10-K 1 bbep12311110k.htm FORM 10-K BBEP 12.31.11 10K


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

2



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,

6



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,

14



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.

33



 
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

36



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

37



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

38



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.


42



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



43



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.


44



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

45



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

47



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.


49



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