 million. With a $10 per barrel decrease in the price of oil, and a corresponding $1 per Mcf decrease in natural gas, our net commodity derivative instrument asset at December 31, 2011 would have increased by approximately $150 million.
Price risk sensitivities were calculated by assuming across-the-board increases in price of $10 per barrel for oil and $1 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 portfolio would typically change by less than the amounts given due to lower volatility in out-month prices.
The fair value of our outstanding interest rate derivative instruments was a net liability of approximately $4.4 million at December 31, 2011 and $4.8 million at December 31, 2010. With a 1% increase in the LIBOR rate, our outstanding interest rate derivative instruments net liability at December 31, 2011 would have decreased by approximately $3 million. With a 1% decrease in the LIBOR rate to a minimum rate of zero, our net liability at December 31, 2011 would have increased by approximately $2 million.
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Changes in derivative instruments since December 31, 2011
On February 9, 2012, we entered into IPE Brent crude oil fixed price swap contracts for 500 Bbl/d for 2015 at $98.50 per Bbl.
Item 8. Financial Statements and Supplementary Data.
The information required by this Item 8 is incorporated herein by reference from the consolidated financial statements beginning on page F-1.
Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of 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 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 December 31, 2011 at the reasonable assurance level.
Management’s Report on Internal Control Over Financial Reporting
The information required by this Item is incorporated by reference from "Management’s Report on Internal Control Over Financial Reporting" located on page F-2.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2011 that has not previously been reported.
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PART III
Item 10. Directors, Executive Officers and Corporate Governance.
Information concerning our directors, executive officers and corporate governance required by this Item is incorporated by reference to the material appearing in our Proxy Statement for the 2012 Annual Meeting of Unitholders ("2012 Proxy Statement"). The 2012 Annual Meeting of Unitholders is to be held on June 21, 2012.
The Board has established an audit committee and determined which members are our "audit committee financial experts." Information concerning our audit committee required by this Item is incorporated by reference to the material appearing in our 2012 Proxy Statement.
We have adopted a Code of Ethics for Chief Executive Officers and Senior Officers. It is available on our website at http://ir.breitburn.com/documentdisplay.cfm?DocumentID=804.
Directors and Executive Officers of BreitBurn GP, LLC
The following table sets forth certain information with respect to the members of the board of directors and the executive officers of our General Partner. Executive officers and directors will serve until their successors are duly appointed or elected.
Name | Age | Position with BreitBurn GP, LLC | ||
Halbert S. Washburn | 51 | Chief Executive Officer, Director | ||
Randall H. Breitenbach | 51 | President, Director | ||
Mark L. Pease | 55 | Executive Vice President and Chief Operating Officer | ||
James G. Jackson | 47 | Executive Vice President and Chief Financial Officer | ||
Gregory C. Brown | 60 | Executive Vice President and General Counsel | ||
Chris E. Williamson | 54 | Senior Vice President –Southern Division | ||
W. Jackson Washburn | 49 | Senior Vice President – Business Development | ||
David D. Baker | 39 | Vice President – Northern Division | ||
Bruce D. McFarland | 55 | Vice President and Treasurer | ||
Lawrence C. Smith | 58 | Vice President and Controller | ||
John R. Butler, Jr.* | 73 | Chairman of the Board | ||
David B. Kilpatrick* | 62 | Director | ||
Gregory J. Moroney* | 60 | Director | ||
Charles S. Weiss* | 59 | Director |
* Independent Directors
In accordance with that certain Settlement Agreement dated April 5, 2010, by and among Quicksilver, the Partnership, BreitBurn GP and certain other parties named therein, Messrs. W. Yandell Rogers, III and Walker C. Friedman each submitted his resignation, effective December 5, 2011, as a member of the Board due to Quicksilver having disposed of 100% of its interest in the Partnership. On December 5, 2011, the Board elected Messrs. Halbert S. Washburn, our Chief Executive Officer, and Randall H. Breitenbach, our President, as members of the Board. Mr. Washburn was elected to a term that will expire at the annual meeting to be held in 2013, and Mr. Breitenbach was elected to a term that will expire at the annual meeting to be held in 2014. Upon the expiration of their respective terms, they may each be reelected for a three year term. Messrs. Washburn and Breitenbach, as management of the Company, will not serve as members of the two independent committees of the Board and will not receive additional compensation for their services as directors.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the directors and executive officers of our General Partner, and persons who own more than 10% of a registered class of our equity securities (collectively, "Insiders"), to file reports of beneficial ownership on Form 3 and reports of changes in beneficial ownership on Form 4 or Form 5 with the SEC. Based solely on our review of the reporting forms and written representations provided to us from the individuals required to file reports, we believe that each of our executive officers and directors has complied with the applicable reporting
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requirements for transactions in our securities during the fiscal year ended December 31, 2011 except as follows: Messrs. Brown and Smith each reported late the acquisition of Common Units, as a result of automatic distribution reinvestments, on February 14, 2011.
Item 11. Executive Compensation.
Information required by this Item is incorporated by reference to the material appearing in our 2012 Proxy Statement.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
Information required by this Item is incorporated by reference to the material appearing in our 2012 Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth certain information with respect to our equity compensation plans as of December 31, 2011.
Plan category, thousands | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted- average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | |||||||
(a) | (b) | (c) | ||||||||
Equity compensation plans approved by security holders | — | — | — | |||||||
Equity compensation plans not approved by security holders - Partnership LTIP | 1,738 | (1) | N/A | (2) | 5,681 | (3) | ||||
Total | 1,738 | N/A | 5,681 | |||||||
(1) Represents the number of units issued under the Partnership First Amended and Restated 2006 Long-Term Incentive Plan ("Partnership LTIP"). | ||||||||||
(2) Unit awards under the Partnership LTIP and the BreitBurn Management Long Term Incentive Plan vest without payment by recipients. | ||||||||||
(3) The Partnership LTIP provides that the Board or a committee of the Board may award restricted units, performance units, unit appreciation rights or other unit-based awards and unit awards. |
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Information required by this Item is incorporated by reference to the material appearing in our 2012 Proxy Statement.
Item 14. Principal Accounting Fees and Services.
Information required by this Item is incorporated by reference to the material appearing in our 2012 Proxy Statement.
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PART IV
Item 15. Exhibits and Financial Statement Schedules.
(a) (1) Financial Statements
See “Index to the Consolidated Financial Statements” set forth on Page F-1.
(2) Financial Statement Schedules
All schedules are omitted because they are not applicable or the required information is presented in the consolidated financial statements or notes thereto.
(3) Exhibits
NUMBER | DOCUMENT | |
3.1 | Certificate of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 (File No. 333-134049) filed on July 13, 2006). | |
3.2 | 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). | |
3.3 | 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). | |
3.4 | 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 April 9, 2009). | |
3.5 | 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 September 1, 2009). | |
3.6 | 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). | |
3.7 | Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC dated as of April 5, 2010 (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2011). | |
3.8 | Amendment No. 1 to the Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC dated as of December 30, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). | |
4.1 | Registration Rights Agreement, dated as of November 1, 2007, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007). | |
4.2 | First Amendment to the Registration Rights Agreement, dated as of April 5, 2010, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010). | |
4.3 | Unit Purchase Rights Agreement, dated as of December 22, 2008, between BreitBurn Energy Partners L.P. and American Stock Transfer & Trust Company LLC as Rights Agreement (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on December 23, 2008). | |
4.4 | Indenture, dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (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). | |
4.5 | Registration Rights Agreement, dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010). | |
4.6 | 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. Bank National 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). |
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NUMBER | DOCUMENT | |
4.7 | Registration Rights Agreement, dated as of January 13, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on January 13, 2012). | |
10.1 | Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners I, L.P. dated May 5, 2003 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on May 29, 2007). | |
10.2† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Executive Form) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on March 11, 2008). | |
10.3† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Executive Form) (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on March 11, 2008). | |
10.4† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Units Directors’ Award Agreement (incorporated herein by reference to Exhibit 10.35 to the Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-33055) and filed on March 17, 2008). | |
10.5 | Amendment No. 1 to the Operations and Proceeds Agreement, relating to the Dominguez Field and dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008). | |
10.6 | Amendment No. 1 to the Surface Operating Agreement dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and its predecessor BreitBurn Energy Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008). | |
10.7† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement (Employment Agreement Form) (incorporated herein by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the period ended June 30, 2008 (File No. 001-33055) and filed on August 11, 2008). | |
10.8† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement (Non-Employment Agreement Form) (incorporated herein by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the period ended June 30, 2008 and (File No. 001-33055) filed on August 11, 2008). | |
10.9 | Second Amended and Restated Administrative Services Agreement dated August 26, 2008 by and between BreitBurn Energy Company L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 02, 2008). | |
10.10 | Omnibus Agreement, dated August 26, 2008, by and among BreitBurn Energy Holdings LLC, BEC (GP) LLC, BreitBurn Energy Company L.P, BreitBurn GP, LLC, BreitBurn Management Company, LLC and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on September 02, 2008). | |
10.11 | Indemnity Agreement between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Halbert S. Washburn, together with a schedule identifying other substantially identical agreements between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and each of its executive officers and non-employee directors identified on the schedule (incorporated herein by reference to Exhibit 10.1 to the Current Report on form 8-K (File No. 001-33055) filed on November 4, 2009). | |
10.12† | First Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.2 to the Current Report on form 8-K (File No. 001-33055) filed on November 4, 2009). | |
10.13† | First Amended and Restated BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan effective as of October 29, 2009 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the period ended September 30, 2009 (File No. 001-33055) filed on November 6, 2009). | |
10.14 | Settlement Agreement as of April 5, 2010 by and among Quicksilver Resources Inc., BreitBurn Energy Partners L.P., BreitBurn GP LLC, Provident Energy Trust, Randall H. Breitenbach and Halbert S. Washburn (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 9, 2010). | |
10.15† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Executive Form) (incorporated herein by reference to Exhibit 10.21 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011. |
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NUMBER | DOCUMENT | |
10.16† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Executive Form) (incorporated herein by reference to Exhibit 10.22 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011. | |
10.17† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Director Form) (incorporated herein by reference to Exhibit 10.23 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011. | |
10.18† | Form of Second Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.24 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011. | |
10.19† | Form of Third Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.25 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011. | |
10.20 | Third Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Halbert S. Washburn (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). | |
10.21 | Third Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). | |
10.22 | Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Mark L. Pease (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). | |
10.23 | Second Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and James G. Jackson (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). | |
10.24 | Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Gregory C. Brown (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). | |
10.25 | Second Amended and Restated Credit Agreement, dated May 7, 2010, by and among BreitBurn Operating L.P, as borrower, BreitBurn Energy Partners L.P., as parent guarantor, and Wells Fargo Bank, N.A., as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the period ended March 31, 2010 (File No. 001-33055) filed on May 10, 2010). | |
10.26 | First Amendment dated September 17, 2010 to the Second Amended and Restated Credit Agreement dated May 7, 2010, by and among BreitBurn Operating L.P, as borrower, BreitBurn Energy Partners L.P., as parent guarantor, and Wells Fargo Bank, N.A., as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 23, 2010). | |
10.27 | Second Amendment to the Second Amended and Restated Credit Agreement dated May 9, 2011 (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 001-33055) filed on May 10, 2011. | |
10.28 | Asset Purchase Agreement, dated as of July 26, 2011, between Cabot Oil & 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 July 29, 2011. | |
10.29 | Third Amendment to the Second Amended and Restated Credit Agreement dated August 3, 2011 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-33055) filed on August 8, 2011. | |
10.30 | Fourth Amendment to the Second Amended and Restated Credit Agreement dated October 5, 2011 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2011. | |
14.1 | BreitBurn Energy Partners L.P. and BreitBurn GP, LLC Code of Ethics for Chief Executive Officers and Senior Officers (as amended and restated on February 28, 2007) (incorporated herein by reference to Exhibit 14.1 to the Current Report on Form 8-K filed on March 5, 2007). | |
21.1* | List of subsidiaries of BreitBurn Energy Partners L.P. | |
23.1* | Consent of PricewaterhouseCoopers LLP. | |
23.2* | Consent of Netherland, Sewell & Associates, Inc. |
67
NUMBER | DOCUMENT | |
23.3* | Consent of Schlumberger Data and Consulting Services. | |
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. | |
99.1* | Netherland, Sewell & Associates, Inc. reserve report for certain properties located in Wyoming. | |
99.2* | Netherland, Sewell & Associates, Inc. reserve report for certain properties located in California and Florida. | |
99.3* | Schlumberger Technology Corporation reserve report. | |
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. |
68
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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: February 29, 2012 | By: | /s/ Halbert S. Washburn |
Halbert S. Washburn | ||
Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Name | Title | Date | ||
/s/ Halbert S. Washburn | Chief Executive Officer and Director of | February 29, 2012 | ||
Halbert S. Washburn | BreitBurn GP, LLC | |||
(Principal Executive Officer) | ||||
/s/ James G. Jackson | Chief Financial Officer of | February 29, 2012 | ||
James G. Jackson | BreitBurn GP, LLC | |||
(Principal Financial Officer) | ||||
/s/ Lawrence C. Smith | Vice President and Controller of | February 29, 2012 | ||
Lawrence C. Smith | BreitBurn GP, LLC | |||
(Principal Accounting Officer) | ||||
/s/ Randall H. Breitenbach | President and Director of | February 29, 2012 | ||
Randall H. Breitenbach | BreitBurn GP, LLC | |||
/s/ John R. Butler, Jr. | Chairman of the Board of | February 29, 2012 | ||
John R. Butler, Jr. | BreitBurn GP, LLC | |||
/s/ David B. Kilpatrick | Director of | February 29, 2012 | ||
David B. Kilpatrick | BreitBurn GP, LLC | |||
/s/ Gregory J. Moroney | Director of | February 29, 2012 | ||
Gregory J. Moroney | BreitBurn GP, LLC | |||
/s/ Charles S. Weiss | Director of | February 29, 2012 | ||
Charles S. Weiss | BreitBurn GP, LLC |
69
BREITBURN ENERGY PARTNERS L.P. AND SUBSIDIARIES
INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS
F-1
Management’s Report on Internal Control Over Financial Reporting
The management of BreitBurn Energy Partners, L.P. (the "Partnership") is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. The term "internal control over financial reporting" is defined as a process designed by, or under the supervision of, the Partnership's principal executive and principal financial officers, or persons performing similar functions, and effected by the Partnership’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Partnership; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Partnership are being made only in accordance with authorizations of management and directors of the Partnership; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Partnership's assets that could have a material effect on the financial statements.
Internal control over financial reporting, no matter how well designed, has inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
As required by Rule 13a-15(c) under the Exchange Act, the Partnership’s management, with the participation of the General Partner’s principal executive officers and principal financial officer, assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2011. In making this assessment, the Partnership’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control Integrated Framework. Based on this assessment, the Partnership’s management, including the general partner’s principal executive officers and principal financial officer, concluded that, as of December 31, 2011, the Partnership’s internal control over financial reporting was effective based on those criteria.
Management excluded from its assessment of the effectiveness of the Partnership's internal control over financial reporting the properties acquired in the Cabot Acquisition (as further described in Note 4 to the consolidated financial statements) because they were acquired in October 2011. The Cabot Assets represented approximately 13% of the Partnership's total assets as of December 31, 2011 and revenue from the Cabot Assets represented approximately 2% of the Partnership's total revenue for the year ended December 31, 2011.
PricewaterhouseCoopers LLP, the independent registered public accounting firm who audited the consolidated financial statements included in this Annual Report on Form 10-K, has issued a report on the Partnership’s internal control over financial reporting as of December 31, 2011, which appears on page F-3.
/s/ Halbert S. Washburn | /s/ James G. Jackson | |
Halbert S. Washburn | James G. Jackson | |
Chief Executive Officer of BreitBurn GP, LLC | Chief Financial Officer of BreitBurn GP, LLC |
F-2
Report of Independent Registered Public Accounting Firm
To the Board of Directors of BreitBurn GP, LLC and Unitholders of BreitBurn Energy Partners L.P.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners' equity and cash flows present fairly, in all material respects, the financial position of BreitBurn Energy Partners L.P. and its subsidiaries (“the Partnership”) at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As described in Management's Report on Internal Control Over Financial Reporting, management has excluded the properties acquired in the Cabot Acquisition from its assessment of internal control over financial reporting as of December 31, 2011 because the assets were acquired by the Partnership in a purchase business combination during October 2011. We have also excluded the Cabot properties from our audit of internal control over financial reporting. The Cabot properties total assets and total revenues represent 13% and 2%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2011.
/s/ PricewaterhouseCoopers LLP |
Los Angeles, California |
February 29, 2012 |
F-3
BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Balance Sheets
December 31, | ||||||||
Thousands | 2011 | 2010 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash | $ | 5,328 | $ | 3,630 | ||||
Accounts and other receivables, net (note 2) | 73,018 | 53,520 | ||||||
Derivative instruments (note 5) | 83,452 | 54,752 | ||||||
Related party receivables (note 6) | 4,245 | 4,345 | ||||||
Inventory (note 7) | 4,724 | 7,321 | ||||||
Prepaid expenses | 2,053 | 1,736 | ||||||
Total current assets | 172,820 | 125,304 | ||||||
Equity investments (note 8) | 7,491 | 7,700 | ||||||
Property, plant and equipment | ||||||||
Oil and gas properties | 2,583,993 | 2,133,099 | ||||||
Other assets | 13,431 | 10,832 | ||||||
2,597,424 | 2,143,931 | |||||||
Accumulated depletion and depreciation (note 9) | (524,665 | ) | (421,636 | ) | ||||
Net property, plant and equipment | 2,072,759 | 1,722,295 | ||||||
Other long-term assets | ||||||||
Derivative instruments (note 5) | 55,337 | 50,652 | ||||||
Other long-term assets | 22,442 | 24,216 | ||||||
Total assets | $ | 2,330,849 | $ | 1,930,167 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 33,494 | $ | 26,808 | ||||
Derivative instruments (note 5) | 8,881 | 37,071 | ||||||
Revenue and royalties payable | 19,641 | 16,427 | ||||||
Salaries and wages payable | 13,655 | 12,594 | ||||||
Accrued liabilities | 14,218 | 8,417 | ||||||
Total current liabilities | 89,889 | 101,317 | ||||||
Credit facility (note 10) | 520,000 | 228,000 | ||||||
Senior notes, net (note 10) | 300,613 | 300,116 | ||||||
Deferred income taxes (note 12) | 2,803 | 2,089 | ||||||
Asset retirement obligation (note 13) | 82,397 | 47,429 | ||||||
Derivative instruments (note 5) | 3,084 | 39,722 | ||||||
Other long-term liabilities | 4,849 | 2,237 | ||||||
Total liabilities | 1,003,635 | 720,910 | ||||||
Commitments and contingencies (note 14) | ||||||||
Equity: | ||||||||
Partners' equity (note 15) | 1,326,764 | 1,208,803 | ||||||
Noncontrolling interest (note 16) | 450 | 454 | ||||||
Total equity | 1,327,214 | 1,209,257 | ||||||
Total liabilities and equity | $ | 2,330,849 | $ | 1,930,167 | ||||
Common units issued and outstanding | 59,864 | 53,957 |
The accompanying notes are an integral part of these consolidated financial statements.
F-4
BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statements of Operations
Year Ended December 31, | ||||||||||||
Thousands of dollars, except per unit amounts | 2011 | 2010 | 2009 | |||||||||
Revenues and other income items: | ||||||||||||
Oil, natural gas and natural gas liquid sales | $ | 394,393 | $ | 317,738 | $ | 254,917 | ||||||
Gain (loss) on commodity derivative instruments, net (note 5) | 81,667 | 35,112 | (51,437 | ) | ||||||||
Other revenue, net (note 8) | 4,310 | 2,498 | 1,382 | |||||||||
Total revenues and other income items | 480,370 | 355,348 | 204,862 | |||||||||
Operating costs and expenses: | ||||||||||||
Operating costs | 165,969 | 142,525 | 138,498 | |||||||||
Depletion, depreciation and amortization (note 9) | 107,503 | 102,758 | 106,843 | |||||||||
General and administrative expenses | 53,313 | 44,907 | 36,367 | |||||||||
(Gain) loss on sale of assets | (111 | ) | 14 | 5,965 | ||||||||
Unreimbursed litigation costs | (113 | ) | 1,401 | — | ||||||||
Total operating costs and expenses | 326,561 | 291,605 | 287,673 | |||||||||
Operating income (loss) | 153,809 | 63,743 | (82,811 | ) | ||||||||
Interest expense, net of capitalized interest (note 10) | 39,165 | 24,552 | 18,827 | |||||||||
Loss on interest rate swaps (note 5) | 2,777 | 4,490 | 7,246 | |||||||||
Other income, net | (19 | ) | (8 | ) | (99 | ) | ||||||
Income (loss) before taxes | 111,886 | 34,709 | (108,785 | ) | ||||||||
Income tax expense (benefit) (note 12) | 1,188 | (204 | ) | (1,528 | ) | |||||||
Net income (loss) | 110,698 | 34,913 | (107,257 | ) | ||||||||
Less: Net income attributable to noncontrolling interest (note 16) | (201 | ) | (162 | ) | (33 | ) | ||||||
Net income (loss) attributable to the partnership | $ | 110,497 | $ | 34,751 | $ | (107,290 | ) | |||||
Basic net income (loss) per unit (note 15) | $ | 1.80 | $ | 0.61 | $ | (2.03 | ) | |||||
Diluted net income (loss) per unit (note 15) | $ | 1.79 | $ | 0.61 | $ | (2.03 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
F-5
BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statements of Cash Flows
Year Ended December 31, | ||||||||||||
Thousands of dollars | 2011 | 2010 | 2009 | |||||||||
Cash flows from operating activities | ||||||||||||
Net income (loss) | $ | 110,698 | $ | 34,913 | $ | (107,257 | ) | |||||
Adjustments to reconcile to cash flow from operating activities: | ||||||||||||
Depletion, depreciation and amortization | 107,503 | 102,758 | 106,843 | |||||||||
Unit based compensation expense | 22,043 | 20,422 | 12,661 | |||||||||
Unrealized (gain) loss on derivative instruments | (98,214 | ) | 33,116 | 213,251 | ||||||||
Income from equity affiliates, net | 210 | 450 | 1,302 | |||||||||
Deferred income taxes | 714 | (403 | ) | (1,790 | ) | |||||||
Amortization of intangibles | — | 495 | 2,771 | |||||||||
(Gain) loss on sale of assets | (111 | ) | 14 | 5,965 | ||||||||
Other | (312 | ) | 3,528 | 3,294 | ||||||||
Changes in net assets and liabilities | ||||||||||||
Accounts receivable and other assets | (17,833 | ) | 11,552 | (6,313 | ) | |||||||
Inventory | 2,597 | (1,498 | ) | (4,573 | ) | |||||||
Net change in related party receivables and payables | 100 | (15,218 | ) | 2,957 | ||||||||
Accounts payable and other liabilities | 1,148 | (8,107 | ) | (4,753 | ) | |||||||
Net cash provided by operating activities | 128,543 | 182,022 | 224,358 | |||||||||
Cash flows from investing activities | ||||||||||||
Capital expenditures | (78,107 | ) | (66,947 | ) | (29,513 | ) | ||||||
Proceeds from sale of assets | 2,339 | 337 | 23,284 | |||||||||
Property acquisitions | (338,805 | ) | (1,676 | ) | — | |||||||
Net cash used in investing activities | (414,573 | ) | (68,286 | ) | (6,229 | ) | ||||||
Cash flows from financing activities | ||||||||||||
Issuance of common units | 99,443 | — | — | |||||||||
Distributions (a) | (102,686 | ) | (65,197 | ) | (28,038 | ) | ||||||
Proceeds from issuance of long-term debt, net | 661,500 | 1,047,992 | 249,975 | |||||||||
Repayments of long-term debt | (369,500 | ) | (1,079,000 | ) | (426,975 | ) | ||||||
Change in bank overdraft | 2,636 | 1,025 | (9,871 | ) | ||||||||
Debt issuance costs | (3,665 | ) | (20,692 | ) | — | |||||||
Net cash provided by (used in) financing activities | 287,728 | (115,872 | ) | (214,909 | ) | |||||||
Increase (decrease) in cash | 1,698 | (2,136 | ) | 3,220 | ||||||||
Cash beginning of period | 3,630 | 5,766 | 2,546 | |||||||||
Cash end of period | $ | 5,328 | $ | 3,630 | $ | 5,766 |
(a) 2011, 2010 and 2009 include distributions on unissued units under incentive plans of $5.1 million, $4.0 million and $0.7 million, respectively.
The accompanying notes are an integral part of these consolidated financial statements.
F-6
BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statements of Partners' Equity
Thousands | Common Units | Partners' Equity | |||||
Balance, December 31, 2008 | 52,636 | $ | 1,352,892 | ||||
Distributions | — | (27,371 | ) | ||||
Distributions paid on unissued units under incentive plans | — | (667 | ) | ||||
Units issued under incentive plans | 148 | 7,488 | |||||
Unit-based compensation | — | 3,322 | |||||
Net loss attributable to the partnership | — | (107,290 | ) | ||||
Other | — | (1 | ) | ||||
Balance, December 31, 2009 | 52,784 | $ | 1,228,373 | ||||
Distributions | — | (61,161 | ) | ||||
Distributions paid on unissued units under incentive plans | — | (4,020 | ) | ||||
Units issued under incentive plans | 1,173 | 7,677 | |||||
Unit-based compensation | — | 3,183 | |||||
Net income attributable to the partnership | — | 34,751 | |||||
Balance, December 31, 2010 | 53,957 | $ | 1,208,803 | ||||
Distributions | — | (97,590 | ) | ||||
Distributions paid on unissued units under incentive plans | — | (5,096 | ) | ||||
Issuance of common units | 4,945 | 99,443 | |||||
Units issued under incentive plans | 962 | 11,840 | |||||
Unit-based compensation | — | (1,133 | ) | ||||
Net income attributable to the partnership | — | 110,497 | |||||
Balance, December 31, 2011 | 59,864 | $ | 1,326,764 |
The accompanying notes are an integral part of these consolidated financial statements.
F-7
Notes to Consolidated Financial Statements
Note 1. Organization
We are a Delaware limited partnership formed on March 23, 2006. Our initial public offering was in October 2006. Pacific Coast Energy Company LP ("PCEC"), formerly BreitBurn Energy Company L.P., was our Predecessor.
Our general partner is BreitBurn GP, LLC, a Delaware limited liability company (the "General Partner"), also formed on March 23, 2006. The board of directors of our General Partner has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly owned subsidiary, BreitBurn Operating L.P, ("BOLP") and BOLP’s general partner BreitBurn Operating GP, LLC ("BOGP"). We own all of the ownership interests in BOLP and BOGP.
Our wholly owned subsidiary, BreitBurn Management, manages our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. See Note 6 for information regarding our relationship with BreitBurn Management. Our wholly owned subsidiary, BreitBurn Finance Corporation, was incorporated on June 1, 2009 under the laws of the State of Delaware. BreitBurn Finance Corporation has no assets or liabilities. Its activities are limited to co-issuing debt securities and engaging in other activities incidental thereto. Our wholly owned subsidiary, BreitBurn Collingwood Utica LLC ("Utica") holds certain non-producing oil and gas zones in the Collingwood-Utica shale play in Michigan and is classified as an unrestricted subsidiary under our credit facility.
During 2011, Quicksilver Resources Inc. ("Quicksilver"), a holder of 15.7 million of our limited partnership units ("Common Units") as of December 31, 2010, sold 0.1 million of our Common Units at an average price to the public of $21.88 per Common Unit, 7.6 million Common Units at a price to the public of $19.78 per Common Unit and 8.0 million Common Units at a price to the public of $16.52. These sales resulted in Quicksilver having disposed of 100% of its interest in the Partnership as of November 30, 2011. In 2011, The Baupost Group, L.L.C. sold 4.4 million of our Common Units, disposing of 100% of its interest in the Partnership.
As of December 31, 2011, public unitholders owned 98.85% of our Common Units and BreitBurn Energy Corporation owned 0.7 million Common Units, representing a 1.15% limited partner interest. We own 100% of the General Partner, BreitBurn Management, BOLP, BreitBurn Finance Corporation and Utica.
2. Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. Investments in affiliated companies with a 20% or greater ownership interest, and in which we do not have control, are accounted for on the equity basis. Investments in affiliated companies with less than a 20% ownership interest, and in which we do not have control, are accounted for on the cost basis. Investments in which we own greater than 50% interest and in which we have control are consolidated. Investments in which we own less than a 50% interest but are deemed to have control, or where we have a variable interest in an entity in which we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated. The effects of all intercompany transactions have been eliminated.
Basis of presentation
Our financial statements are prepared in conformity with U.S. generally accepted accounting principles. Certain items included in the prior year financial statements were reclassified to conform to the 2011 presentation.
F-8
In 2011, we began classifying all debt issuance costs as long-term assets rather than allocating a portion to prepaid expenses. As such, we have revised the classification of debt issuance costs as of December 31, 2010, which is reflected in the following table. The change was not material to the prior period.
Thousands of dollars | December 31, 2010 | |||
Prepaid expenses | ||||
As previously reported | $ | 6,449 | ||
Reclassification to other long-term assets | (4,713 | ) | ||
As revised | $ | 1,736 | ||
Other long-term assets | ||||
As previously reported | $ | 19,503 | ||
Reclassification from prepaid expenses | 4,713 | |||
As revised | $ | 24,216 |
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including fair value of derivative instruments, unit based compensation and oil and gas reserve quantities, which are the basis for the calculation of depletion, depreciation, amortization, asset retirement obligations and impairment of oil and gas properties.
Business segment information
We report in one segment because our oil and gas operating areas have similar economic characteristics. We acquire, exploit, develop and produce oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas.
Revenue recognition
Revenues associated with sales of our crude oil and natural gas are recognized when title passes from us to our customer. Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest ("entitlement" method of accounting). We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold. As a result, we have no material natural gas producer imbalance positions.
Accounts receivable
Our accounts receivable are primarily from purchasers of crude oil and natural gas and counterparties to our financial instruments. Crude oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2011 and 2010, we did not carry an allowance for doubtful accounts receivable.
The settlement costs related to the Quicksilver lawsuit and the associated legal expenses were $13.0 million and approximately $8.7 million, respectively, of which we collected approximately $10.0 million from our insurance companies during the year ended December 31, 2010. Of the costs incurred in connection with the lawsuit, $1.4 million was estimated to be not recoverable from the insurance companies and is reflected as an expense in unreimbursed litigation costs on the consolidated statements of operations for the year ended December 31, 2010. The receivable at December 31, 2010 was $10.3 million. In 2011, we reduced the previously recorded $1.4 million provision by $0.1 million in anticipation of the final
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insurance recovery payment of $10.4 million, which we received in January 2012. At December 31, 2011, accounts receivable included $10.4 million due from our insurance companies related to the lawsuit.
Inventory
Oil inventories are carried at the lower of cost to produce or market price. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded as inventory.
Investments in equity affiliates
Income from equity affiliates is included as a component of operating income, as the operations of these affiliates are associated with the processing and transportation of our natural gas production.
Property, plant and equipment
Oil and gas properties
We follow the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred.
Upon sale or retirement of proved properties, the cost thereof and the accumulated depletion, depreciation and amortization ("DD&A") are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, are generally computed on a field-by-field basis where applicable and recognized using the units-of-production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using straight line, generally over 20 years.
We capitalize interest costs to oil and gas properties on expenditures made in connection with drilling and completion of new oil and natural gas wells. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. During 2011 and 2010, interest of $0.1 million and $0.3 million, respectively, was capitalized and included in our capital expenditures. We had no capitalized interest in 2009.
Non-oil and gas assets
Buildings and non-oil and gas assets are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to 10 years.
Oil and natural gas reserve quantities
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with the Securities and Exchange Commission (the "SEC") guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports.
Asset retirement obligations
We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations. The fair value of a liability for an asset retirement obligation ("ARO") is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and expensed. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of crude oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance.
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Impairment of assets
Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. A long-lived asset is tested for impairment periodically and when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves, and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2.5% per year. For impairment charges, the associated property’s expected future net cash flows are discounted using a rate of approximately 10%. Reserves are calculated based upon reports from third-party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Unproved properties are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.
We assess our long-lived assets for impairment generally on a field-by-field basis where applicable. See Note 9 for a discussion of our impairments and price related depletion and depreciation adjustments.
Debt issuance costs
The costs incurred to obtain financing have been capitalized. Debt issuance costs are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the "effective interest" method of amortization. Amortization of debt issuance costs for the year ended December 31, 2010 included a $1.5 million write-off of debt issuance costs as a result of the reduced borrowing base under our credit facility.
Equity-based compensation
BreitBurn Management has various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 17. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period. We recognize equity-based compensation costs on a straight line basis over the annual vesting periods. Awards classified as liabilities are revalued at each reporting period and changes in the fair value of the options are recognized as compensation expense over the vesting schedules of the awards.
Fair market value of financial instruments
The carrying amount of our cash, accounts receivable, accounts payable, related party receivables and payables, and accrued expenses approximate their respective fair value due to the relatively short term of the related instruments. The carrying amount of long-term debt under our credit facility approximates fair value; however, changes in the credit markets may impact our ability to enter into future credit facilities at similar terms. See Note 10 for the fair value of our Senior Notes.
Accounting for business combinations
We account for all business combinations using the acquisition method. Under the acquisition method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is recognized as a gain at the time of acquisition. All purchase price allocations are finalized within one year from the acquisition date. We have not recognized any goodwill from any business combinations.
Concentration of credit risk
We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk. At times, such balances may be in excess of the Federal Insurance Corporation insurance limit. As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers and pay vendors on behalf of joint owners for oil and gas services. We periodically monitor our major purchasers’ credit ratings. We enter into commodity and interest rate derivative instruments. Our derivative counterparties are all lenders under our credit facility and
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we periodically monitor their credit ratings.
Derivatives
Financial Accounting Standards Board ("FASB") Accounting Standards establish accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. These standards require recognition of all derivative instruments as assets or liabilities on our balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. We currently do not designate any of our derivatives as hedges for financial accounting purposes. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities.
Fair value measurement is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date. The objective of fair value measurement is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If there is an active market for the asset or liability, the fair value measurement shall represent the price in that market whether the price is directly observable or otherwise obtained using a valuation technique.
Income taxes
Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided.
We have three wholly owned subsidiaries which are subject to corporate income taxes. Deferred income taxes are recorded under the asset and liability method. Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities.
FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial-statement comparability among different companies.
We performed evaluations as of December 31, 2011, 2010 and 2009 and concluded that there were no uncertain tax positions requiring recognition in our financial statements.
Net Income or loss 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 restricted phantom units ("RPUs") and convertible phantom units ("CPUs") participate in dividends on an equal basis with Common Units; therefore, there is no difference in undistributed earnings allocated to each participating security. Accordingly, our calculation is prepared on a combined basis and is presented as net income (loss) per Common Unit. See Note 15 for our earnings per Common Unit calculation.
Environmental expenditures
We review, on an annual basis, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. We do not discount these liabilities. At December 31, 2011, we had a $1.9 million environmental liability accrued that included cost estimates related to the maintenance of ground water monitoring wells associated with certain former well sites in Michigan that are no longer producing. At December 31, 2010, we had a $2.1 million environmental liability accrued.
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3. Accounting Standards
Effective January 1, 2010, we adopted guidance issued by the FASB in June 2009 related to the consolidation of variable interest entities with no impact on our financial position, results of operations or cash flows.
In January 2010, the FASB issued an Accounting Standards Update ("ASU") that required two additional fair value measurement disclosures and clarifies two existing fair value measurement disclosures. The new disclosures require details of significant transfers in and out of Level 1 and Level 2 measurements and the reasons for the transfers, and a gross presentation of activity within the Level 3 roll forward that presents separately, information about purchases, sales, issuances and settlements. The ASU clarified the existing disclosures with regard to the level of disaggregation of fair value measurements by class of assets and liabilities rather than major category where the reporting entities would need to apply judgment to determine the appropriate classes of other assets and liabilities. The second clarification related to disclosures of valuation techniques and inputs for recurring and non-recurring fair value measurements using significant other observable inputs and significant unobservable inputs for Level 2 and Level 3 measurements, respectively. We adopted the ASU effective for our financial statements issued for interim and annual periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements which we adopted effective for interim and annual periods beginning after December 15, 2010. The adoption of the ASU has not had an impact on our financial position, results of operations or cash flows.
In May 2011, the FASB issued an ASU to improve comparability between US GAAP and International Financial Reporting Standards ("IFRS") fair value measurement and disclosure requirements. This amendment changes the wording used to describe many of the requirements in US GAAP for measuring fair value and for disclosing information about fair value measurements, particularly for Level 3 fair value measurements. For many of the requirements, the FASB does not intend for the amendments to result in a change in the application of the fair value measurement and disclosure requirements. Some of the amendments clarify the FASB's intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. This ASU is effective for interim and annual periods beginning after December 15, 2011. This ASU requires prospective application. We do not expect the adoption of this ASU to have a material impact on our financial position, results of operations or cash flows.
In December 2011, the FASB issued an ASU which requires companies to disclose information about financial instruments that have been offset and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. Companies will be required to provide both net (offset amounts) and gross information in the notes to the financial statements for relevant assets and liabilities that are offset. This update is effective for interim and annual periods beginning on or after January 1, 2013 and requires retrospective application. We do not expect the adoption of this ASU to have a material impact on our financial position, results of operations or cash flows.
4. Acquisitions and Dispositions
Greasewood Acquisition
On July 28, 2011, we completed the acquisition of crude oil properties in the Powder River Basin in eastern Wyoming (the "Greasewood Field") with an effective date of July 1, 2011 (the "Greasewood Acquisition"). We used borrowings under our credit facility to fund the Greasewood Acquisition. The Greasewood Field is 100% oil and produced approximately 605 Bbl/d net in fourth quarter of 2011. This transaction was accounted for using the acquisition method. The purchase price for the acquisition was approximately $57 million in cash, and was allocated to the assets acquired and liabilities assumed as follows:
Thousands of dollars | ||||
Oil and gas properties | $ | 57,515 | ||
Asset retirement obligation | (135 | ) | ||
$ | 57,380 |
The purchase price allocation is based on discounted cash flows, quoted market prices and estimates made by management, the most significant assumptions related to the estimated fair values assigned to oil and gas properties with proved reserves. To estimate the fair values of these properties, estimates of oil and 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
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proved reserves, the future net revenues were discounted using a rate of approximately 10%. There were no estimated quantities of hydrocarbons other than proved reserves allocated in the purchase price. Acquisition related costs for the Greasewood Acquisition were $0.1 million and were reflected in general and administrative expenses on the consolidated statements of operations.
In 2011, we recorded $7.4 million in sales revenue and $1.9 million in lease operating expenses, including production and property taxes, from the properties acquired in the Greasewood Acquisition.
Cabot Acquisition
On October 6, 2011, we completed the acquisition of oil and gas properties from Cabot Oil & Gas Corporation ("Cabot") located primarily in the Evanston and Green River Basins in southwestern Wyoming (the "Cabot Acquisition"), with an effective date of September 1, 2011. We used borrowings under our credit facility to fund the Cabot Acquisition. The assets acquired also include limited acreage and non-operated oil and gas interests in Colorado and Utah. These properties are 95% natural gas. These properties produced approximately 26 MMcfe/d net in fourth quarter of 2011. This transaction was accounted for under the acquisition method of accounting.
The preliminary purchase price of $281 million was allocated to the assets acquired and liabilities assumed as follows:
Thousands of dollars | ||||
Accounts receivable | $ | 767 | ||
Oil and gas properties | 294,500 | |||
Accounts payable | (197 | ) | ||
Revenue and royalties payable | (798 | ) | ||
Asset retirement obligation | (10,845 | ) | ||
Other long-term liabilities | (2,820 | ) | ||
$ | 280,607 |
The preliminary purchase price allocation is based on discounted cash flows, quoted market prices and estimates made by management, the most significant assumptions related to the estimated fair values assigned to oil and gas properties with proved reserves. To estimate the fair values of these properties, estimates of oil and 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 rate of approximately 10%. There were no estimated quantities of hydrocarbons other than proved reserves allocated in the preliminary purchase price. We will finalize the purchase price allocation within one year of the acquisition date. Acquisition related costs for the Cabot Acquisition were $0.6 million and were recorded in general and administrative expenses on the consolidated statements of operations.
In 2011, we recorded $9.1 million in sales revenue and $3.9 million in lease operating expenses, including production and property taxes, from the properties acquired in the Cabot Acquisition.
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The following unaudited pro forma financial information presents a summary of our combined statement of operations for the years ended December 31, 2011 and 2010, assuming the Cabot Acquisition had been completed on January 1, 2010, including adjustments to reflect the allocation of the preliminary purchase price to the acquired net assets. The pro forma financial information is not necessarily indicative of the results of operations if the acquisition had been effective January 1, 2010.
Pro Forma Year Ended December 31, | ||||||||
Thousands of dollars, except per unit amounts | 2011 | 2010 | ||||||
Revenues | $ | 520,048 | $ | 409,897 | ||||
Net income attributable to partnership | 120,195 | 44,498 | ||||||
Net income per unit: | ||||||||
Basic | $ | 1.95 | $ | 0.78 | ||||
Diluted | $ | 1.95 | $ | 0.78 |
Dispositions
On July 17, 2009, we sold the Lazy JL Field located in the Permian Basin of West Texas to a private buyer for $23 million in cash. This transaction was effective July 1, 2009. The Lazy JL Field properties produced approximately 245 Boe per day during the first six months of 2009, of which 96% was crude oil. The net carrying value at the date of sale was $28.5 million, of which $28.7 million was reflected in net property, plant and equipment on the balance sheet and $0.2 million was reflected in asset retirement obligation on the balance sheet. We recognized a loss of $5.5 million in 2009 related to the sale of the field.
5. Financial Instruments and Fair Value Measurements
Our risk management programs are intended to reduce our exposure to commodity prices and interest rates and to assist with stabilizing cash flows.
Commodity Activities
Due to the historical volatility of crude oil and natural gas prices, we have entered into various derivative instruments to manage exposure to volatility in the market price of crude oil and natural gas to achieve more predictable cash flows. We use swaps, collars and options for managing risk relating to commodity prices. All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement. While this strategy may result in us having lower revenues than we would otherwise have if we had not utilized these instruments in times of higher oil and natural gas prices, management believes that the resulting reduced volatility of prices and cash flow is beneficial. While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected.
The derivative instruments we utilize are based on index prices that may and often do differ from the actual crude oil and natural gas prices realized in our operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges under FASB Accounting Standards. Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial accounting purposes and instead recognize changes in the fair value immediately in earnings.
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We had the following oil contracts in place at December 31, 2011:
Year | ||||||||||||||||
2012 | 2013 | 2014 | 2015 | |||||||||||||
Oil Positions: | ||||||||||||||||
Fixed price swaps - NYMEX WTI | ||||||||||||||||
Hedged volume (Bbl/d) | 2,402 | 2,580 | 1,500 | 2,500 | ||||||||||||
Average price ($/Bbl) | $ | 86.84 | $ | 87.13 | $ | 88.33 | $ | 99.50 | ||||||||
Fixed price swaps - IPE Brent | ||||||||||||||||
Hedged volume (Bbl/d) | 2,637 | 3,900 | 3,500 | 1,000 | ||||||||||||
Average price ($/Bbl) | $ | 105.46 | $ | 97.23 | $ | 96.86 | $ | 94.05 | ||||||||
Collars - NYMEX WTI | ||||||||||||||||
Hedged volume (Bbl/d) | 2,477 | 500 | 1,000 | 1,000 | ||||||||||||
Average floor price ($/Bbl) | $ | 110.00 | $ | 77.00 | $ | 90.00 | $ | 90.00 | ||||||||
Average ceiling price ($/Bbl) | $ | 145.39 | $ | 103.10 | $ | 112.00 | $ | 113.50 | ||||||||
Total: | ||||||||||||||||
Hedged volume (Bbl/d) | 7,516 | 6,980 | 6,000 | 4,500 | ||||||||||||
Average price ($/Bbl) | $ | 101.00 | $ | 92.05 | $ | 93.58 | $ | 96.18 |
In the fourth quarter of 2011, in order to improve the effectiveness of our hedge portfolio, we terminated certain crude oil fixed price swaps at NYMEX WTI prices for a total termination cost of $36.8 million and entered into new crude oil fixed price swaps for the same volumes and periods at IPE Brent prices. These transactions are reflected in the summary of oil commodity derivatives table above.
We had the following natural gas contracts in place at December 31, 2011:
Year | ||||||||||||||||
2012 | 2013 | 2014 | 2015 | |||||||||||||
Gas Positions: | ||||||||||||||||
Fixed price swaps - Mich Con City-Gate | ||||||||||||||||
Hedged volume (MMBtu/d) | 19,128 | 37,000 | 7,500 | 7,500 | ||||||||||||
Average Price ($/MMBtu) | $ | 7.10 | $ | 6.50 | $ | 6.00 | $ | 6.00 | ||||||||
Fixed price swaps - Henry Hub | ||||||||||||||||
Hedged volume (MMBtu/d) | 16,000 | 19,000 | 23,000 | 23,000 | ||||||||||||
Average price ($/MMBtu) | $ | 4.88 | $ | 4.90 | $ | 5.24 | $ | 5.41 | ||||||||
Collars - Mich Con City-Gate | ||||||||||||||||
Hedged volume (MMBtu/d) | 19,129 | — | — | — | ||||||||||||
Average floor price ($/MMBtu) | $ | 9.00 | $ | — | $ | — | $ | — | ||||||||
Average ceiling price ($/MMBtu) | $ | 11.89 | $ | — | $ | — | $ | — | ||||||||
Total: | ||||||||||||||||
Hedged volume (MMBtu/d) | 54,257 | 56,000 | 30,500 | 30,500 | ||||||||||||
Average price ($/MMBtu) | $ | 7.12 | $ | 5.96 | $ | 5.43 | $ | 5.55 | ||||||||
Calls - Henry Hub | ||||||||||||||||
Hedged volume (MMBtu/d) | — | — | 30,000 | 15,000 | — | |||||||||||
Average price ($/MMBtu) | — | $ | — | $ | 8.00 | $ | 9.00 | $ | — | |||||||
Premium ($/MMBtu) | $ | — | $ | 0.08 | $ | 0.12 | $ | — |
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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. As of December 31, 2011, our total debt outstanding under our credit facility was $520 million. In order to mitigate our interest rate exposure, we had the following interest rate swaps, indexed to 1-month LIBOR, in place at December 31, 2011, to fix a portion of floating LIBOR-base debt under our credit facility:
Notional amounts in thousands of dollars | Notional Amount | Fixed Rate | ||||
Period Covered | ||||||
January 1, 2012 to December 20, 2012 | 100,000 | 1.1550 | % | |||
January 20, 2012 to January 20, 2014 | 100,000 | 2.4800 | % |
We do not currently designate any of our interest rate derivatives as hedges for financial accounting purposes.
Fair Value of Financial Instruments
FASB Accounting Standards require disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The required disclosures are detailed below.
Fair value of derivative instruments not designated as hedging instruments:
Balance sheet location, thousands of dollars | Oil Commodity Derivatives | Natural Gas Commodity Derivatives | Interest Rate Derivatives | Commodity Derivatives Netting (a) | Total Financial Instruments | |||||||||||||||
As of December 31, 2011 | ||||||||||||||||||||
Assets | ||||||||||||||||||||
Current assets - derivative instruments | $ | 11,795 | $ | 73,312 | $ | — | $ | (1,655 | ) | $ | 83,452 | |||||||||
Other long-term assets - derivative instruments | 6,032 | 58,605 | — | (9,300 | ) | 55,337 | ||||||||||||||
Total assets | 17,827 | 131,917 | — | (10,955 | ) | 138,789 | ||||||||||||||
Liabilities | ||||||||||||||||||||
Current liabilities - derivative instruments | (8,032 | ) | — | (2,504 | ) | 1,655 | (8,881 | ) | ||||||||||||
Long-term liabilities - derivative instruments | (10,520 | ) | — | (1,864 | ) | 9,300 | (3,084 | ) | ||||||||||||
Total liabilities | (18,552 | ) | — | (4,368 | ) | 10,955 | (11,965 | ) | ||||||||||||
Net assets (liabilities) | $ | (725 | ) | $ | 131,917 | $ | (4,368 | ) | $ | — | $ | 126,824 | ||||||||
As of December 31, 2010 | ||||||||||||||||||||
Assets | ||||||||||||||||||||
Current assets - derivative instruments | $ | 9,438 | $ | 48,972 | $ | — | $ | (3,658 | ) | $ | 54,752 | |||||||||
Other long-term assets - derivative instruments | 15,785 | 55,806 | — | (20,939 | ) | 50,652 | ||||||||||||||
Total assets | 25,223 | 104,778 | — | (24,597 | ) | 105,404 | ||||||||||||||
Liabilities | ||||||||||||||||||||
Current liabilities - derivative instruments | (37,610 | ) | — | (3,119 | ) | 3,658 | (37,071 | ) | ||||||||||||
Long-term liabilities - derivative instruments | (58,766 | ) | (166 | ) | (1,729 | ) | 20,939 | (39,722 | ) | |||||||||||
Total liabilities | (96,376 | ) | (166 | ) | (4,848 | ) | 24,597 | (76,793 | ) | |||||||||||
Net assets (liabilities) | $ | (71,153 | ) | $ | 104,612 | $ | (4,848 | ) | $ | — | $ | 28,611 |
(a) Represents counterparty netting under derivative netting agreements - these contracts are reflected net on the balance sheet.
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Gains and losses on derivative instruments not designated as hedging instruments:
Location of gain/loss, thousands of dollars | Oil Commodity Derivatives (a) | Natural Gas Commodity Derivatives (a) | Interest Rate Derivatives (b) | Total Financial Instruments | ||||||||||||
Year Ended December 31, 2011 | ||||||||||||||||
Realized gain (loss) | $ | (70,398 | ) | $ | 54,331 | $ | (3,257 | ) | $ | (19,324 | ) | |||||
Unrealized gain | 70,430 | 27,304 | 480 | 98,214 | ||||||||||||
Net gain (loss) | $ | 32 | $ | 81,635 | $ | (2,777 | ) | $ | 78,890 | |||||||
Year Ended December 31, 2010 | ||||||||||||||||
Realized gain (loss) | $ | 11,252 | $ | 63,573 | $ | (11,087 | ) | $ | 63,738 | |||||||
Unrealized gain (loss) | (62,239 | ) | 22,526 | 6,597 | (33,116 | ) | ||||||||||
Net gain (loss) | $ | (50,987 | ) | $ | 86,099 | $ | (4,490 | ) | $ | 30,622 | ||||||
Year Ended December 31, 2009 | ||||||||||||||||
Realized gain (loss) | $ | 66,176 | $ | 101,507 | $ | (13,115 | ) | $ | 154,568 | |||||||
Unrealized gain (loss) | (195,127 | ) | (23,993 | ) | 5,869 | (213,251 | ) | |||||||||
Net gain (loss) | $ | (128,951 | ) | $ | 77,514 | $ | (7,246 | ) | $ | (58,683 | ) |
(a) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations.
(b) Included in loss on interest rate swaps on the consolidated statements of operations.
In January 2009, we terminated a portion of our 2011 and 2012 crude oil and natural gas derivative contracts and replaced them with new contracts with the same counterparty for the same volumes at market prices. We realized gains of $32.3 million from the termination of crude oil contracts and $13.3 million from the termination of natural gas contracts.
In June 2009, we terminated an additional portion of our 2011 and 2012 crude oil and natural gas derivative contracts and replaced them with new contracts for the same volumes at market prices. We realized gains of $6.1 million from the termination of crude oil contracts and $18.9 million from the termination of natural gas derivative contracts.
In the fourth quarter of 2011, we terminated certain crude oil fixed price swaps at NYMEX WTI prices and entered into new crude oil fixed price swaps for the same volumes and periods at IPE Brent prices. We realized losses of $36.8 million from the terminations.
FASB Accounting Standards define fair value, establish a framework for measuring fair value and establish required disclosures about fair value measurements. They also establish a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are. We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third party market participants. We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements. The fair value hierarchy gives the highest priority of Level 1 to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 to unobservable inputs. We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are. The three levels of inputs are described further as follows:
Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2 – Inputs other than quoted prices that are included in Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. We consider the over the counter ("OTC") commodity and interest rate swaps in our portfolio to be Level 2. Level 3 – Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Certain OTC derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. As of December 31, 2011 and 2010, our Level 3 derivative assets and liabilities consisted entirely of OTC commodity put and call options.
F-18
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 years ended December 31, 2011, 2010 and 2009. 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 that we receive from the 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 models include fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity forward price curves, volatility and interest rate factors and time to expiry. Model inputs are obtained from our counterparties and third party data providers and are verified to published data where available (e.g., NYMEX). Additional inputs to our Level 3 derivatives 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 derivatives, and inputs include LIBOR forward interest rates, one-month LIBOR rates and risk-free interest rates for present value discounting.
Assumed credit risk adjustments, based on published credit ratings and credit default swap rates, are applied to our derivative instruments.
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:
As of December 31, 2011 | ||||||||||||||||
Thousands of dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets (liabilities): | ||||||||||||||||
Commodity derivatives (swaps, put and call options) | $ | — | $ | 85,634 | $ | 45,558 | $ | 131,192 | ||||||||
Other derivatives (interest rate swaps) | — | (4,368 | ) | — | (4,368 | ) | ||||||||||
Total | $ | — | $ | 81,266 | $ | 45,558 | $ | 126,824 | ||||||||
As of December 31, 2010 | ||||||||||||||||
Thousands of dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets (liabilities): | ||||||||||||||||
Commodity derivatives (swaps, put and call options) | $ | — | $ | (52,794 | ) | $ | 86,253 | $ | 33,459 | |||||||
Other derivatives (interest rate swaps) | — | (4,848 | ) | — | (4,848 | ) | ||||||||||
Total | $ | — | $ | (57,642 | ) | $ | 86,253 | $ | 28,611 |
The following table sets forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3:
Year Ended December 31, | ||||||||||||
Thousands of dollars | 2011 | 2010 | 2009 | |||||||||
Assets (liabilities): | ||||||||||||
Beginning balance | $ | 86,253 | $ | 102,475 | $ | 153,218 | ||||||
Realized gain (a) | 44,286 | 26,732 | 19,062 | |||||||||
Unrealized loss (a) | (84,981 | ) | (42,954 | ) | (63,775 | ) | ||||||
Settlements (b) | — | — | (6,030 | ) | ||||||||
Ending balance | $ | 45,558 | $ | 86,253 | $ | 102,475 |
(a) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations.
(b) Settlements reflect the monetization of oil collar contracts in June 2009.
F-19
Credit and Counterparty Risk
Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of December 31, 2011, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, U.S Bank National Association and Toronto-Dominion Bank. Our counterparties are all lenders under our Amended and Restated Credit Agreement. Our credit agreement is secured by our crude oil, natural gas and NGL reserves, so we are not required to post any collateral, and we conversely do not receive collateral from our counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty's financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. 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 fail to perform in accordance with the terms of the contract. This risk is managed by diversifying our derivatives portfolio. As of December 31, 2011, each of these financial institutions had an investment grade credit rating. As of December 31, 2011, our largest derivative asset balances were with JP Morgan Chase Bank N.A., Union Bank N.A and Wells Fargo Bank National Association which accounted for approximately 37%, 10% and 10% of our derivative asset balances, respectively. As of December 31, 2011, our largest derivative liability balances were with BNP Paribas, The Royal Bank of Scotland plc and Citibank, N.A. which accounted for approximately 34%, 31% and 22% of our derivative liability balances, respectively.
6. Related Party Transactions
BreitBurn Management 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.
On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark Capital Partners ("Metalmark"), Greenhill Capital Partners ("Greenhill") and a third-party institutional investor, completed the acquisition of PCEC. This transaction included the acquisition of a 96.02% indirect interest in PCEC, previously owned by Provident Energy Trust ("Provident"), and the remaining indirect interests in PCEC, previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of our senior management. PCEC is a separate Delaware oil and gas partnership with operations in California, was a separate U.S. subsidiary of Provident and was our Predecessor.
In connection with the acquisition of Provident’s ownership in PCEC by members of senior management, Metalmark, Greenhill and a third party institutional investor, BreitBurn Management entered into the Second Amended and Restated Administrative Services Agreement (the "Administrative Services Agreement") to manage PCEC's properties for a term of five years. In addition to a monthly fee for indirect expenses, BreitBurn Management charges PCEC for all direct expenses including incentive plan costs and direct payroll and administrative costs related to PCEC properties and operations. The monthly fee is contractually based on an annual projection of anticipated time spent by each employee who provides services to both us and PCEC during the ensuing year and is subject to renegotiation annually by the parties during the term of the agreement. Beginning in 2009, each BreitBurn Management employee estimated his or her time allocation independently. These estimates were then reviewed and approved by each employee’s manager or supervisor. The results of this process were provided to both the audit committee of the board of directors of our General Partner (composed entirely of independent directors) (the "audit committee") and the board of representatives of PCEC’s parent (the "PCEC board"). The audit committee and the non-management members of the PCEC board agreed on the monthly fee as provided in the Administrative Services Agreement. The monthly fees for 2011, 2010 and 2009 were set at $481,000, $456,000 and $500,000, respectively.
In addition, we entered into an Omnibus Agreement with PCEC detailing rights with respect to business opportunities and providing us with a right of first offer with respect to the sale of assets by PCEC.
At December 31, 2011 and December 31, 2010, we had net current receivables of $2.8 million and $3.2 million, respectively, due from PCEC related to the Administrative Services Agreement and employee related costs and oil and gas sales made by PCEC on our behalf from certain properties. During 2011, the monthly charges to PCEC for indirect expenses totaled $5.8 million and charges for direct expenses including direct payroll and administrative costs totaled $9.0 million. During 2011, net oil and gas sales made by PCEC on our behalf were approximately $13.9 million. During 2010, the monthly charges to PCEC for indirect expenses totaled $5.4 million and charges for direct expenses including direct payroll and administrative costs totaled $6.2 million. During 2010, net oil and gas sales made by PCEC on our behalf were approximately $10.3 million. During 2009, the monthly charges to BEC for indirect expenses totaled $6.5 million and charges for direct expenses including direct payroll and administrative costs totaled $6.1 million. During 2009, net oil and gas sales made by BEC on our behalf were
F-20
approximately $7.9 million.
At December 31, 2011 and December 31, 2010, we had receivables of $1.4 million and $0.4 million 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.
Quicksilver buys natural gas from us in Michigan. For the year ended December 31, 2011, total net gas sales to Quicksilver were approximately $3.9 million. For the year ended December 31, 2010, total net gas sales to Quicksilver were approximately $3.4 million and the related receivable as of December 31, 2010 was $0.7 million. As of December 31, 2011, Quicksilver was no longer a related party.
7. Inventory
In Florida, crude oil inventory was $4.7 million and $7.3 million at December 31, 2011and 2010, respectively. For the year ended December 31, 2011, we sold 862 MBbls of crude oil and produced 782 MBbls from our Florida operations. For the year ended December 31, 2010, we sold 689 MBbls of crude oil and produced 734 MBbls 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 at cost and represent our production costs. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded to inventory.
We carry inventory at the lower of cost or market. When using lower of cost or market to value inventory, market should not exceed the net realizable value or the estimated selling price less costs of completion and disposal. We assessed our crude oil inventory at December 31, 2011 and December 31, 2010 and determined that the carrying value of our inventory was below market value and, therefore, no write-down was necessary.
For our properties in Florida, there are a limited number of alternative methods of transportation for our production. Substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs, or involuntary curtailment of our oil production, which could have a negative impact on our future consolidated financial position, results of operations and cash flows.
8. Equity Investments
We had equity investments at December 31, 2011 and December 31, 2010 totaling $7.5 million and $7.7 million, respectively, which primarily represent investments in natural gas processing facilities. For the years ended December 31, 2011 and 2010, we recorded $0.7 million in each period in earnings from equity investments and $0.9 million and $1.2 million, respectively, in dividends. For the year ended December 31, 2009, we recorded less than $0.1 million in earnings from equity investments and $1.4 million in dividends. Earnings from equity investments are reported in other revenue, net on the consolidated statements of operations.
At December 31, 2011, our equity investments consisted primarily of a 24.5% limited partner interest and a 25.5% general partner interest in Wilderness Energy Services LP, with a combined carrying value of $6.4 million. The remaining $1.1 million consists of smaller interests in several other investments where we have significant influence.
9. Impairments and Price Related Depletion and Depreciation Adjustments
We assess our developed and undeveloped oil and gas properties and other long-lived assets for possible impairment periodically and whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.
Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for market supply and demand conditions for crude oil and natural gas. We consider the inputs for our impairments calculations to be Level 3 inputs. The impairment reviews and calculations are based on assumptions that are consistent with our business plans.
F-21
During the year ended December 31, 2011, we recorded impairments of approximately $0.6 million related to uneconomic proved properties in Michigan primarily due to a decrease in natural gas prices. During the year ended December 31, 2010, we recorded impairments of approximately $6.3 million related to our Eastern region properties, including a $4.2 million write-down of uneconomic proved properties and a $2.1 million write-down of expired unproved lease properties. For the year ended December 31, 2009, we reviewed our long-lived oil and gas assets and did not record any material impairments or price related adjustments to depletion and depreciation expense.
An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable, given the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.
10. Long-Term Debt
Senior Notes Due 2020
On October 6, 2010, we and BreitBurn Finance Corporation (the "Issuers"), and certain of our subsidiaries as guarantors (the "Guarantors"), issued $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the "2020 Senior Notes"). The 2020 Senior Notes were sold pursuant to a private placement exemption from the Securities Act of 1933, as amended (the "Securities Act") to a group of initial purchasers" and then resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. In connection with the issuance of the 2020 Senior Notes, on January 19, 2011, the Issuers filed a registration statement on Form S-4 with the SEC with respect to an offer to exchange the 2020 Senior Notes for substantially identical notes that are registered under the Securities Act. On February 17, 2011, the exchange registration statement became effective and we commenced the exchange offer, which was completed on March 30, 2011.
We received net proceeds of approximately $291.2 million (after deducting estimated fees and offering expenses). We used $290 million of the net proceeds to repay amounts outstanding under our credit facility. In connection with the 2020 Senior Notes, we incurred financing fees and expenses of approximately $8.8 million, which will be amortized over the life of the 2020 Senior Notes. The 2020 Senior Notes were offered at a discount price of 98.358%, or $300 million. The $5 million discount will be amortized straight-line over the life of the 2020 Senior Notes.
As of December 31, 2011 and 2010, the 2020 Senior Notes had a carrying value of $300.6 million and $300.1 million, respectively, net of an unamortized discount of $4.4 million and $4.9 million, respectively. As of December 31, 2011 and 2010, the fair value of the 2020 Senior Notes was estimated to be $320 million and $307 million, respectively, based on prices quoted from third-party financial institutions.
Credit Facility
On November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as borrower, and we and our wholly owned subsidiaries, as guarantors, entered into a four year, amended and restated revolving credit facility with Wells Fargo Bank, N.A., Credit Suisse Securities (USA) LLC and a syndicate of banks (the "Amended and Restated Credit Agreement"). On May 7, 2010, BOLP, as borrower, and we and our wholly-owned subsidiaries, as guarantors, entered into the Second Amended and Restated Credit Agreement, a four-year, $1.5 billion revolving credit facility with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (the "Second Amended and Restated Credit Agreement"). The Second Amended and Restated Credit Agreement set our borrowing base at $735 million and extended the maturity date to May 7, 2014.
On September 17, 2010, we entered into the First Amendment to the Second Amended and Restated Credit Agreement, which included a consent to the formation of a new wholly owned subsidiary, Utica, and its designation as an unrestricted subsidiary under our credit facility. Utica is not a guarantor of indebtedness under our credit facility. As a result of the issuance of the 2020 Senior Notes on October 6, 2010, our borrowing base was automatically reduced to $658.8 million.
On May 9, 2011, we entered into the Second Amendment to the Second Amended and Restated Credit Agreement (the "Second Amendment"), which increased our borrowing base to $735 million and extended the maturity date to May 9, 2016. The Second Amendment also revised certain covenants in the credit facility, which included: eliminating the interest coverage ratio and the "borrowing base availability" test (applied prior to making distributions to unitholders or making other restricted payments); increasing the maximum leverage coverage ratio to 4.00 to 1.00 from 3.75 to 1.00; increasing our ability to incur or
F-22
guaranty an additional $350 million of unsecured senior notes (subject to our borrowing base being reduced by 25% of the original stated principal amount of such new debt); and adjusting the pricing grid by decreasing the applicable margins (as defined in the Second Amended and Restated Credit Agreement) by 25 basis points.
On August 3, 2011, we entered into the Third Amendment (the "Third Amendment") to the Second Amended and Restated Credit Agreement, which permits us to hedge oil and gas volumes for properties for which we have entered into a purchase agreement prior to closing the transaction. The Third Amendment also provides that such hedges must be terminated in the event that the acquisition does not close within 90 days of the execution of such purchase agreement.
On October 5, 2011, in connection with the completion of the Cabot Acquisition, we entered into the Fourth Amendment (the "Fourth Amendment") to the Second Amended and Restated Credit Agreement. The Fourth Amendment provides for an increase in the volume of permitted gas imbalances under the Credit Agreement from 300 MMcf to 1,000 MMcf
On October 11, 2011, our semi-annual borrowing base redetermination resulted in our borrowing base being set at $850 million.
As of December 31, 2011 and December 31, 2010, we had $520.0 million and $228.0 million, respectively, in indebtedness outstanding under the credit facility. At December 31, 2011, the 1-month LIBOR interest rate plus an applicable spread was 2.550% on the 1-month LIBOR portion of $518.0 million and the prime rate plus an applicable spread was 4.500% on the prime debt portion of $2.0 million. The amounts reported on our consolidated balance sheets for long-term debt approximate fair value due to the variable nature of our interest rates.
Borrowings under the Second Amended and Restated Credit Agreement are secured by first-priority liens on and security interests in substantially all of our and certain of our subsidiaries’ assets, representing not less than 80% of the total value of our oil and gas properties.
The Second Amended and Restated Credit Agreement contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders or repurchase units (including the restriction on our ability to make distributions unless, after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.
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, depletion, depreciation and amortization, unrealized loss or gain on derivative instruments, non-cash charges, including non-cash unit based compensation expense, loss or gain on sale of assets (excluding gain or loss on monetization of derivative instruments), cumulative effect of changes in accounting principles, cash distributions received from our unrestricted entities (as defined in the Second Amended and Restated Credit Agreement) and BreitBurn Energy Partners I, L.P. ("BEPI") and excluding income from our unrestricted entities and BEPI. All calculations of EBITDAX, for any applicable period during which a permitted acquisition or disposition is consummated, are determined on a pro forma basis as if such acquisition or disposition was consummated on the first day of such applicable period.
The Second Amended and Restated Credit Agreement also permits us to terminate derivative contracts without obtaining the consent of the lenders in the facility, provided that the net effect of such termination plus the aggregate value of all dispositions of oil and gas properties made during such period, together, does not exceed 5% of the borrowing base, and the borrowing base will be automatically reduced by an amount equal to the net effect of the termination.
The events that constitute an Event of Default (as defined in the Second Amended and Restated Credit Agreement) include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain other indebtedness; adverse judgments against us in excess of a specified amount; changes in management or control; loss of permits; certain insolvency events; and assertion of certain environmental claims.
F-23
Interest Expense
Our interest expense is detailed in the following table:
Year Ended December 31, | ||||||||||||
Thousands of dollars | 2011 | 2010 | 2009 | |||||||||
Credit facility (including commitment fees) | $ | 8,266 | $ | 13,060 | $ | 15,532 | ||||||
Senior notes | 26,233 | 6,284 | — | |||||||||
Amortization of discount and deferred issuance costs | 4,743 | 5,478 | 3,295 | |||||||||
Capitalized interest | (77 | ) | (270 | ) | — | |||||||
Total | $ | 39,165 | $ | 24,552 | $ | 18,827 | ||||||
Cash paid for interest | $ | 37,756 | $ | 23,755 | $ | 28,350 |
11. Condensed Consolidating Financial Statements
Given that certain, but not all, of our subsidiaries have issued full, unconditional and joint and several guarantees of our Senior Notes, in accordance with Rule 3-10(d) of Regulation S-X, the following presents condensed consolidating financial information as of December 31, 2011 and 2010, and for the years ended December 31, 2011, 2010 and 2009 on a parent/co-issuer, guarantor subsidiaries, non-guarantor subsidiaries, eliminating entries, and consolidated basis. Such subsidiary guarantees may be released under certain circumstances including the sale of the subsidiary or its assets. All subsidiaries are reflected on an equity method basis. Eliminating entries presented are necessary to combine the parent/co-issuer, guarantor subsidiaries and non-guarantor subsidiaries. For purposes of the following tables, we and BreitBurn Finance Corporation are referred to as "Parent/Co-Issuer" and the "Guarantor Subsidiaries" are all of our subsidiaries other than BEPI and Utica (together the "Non-Guarantor Subsidiaries").
F-24
Condensed Consolidating Balance Sheets
As of December 31, 2011 | ||||||||||||||||||||
Thousands of dollars | Parent/ Co-Issuer | Combined Guarantor Subsidiaries | Combined Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
ASSETS | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash | $ | 61 | $ | 1,952 | $ | 3,315 | $ | — | $ | 5,328 | ||||||||||
Accounts and other receivables, net | 10,363 | 60,519 | 2,136 | — | 73,018 | |||||||||||||||
Derivative instruments | — | 83,452 | — | — | 83,452 | |||||||||||||||
Related party receivables | — | 4,245 | — | — | 4,245 | |||||||||||||||
Inventory | — | 4,724 | — | — | 4,724 | |||||||||||||||
Prepaid expenses | — | 2,053 | — | — | 2,053 | |||||||||||||||
Total current assets | 10,424 | 156,945 | 5,451 | — | 172,820 | |||||||||||||||
Investments in subsidiaries | 1,382,929 | 30,809 | — | (1,413,738 | ) | — | ||||||||||||||
Intercompany receivables (payables) | 225,129 | (221,324 | ) | (3,805 | ) | — | — | |||||||||||||
Equity investments | — | 7,491 | — | — | 7,491 | |||||||||||||||
Property, plant and equipment | ||||||||||||||||||||
Oil and gas properties | 8,467 | 2,521,908 | 53,618 | — | 2,583,993 | |||||||||||||||
Other assets | — | 13,431 | — | — | 13,431 | |||||||||||||||
8,467 | 2,535,339 | 53,618 | — | 2,597,424 | ||||||||||||||||
Accumulated depletion and depreciation | (1,424 | ) | (509,034 | ) | (14,207 | ) | — | (524,665 | ) | |||||||||||
Net property, plant and equipment | 7,043 | 2,026,305 | 39,411 | — | 2,072,759 | |||||||||||||||
Other long-term assets | ||||||||||||||||||||
Derivative instruments | — | 55,337 | — | — | 55,337 | |||||||||||||||
Other long-term assets | 7,855 | 14,511 | 76 | — | 22,442 | |||||||||||||||
Total assets | $ | 1,633,380 | $ | 2,070,074 | $ | 41,133 | $ | (1,413,738 | ) | $ | 2,330,849 | |||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable | $ | 5,845 | $ | 25,764 | $ | 1,885 | $ | — | $ | 33,494 | ||||||||||
Derivative instruments | — | 8,881 | — | — | 8,881 | |||||||||||||||
Revenue and royalties payable | — | 17,961 | 1,680 | — | 19,641 | |||||||||||||||
Salaries and wages payable | — | 13,655 | — | — | 13,655 | |||||||||||||||
Accrued liabilities | — | 13,683 | 535 | — | 14,218 | |||||||||||||||
Total current liabilities | 5,845 | 79,944 | 4,100 | — | 89,889 | |||||||||||||||
Credit facility | — | 520,000 | — | — | 520,000 | |||||||||||||||
Senior notes, net | 300,613 | — | — | — | 300,613 | |||||||||||||||
Deferred income taxes | — | 2,803 | — | — | 2,803 | |||||||||||||||
Asset retirement obligation | — | 76,465 | 5,932 | — | 82,397 | |||||||||||||||
Derivative instruments | — | 3,084 | — | — | 3,084 | |||||||||||||||
Other long-term liabilities | — | 4,849 | — | — | 4,849 | |||||||||||||||
Total liabilities | 306,458 | 687,145 | 10,032 | — | 1,003,635 | |||||||||||||||
Equity: | ||||||||||||||||||||
Partners' equity | 1,326,922 | 1,382,929 | 31,101 | (1,414,188 | ) | 1,326,764 | ||||||||||||||
Noncontrolling interest | — | — | — | 450 | 450 | |||||||||||||||
Total equity | 1,326,922 | 1,382,929 | 31,101 | (1,413,738 | ) | 1,327,214 | ||||||||||||||
Total liabilities and equity | $ | 1,633,380 | $ | 2,070,074 | $ | 41,133 | $ | (1,413,738 | ) | $ | 2,330,849 |
F-25
Condensed Consolidating Balance Sheets
As of December 31, 2010 | ||||||||||||||||||||
Thousands of dollars | Parent/ Co-Issuer | Combined Guarantor Subsidiaries | Combined Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
ASSETS | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash | $ | 70 | $ | 1,836 | $ | 1,724 | $ | — | $ | 3,630 | ||||||||||
Accounts and other receivables, net | 10,000 | 41,945 | 1,575 | — | 53,520 | |||||||||||||||
Derivative instruments | — | 54,752 | — | — | 54,752 | |||||||||||||||
Related party receivables | — | 4,345 | — | — | 4,345 | |||||||||||||||
Inventory | — | 7,321 | — | — | 7,321 | |||||||||||||||
Prepaid expenses | 877 | 859 | — | — | 1,736 | |||||||||||||||
Total current assets | 10,947 | 111,058 | 3,299 | — | 125,304 | |||||||||||||||
Investments in subsidiaries | 1,243,910 | 30,647 | — | (1,274,557 | ) | — | ||||||||||||||
Intercompany receivables (payables) | 245,323 | (242,011 | ) | (3,312 | ) | — | — | |||||||||||||
Equity investments | — | 7,700 | — | — | 7,700 | |||||||||||||||
Property, plant and equipment | ||||||||||||||||||||
Oil and gas properties | 8,467 | 2,076,074 | 48,558 | — | 2,133,099 | |||||||||||||||
Other assets | — | 10,832 | — | — | 10,832 | |||||||||||||||
8,467 | 2,086,906 | 48,558 | — | 2,143,931 | ||||||||||||||||
Accumulated depletion and depreciation | (1,014 | ) | (408,850 | ) | (11,772 | ) | — | (421,636 | ) | |||||||||||
Net property, plant and equipment | 7,453 | 1,678,056 | 36,786 | — | 1,722,295 | |||||||||||||||
Other long-term assets | ||||||||||||||||||||
Derivative instruments | — | 50,652 | — | — | 50,652 | |||||||||||||||
Other long-term assets | 7,746 | 16,394 | 76 | — | 24,216 | |||||||||||||||
Total assets | $ | 1,515,379 | $ | 1,652,496 | $ | 36,849 | $ | (1,274,557 | ) | $ | 1,930,167 | |||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable | $ | 6,300 | $ | 19,566 | $ | 942 | $ | — | $ | 26,808 | ||||||||||
Derivative instruments | — | 37,071 | — | — | 37,071 | |||||||||||||||
Related party payables | — | — | — | — | — | |||||||||||||||
Revenue and royalties payable | — | 15,016 | 1,411 | — | 16,427 | |||||||||||||||
Salaries and wages payable | — | 12,594 | — | — | 12,594 | |||||||||||||||
Accrued liabilities | — | 7,912 | 505 | — | 8,417 | |||||||||||||||
Total current liabilities | 6,300 | 92,159 | 2,858 | — | 101,317 | |||||||||||||||
Credit facility | — | 228,000 | — | — | 228,000 | |||||||||||||||
Senior notes, net | 300,116 | — | — | — | 300,116 | |||||||||||||||
Deferred income taxes | — | 2,089 | — | — | 2,089 | |||||||||||||||
Asset retirement obligation | — | 44,379 | 3,050 | — | 47,429 | |||||||||||||||
Derivative instruments | — | 39,722 | — | — | 39,722 | |||||||||||||||
Other long-term liabilities | — | 2,237 | — | — | 2,237 | |||||||||||||||
Total liabilities | 306,416 | 408,586 | 5,908 | — | 720,910 | |||||||||||||||
Equity: | ||||||||||||||||||||
Partners' equity | 1,208,963 | 1,243,910 | 30,941 | (1,275,011 | ) | 1,208,803 | ||||||||||||||
Noncontrolling interest | — | — | — | 454 | 454 | |||||||||||||||
Total equity | 1,208,963 | 1,243,910 | 30,941 | (1,274,557 | ) | 1,209,257 | ||||||||||||||
Total liabilities and equity | $ | 1,515,379 | $ | 1,652,496 | $ | 36,849 | $ | (1,274,557 | ) | $ | 1,930,167 | |||||||||
F-26
Condensed Consolidating Statements of Operations
Year Ended December 31, 2011 | ||||||||||||||||||||
Thousands of dollars | Parent/ Co-Issuer | Combined Guarantor Subsidiaries | Combined Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Revenues and other income items: | ||||||||||||||||||||
Oil, natural gas and natural gas liquid sales | $ | — | $ | 361,433 | $ | 32,960 | $ | — | $ | 394,393 | ||||||||||
Gain on commodity derivative instruments, net | — | 81,667 | — | — | 81,667 | |||||||||||||||
Other revenue, net | — | 4,310 | — | — | 4,310 | |||||||||||||||
Total revenues and other income items | — | 447,410 | 32,960 | — | 480,370 | |||||||||||||||
Operating costs and expenses: | ||||||||||||||||||||
Operating costs | — | 155,588 | 10,381 | — | 165,969 | |||||||||||||||
Depletion, depreciation and amortization | 410 | 104,407 | 2,686 | — | 107,503 | |||||||||||||||
General and administrative expenses | 596 | 52,711 | 6 | — | 53,313 | |||||||||||||||
Gain on sale of assets | — | (111 | ) | — | — | (111 | ) | |||||||||||||
Unreimbursed litigation costs | (113 | ) | — | — | — | (113 | ) | |||||||||||||
Total operating costs and expenses | 893 | 312,595 | 13,073 | — | 326,561 | |||||||||||||||
Operating income (loss) | (893 | ) | 134,815 | 19,887 | — | 153,809 | ||||||||||||||
Interest expense, net | 27,608 | 11,557 | — | — | 39,165 | |||||||||||||||
Loss on interest rate swaps | — | 2,777 | — | — | 2,777 | |||||||||||||||
Other income, net | — | (16 | ) | (3 | ) | — | (19 | ) | ||||||||||||
Income (loss) before taxes | (28,501 | ) | 120,497 | 19,890 | — | 111,886 | ||||||||||||||
Income tax expense | 27 | 1,158 | 3 | — | 1,188 | |||||||||||||||
Equity in earnings of subsidiaries | 139,023 | 19,684 | — | (158,707 | ) | — | ||||||||||||||
Net income | 110,495 | 139,023 | 19,887 | (158,707 | ) | 110,698 | ||||||||||||||
Less: Net income attributable to noncontrolling interest | — | — | — | (201 | ) | (201 | ) | |||||||||||||
Net income attributable to the partnership | $ | 110,495 | $ | 139,023 | $ | 19,887 | $ | (158,908 | ) | $ | 110,497 |
F-27
Condensed Consolidating Statements of Operations
Year Ended December 31, 2010 | ||||||||||||||||||||
Thousands of dollars | Parent/ Co-Issuer | Combined Guarantor Subsidiaries | Combined Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Revenues and other income items: | ||||||||||||||||||||
Oil, natural gas and natural gas liquid sales | $ | — | $ | 293,432 | $ | 24,306 | $ | — | $ | 317,738 | ||||||||||
Gain on commodity derivative instruments, net | — | 35,112 | — | — | 35,112 | |||||||||||||||
Other revenue, net | — | 2,498 | — | — | 2,498 | |||||||||||||||
Total revenues and other income items | — | 331,042 | 24,306 | — | 355,348 | |||||||||||||||
Operating costs and expenses: | ||||||||||||||||||||
Operating costs | — | 132,701 | 9,824 | — | 142,525 | |||||||||||||||
Depletion, depreciation and amortization | 416 | 99,874 | 2,468 | — | 102,758 | |||||||||||||||
General and administrative expenses | 443 | 44,448 | 16 | — | 44,907 | |||||||||||||||
Loss on sale of assets | — | 14 | — | — | 14 | |||||||||||||||
Unreimbursed litigation costs | — | 1,401 | — | — | 1,401 | |||||||||||||||
Total operating costs and expenses | 859 | 278,438 | 12,308 | — | 291,605 | |||||||||||||||
Operating income (loss) | (859 | ) | 52,604 | 11,998 | — | 63,743 | ||||||||||||||
Interest expense, net | 6,628 | 17,924 | — | — | 24,552 | |||||||||||||||
Loss on interest rate swaps | — | 4,490 | — | — | 4,490 | |||||||||||||||
Other income, net | — | (6 | ) | (2 | ) | — | (8 | ) | ||||||||||||
Income (loss) before taxes | (7,487 | ) | 30,196 | 12,000 | — | 34,709 | ||||||||||||||
Income tax expense (benefit) | (27 | ) | (178 | ) | 1 | — | (204 | ) | ||||||||||||
Equity in earnings of subsidiaries | 42,253 | 11,879 | — | (54,132 | ) | — | ||||||||||||||
Net income | 34,793 | 42,253 | 11,999 | (54,132 | ) | 34,913 | ||||||||||||||
Less: Net income attributable to noncontrolling interest | — | — | — | (162 | ) | (162 | ) | |||||||||||||
Net income attributable to the partnership | $ | 34,793 | $ | 42,253 | $ | 11,999 | $ | (54,294 | ) | $ | 34,751 |
F-28
Condensed Consolidating Statements of Operations
Year Ended December 31, 2009 | ||||||||||||||||||||
Thousands of dollars | Parent/ Co-Issuer | Combined Guarantor Subsidiaries | Non-Guarantor Subsidiary | Eliminations | Consolidated | |||||||||||||||
Revenues and other income items: | ||||||||||||||||||||
Oil, natural gas and natural gas liquid sales | $ | — | $ | 236,266 | $ | 18,651 | $ | — | $ | 254,917 | ||||||||||
Loss on commodity derivative instruments, net | — | (51,437 | ) | — | — | (51,437 | ) | |||||||||||||
Other revenue, net | — | 1,382 | — | — | 1,382 | |||||||||||||||
Total revenues and other income items | — | 186,211 | 18,651 | — | 204,862 | |||||||||||||||
Operating costs and expenses: | ||||||||||||||||||||
Operating costs | 11 | 129,542 | 8,945 | — | 138,498 | |||||||||||||||
Depletion, depreciation and amortization | 387 | 104,274 | 2,182 | — | 106,843 | |||||||||||||||
General and administrative expenses | 482 | 35,890 | (5 | ) | — | 36,367 | ||||||||||||||
Loss on sale of assets | — | 5,965 | — | — | 5,965 | |||||||||||||||
Total operating costs and expenses | 880 | 275,671 | 11,122 | — | 287,673 | |||||||||||||||
Operating income (loss) | (880 | ) | (89,460 | ) | 7,529 | — | (82,811 | ) | ||||||||||||
Interest expense, net | — | 18,827 | — | — | 18,827 | |||||||||||||||
Loss on interest rate swaps | — | 7,246 | — | — | 7,246 | |||||||||||||||
Other income, net | — | (98 | ) | (1 | ) | — | (99 | ) | ||||||||||||
Income (loss) before taxes | (880 | ) | (115,435 | ) | 7,530 | — | (108,785 | ) | ||||||||||||
Income tax expense (benefit) | 61 | (1,590 | ) | 1 | — | (1,528 | ) | |||||||||||||
Equity in earnings of subsidiaries | (106,391 | ) | 7,454 | — | 98,937 | — | ||||||||||||||
Net income (loss) | (107,332 | ) | (106,391 | ) | 7,529 | 98,937 | (107,257 | ) | ||||||||||||
Less: Net income attributable to noncontrolling interest | — | — | — | (33 | ) | (33 | ) | |||||||||||||
Net income (loss) attributable to the partnership | $ | (107,332 | ) | $ | (106,391 | ) | $ | 7,529 | $ | 98,904 | $ | (107,290 | ) |
F-29
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2011 | ||||||||||||||||||||
Thousands of dollars | Parent/ Co-Issuer | Combined Guarantor Subsidiaries | Combined Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Cash flows from operating activities | ||||||||||||||||||||
Net income | $ | 110,495 | $ | 139,023 | $ | 19,887 | $ | (158,707 | ) | $ | 110,698 | |||||||||
Adjustments to reconcile to cash flow from operating activities: | ||||||||||||||||||||
Depletion, depreciation and amortization | 410 | 104,407 | 2,686 | — | 107,503 | |||||||||||||||
Unit-based compensation expense | — | 22,043 | — | — | 22,043 | |||||||||||||||
Unrealized gain on derivative instruments | — | (98,214 | ) | — | — | (98,214 | ) | |||||||||||||
Income from equity affiliates, net | — | 210 | — | — | 210 | |||||||||||||||
Equity in earnings of subsidiaries | (139,023 | ) | (19,684 | ) | — | 158,707 | — | |||||||||||||
Deferred income taxes | — | 714 | — | — | 714 | |||||||||||||||
Gain on sale of assets | — | (111 | ) | — | — | (111 | ) | |||||||||||||
Other | 1,154 | (1,466 | ) | — | — | (312 | ) | |||||||||||||
Changes in net assets and liabilities: | ||||||||||||||||||||
Accounts receivable and other assets | (182 | ) | (17,089 | ) | (562 | ) | — | (17,833 | ) | |||||||||||
Inventory | — | 2,597 | — | — | 2,597 | |||||||||||||||
Net change in related party receivables and payables | — | 100 | — | — | 100 | |||||||||||||||
Accounts payable and other liabilities | (453 | ) | 975 | 626 | — | 1,148 | ||||||||||||||
Net cash provided by (used in) operating activities | (27,599 | ) | 133,505 | 22,637 | — | 128,543 | ||||||||||||||
Cash flows from investing activities | ||||||||||||||||||||
Capital expenditures | — | (76,334 | ) | (1,773 | ) | — | (78,107 | ) | ||||||||||||
Proceeds from sale of assets, net | — | 2,339 | — | — | 2,339 | |||||||||||||||
Property acquisitions | — | (338,805 | ) | — | — | (338,805 | ) | |||||||||||||
Net cash used in investing activities | — | (412,800 | ) | (1,773 | ) | — | (414,573 | ) | ||||||||||||
Cash flows from financing activities | ||||||||||||||||||||
Issuance of common units | 99,443 | — | — | — | 99,443 | |||||||||||||||
Distributions | (102,686 | ) | — | — | — | (102,686 | ) | |||||||||||||
Proceeds from the issuance of long-term debt | — | 661,500 | — | — | 661,500 | |||||||||||||||
Repayments of long-term debt | — | (369,500 | ) | — | — | (369,500 | ) | |||||||||||||
Book overdraft | — | 2,636 | — | — | 2,636 | |||||||||||||||
Debt issuance costs | (69 | ) | (3,596 | ) | — | — | (3,665 | ) | ||||||||||||
Intercompany activity | 30,902 | (11,629 | ) | (19,273 | ) | — | — | |||||||||||||
Net cash provided by (used in) financing activities | 27,590 | 279,411 | (19,273 | ) | — | 287,728 | ||||||||||||||
Increase (decrease) in cash | (9 | ) | 116 | 1,591 | — | 1,698 | ||||||||||||||
Cash beginning of period | 70 | 1,836 | 1,724 | — | 3,630 | |||||||||||||||
Cash end of period | $ | 61 | $ | 1,952 | $ | 3,315 | $ | — | $ | 5,328 |
F-30
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2010 | ||||||||||||||||||||
Thousands of dollars | Parent/ Co-Issuer | Combined Guarantor Subsidiaries | Combined Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Cash flows from operating activities | ||||||||||||||||||||
Net income | $ | 34,793 | $ | 42,253 | $ | 11,999 | $ | (54,132 | ) | $ | 34,913 | |||||||||
Adjustments to reconcile to cash flow from operating activities: | ||||||||||||||||||||
Depletion, depreciation and amortization | 416 | 99,874 | 2,468 | — | 102,758 | |||||||||||||||
Unit-based compensation expense | — | 20,422 | — | — | 20,422 | |||||||||||||||
Unrealized loss on derivative instruments | — | 33,116 | — | — | 33,116 | |||||||||||||||
Income from equity affiliates, net | — | 450 | — | — | 450 | |||||||||||||||
Equity in earnings of subsidiaries | (42,253 | ) | (11,879 | ) | — | 54,132 | — | |||||||||||||
Deferred income taxes | — | (403 | ) | — | — | (403 | ) | |||||||||||||
Amortization of intangibles | — | 495 | — | — | 495 | |||||||||||||||
Loss on sale of assets | — | 14 | — | — | 14 | |||||||||||||||
Other | 343 | 3,185 | — | — | 3,528 | |||||||||||||||
Changes in net assets and liabilities: | ||||||||||||||||||||
Accounts receivable and other assets | 3,000 | 8,133 | 419 | — | 11,552 | |||||||||||||||
Inventory | — | (1,498 | ) | — | — | (1,498 | ) | |||||||||||||
Net change in related party receivables and payables | (13,000 | ) | (2,218 | ) | — | — | (15,218 | ) | ||||||||||||
Accounts payable and other liabilities | 6,299 | (14,525 | ) | 119 | — | (8,107 | ) | |||||||||||||
Net cash provided by (used in) operating activities | (10,402 | ) | 177,419 | 15,005 | — | 182,022 | ||||||||||||||
Cash flows from investing activities | ||||||||||||||||||||
Capital expenditures | — | (64,795 | ) | (2,152 | ) | — | (66,947 | ) | ||||||||||||
Proceeds from sale of assets, net | — | 337 | — | — | 337 | |||||||||||||||
Property acquisitions | — | (1,676 | ) | — | — | (1,676 | ) | |||||||||||||
Net cash used in investing activities | — | (66,134 | ) | (2,152 | ) | — | (68,286 | ) | ||||||||||||
Cash flows from financing activities | ||||||||||||||||||||
Distributions | (65,197 | ) | — | — | — | (65,197 | ) | |||||||||||||
Proceeds from the issuance of long-term debt | 299,992 | 748,000 | — | — | 1,047,992 | |||||||||||||||
Repayments of long-term debt | — | (1,079,000 | ) | — | — | (1,079,000 | ) | |||||||||||||
Book overdraft | — | 1,025 | — | — | 1,025 | |||||||||||||||
Debt issuance costs | (8,767 | ) | (11,925 | ) | — | — | (20,692 | ) | ||||||||||||
Intercompany activity | (215,705 | ) | 227,534 | (11,829 | ) | — | — | |||||||||||||
Net cash provided by (used in) financing activities | 10,323 | (114,366 | ) | (11,829 | ) | — | (115,872 | ) | ||||||||||||
Increase (decrease) in cash | (79 | ) | (3,081 | ) | 1,024 | — | (2,136 | ) | ||||||||||||
Cash beginning of period | 149 | 4,917 | 700 | — | 5,766 | |||||||||||||||
Cash end of period | $ | 70 | $ | 1,836 | $ | 1,724 | $ | — | $ | 3,630 |
F-31
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2009 | ||||||||||||||||||||
Thousands of dollars | Parent/ Co-Issuer | Combined Guarantor Subsidiaries | Non-Guarantor Subsidiary | Eliminations | Consolidated | |||||||||||||||
Cash flows from operating activities | ||||||||||||||||||||
Net income (loss) | $ | (107,332 | ) | $ | (106,391 | ) | $ | 7,529 | $ | 98,937 | $ | (107,257 | ) | |||||||
Adjustments to reconcile to cash flow from operating activities: | ||||||||||||||||||||
Depletion, depreciation and amortization | 387 | 104,274 | 2,182 | — | 106,843 | |||||||||||||||
Unit-based compensation expense | — | 12,661 | — | — | 12,661 | |||||||||||||||
Unrealized loss on derivative instruments | — | 213,251 | — | — | 213,251 | |||||||||||||||
Income from equity affiliates, net | — | 1,302 | — | — | 1,302 | |||||||||||||||
Equity in (earnings) losses of subsidiaries | 106,391 | (7,454 | ) | — | (98,937 | ) | — | |||||||||||||
Deferred income taxes | — | (1,790 | ) | — | — | (1,790 | ) | |||||||||||||
Amortization of intangibles | — | 2,771 | — | — | 2,771 | |||||||||||||||
Loss on sale of assets | — | 5,965 | — | — | 5,965 | |||||||||||||||
Other | — | 3,294 | — | — | 3,294 | |||||||||||||||
Changes in net assets and liabilities: | ||||||||||||||||||||
Accounts receivable and other assets | — | (5,013 | ) | (1,300 | ) | — | (6,313 | ) | ||||||||||||
Inventory | — | (4,573 | ) | — | — | (4,573 | ) | |||||||||||||
Net change in related party receivables and payables | — | 2,957 | — | — | 2,957 | |||||||||||||||
Accounts payable and other liabilities | — | (5,078 | ) | 325 | — | (4,753 | ) | |||||||||||||
Net cash provided by (used in) operating activities | (554 | ) | 216,176 | 8,736 | — | 224,358 | ||||||||||||||
Cash flows from investing activities | ||||||||||||||||||||
Capital expenditures | — | (28,828 | ) | (685 | ) | — | (29,513 | ) | ||||||||||||
Proceeds from sale of assets, net | — | 23,284 | — | — | 23,284 | |||||||||||||||
Net cash used in investing activities | — | (5,544 | ) | (685 | ) | — | (6,229 | ) | ||||||||||||
Cash flows from financing activities | ||||||||||||||||||||
Distributions | (28,038 | ) | — | — | — | (28,038 | ) | |||||||||||||
Proceeds from the issuance of long-term debt | — | 249,975 | — | — | 249,975 | |||||||||||||||
Repayments of long-term debt | — | (426,975 | ) | — | — | (426,975 | ) | |||||||||||||
Book overdraft | — | (9,871 | ) | — | — | (9,871 | ) | |||||||||||||
Intercompany activity | 28,739 | (19,575 | ) | (9,164 | ) | — | — | |||||||||||||
Net cash provided by (used in) financing activities | 701 | (206,446 | ) | (9,164 | ) | — | (214,909 | ) | ||||||||||||
Increase (decrease) in cash | 147 | 4,186 | (1,113 | ) | — | 3,220 | ||||||||||||||
Cash beginning of period | 2 | 731 | 1,813 | — | 2,546 | |||||||||||||||
Cash end of period | $ | 149 | $ | 4,917 | $ | 700 | $ | — | $ | 5,766 |
F-32
12. 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.
The consolidated income tax expense (benefit) attributable to our tax-paying entities consisted of the following:
Year Ended December 31, | ||||||||||||
Thousands of dollars | 2011 | 2010 | 2009 | |||||||||
Federal income tax expense (benefit) | ||||||||||||
Current | $ | 378 | $ | 347 | $ | 247 | ||||||
Deferred (a) | 714 | (403 | ) | (1,790 | ) | |||||||
State income tax expense (benefit) (b) | 96 | (148 | ) | 15 | ||||||||
Total | $ | 1,188 | $ | (204 | ) | $ | (1,528 | ) |
(a) Related to Phoenix Production Company, our wholly owned subsidiary.
(b) Primarily in Michigan, California and Texas.
The following is a reconciliation of federal income taxes at the statutory rates to federal income tax expense (benefit) for Phoenix:
Year Ended December 31, | ||||||||||||
Thousands of dollars | 2011 | 2010 | 2009 | |||||||||
Income (loss) subject to federal income tax | $ | 3,329 | $ | (565 | ) | $ | (4,052 | ) | ||||
Federal income tax rate | 34 | % | 34 | % | 34 | % | ||||||
Income tax at statutory rate | 1,132 | (192 | ) | (1,378 | ) | |||||||
Other | — | (13 | ) | (299 | ) | |||||||
Income tax expense (benefit) | $ | 1,132 | $ | (205 | ) | $ | (1,677 | ) |
At December 31, 2011 and 2010, net deferred federal income tax liabilities of $2.8 million and $2.1 million, respectively, were reported in our consolidated balance sheet for Phoenix. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and the amount used for income tax purposes. Significant components of our net deferred tax liabilities are presented in the following table:
December 31, | ||||||||
Thousands of dollars | 2011 | 2010 | ||||||
Deferred tax assets: | ||||||||
Net operating loss carry forwards | $ | — | $ | 154 | ||||
Asset retirement obligation | 431 | 394 | ||||||
Unrealized hedge loss | — | 673 | ||||||
Other | 368 | 445 | ||||||
Deferred tax liabilities: | ||||||||
Depreciation, depletion and intangible drilling costs | (3,199 | ) | (3,223 | ) | ||||
Unrealized hedge gain | (326 | ) | — | |||||
Deferred realized hedge gain | (77 | ) | (532 | ) | ||||
Net deferred tax liability | $ | (2,803 | ) | $ | (2,089 | ) |
F-33
At December 31, 2011 and 2010, we had $0 and $0.5 million, respectively, of estimated unused operating loss carry forwards. We did not provide a valuation allowance against this deferred tax asset as taxable income offset our prior operating loss carry forwards.
On a consolidated basis, cash paid for federal and state income taxes totaled $0.3 million in 2011, $0.2 million in 2010 and $0.6 million in 2009.
FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. FASB Accounting Standards also provide guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial statement comparability among different companies.
We performed evaluations as of December 31, 2011, 2010 and 2009 and concluded that there were no uncertain tax positions requiring recognition in our financial statements.
During 2011, Quicksilver sold its total interests of 15.7 million of our Common Units. The sales by Quicksilver, together with normal trading activity by other public unitholders, resulted in the sale or exchange of greater than 50% of our capital and profits interests within a 12-month period, which caused a technical termination of the Partnership for federal income tax purposes. This technical termination does not affect our financial statements nor does it affect our classification as a partnership for federal income tax purposes or otherwise impact the nature of our qualifying income. The technical termination will result in a deferral of depreciation deductions that would otherwise be allowable in computing the taxable income of our unit holders. Other tax adjustments allowable in computing the taxable income of unitholders for calendar year 2011 could also not be evenly distributed over the two tax periods.
The technical termination will result in the closing of our taxable year for all units holders as of November 30, 2011, with two taxable periods for 2011 - one from January 1, 2011 to November 30, 2011 and one from December 1, 2011 to December 31, 2011. As a result, we will be required to file two tax returns and issue two sets of schedule K-1s to each unitholder if relief is not granted by the IRS. The IRS has a technical termination relief program that allows publicly traded partnerships that have technically terminated to apply for relief and if such relief is granted, we will be able to provide only one schedule K-1 to unit holders for the year even though we must still file two separate period tax returns for the year (i.e., the two tax periods would be combined into one schedule K-1 for unit holders). Although we have applied to the IRS for this relief, there is no assurance that this relief will be granted.
13. Asset Retirement Obligation
Our asset retirement obligation is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities as well as our estimate of the future timing of the costs to be incurred. Payments to settle asset retirement obligations occur over the operating lives of the assets, estimated to be from less than one year to 50 years. We expect our cash settlements to be approximately $0.1 million, $0.1 million and $0.5 million for the years 2013, 2015 and 2016, respectively. Cash settlements for the years after 2016 are expected to be $81.7 million. Our estimated asset retirement obligation has 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. Each year we review and, to the extent necessary, revise our asset retirement obligation estimates. During 2011 and 2010, we obtained new estimates to evaluate the cost of abandoning our properties. As a result, we increased our ARO estimates by $20.0 million and $9.6 million, respectively, to reflect recent increases in the costs incurred for plugging and abandonment activities primarily in California.
We consider the inputs to our asset retirement obligation valuation to be Level 3 as fair value is determined using discounted cash flow methodologies based on standardized inputs that are not readily observable in public markets.
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Changes in the asset retirement obligation are presented in the following table:
Year Ended December 31, | ||||||||
Thousands of dollars | 2011 | 2010 | ||||||
Carrying amount, beginning of period | $ | 47,429 | $ | 36,635 | ||||
Acquisitions | 10,980 | — | ||||||
Liabilities incurred | 5,701 | 509 | ||||||
Liabilities settled | (5,301 | ) | (1,952 | ) | ||||
Revisions (a) | 20,005 | 9,611 | ||||||
Accretion expense | 3,583 | 2,626 | ||||||
Carrying amount, end of period | $ | 82,397 | $ | 47,429 |
(a) Attributable to increased cost estimates and revisions to reserve life.
14. Commitments and Contingencies
Lease Rental and Purchase Obligations
We have operating leases for office space and other property and equipment having initial or remaining non-cancelable lease terms in excess of one year. Our future minimum rental payments for operating leases at December 31, 2011 are presented below:
Payments Due by Year | ||||||||||||||||||||||||||||
Thousands of dollars | 2012 | 2013 | 2014 | 2015 | 2016 | after 2016 | Total | |||||||||||||||||||||
Operating leases | $ | 3,782 | $ | 2,876 | $ | 2,513 | $ | 2,268 | $ | 1,477 | $ | 1,565 | $ | 14,481 |
Net rental expense under non-cancelable operating leases was $3.4 million, $3.0 million and $2.6 million in 2011, 2010 and 2009, respectively.
At December 31, 2011, we had purchase obligations of $0.2 million and $0.2 million for 2012 and 2013, respectively.
Surety Bonds and Letters of Credit
In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At December 31, 2011, we had $22.1 million in surety bonds and $0.3 million in letters of credit outstanding. At December 31, 2010, we had $15.1 million in surety bonds and $0.3 million in letters of credit outstanding.
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 statues to which we are subject.
15. Partners' Equity
At December 31, 2011 and 2010, we had 59.9 million and 54.0 million Common Units outstanding, respectively.
At December 31, 2011 and December 31, 2010, we had 9.7 million and 6.7 million, respectively, of units authorized for issuance under our long-term incentive compensation plans and there were 1.7 million and 2.6 million, respectively, of units outstanding under grants that are eligible to be paid in Common Units upon vesting.
During the years ended December 31, 2011, 2010 and 2009, approximately 1.0 million, 1.2 million and 0.1 million Common Units, respectively, were issued to employees and outside directors pursuant to vested grants under our First
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Amended and Restated 2006 Long Term Incentive Plan ("LTIP").
On February 11, 2011, we sold approximately 4.9 million Common Units at a price to the public of $21.25 per Common Unit, resulting in proceeds net of underwriting discounts and expenses of $100 million.
Earnings per common 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 distribution rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested RPUs and CPUs participate in distributions on an equal basis with Common Units. Accordingly, the presentation below is prepared on a combined basis and is presented as net income (loss) per common unit.
The following is a reconciliation of net income (loss) and weighted average units for calculating basic net income (loss) per common unit and diluted net income (loss) per common unit.
Year Ended December 31, | ||||||||||||
Thousands, except per unit amounts | 2011 | 2010 | 2009 | |||||||||
Net income (loss) attributable to limited partners | $ | 110,497 | $ | 34,751 | $ | (107,290 | ) | |||||
Distributions on participating units not expected to vest | 29 | 15 | — | |||||||||
Net income (loss) attributable to common unitholders and participating securities | $ | 110,526 | $ | 34,766 | $ | (107,290 | ) | |||||
Weighted average number of units used to calculate basic and diluted net income (loss) per unit: | ||||||||||||
Common Units | 58,522 | 53,302 | 52,757 | |||||||||
Participating securities (a) | 2,948 | 3,454 | — | |||||||||
Denominator for basic earnings per common unit | 61,470 | 56,756 | 52,757 | |||||||||
Dilutive units (b) | 134 | 137 | — | |||||||||
Denominator for diluted earnings per common unit | 61,604 | 56,893 | 52,757 | |||||||||
Net income (loss) per common unit | ||||||||||||
Basic | $ | 1.80 | $ | 0.61 | $ | (2.03 | ) | |||||
Diluted | $ | 1.79 | $ | 0.61 | $ | (2.03 | ) |
(a) Basic earnings per unit is based upon the weighted average number of Common Units outstanding plus the weighted average number of potentially issuable RPUs and CPUs. The year ended December 31, 2009 excludes 2,637 of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.
(b) The year ended December 31, 2009 excludes 102 weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position.
Cash Distributions
The partnership agreement requires us to distribute all of our available cash quarterly. Available cash is cash on hand, including cash from borrowings, at the end of a quarter after the payment of expenses and the establishment of reserves for future capital expenditures and operational needs. We may fund a portion of capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. The partnership agreement does not restrict our ability to borrow to pay distributions. The cash distribution policy reflects a basic judgment that unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it.
Distributions are not cumulative. Consequently, if distributions on Common Units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future.
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Distributions are paid within 45 days of the end of each fiscal quarter to holders of record on or about the first or second week of each such month. If the distribution date does not fall on a business day, the distribution will be made on the business day immediately preceding the indicated distribution date.
We do not have a legal obligation to pay distributions at any rate except as provided in the partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under the partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves the General Partner determines is necessary or appropriate to provide for the conduct of the business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters. The partnership agreement provides that any determination made by the General Partner in its capacity as general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity.
On February 11, 2011, we paid a cash distribution of approximately $22.4 million to our common unitholders of record as of the close of business on February 8, 2011. The distribution that was paid to unitholders was $0.4125 per Common Unit. We also paid cash equivalent to the distribution paid to our unitholders of $1.2 million to holders of outstanding RPUs and CPUs issued under our LTIP.
On May 13, 2011, we paid a cash distribution of approximately $24.6 million to our common unitholders of record as of the close of business on May 10, 2011. The distribution that was paid to unitholders was $0.4175 per Common Unit. We also paid cash equivalent to the distribution paid to our unitholders of $1.3 million to holders of outstanding RPUs and CPUs issued under our LTIP.
On August 12, 2011, we paid a cash distribution of approximately $24.9 million to our common unitholders of record as of the close of business on August 9, 2011. The distribution that was paid to unitholders was $0.4225 per Common Unit. We also paid cash equivalent to the distribution paid to our unitholders of $1.3 million to holders of outstanding RPUs and CPUs issued under our LTIP.
On November 14, 2011, we paid a cash distribution of approximately $25.7 million to our common unitholders of record as of the close of business on November 9, 2011. The distribution that was paid to unitholders was $0.4350 per Common Unit. We also paid cash equivalent to the distribution paid to our unitholders of $1.3 million to holders of outstanding RPUs and CPUs issued under our LTIP.
16. Noncontrolling interest
FASB Accounting Standards require that noncontrolling interests be classified as a component of equity and establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.
We own the limited partner interest (99%) of BEPI. As such, we are fully consolidating the results of BEPI and are recognizing a noncontrolling interest representing the book value of the general partner’s interests. BEPI’s general partner interest is held by a wholly owned subsidiary of PCEC. At December 31, 2011 and December 31, 2010, the amount of this noncontrolling interest was $0.5 million and $0.5 million, respectively. For the years ended December 31, 2011 and 2010, we recorded net income attributable to the noncontrolling interest of $0.2 million and $0.2 million, respectively, and $0.2 million and $0.1 million, respectively, in dividends.
The general partner of BEPI holds a 35% reversionary interest under the existing limited partnership agreement applicable to the properties. This reversionary interest is expected to occur at a defined payout, which is estimated to occur in the second quarter of 2012 based on year-end price and cost projections.
17. Unit and Other Valuation-Based Compensation Plans
Effective on the initial public offering date of October 10, 2006, BreitBurn Management adopted the existing Long-Term Incentive Plan ("BreitBurn Management LTIP") and the Unit Appreciation Rights Plan ("UAR plan") of the predecessor as previously amended. The predecessor’s Executive Phantom Option Plan, Unit Appreciation Plan for Officers and Key Individuals (Founders Plan), and the Performance Trust Units awarded to the Chief Financial Officer during 2006 under the BreitBurn Management LTIP, were adopted by BreitBurn Management with amendments at the initial public offering date as
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described in the subject plan discussions below.
In 2007, we entered into the First Amended and Restated 2006 Long-Term Incentive Plan ("LTIP").
We may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. We also have the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the Common Units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire when units are no longer available under the plan for grants or, if earlier, it is terminated by us.
Unit Based Compensation
FASB Accounting Standards establish requirements for charging compensation expenses based on fair value provisions. At December 31, 2011, the Restricted Phantom Units ("RPUs") and the Convertible Phantom Units ("CPUs") granted under our LTIP as well as the outstanding Directors RPUs discussed below were all classified as equity awards. These awards are being recognized as compensation expense on a straight line basis over the annual vesting periods as prescribed in the award agreements.
Prior year awards classified as liabilities were revalued at each reporting period using the Black-Scholes option pricing model and changes in the fair value of the options were recognized as compensation expense over the vesting schedules of the awards. These awards were settled in cash or had the option of being settled in cash or units at the choice of the holder, and were indexed to either our Common Units or to Provident Trust Units. The liability-classified option awards were distribution-protected awards through either an Adjustment Ratio as defined in the plan or the holders received cumulative distribution amounts upon vesting equal to the actual distribution amounts per Common Unit of the underlying notional Units.
We recognized $22.0 million, $20.4 million and $12.7 million of compensation expense related to our various plans for the years ended December 31, 2011, 2010 and 2009, respectively.
Restricted Phantom Units
RPUs are phantom equity awards that, to the extent vested, represent the right to receive actual partnership units upon specified payment events. Certain of our employees including our executives are eligible to receive RPU awards. We believe that RPUs properly incentivize holders of these awards to grow stable distributions for our common unitholders. RPUs generally vest in three equal annual installments on each anniversary of the vesting commencement date of the award. In addition, each RPU is granted in tandem with a distribution equivalent right that will remain outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitles the grantee to receive payment of amounts equal to distributions paid to each holder of an actual partnership unit during such period. RPUs that do not vest for any reason are forfeited upon a grantee’s termination of employment.
The fair value of the RPUs is determined based on the fair market value of our units on the date of grant. RPU awards were granted to BreitBurn Management employees during the years ended December 31, 2011, 2010 and 2009 as shown in the table below. We recorded compensation expense of $16.9 million in 2011, $15.6 million in 2010 and $9.1 million in 2009 related to the amortization of outstanding RPUs over their related vesting periods. As of December 31, 2011, there was $17.4 million of total unrecognized compensation cost remaining for the unvested RPUs. This amount is expected to be recognized over the next two years. The total fair value of units that vested during the years ended December 31, 2011, 2010 and 2009 was $21.5 million, $16.9 million and $10.6 million, respectively.
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The following table summarizes information about RPUs:
Year Ended December 31, | |||||||||||||||||||||
2011 | 2010 | 2009 | |||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | ||||||||||||||||
of | Average | of | Average | of | Average | ||||||||||||||||
Thousands, except per unit amounts | RPUs | Fair Value | RPUs | Fair Value | RPUs | Fair Value | |||||||||||||||
Outstanding, beginning of period | 1,747 | $ | 13.40 | 1,575 | $ | 12.82 | 607 | $ | 26.91 | ||||||||||||
Granted | 758 | 21.60 | 1,482 | 13.77 | 1,791 | 8.17 | |||||||||||||||
Exercised | (1,505 | ) | 14.26 | (1,289 | ) | 13.13 | (809 | ) | 13.08 | ||||||||||||
Cancelled | (17 | ) | 16.68 | (21 | ) | 12.80 | (14 | ) | 14.45 | ||||||||||||
Outstanding, end of period | 983 | $ | 18.35 | 1,747 | $ | 13.40 | 1,575 | $ | 12.82 | ||||||||||||
Exercisable, end of period | — | $ | — | — | $ | — | — | $ | — |
Convertible Phantom Units
In December 2007, seven executives, Halbert Washburn, Randall Breitenbach, Mark Pease, James Jackson, Gregory Brown, Thurmon Andress and Jackson Washburn, received 0.7 million units of CPUs at a grant price of $30.29 per Common Unit. Each of the awards has the vesting commencement date of January 1, 2008. CPUs are significantly tied to the amount of distributions we make to holders of our Common Units. As discussed further below, the number of CPUs ultimately awarded to each of these senior executives will be based upon the level of distributions to common unitholders achieved during the term of the CPUs. The CPU grants vest over a longer-term period of up to five years. Therefore, these grants will not be made on an annual basis. New grants could be made at the Board’s discretion at a future date after the present CPU grants have vested.
CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or "disability" of the grantee or his or her termination without "cause" or for "good reason" (as defined in the holder’s employment agreement, if applicable). Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management. Prior to vesting, a holder of a CPU is entitled to receive payments equal to the amount of distributions made by us with respect to each of the Common Units multiplied by the number of Common Unit equivalents underlying the CPUs at the time of the distribution.
Under the original CPU Agreements, one Common Unit Equivalent (CUE) underlies each CPU at the time it was awarded to the grantee. However, the number of CUEs underlying the CPUs would increase at a compounded rate of 25% upon the achievement of each 5% compounded increase in the distributions paid by us to our common unitholders. Conversely, the number of CUEs underlying the CPUs would decrease at a compounded rate of 25% if the distributions paid by us to our common unitholders decreases at a compounded rate of 5%.
On October 29, 2009, the Compensation and Governance Committee approved an amendment to each of the existing CPU Agreements entered into with each named executive. Originally under the CPU Agreements, the number of CUEs per CPU could be reduced over the five year life of the agreement to a minimum of zero, or be multiplied by a maximum of 4.77 times, based on our distribution levels. We suspended the payment of distributions in April 2009; therefore, holders of CPUs did not receive any distributions under the CPU Agreements as long as distributions were suspended. Under the original chart, if the CPUs were to vest currently – for instance in the case of the death or disability of a holder – zero units would vest to that holder. The Committee determined that the elimination of multipliers between zero and one best represented the original incentive and retention purpose of the CPU Agreements. With this modification to the CPU Agreements, the number of CUEs per CPU can no longer be less than one, regardless of Common Unit distribution levels.
On January 29, 2010, the Committee approved an amendment to each of the existing CPU Agreements entered into with each named executive. Under these agreements, each CPU entitles its holder to receive (i) a number of our Common Units at the time of vesting equal to the number of "common unit equivalents" ("CUEs") underlying the CPU at vesting, and (ii) current distributions on Common Units during the vesting period based on the number of CUEs underlying the CPU at the time of such distribution. The number of CUEs underlying each CPU is determined by reference to Common Unit distribution levels during the applicable vesting period, generally calculated based upon the aggregate amount of distributions made per Common Unit
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for the four quarters preceding vesting. The amendment to the CPU agreements now limits the multiplier for 20% of the total number of CPUs and related CUEs granted in each award to "1."
On January 28, 2011, the Committee approved an amendment to each of the existing CPU Agreements entered into with each of named executives. This amendment to the CPU agreements now limits the multiplier for 40% of the total number of CPUs and related CUEs granted in each award to "1" instead of 20% in the prior amendment approved on January 29, 2010. As a result at vesting, CPUs for 40% of each award will convert to Common Units on a 1:1 basis, and with respect to that portion of the award, holders will lose the ability to earn additional Common Units based on increased distributions on Common Units. No other modification was made to the CPU Agreements under this amendment. The Committee determined that this cap on 40% of the CPUs was appropriate in light of the overall long-term incentive grants made to BreitBurn's executive officers in 2011. Because we were accruing compensation expense assuming a CUE multiplier of one, all of these amendments had no impact on compensation expense recorded. Compensation expense will be adjusted upon such time it deems probable that the CUE would increase due to increased distributions.
In the event that the CPUs vest on January 1, 2013 or if the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than $3.10 per Common Unit, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time (calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters subject to the 60% limitation put in place on January 28, 2011 as noted above). After January 1, 2011, under the terms of the CPU Agreements, all unvested CPUs would fully vest in the event of a termination without cause or good reason and upon death or disability.
We recorded compensation expense for CPUs of $4.1 million in 2011, $4.1 million in 2010 and $4.1 million in 2009. At December 31, 2011, there was $4.1 million of total unrecognized compensation cost related to remaining unvested CPUs. This amount is expected to be recognized in 2012.
Founders Plan Awards
Under the Founders Plan, participants received unit appreciation rights which provide cash compensation in relation to the appreciation in the value of a specified number of underlying notional phantom units. The value of the unit appreciation rights was determined on the basis of a valuation of the predecessor at the end of the fiscal period plus distributions during the period less the value of the predecessor at the beginning of the period. The base price and vesting terms were determined by BreitBurn Management at the time of the grant. Outstanding unit appreciation rights vest in the following manner: one-third vest three years after the grant date, one-third vest four years after the grant date and one-third vest five years after the grant date and are subject to specified service requirements.
Effective on the initial public offering date of October 10, 2006, all outstanding unit appreciation rights under the Founders Plan were adopted by BreitBurn Management and converted into three separate awards. The first and second awards became the obligations of our predecessor. The third award represented 0.3 million Partnership unit appreciation rights at a base price of $18.50 per unit with respect to the operations of the properties that were transferred to us for the period beginning on the initial public offering date of October 10, 2006. The award is liability-classified and is being charged to us as compensation expense over the remaining vesting schedule.
We recorded less than $0.1 million, less than $0.1 million and $(0.4) million for compensation expense (income) under the plan for the years ended December 31, 2011, December 31, 2010 and December 31, 2009, respectively.
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The following table summarizes information about unit appreciation rights issued under the Founders Plan:
Year Ended December 31, | |||||||||||||||||||||
2011 | 2010 | 2009 | |||||||||||||||||||
Thousands, except per unit amounts | Number of Units | Weighted Average Exercise Price | Number of Units | Weighted Average Exercise Price | Number of Units | Weighted Average Exercise Price | |||||||||||||||
Outstanding, beginning of period | 10 | $ | 18.50 | 20 | $ | 18.50 | 122 | $ | 18.50 | ||||||||||||
Exercised | (10 | ) | 18.50 | (10 | ) | 18.50 | — | — | |||||||||||||
Cancelled (a) | — | — | — | — | (102 | ) | 18.50 | ||||||||||||||
Outstanding, end of period (a) | — | $ | — | 10 | $ | 18.50 | 20 | $ | 18.50 | ||||||||||||
Exercisable, end of period | — | $ | — | — | $ | — | — | $ | — |
(a) In 2009, 102 units expired out of the money.
Partnership LTIP
Under our LTIP, Partnership-indexed restricted units (RTUs) and/or performance units (PTUs) were granted in 2007 to certain individuals other than the Chief Executive Officer and President. Partnership-indexed RTUs vest one third at the end of year one, one third at the end of year two and one third at the end of year three after grant. In general, cash payments equal to the value of the underlying notional units were made on the anniversary dates of the RTUs. Partnership-indexed PTUs vest three years from the end of third year after grant and are payable in cash or in Common Units of the Partnership if elected by the grantee at least 60 days prior to the vesting date. Partnership-indexed PTU payouts are further determined by a performance multiplier which can range from zero to 200% of the initial grant depending on the total return of the underlying notional units as compared to the returns of a selected peer group of companies. The multiplier is determined by comparing our total return to the returns of 49 companies in the Alerian MLP Index. Underlying notional units are established based on target salary LTIP threshold for each employee. The awarded notional units are adjusted cumulatively thereafter for distribution payments through the use of an adjustment ratio. The estimated fair value associated with the Partnership-indexed RTUs and PTUs is expensed in the statement of income over the vesting period.
Due to the suspension of our distribution in April 2009, the multiplier as calculated at the end of 2009 was below that required to generate a payout. As a result, all outstanding Partnership-indexed PTUs vested and expired January 1, 2010 and no payout was made. The remaining Partnership-indexed RTUs had a value of less than $0.1 million at December 31, 2009 which were paid in cash in January 2010.
We recognized a credit of $0.5 million of compensation expense for the year ended December 31, 2009.
Director Restricted Phantom Units
Effective with the initial public offering, we also made grants of Restricted Phantom Units in the Partnership to the non-employee directors of our General Partner. Each phantom unit is accompanied by a distribution equivalent unit right entitling the holder to an additional number of phantom units with a value equal to the amount of distributions paid on each of our Common Units until settlement. Upon vesting, the majority of the phantom units will be paid in Common Units, except for certain directors’ awards which will be settled in cash. The unit-settled awards are classified as equity and the cash-settled awards are classified as liabilities. The estimated fair value associated with these phantom units is expensed in the statement of income over the vesting period. The accumulated compensation expense for unit-settled awards is reported in equity, and for cash-settled grants, it is reflected as a liability on the consolidated balance sheet.
We recorded compensation expense for the director’s phantom units of approximately $1.0 million in 2011, $0.6 million in 2010 and $0.4 million in 2009. As of December 31, 2011, there was $0.6 million of total unrecognized compensation cost for the unvested Director Performance Units and such cost is expected to be recognized over the next two years.
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The following table summarizes information about the Director Restricted Phantom Units:
Year Ended December 31, | |||||||||||||||||||||
2011 | 2010 | 2009 | |||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | ||||||||||||||||
of | Average | of | Average | of | Average | ||||||||||||||||
Thousands, except per unit amounts | Units | Fair Value * | Units | Fair Value * | Units | Fair Value * | |||||||||||||||
Outstanding, beginning of period | 131 | $ | 13.05 | 81 | $ | 13.80 | 35 | $ | 22.60 | ||||||||||||
Granted | 41 | 21.68 | 60 | 13.94 | 57 | 9.20 | |||||||||||||||
Exercised | (40 | ) | 20.55 | (10 | ) | 24.10 | (11 | ) | 18.50 | ||||||||||||
Outstanding, end of period | 132 | $ | 13.45 | 131 | $ | 13.05 | 81 | $ | 13.80 | ||||||||||||
Exercisable, end of period | — | $ | — | — | $ | — | — | $ | — |
* At grant date
18. Retirement Plan
BreitBurn Management 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 has a defined contribution retirement plan, which covers substantially all of its employees on the first day of the month following the month of hire. The plan provides for BreitBurn Management to make regular contributions based on employee contributions as provided for in the plan agreement. Employees fully vest in BreitBurn Management’s contributions after five years of service. PCEC is charged for a portion of the matching contributions made by BreitBurn Management. For the years ended December 31, 2011, 2010 and 2009, we recognized expense related to matching contributions of $1.1 million, $1.0 million and $1.0 million, respectively.
19. Significant Customers
We sell oil, natural gas and natural gas liquids primarily to large domestic refiners. For the year ended December 31, 2011, purchasers that accounted for 10% or more of our net sales were ConocoPhillips, Plains Marketing & Transportation LLC, Marathon Oil Company and Sunoco Partners Marketing and Terminals L.P., which accounted for approximately 30%, 16%, 15% and 9% of net sales, respectively.
For the year ended December 31, 2010, purchasers that accounted for 10% or more of our net sales were ConocoPhillips, Marathon Oil Company, Plains Marketing & Transportation LLC and Sunoco Partners Marketing and Terminals L.P., which accounted for 30%, 16%, 12% and 10% of net sales, respectively.
For the year ended December 31, 2009, purchasers that accounted for 10% or more of our net sales were ConocoPhillips, Marathon Oil Company and Plains Marketing & Transportation LLC which accounted for 30%, 16% and 11% of net sales, respectively.
20. Subsequent Events
On January 10, 2012, we and BreitBurn Finance Corporation (the "Issuers"), and certain of our subsidiaries (the "Guarantors"), entered into a Purchase Agreement (the "Purchase Agreement") with the Initial Purchasers as defined therein (the "Initial Purchasers"), pursuant to which the Issuers agreed to sell $250 million in aggregate principal amount of the Issuers’ 7.875% Senior Notes due 2022 (the "2022 Senior Notes") to the Initial Purchasers in a private placement exempt from the registration requirements under the Securities Act. The 2022 Senior Notes have not been registered under the Securities Act or any state securities laws, and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The 2022 Senior Notes were resold by the Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act.
The 2022 Senior Notes were issued at a discount of 99.154%, or $247.9 million. The $2.1 million discount will be amortized over the life of the senior notes. In connection with the 2022 Senior Notes, our estimated financing fees and
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expenses were approximately $5.6 million, which will be amortized over the life of the 2022 Senior Notes.
In connection with the issuance of the 2022 Senior Notes, we entered into a Registration Rights Agreement (the "Registration Rights Agreement") with the Guarantors and Initial Purchasers. Under the Registration Rights Agreement, the Issuers and the Guarantors agreed to cause to be filed with the SEC a registration statement with respect to an offer to exchange the senior notes for substantially identical notes that are registered under the Securities Act. The Issuers and the Guarantors agreed to use their commercially reasonable efforts to cause such exchange offer registration statement to become effective under the Securities Act. In addition, the Issuers and the Guarantors agreed to use their commercially reasonable efforts to cause the exchange offer to be consummated not later than 400 days after January 13, 2012. If the offer to exchange is not completed on or before the 400th day following January 13, 2012, the annual interest rate borne by the notes will increase by 1% per annum until the offer to exchange is completed.
In January 2012, in connection with the issuance of the 2022 Senior Notes, our borrowing base was automatically reduced to $787.5 million in accordance with the terms of our credit facility. Our next semi-annual borrowing base redetermination is scheduled for April 2012.
On January 27, 2012, we announced a cash distribution to unitholders for the fourth quarter of 2011 at the rate of $0.4500 per Common Unit, which was paid on February 14, 2012 to the record holders of common units at the close of business on February 6, 2012.
In February 2012, we sold 9.2 million Common Units at a price to the public of $18.80, resulting in proceeds net of underwriting discounts and estimated offering expenses of $165.9 million.
On February 9, 2012, we entered into IPE Brent crude oil fixed price swap contracts for 500 Bbl/d for 2015 at $98.50 per Bbl.
Supplemental Information
A. Oil and Natural Gas Activities (Unaudited)
We calculate total estimated proved reserves and disclose our oil and natural gas activities in accordance with SEC guidelines. The definition of proved reserves incorporates a definition of “reasonable certainty" using the PRMS (Petroleum Resource Management System) standard of “high degree of confidence" for deterministic method estimates, or a 90% recovery probability for probabilistic methods used in estimating proved reserves. While SEC guidelines permit a company to establish undeveloped reserves as proved with appropriate degrees of reasonable certainty established absent actual production tests and without artificially limiting such reserves to spacing units adjacent to a producing well, we have elected not to add such undeveloped reserves as proved. For reserve reporting purposes we use unweighted average first-day-of-the-month pricing for the 12 calendar months. Costs associated with reserves are measured on the last day of the fiscal year.
Costs incurred
Our oil and natural gas activities are conducted in the United States. The following table summarizes our costs incurred for the past three years:
Year Ended December 31, | ||||||||||||
Thousands of dollars | 2011 | 2010 | 2009 | |||||||||
Property acquisition costs | ||||||||||||
Proved | $ | 341,602 | $ | 1,676 | $ | — | ||||||
Unproved | 1,073 | 2,877 | — | |||||||||
Asset retirement costs | 10,980 | — | — | |||||||||
Development costs | 75,635 | 64,951 | 28,669 | |||||||||
Asset retirement costs - development | 25,706 | 10,120 | 4,883 | |||||||||
Total costs incurred | $ | 454,996 | $ | 79,624 | $ | 33,552 |
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Capitalized costs
The following table presents the aggregate capitalized costs subject to depreciation, depletion and amortization relating to oil and gas activities, and the aggregate related accumulated allowance:
December 31, | ||||||||
Thousands of dollars | 2011 | 2010 | ||||||
Proved properties and related producing assets | $ | 2,319,857 | $ | 1,873,398 | ||||
Pipelines and processing facilities | 152,551 | 146,630 | ||||||
Unproved properties | 111,585 | 113,071 | ||||||
Accumulated depreciation, depletion and amortization | (516,214 | ) | (415,372 | ) | ||||
Net capitalized costs | $ | 2,067,779 | $ | 1,717,727 |
The average DD&A rate per equivalent unit of production for the year ended December 31, 2011, excluding non-oil and gas related DD&A, was $14.90 per Boe. The average DD&A rate per equivalent unit of production for the year ended December 31, 2010, excluding non-oil and gas related DD&A, was $14.95 per Boe.
Results of operations for oil and gas producing activities
The results of operations from oil and gas producing activities below exclude general and administrative expenses, interest expenses and interest income:
Year Ended December 31, | ||||||||||||
Thousands of dollars | 2011 | 2010 | 2009 | |||||||||
Oil, natural gas and NGL sales | $ | 394,393 | $ | 317,738 | $ | 254,917 | ||||||
Gain (loss) on commodity derivative instruments, net | 81,667 | 35,112 | (51,437 | ) | ||||||||
Operating costs | (165,969 | ) | (142,525 | ) | (138,498 | ) | ||||||
Depreciation, depletion, and amortization | (105,066 | ) | (100,183 | ) | (104,299 | ) | ||||||
Income tax (expense) benefit | (1,188 | ) | 204 | 1,528 | ||||||||
Results of operations from producing activities (a) | $ | 203,837 | $ | 110,346 | $ | (37,789 | ) |
(a) Excludes (gain) loss on sale of assets of $(111), $14 and $5,965 for the years ended December 31, 2011,
2010 and 2009, respectively.
Supplemental reserve information
The following information summarizes our estimated proved reserves of oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the years ended December 31, 2011, 2010 and 2009. The following reserve information is based upon reports by Netherland, Sewell & Associates, Inc. ("NSAI") and Schlumberger Data & Consulting Services ("SLB"), independent petroleum engineering firms. NSAI provides reserve data for our California, Wyoming and Florida properties, and SLB provides reserve data for our Michigan, Kentucky and Indiana properties. The estimates are prepared in accordance with SEC regulations. We only utilize large, widely known, highly regarded, and reputable engineering consulting firms. Not only the firms, but the technical persons that sign and seal the reports are licensed and certify that they meet all professional requirements. Licensing requirements formally require mandatory continuing education and professional qualifications. They are independent petroleum engineers, geologists, geophysicists and petrophysicists.
Our reserve estimation process involves petroleum engineers and geoscientists. As part of this process, all reserves volumes are estimated using a forecast of production rates, current operating costs and projected capital expenditures. Reserves are based upon the unweighted average first-day-of-the-month prices for each year. Price differentials are then applied to adjust these prices to the expected realized field price. Specifics of each operating agreement are then used to estimate the net reserves. Production rate forecasts are derived by a number of methods, including decline curve analyses, volumetrics, material balance or computer simulation of the reservoir performance. Operating costs and capital costs are forecast using current costs combined with expectations of future costs for specific reservoirs. In many cases, activity-based cost models for a reservoir are utilized to project operating costs as production rates and the number of wells for production and injection vary.
The technical person primarily responsible for overseeing preparation of the reserves estimates and the third party reserve
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reports is Mark L. Pease, the Executive Vice President and Chief Operating Officer of our General Partner. Mr. Pease received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines in 1979. Prior to joining our General Partner, Mr. Pease was Senior Vice President, E&P Technology & Services for Anadarko Petroleum Corporation. Mr. Pease has over 30 years of experience working in various capacities in the energy industry, including acquisition analysis, reserve estimation, reservoir engineering and operations engineering. Mr. Pease consults with NSAI and SLB during the reserve estimation process to review properties, assumptions and relevant data.
Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report included in this report as exhibits 99.1 and 99.2 are Mr. J. Carter Henson, Jr. and Mr. Mike K. Norton. J. Carter Henson, Jr. has been practicing consulting petroleum engineering at NSAI since 1989. Carter is a Registered Professional Engineer in the State of Texas (License No. 73964) and has over 30 years of practical experience in petroleum engineering, with over 22 years experience in the estimation and evaluation of reserves. He graduated from Rice University in 1981 with a Bachelor of Science Degree in Mechanical Engineering. Mike Norton has been practicing consulting petroleum geology at NSAI since 1989. Mike is a Certified Petroleum Geologist in the State of Texas (License No. 441) and has over 33 years of practical experience in petroleum geosciences, with over 28 years experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
Within SLB. the technical person primarily responsible for preparing the reserves estimates set forth in the SLB reserves report including in this report as exhibit 99.3 is Mr. Charles M. Boyer II, who has been with Data & Consulting Services (DCS) Division of SLB since 1998. He attended The Pennsylvania State University and graduated with a Bachelor of Science Degree in Geological Sciences in 1976; he is a Certified Petroleum Geologist of the American Association of Petroleum Geologists (Reg. No. 5733); he is a Registered Professional Geologist in the Commonwealth of Pennsylvania (Reg. No. PG004509) and has in excess of 20 years' experience in the conduct of evaluation and engineering studies relating to oil and gas interests.
Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation methods and procedures consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of the estimated proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure of discounted net future cash flows shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Decreases in the prices of oil and natural gas and increases in operating expenses have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and revenues, profitability and cash flow.
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The following table sets forth certain data pertaining to our estimated proved and proved developed reserves for the years ended December 31, 2011, 2010 and 2009.
Year Ended December 31, | |||||||||||||||||||||||||||
2011 | 2010 | 2009 | |||||||||||||||||||||||||
Total (MBoe) | Oil (MBbl) | Gas (MMcf) | Total (MBoe) | Oil (MBbl) | Gas (MMcf) | Total (MBoe) | Oil (MBbl) | Gas (MMcf) | |||||||||||||||||||
Proved Reserves | |||||||||||||||||||||||||||
Beginning balance | 118,908 | 41,659 | 463,491 | 111,301 | 38,846 | 434,730 | 103,649 | 25,910 | 466,434 | ||||||||||||||||||
Revision of previous estimates | 7,037 | 10,074 | (18,222 | ) | 12,819 | 5,900 | 41,510 | 15,303 | 17,034 | (10,389 | ) | ||||||||||||||||
Purchase of reserves in-place | 32,198 | 4,204 | 167,971 | 1,487 | 70 | 8,502 | — | — | — | ||||||||||||||||||
Sale of reserves in-place | — | — | — | — | — | — | (1,135 | ) | (1,109 | ) | (154 | ) | |||||||||||||||
Production | (7,037 | ) | (3,255 | ) | (22,697 | ) | (6,699 | ) | (3,157 | ) | (21,251 | ) | (6,516 | ) | (2,989 | ) | (21,161 | ) | |||||||||
Ending balance | 151,106 | 52,682 | 590,543 | 118,908 | 41,659 | 463,491 | 111,301 | 38,846 | 434,730 | ||||||||||||||||||
Proved Developed Reserves | |||||||||||||||||||||||||||
Beginning balance | 108,283 | 38,719 | 417,381 | 100,968 | 34,436 | 399,190 | 95,643 | 23,346 | 433,780 | ||||||||||||||||||
Ending balance | 131,462 | 47,813 | 501,891 | 108,283 | 38,719 | 417,381 | 100,968 | 34,436 | 399,190 | ||||||||||||||||||
Proved Undeveloped Reserves | |||||||||||||||||||||||||||
Beginning balance | 10,625 | 2,940 | 46,110 | 10,333 | 4,410 | 35,540 | 8,006 | 2,564 | 32,654 | ||||||||||||||||||
Ending balance | 19,644 | 4,869 | 88,652 | 10,625 | 2,940 | 46,110 | 10,333 | 4,410 | 35,540 |
Revisions of Previous Estimates
In 2011, we had positive revisions of 7.0 MMBoe, primarily related to an increase in oil prices partially offset by a decrease in natural gas prices. Unweighted average first-day-of-the-month crude oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2011 were $95.97 per Bbl of oil for Michigan, California and Florida, $76.79 per Bbl of oil for Wyoming and $4.12 per MMBtu of gas, compared to $79.40 per Bbl of oil for Michigan, California and Florida, $65.36 per Bbl of oil for Wyoming and $4.38 per MMBtu of gas in 2010.
In 2010, we had positive revisions of 12.8 MMBoe, primarily related to an increase in both oil and natural gas prices. Unweighted average first-day-of-the-month market prices for the reserve reports for the year ended December 31, 2009 were $61.18 per Bbl of oil for Michigan, California and Florida, $51.29 per Bbl of oil for Wyoming and $3.87 per MMBtu of gas.
In 2009, we had positive revisions of 15.3 MMBoe, primarily related to an increase in oil prices, partially offset by a decrease in natural gas prices. In accordance with SEC guidelines for 2008, oil and gas prices in effect as of December 31, 2008 were used as representative market prices for the reserve reports. The prices used in 2008 were $44.60 ($20.12 for Wyoming) per barrel of oil, and $5.71 per MMBtu of gas.
Conversion of Proved Undeveloped Reserves
During the years ended December 31, 2011, 2010 and 2009 , we incurred $15.4 million, $32.6 million and $5.8 million in capital expenditures, respectively, and drilled 28 wells, 16 wells and 11 wells, respectively, related to the conversion of proved undeveloped to proved developed reserves. During the years ended December 31, 2011, 2010 and 2009, we converted 1.0 MMBoe, 3.2 MMBoe and 0.6 MMBoe, respectively, from proved undeveloped to proved developed reserves. As of December 31, 2011, 2010 and 2009, we had no material proved undeveloped reserves that have remained undeveloped for more than five years. The increase in proved undeveloped reserves during the year ended December 31, 2011 was primarily due to the acquisition of 10.3 MMBoe and 1.9 MMBoe of proved undeveloped reserves in the Cabot Acquisition and the Greasewood Acquisition, respectively. The increase in proved undeveloped reserves during the year ended December 31, 2010 was not material.
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Standardized measure of discounted future net cash flows
The standardized measure of discounted future net cash flows relating to our estimated proved crude oil and natural gas reserves as of December 31, 2011, 2010 and 2009 is presented below:
December 31, | ||||||||||||
Thousands of dollars | 2011 | 2010 | 2009 | |||||||||
Future cash inflows | $ | 7,338,443 | $ | 5,097,644 | $ | 3,837,605 | ||||||
Future development costs | (338,273 | ) | (251,181 | ) | (197,709 | ) | ||||||
Future production expense | (3,531,192 | ) | (2,618,470 | ) | (2,103,381 | ) | ||||||
Future net cash flows | 3,468,978 | 2,227,993 | 1,536,515 | |||||||||
Discounted at 10% per year | (1,809,677 | ) | (1,163,069 | ) | (776,893 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 1,659,301 | $ | 1,064,924 | $ | 759,622 |
The standardized measure of discounted future net cash flows discounted at 10% from production of proved reserves was developed as follows:
1. | An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions. |
2. | In accordance with SEC guidelines, the reserve engineers' estimates of future net revenues from our estimated proved properties and the present value thereof are made using unweighted average first-day-of-the-month oil and gas sales prices and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. We have entered into various derivative instruments to fix or limit the prices relating to a portion of our oil and gas production. Derivative instruments in effect at December 31, 2011 and 2010 are discussed in Note 5. Such derivative instruments are not reflected in the reserve reports. Representative unweighted average first-day-of-the-month market prices for the reserve reports for the year ended December 31, 2011 were $95.97 per Bbl of oil for Michigan, California and Florida, $76.79 per Bbl of oil for Wyoming and $4.12 per MMBtu of gas, compared to $79.40 per Bbl of oil for Michigan, California and Florida, $65.36 per Bbl of oil for Wyoming and $4.38 per MMBtu of gas in 2010. Unweighted average first-day-of-the-month market prices for the reserve reports for the year ended December 31, 2009 were $61.18 per Bbl of oil for Michigan, California and Florida, $51.29 per Bbl of oil for Wyoming and $3.87 per MMBtu of gas. |
3. | The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs. Future net cash flows assume no future income tax expense as we are essentially a non-taxable entity except for four tax-paying corporations whose future income tax liabilities on a discounted basis are insignificant. |
The principal sources of changes in the standardized measure of the future net cash flows for the years ended December 31, 2011, 2010 and 2009 are presented below:
Year Ended December 31, | ||||||||||||
Thousands of dollars | 2011 | 2010 | 2009 | |||||||||
Beginning balance | $ | 1,064,924 | $ | 759,622 | $ | 592,260 | ||||||
Sales, net of production expense | (228,424 | ) | (175,213 | ) | (116,419 | ) | ||||||
Net change in sales and transfer prices, net of production expense | 393,183 | 306,311 | 217,756 | |||||||||
Previously estimated development costs incurred during year | 39,665 | 47,732 | 29,041 | |||||||||
Changes in estimated future development costs | (35,886 | ) | (105,207 | ) | (37,002 | ) | ||||||
Purchase of reserves in place | 342,675 | 1,676 | — | |||||||||
Sale of reserves in-place | — | — | (4,001 | ) | ||||||||
Revision of quantity estimates and timing of estimated production | (23,328 | ) | 154,041 | 18,761 | ||||||||
Accretion of discount | 106,492 | 75,962 | 59,226 | |||||||||
Ending balance | $ | 1,659,301 | $ | 1,064,924 | $ | 759,622 |
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B. Quarterly Financial Data (Unaudited)
Year Ended December 31, 2011 | ||||||||||||||||
First | Second | Third | Fourth | |||||||||||||
Thousands of dollars except per unit amounts | Quarter | Quarter | Quarter | Quarter | ||||||||||||
Oil, natural gas and natural gas liquid sales | $ | 92,575 | $ | 94,742 | $ | 97,356 | $ | 109,720 | ||||||||
Gain (loss) on derivative instruments, net | (106,177 | ) | 46,483 | 178,826 | (37,465 | ) | ||||||||||
Other revenue, net | 898 | 1,143 | 1,375 | 894 | ||||||||||||
Total revenue | (12,704 | ) | 142,368 | 277,557 | 73,149 | |||||||||||
Operating income (loss) | (86,641 | ) | 69,439 | 190,518 | (19,507 | ) | ||||||||||
Net income (loss) | $ | (94,713 | ) | $ | 57,523 | $ | 178,227 | $ | (30,339 | ) | ||||||
Basic net income (loss) per limited partner unit (a) | $ | (1.67 | ) | $ | 0.93 | $ | 2.87 | $ | (0.51 | ) | ||||||
Diluted net income (loss) per limited partner unit (a) | $ | (1.67 | ) | $ | 0.92 | $ | 2.87 | $ | (0.51 | ) |
Year Ended December 31, 2010 | ||||||||||||||||
First | Second | Third | Fourth | |||||||||||||
Thousands of dollars except per unit amounts | Quarter | Quarter | Quarter | Quarter | ||||||||||||
Oil, natural gas and natural gas liquid sales | $ | 80,469 | $ | 82,079 | $ | 77,055 | $ | 78,135 | ||||||||
Gain (loss) on derivative instruments, net | 52,065 | 51,650 | (7,973 | ) | (60,630 | ) | ||||||||||
Other revenue, net | 632 | 487 | 719 | 660 | ||||||||||||
Total revenue | 133,166 | 134,216 | 69,801 | 18,165 | ||||||||||||
Operating income (loss) | 63,889 | 60,595 | 577 | (61,318 | ) | |||||||||||
Net income (loss) | $ | 57,910 | $ | 53,597 | $ | (5,726 | ) | $ | (70,868 | ) | ||||||
Basic net income (loss) per limited partner unit (a) | $ | 1.02 | $ | 0.94 | $ | (0.11 | ) | $ | (1.33 | ) | ||||||
Diluted net income (loss) per limited partner unit (a) | $ | 1.02 | $ | 0.94 | $ | (0.11 | ) | $ | (1.33 | ) |
(a) Due to changes in the number of weighted average common units outstanding that may occur each quarter, the earnings per unit amounts for certain quarters may not be additive.
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EXHIBIT INDEX
NUMBER | DOCUMENT | |
3.1 | Certificate of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 (File No. 333-134049) filed on July 13, 2006). | |
3.2 | 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). | |
3.3 | 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). | |
3.4 | 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 April 9, 2009). | |
3.5 | 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 September 1, 2009). | |
3.6 | 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). | |
3.7 | Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC dated as of April 5, 2010 (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2011). | |
3.8 | Amendment No. 1 to the Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC dated as of December 30, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). | |
4.1 | Registration Rights Agreement, dated as of November 1, 2007, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007). | |
4.2 | First Amendment to the Registration Rights Agreement, dated as of April 5, 2010, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010). | |
4.3 | Unit Purchase Rights Agreement, dated as of December 22, 2008, between BreitBurn Energy Partners L.P. and American Stock Transfer & Trust Company LLC as Rights Agreement (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on December 23, 2008). | |
4.4 | Indenture, dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (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). | |
4.5 | Registration Rights Agreement, dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010). | |
4.6 | 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. Bank National 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). | |
4.7 | Registration Rights Agreement, dated as of January 13, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on January 13, 2012). | |
10.1 | Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners I, L.P. dated May 5, 2003 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on May 29, 2007). | |
10.2† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Executive Form) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on March 11, 2008). | |
10.3† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Executive Form) (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on March 11, 2008). | |
10.4† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Units Directors’ Award Agreement (incorporated herein by reference to Exhibit 10.35 to the Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-33055) and filed on March 17, 2008). |
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NUMBER | DOCUMENT | |
10.5 | Amendment No. 1 to the Operations and Proceeds Agreement, relating to the Dominguez Field and dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008). | |
10.6 | Amendment No. 1 to the Surface Operating Agreement dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and its predecessor BreitBurn Energy Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008). | |
10.7† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement (Employment Agreement Form) (incorporated herein by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the period ended June 30, 2008 (File No. 001-33055) and filed on August 11, 2008). | |
10.8† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement (Non-Employment Agreement Form) (incorporated herein by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the period ended June 30, 2008 and (File No. 001-33055) filed on August 11, 2008). | |
10.9 | Second Amended and Restated Administrative Services Agreement dated August 26, 2008 by and between BreitBurn Energy Company L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 02, 2008). | |
10.10 | Omnibus Agreement, dated August 26, 2008, by and among BreitBurn Energy Holdings LLC, BEC (GP) LLC, BreitBurn Energy Company L.P, BreitBurn GP, LLC, BreitBurn Management Company, LLC and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on September 02, 2008). | |
10.11 | Indemnity Agreement between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Halbert S. Washburn, together with a schedule identifying other substantially identical agreements between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and each of its executive officers and non-employee directors identified on the schedule (incorporated herein by reference to Exhibit 10.1 to the Current Report on form 8-K (File No. 001-33055) filed on November 4, 2009). | |
10.12† | First Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.2 to the Current Report on form 8-K (File No. 001-33055) filed on November 4, 2009). | |
10.13† | First Amended and Restated BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan effective as of October 29, 2009 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the period ended September 30, 2009 (File No. 001-33055) filed on November 6, 2009). | |
10.14 | Settlement Agreement as of April 5, 2010 by and among Quicksilver Resources Inc., BreitBurn Energy Partners L.P., BreitBurn GP LLC, Provident Energy Trust, Randall H. Breitenbach and Halbert S. Washburn (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 9, 2010). | |
10.15† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Executive Form) (incorporated herein by reference to Exhibit 10.21 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011. | |
10.16† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Executive Form) (incorporated herein by reference to Exhibit 10.22 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011. | |
10.17† | Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Director Form) (incorporated herein by reference to Exhibit 10.23 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011. | |
10.18† | Form of Second Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.24 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011. | |
10.19† | Form of Third Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.25 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011. | |
10.20 | Third Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Halbert S. Washburn (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). |
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NUMBER | DOCUMENT | |
10.21 | Third Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). | |
10.22 | Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Mark L. Pease (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). | |
10.23 | Second Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and James G. Jackson (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). | |
10.24 | Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Gregory C. Brown (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011). | |
10.25 | Second Amended and Restated Credit Agreement, dated May 7, 2010, by and among BreitBurn Operating L.P, as borrower, BreitBurn Energy Partners L.P., as parent guarantor, and Wells Fargo Bank, N.A., as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the period ended March 31, 2010 (File No. 001-33055) filed on May 10, 2010). | |
10.26 | First Amendment dated September 17, 2010 to the Second Amended and Restated Credit Agreement dated May 7, 2010, by and among BreitBurn Operating L.P, as borrower, BreitBurn Energy Partners L.P., as parent guarantor, and Wells Fargo Bank, N.A., as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 23, 2010). | |
10.27 | Second Amendment to the Second Amended and Restated Credit Agreement dated May 9, 2011 (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 001-33055) filed on May 10, 2011. | |
10.28 | Asset Purchase Agreement, dated as of July 26, 2011, between Cabot Oil & 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 July 29, 2011. | |
10.29 | Third Amendment to the Second Amended and Restated Credit Agreement dated August 3, 2011 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-33055) filed on August 8, 2011. | |
10.30 | Fourth Amendment to the Second Amended and Restated Credit Agreement dated October 5, 2011 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2011. | |
14.1 | BreitBurn Energy Partners L.P. and BreitBurn GP, LLC Code of Ethics for Chief Executive Officers and Senior Officers (as amended and restated on February 28, 2007) (incorporated herein by reference to Exhibit 14.1 to the Current Report on Form 8-K filed on March 5, 2007). | |
21.1* | List of subsidiaries of BreitBurn Energy Partners L.P. | |
23.1* | Consent of PricewaterhouseCoopers LLP. | |
23.2* | Consent of Netherland, Sewell & Associates, Inc. | |
23.3* | Consent of Schlumberger Data and Consulting Services. | |
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. | |
99.1* | Netherland, Sewell & Associates, Inc. reserve report for certain properties located in Wyoming. | |
99.2* | Netherland, Sewell & Associates, Inc. reserve report for certain properties located in California and Florida. | |
99.3* | Schlumberger Technology Corporation reserve report. | |
101†† | Interactive Data Files |
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* | 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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