BBEP 12.31.12 10K

10-K 1 bbep12311210k.htm FORM 10-K 2012 BBEP 12.31.12 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, 2012



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 $1.1 billion on June 30, 2012, the last business day of the registrant’s most recently completed second fiscal quarter, based on $16.58 per unit, the last reported sales price on The NASDAQ Global Select Market on such date.

As of February 27, 2013, there were 99,679,796 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 2013 annual meeting of unitholders to be held on June 19, 2013.

BREITBURN ENERGY PARTNERS L.P. AND SUBSIDIARIES

TABLE OF CONTENTS



		Page
		No.
	Glossary of Oil and Gas Terms, Description of References	1

	PART I

Item 1.	Business.	4
Item 1A.	Risk Factors.	21
Item 1B.	Unresolved Staff Comments.	43
Item 2.	Properties.	43
Item 3.	Legal Proceedings.	43
Item 4.	Mine Safety Disclosures.	43

	PART II

Item 5.	Market For Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.	44
Item 6.	Selected Financial Data.	46
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	49
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	65
Item 8.	Financial Statements and Supplementary Data.	67
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	67
Item 9A.	Controls and Procedures.	67
Item 9B.	Other Information.	67

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance.	68
Item 11.	Executive Compensation.	69
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.	69
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	69
Item 14.	Principal Accounting Fees and Services.	69

	PART IV

Item 15.	Exhibits and Financial Statement Schedules.	70

Signatures		75

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: The specific gravity or density of oil expressed in terms of a 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.

completion: The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

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.

differential: The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil price, and the wellhead price received.

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.

ICE: Intercontinental Exchange.

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 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 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 (until December 31, 2012) 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 natural gas properties primarily located in Wyoming on October 6, 2011. References in this filing to “NiMin” refer to NiMin Energy Corp., from whom we acquired oil properties located in Wyoming on June 28, 2012. References in this filing to “Element” refer to Element Petroleum, LP, from whom we acquired oil and natural gas properties located in Texas on July 2, 2012. References in this filing to “CrownRock” refer to CrownRock, L.P., from whom we acquired oil and natural gas properties located in Texas on July 2, 2012 and December 28, 2012. References in this filing to “AEO” refer to American Energy Operations, Inc., from whom we acquired principally oil gas properties located in California on November 30, 2012. References in this filing to “Lynden” refer to Lynden USA Inc., from whom we acquired oil and natural gas properties located in Texas on December 28, 2012. References in this filing to “Piedra” refer to Piedra Energy I, LLC, from whom we acquired oil and natural gas properties located in Texas on December 28, 2012.

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 (the “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


•	the Antrim Shale and several non-Antrim formations in Michigan;


•	the Evanston, Green River, Wind River, Big Horn and Powder River Basins in Wyoming;


•	the Los Angeles and San Joaquin Basins in California;


•	the Permian Basin in Texas;


•	the Sunniland Trend in Florida; and


•	the New Albany Shale in Indiana and Kentucky.

Our assets are characterized by stable, long-lived production and proved reserve life indexes averaging greater than 17 years. We have high net revenue interests in our properties. As of December 31, 2012, our total estimated proved reserves were 149.4 MMBoe, of which approximately 53% was crude oil and 47% was natural gas.

We are a Delaware limited partnership formed in 2006 and have been publicly traded since October 2006. Our general partner is BreitBurn GP, a Delaware limited liability company, also formed in 2006, and has been our wholly-owned subsidiary since June 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.

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 Partnership 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, 2012:

As of December 31, 2012, we had 84.7 million limited partnership units (“Common Units”) outstanding.

In January 2013, we issued less than 0.1 million Common Units to employees and outside directors for phantom units and distribution equivalent rights that were granted in 2008, 2011 and 2012 and vested in January 2013. In February 2013, we sold 14.95 million Common Units at a price to the public of $19.86, resulting in proceeds net of underwriting discounts and estimated offering expenses of $285.0 million, which we used to reduce borrowings under our credit facility.

As of February 27, 2013, we had 99.7 million Common Units outstanding.

Long-Term Business Strategy

Our long-term goals are to manage our current and future oil and natural 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.

2013 Outlook

We expect our full year 2013 oil and natural gas capital spending program to be approximately $261 million, including capitalized engineering costs and excluding potential acquisitions, compared with approximately $153 million in 2012. In 2013, we anticipate spending approximately 84% principally on oil projects in California, Florida and Texas and approximately 16% principally on oil projects in Michigan, Wyoming, Indiana and Kentucky. We anticipate 89% of our total capital spending will be focused on drilling and rate generating projects that are designed to increase or add to production or reserves. We expect to fund these capital expenditures primarily with cash flow from operations. Without considering potential acquisitions, we expect our 2013 production to be approximately 9.8 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 27, 2013, we had approximately 77% of our expected 2013 production hedged. For 2013, we had 11,038 Bbl/d of oil and 58,100 MMBtu/d of natural gas hedged at average prices of approximately $92.93 and $5.87 respectively. For 2014, we had 11,114 Bbl/d of oil and 52,100 MMBtu/d of natural gas hedged at average prices of approximately $95.17 and $4.99, respectively. For 2015, we had 9,489 Bbl/d of oil and 52,200 MMBtu/d of natural gas hedged at average prices of approximately $95.61 and $5.00, respectively. For 2016, we had 5,911 Bbl/d of oil and 25,200 MMBtu/d of natural gas hedged at average prices of approximately $93.15 and $4.30, respectively. For 2017, we had 1,769 Bbl/d of oil and 5,571 MMBtu/d of natural gas hedged at average prices of approximately $88.20 and $4.51, respectively.

Consistent with our long-term business strategy, we intend to continue to actively pursue oil and natural gas acquisition opportunities in 2013.

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 Permian Basin in Texas, the Los Angeles Basin in California, the Belridge Field in the San Joaquin Basin in California 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 July 2011, we completed the acquisition of oil properties in the Powder River Basin in eastern Wyoming (the “Greasewood Acquisition”) for approximately $57 million in cash. In October 2011, we also completed the acquisition of oil and natural gas properties located primarily in the Evanston and Green River Basins in southwestern Wyoming (the “Cabot Acquisition”) for approximately $281 million in cash. 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.

In June 2012, we completed the acquisition of oil properties located in Park County in the Big Horn Basin of Wyoming from NiMin (the “NiMin Acquisition”) for approximately $95 million in cash (the “NiMin Assets”).

In July 2012, we completed the acquisition of oil and natural gas properties in the Permian Basin in Texas from Element and CrownRock for approximately $148 million and $70 million in cash, respectively. In December 2012, we completed the acquisition of additional oil and natural gas properties in the Permian Basin from CrownRock, Lynden and Piedra for approximately $167 million, $25 million and $10 million, respectively, subject to customary post-closing adjustments. The properties acquired in the Permian Basin during 2012 (the “Permian Basin Acquisitions”) were approximately 79% oil as of December 31, 2012.

In November 2012, we completed the acquisition of oil and natural gas properties from AEO (the “AEO Acquisition”) located in the Belridge Field in the San Joaquin Basin in Kern County, California for approximately $38 million in cash and approximately 3 million Common Units valued at $56 million, subject to customary post-closing adjustments (the “AEO Assets”). The properties acquired in the AEO Acquisition were approximately 85% oil as of December 31, 2012.

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 operated approximately 84% of our production in 2012. 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, 2012, our total estimated proved reserves were 149.4 MMBoe, of which approximately 53% was crude oil and 47% was natural gas. As of December 31, 2011, our total estimated proved reserves were 151.1 MMBoe, of which approximately 35% was crude oil and 65% was natural gas. Our total estimated proved reserve additions in 2012 from acquisitions of 33.7 MMBoe were offset by reserve revisions of 27.1 MMBoe and 8.3 MMBoe of production, resulting in a net decrease of 1.7 MMBoe from 2011. The decrease in 2012 was primarily the result of a 30.9 MMBoe (185.6 Bcf) decrease in natural gas reserves driven primarily by a decrease in natural gas prices. Price related reserve revisions were partially offset by drilling, recompletions, workovers, addition of new drilling locations and revised estimates of existing reserves. 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, 2012 were $94.71 per Bbl of oil and $2.76 per MMBtu of natural gas, compared to $95.97 per Bbl of oil and $4.12 per MMBtu of natural gas in 2011.

The following table summarizes our estimated proved developed and undeveloped oil and gas reserves as of December 31, 2012:



	Summary of Estimated Proved Oil and Gas Reserves as of December 31, 2012
	Total (MMBoe) (a)	Oil (MMBbl)	Gas (Bcf)
Proved
Developed	119.7	59.2	363.4
Undeveloped	29.7	19.8	59.1
Total proved	149.4	79.0	422.5

(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 2012, we incurred $21.6 million in capital expenditures and drilled 20 wells related to the conversion of estimated proved undeveloped to estimated proved developed reserves. During 2012, we converted 2,093 MBbl of oil and 1.4 Bcf of natural gas from estimated proved undeveloped to estimated proved developed reserves. As of December 31, 2012, we had no estimated proved undeveloped reserves that have remained undeveloped for more than five years, and we expect to develop all estimated proved undeveloped reserves within the next five years.

As of December 31, 2012, proved undeveloped reserves were 29.7 MMBoe compared to 19.6 MMBoe as of December 31, 2011. The Permian Basin Acquisitions, the NiMin Acquisition and the AEO Acquisition added 12.9 MMBoe, 2.4 MMBoe and 1.4 MMBoe of proved undeveloped reserves, respectively.

As of December 31, 2012, the total standardized measure of discounted future net cash flows was $1.99 billion. During 2012, we filed estimates of oil and gas reserves as of December 31, 2011 with the U.S. Department of Energy, which were consistent with the reserve data as of December 31, 2011 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, 2012				2012
	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	51.7	34.6	%	47.4	3,370	9,206
Wyoming	39.4	26.4	%	30.8	2,542	7,189
California	25.6	17.1	%	21.7	1,183	4,068
Texas	21.7	14.5	%	8.8	315	3,482
Florida	10.4	7.0	%	10.4	704	1,924
Indiana/Kentucky	0.6	0.4	%	0.6	204	557
Total	149.4	100.0	%	119.7	8,318	26,426

(a) For properties acquired during 2012, includes production and average daily production from acquisition date to December 31, 2012.

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 2012, 2011 and 2010.

The Antrim Shale, which accounted for 27% of our total estimated proved reserves at December 31, 2012, accounted for 30%, 38% and 40% of our total production and 54%, 70% and 76% of our natural gas production for 2012, 2011 and 2010, respectively. Realized prices per Mcfe for our Antrim Shale production were $2.09, $4.21 and $4.58 for 2012, 2011 and 2010, respectively. Lease operating expenses per Mcfe for our Antrim Shale production were $1.69, $1.60 and $1.46 for 2012, 2011 and 2010, 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 costs 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 proved oil and gas reserves is based upon reserve reports prepared as of December 31, 2012. Estimates of our proved reserves were prepared by Netherland, Sewell & Associates, Inc. and Schlumberger PetroTechnical Services, independent petroleum engineering firms. Netherland, Sewell & Associates, Inc. prepares reserve data for our California, Wyoming, Texas and Florida properties, and Schlumberger PetroTechnical Services prepares reserve data for our Michigan, Indiana and Kentucky 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 PetroTechnical 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 PetroTechnical 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 PetroTechnical 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 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 PetroTechnical 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 PetroTechnical 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. See Supplemental Note A to the consolidated financial statements in this report for further details about the qualifications of the technical persons at Netherland, Sewell & Associates, Inc. and Schlumberger PetroTechnical Services primarily responsible for preparing the reserves estimates.

Michigan

As of December 31, 2012, our Michigan operations comprised approximately 35% of our total estimated proved reserves. As of December 31, 2012, approximately 89% of our Michigan total estimated proved reserves were natural gas. For the year ended December 31, 2012, our average production was 9.2 MBoe/d or 55.2 MMcfe/d. Estimated proved reserves attributable to our Michigan properties as of December 31, 2012 were 51.7 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 3,677 productive wells in Michigan.

In 2012, we drilled 11 wells and completed 26 recompletions and 5 workovers. Our capital spending in Michigan for the year ended December 31, 2012 was approximately $12 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, our Antrim Shale wells have a proved reserve life of greater than 16 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

In June 2012, we completed the NiMin Acquisition to acquire crude oil properties in the Big Horn Basin in central Wyoming. The NiMin Assets are 100% oil and produced approximately 497 Bbl/d in the fourth quarter of 2012. Estimated proved reserves for the NiMin Assets as of December 31, 2012 were 5.4 MMBoe.

Our other Wyoming properties consist primarily of crude oil properties in the Powder River Basin in eastern Wyoming, principally natural gas properties in the Evanston and Green River Basins in southwestern Wyoming and principally oil 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. In total, we have interests in 964 productive wells in Wyoming.

For the year ended December 31, 2012, our average production from our Wyoming fields was approximately 7.2 MBoe/d, including average daily production from acquisition date to December 31, 2012 for properties acquired during 2012. Our total Wyoming estimated proved reserves as of December 31, 2012 totaled 39.4 MMBoe. As of December 31, 2012, approximately 53% of our Wyoming total estimated proved reserves were oil. In 2012, we drilled 20 new productive development wells and six recompletions of existing productive wells in Wyoming. Additionally, 20 workovers were performed in Wyoming during 2012. Our capital spending in Wyoming for the year ended December 31, 2012 was approximately $32 million.

California

In November 2012, we completed the AEO Acquisition to acquire principally oil properties located in the Belridge Field in the San Joaquin Basin in Kern County, California. Estimated proved reserves for the AEO Assets as of December 31, 2012 were 3.6 MMBoe.

Our legacy operations in California are concentrated in several large, complex oil fields within the Los Angeles Basin, including 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.

For the year ended December 31, 2012, our average California production was approximately 4.1 MBoe/d, including average daily production from acquisition date to December 31, 2012 for properties acquired during 2012. Our total California estimated proved reserves as of December 31, 2012 were 25.6 MMBoe. As of December 31, 2012, approximately 97% of our California total estimated proved reserves were crude oil. In 2012, we drilled 20 productive wells and completed 14 workovers and one recompletion in California. Our capital spending in California for the year ended December 31, 2012 was approximately $47 million.

Texas

In July 2012, we completed the acquisitions of oil and natural gas properties in the Permian Basin in Texas from Element and CrownRock. In December 2012, we completed the acquisitions of additional oil and natural gas properties in the Permian Basin in Texas from CrownRock, Lynden and Piedra. As of December 31, 2012, the properties acquired in the Permian Basin Acquisitions included interests in 180 proved undeveloped drilling locations. As of December 31, 2012, our total Texas estimated proved reserves were 21.7 MMBoe. Average daily production from acquisition date to December 31, 2012 for our Texas properties was approximately 3.5 MBbl/d. In 2012, we drilled 18 productive wells in Texas. Our capital spending in Texas for the year ended December 31, 2012 was approximately $16 million.

Florida

We operate five Florida fields with 19 actively producing wells as of December 31, 2012. Production is from the Cretaceous Sunniland Trend of the South Florida Basin. Each of our Florida fields is 100% oil. As of December 31, 2012, we had estimated proved reserves of approximately 10.4 MMBbls. In 2012, average daily production from our Florida fields was approximately 1.9 MBbl/d. Production from the Raccoon Point field currently accounts for more than half of our Florida production. In 2012, we drilled four productive wells in Florida. Our capital spending in Florida for the year ended December 31, 2012 was approximately $46 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 2012, our production for our Indiana and Kentucky operations was 0.6 MBoe/d or 3.3 MMcf/d. Our estimated proved reserves in Indiana and Kentucky as of December 31, 2012 were 0.6 MMBoe or 3.4 Bcf. Our capital spending in Indiana and Kentucky for the year ended December 31, 2012 was less than $1 million and included two optimization projects.

Productive Wells

The following table sets forth information for our properties as of December 31, 2012 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	1,010	966	2,252	1,691
Non-operated	86	56	2,084	647
	1,096	1,022	4,336	2,338

Developed and Undeveloped Acreage

The following table sets forth information for our properties as of December 31, 2012 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	44,384	40,245	506,555	258,398
Wyoming	164,569	89,491	53,540	25,405	218,109	114,896
Indiana	46,856	46,117	45,165	44,464	92,021	90,581
Florida	34,402	33,322	3,166	3,100	37,568	36,422
Colorado	14,292	13,198	—	—	14,292	13,198
California	3,958	3,128	—	—	3,958	3,128
Texas	3,760	3,480	8,120	5,311	11,880	8,791
Kentucky	3,148	3,148	4,529	3,754	7,677	6,902
Utah	1,740	529	—	—	1,740	529
	734,896	410,566	158,904	122,279	893,800	532,845

The following table lists the net undeveloped acres as of December 31, 2012, the net acres expiring in the years ending December 31, 2013, 2014 and 2015, and, where applicable, the net acres expiring that are subject to extension options.



		2013 Expirations		2014 Expirations		2015 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.
Indiana	44,464	41,489	—	1,963	—	136	—
Michigan	40,245	9,740	608	919	—	958	—
Wyoming	25,405	9,342	—	1,607	—	2,273	—
Texas	5,311	—	—	—	—	—	—
Kentucky	3,754	3,357	—	175	—	—	—
Florida	3,100	—	—	—	—	—	—
	122,279	63,928	608	4,664	—	3,367	—

As of December 31, 2012, we held more than 130,000 net acres in the developing Utica-Collingwood shale play in Michigan. Approximately 85% of this acreage is held by production. We also hold more than 75,000 net acres in the developing A1-Carbonate play in Michigan, approximately 80% of which 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, 2012, 2011 and 2010. 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,
	2012	2011	2010
Gross development wells:
Productive	107	79	50
Dry	3	2	2
	110	81	52
Net development wells:
Productive	92	69	48
Dry	3	2	2
	95	71	50

Included in the table above for 2012 are 26 recompletions in Michigan, one recompletion in California, six recompletions in Wyoming and one recompletion in Indiana. We drilled three dry development wells in Michigan during 2012. As of December 31, 2012, we had seven gross and net wells in progress in Wyoming, six gross and four net wells in progress in Texas, three gross and net wells in progress in California and one gross and net well in progress in Florida.

Delivery Commitments

As of December 31, 2012, we had no material delivery commitments.

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 2012, our largest purchasers were ConocoPhillips in California and Michigan, which accounted for approximately 31% of our net sales revenues; Plains Marketing & Transportation LLC in Florida, which accounted for approximately 17% of our net sales revenues; and Marathon Oil Company in Wyoming, which accounted for approximately 14% of our net sales revenues.

Crude Oil and Natural Gas Prices

We analyze the prices we realize from sales of our oil and natural 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 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 ICE Brent crude oil prices have fluctuated together, but recently WTI and ICE Brent oil prices have diverged. Management believes that ICE Brent pricing will better correlate with local California prices we receive in the future. In 2012, ICE 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 Western Canadian Select 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 premium to NYMEX primarily because transportation of the oil is via barge resulting in premium pricing relative to NYMEX. Our Texas crude oil traded at a discount to NYMEX due to the deduction of transportation costs and benchmarking to WTI posted prices.

In 2012, the NYMEX WTI spot price averaged approximately $94 per Bbl, compared with about $95 a year earlier. Monthly average NYMEX WTI spot prices during 2012 ranged from a low of $82 per Bbl in June to a high of $106 per Bbl in March. During 2012, the average differentials per barrel to NYMEX WTI spot prices were a $13.30 premium for our California-based production, a $17.55 discount for our Wyoming-based production, a $2.91 premium for our Florida-based production, excluding transportation costs, and a $4.91 discount for our Texas-based production.

Our Michigan properties have favorable natural gas supply and demand characteristics as the state has been importing an increasing percentage of its natural gas. This supply and 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 and demand market balances. Our Texas natural gas traded at a premium to Henry Hub primarily due to its high BTU content. 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 2012, the monthly average Henry Hub spot price ranged from a low of $1.95 per MMBtu in April to a high of $3.54 per MMBtu in November. During 2012, the average differentials per Mcf to the Henry Hub spot price were a $0.21 premium for our Michigan-based production, a $0.18 premium for our Wyoming-based production and a $1.78 premium for our Texas-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 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 minerals-based 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 WTI and ICE Brent crude oil prices and Henry Hub and MichCon City-Gate 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 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 Wyoming, 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 non-winter 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 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, 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, in August 2012, the EPA adopted new rules that establish new air emission control requirements for oil and natural gas production and natural gas processing operations. The new rules include 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. The new regulations 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 rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules establish new leak detection requirements for natural gas processing plants. Compliance with these 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 has 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 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 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 cap and trade program’s first compliance period began in 2013. California's cap and trade program requires us to report our greenhouse gas emissions and essentially sets maximum limits or caps on total emissions of greenhouse gases from all industrial sectors that are or become subject to the cap and trade program due to the levels of greenhouse gases that are emitted. This includes the oil and natural gas extraction sector of which we are a part. Our main sources of greenhouse gas emissions for our Southern California oil and gas operations are primarily attributable to emissions from internal combustion engines powering generators to produce electricity, flares for the disposal of excess field gas, and fugitive emission from equipment such as tanks and components. Under the California program, the cap will decline annually from 2013 through 2020. We will be required to obtain compliance instruments for each metric tonne of greenhouse gases that we emit, in the form of allowances (each the equivalent of one ton of carbon dioxide) or qualifying offset credits. A portion of the allowance will be granted by the state, but any shortfall between the state-granted allowance and the facility's emissions will have to be addressed through the purchase of additional allowances either from the state or a third party. The availability of allowances will decline over time in accordance with the declining cap, and the cost to acquire such allowances may increase over time. However, we do not expect the cost to be material to our operations.

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. Such climatic events could have an adverse effect on our financial condition and results of operations.

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 effect 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, 2012. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2013. 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.

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 7.4% and on gas producers at the rate of 5.8%. 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, and, therefore, 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 a final rule issued by FERC on December 26, 2007 on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“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.

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 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”), as further described below. 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.

In November 2009, the Federal Trade Commission (“FTC”) issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1 million per violation per day. In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the CFTC to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to liquids swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to liquids purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation.

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 for any entity,

directly or indirectly 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, to (1) 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 will continue.

FERC Market Transparency Rules. 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, 2012, BreitBurn Management had 450 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 South Flower Street, 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 division 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.

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 and 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;


•	impact of energy conservation efforts;


•	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;


•	increase in imports of liquid natural gas in the United States; and


•	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 47% of our estimated proved reserves as of December 31, 2012 and approximately 56% of our 2012 production on an MBoe basis, our financial results will be 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, 2012, the monthly average NYMEX WTI spot price ranged from a low of $82 per Bbl in June to a high of $106 per Bbl in March while the monthly average Henry Hub natural gas price ranged from a low of $1.95 per MMBtu in April to a high of $3.54 per MMBtu in November.

Price discounts or differentials between NYMEX WTI prices and what we actually receive are also historically very volatile. For instance, during calendar year 2012, the average quarterly premium to NYMEX WTI for our California production varied from $12.56 to $16.83 per Bbl, with the differential percentage of the total price per Bbl ranging from 13% to 19%. For Wyoming crude oil, our average quarterly price discount from NYMEX WTI varied from $13.69 to $19.29, with the discount percentage ranging from 16% to 21% of the total price per Bbl. During 2012, our crude oil produced from our Florida properties traded at a premium to NYMEX WTI primarily because transportation of the oil is via barge resulting in premium pricing relative to NYMEX. For Florida crude oil, our average quarterly differential to NYMEX WTI varied from a $1.55 discount to a $6.76 premium, excluding transportation expenses, with the differential percentage ranging from a 2% discount to a 7% premium of the total price per Bbl.

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:


•	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 facility.

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 56% of our 2012 production, on an MBoe basis, was 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 an average price at Henry Hub of $4.00 per MMBtu in 2011 to $2.75 per MMBtu in 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. As of December 31, 2012, we had hedged more than 68% of our expected natural gas production in 2013 and 2014 at prices higher than those currently prevailing. However, if prices for natural gas continue to remain depressed for lengthy periods, we may be required to write down the value of our oil and natural gas properties and/or revise our development plans which may cause certain of our undeveloped well locations to no longer be deemed 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 service our indebtedness.

The continuing decline of natural gas prices, a future decline in oil 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 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, a future decline in oil 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, 2012 and 2013, we were able to access the debt and equity capital markets. However, the continuing decline of natural gas prices or a future decline in oil prices could significantly increase the cost of obtaining money in the capital and credit markets and limit our ability to access those markets as a source of funding in the future.

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 or a future decline in oil 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 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 estimated proved reserves and their internal criteria.


•	We may be unable to obtain adequate funding under our credit facility because our lenders may simply be unwilling 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 estimated 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 estimated 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. 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.

In April 2012, our borrowing base was increased to $850.0 million and in September 2012, in connection with the issuance of additional notes maturing April 15, 2022, our borrowing base was automatically reduced to $800 million. In October 2012, we entered into an amendment to the credit facility, which increased our borrowing base to $1 billion and increased our total commitments from existing lenders to $900 million. The amendment also provides us with the ability to increase our total commitments up to the $1 billion borrowing base upon lender approval.

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 that 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;


•	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 (“G&A”);


•	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” in this report.

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.

Drilling for and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition and 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, among other things:


•	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.

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 27, 2013, we had approximately $77.0 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 April 2012, our borrowing base was increased to $850.0 million and in September 2012, in connection with the issuance of additional notes maturing April 15, 2022, our borrowing base was automatically reduced to $800 million. In October 2012, we entered into an amendment to the credit facility, which increased our borrowing base to $1 billion and increased our total commitments from existing lenders to $900 million. The amendment also provides us with the ability to increase our total commitments up to the $1 billion borrowing base upon lender approval. Our next borrowing base redetermination is scheduled for April 2013. 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 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” in this report 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:


•	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 effect 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 27, 2013, our long-term debt totaled $832 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 2013, our oil and gas capital spending program is expected to be approximately $261 million, compared to approximately $153 million in 2012 and approximately $75 million in 2011. We expect to use cash generated from operations to partially fund future capital expenditures, which will reduce cash available for distribution to our unitholders. 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 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, 2012 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.

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. During the year ended December 31, 2012, we recorded non-cash impairment charges of approximately $12.3 million primarily related to uneconomic proved properties in Michigan, Indiana and Kentucky due to a decrease in expected future natural gas prices. 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 commodity derivative losses. As of February 27, 2013, we had hedged, through swaps, options (including collar instruments) and physical contracts, approximately 77% of our expected 2013 production.

The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. The reference prices of the derivative instruments we utilize 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 27, 2013, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, U.S Bank National Association, Toronto-Dominion Bank and Royal Bank of Canada. We periodically obtain credit default swap information on our counterparties. As of December 31, 2012 and February 27, 2013, 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, 2012, our largest derivative asset balances were with Credit Suisse Energy LLC, Wells Fargo Bank National Association and The Royal Bank of Scotland plc which accounted for approximately 21%, 20% and 12% of our derivative asset balances, respectively.

The enactment of derivatives legislation 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.

On July 21, 2010, new comprehensive financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”) was enacted 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 requires the Commodity Futures Trading Commission (“CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. 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 would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Colombia in September of 2012 although the CFTC has stated that it will appeal the District Court's decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap”, “security-based swap”, “swap dealer” and “major swap participant”. Dodd-Frank and CFTC Rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be

finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of Dodd-Frank and CFTC rules on us and the timing of such effects. 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 from swap recordkeeping and reporting requirements through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of some 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 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 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 our 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, 2012 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, 2012 would have decreased by $501.7 million, from $1.99 billion, to $1.49 billion.

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.

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 2012, 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 2012, four customers accounted for approximately 69% 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 2012, ConocoPhillips primarily in California and Michigan accounted for approximately 31% of our net sales revenues, Plains Marketing & Transportation LLC in Florida accounted for approximately 17% of our net sales revenues, Marathon Oil Company in Wyoming accounted for approximately 14% of our net sales revenues and Sunoco Partners Marketing and Terminals L.P. in Michigan accounted for approximately 7% of our net sales revenues. In 2011, ConocoPhillips accounted for approximately 30% of our net sales revenues, Marathon Oil Company accounted for approximately 15% of our net sales revenues, Plains Marketing & Transportation LLC accounted for approximately 16% of our net sales revenues and Sunoco Partners Marketing and Terminals L.P. accounted for approximately 9% 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 operated approximately 84% of our production in 2012. 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 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. 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. Both the Obama Administration's budget proposal for fiscal year 2013 and other recently introduced legislation include proposals that would, among other things, eliminate or reduce certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. 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 development costs and certain environmental clean-up costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) the 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.

•

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 has 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 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.

tanks and components. Under the California program, the cap will decline annually from 2013 through 2020. We will be required to obtain compliance instruments for each metric tonne of greenhouse gases that we emit, in the form of allowances (each the equivalent of one ton of carbon dioxide) or qualifying offset credits. A portion of the allowance will be granted by the state, but any shortfall between the state-granted allowance and the facility's emissions will have to be addressed through the purchase of additional allowances either from the state or a third party. The availability of allowances will decline over time in accordance with the declining cap, and the cost to acquire such allowances may increase over time. However, we do not expect the cost to be material to our operations.

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 the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and disposal. EPA has indicated that it expects to issue its study report in late 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.

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 at the time of issuance) 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), in February 2012, we issued 9.2 million Common Units (or approximately 15% of our outstanding Common Units at issuance), in September 2012, we issued 11.5 million Common Units (or approximately 17% of our outstanding Common Units at issuance), in December 2012 we issued 3.0 million Common Units (or approximately 4% of our outstanding Common Units at issuance) in connection with the acquisition of oil and natural gas properties and in February 2013, we issued 14.95 million Common Units (or approximately 18% 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.

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 an 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 Third 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.

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.

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 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 the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.

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. A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations we believe that we satisfy the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement 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. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.

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 rate, which is currently a maximum 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, gains, losses, or deductions would flow through to you. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders likely causing a substantial reduction in the value of our units.

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such 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 changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Common Units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.

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.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. 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 your share of our income even if you do not receive any cash distributions from us.

Because you will be treated as a partner to whom we will allocate a share of our taxable income which could be different than the cash we distribute, you may be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, even if you receive no 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 resulting from that income.

Tax gain or loss on the disposition of our Common Units could be more or less than expected.

If you sell 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. Because distributions to you in excess of your allocable share of our net taxable income decrease your tax basis in your Common Units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, 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 items,

including depreciation recapture. 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 Common Units by tax-exempt entities, including individual retirement accounts (“IRAs”), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. 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 at the highest applicable effective 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 treat each purchaser of our Common Units as having the same tax benefits without regard to the actual 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 to 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 from the sale of Common Units and could have a negative impact on the value of our Common Units or result in audit 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 date a particular Common Unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department 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 items. The proposed regulations do not, however, specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among unitholders.

A unitholder whose units are the subject of a securities loan (e.g., a loan 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 there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, 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 of their units 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 our 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 deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, 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 in a timely manner 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, the partnership may be permitted 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 were required to file two federal tax returns for the two short periods during the 2011 tax year.

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.

Both the Obama Administration's budget proposal for fiscal year 2013 and other recently introduced legislation include proposals that would, among other things, eliminate or reduce certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. 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 development costs and certain environmental clean-up costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) the 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 jurisdictions where you do not live as a result of investing in our common units.

In addition to federal income taxes, you may be subject to return filing requirements and 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 live in any of those jurisdictions. Further, you may be subject to penalties for failure to comply with those return filing requirements. We currently conduct business and own assets in California, Colorado, Florida, Indiana, Kentucky, Michigan, Texas, Utah and Wyoming. Each of these states other than Florida, Texas and Wyoming 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 conduct business or own assets in additional states that impose a personal income tax. It is the responsibility of each unitholder to file all U.S. federal, state and local tax returns.

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 statutes to which we are subject.

Item 4. Mine Safety Disclosures.

Not applicable.

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, 2012, based upon information received from our transfer agent and brokers and nominees, we had approximately 61,000 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 February 27, 2013 was $19.60 per unit.



	Price Range				Cash Distribution		Date
Period	High		Low		Per Common Unit		Paid
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
First Quarter 2012	20.19		18.65		0.4550		5/14/2012
Second Quarter 2012	19.20		16.06		0.4600		8/14/2012
Third Quarter 2012	19.85		16.51		0.4650		11/14/2012
Fourth Quarter 2012	20.47		16.90		0.4700		2/14/2013

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

The information required by this item is included in our Current Report on Form 8-K filed on November 27, 2012. See also Note 15 of the consolidated financial statements included in this report.

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 2012.

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, 2007. 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.

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 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 for approximately $57 million and the Cabot Acquisition on October 6, 2011 for approximately $281 million. In 2012, we completed the NiMin Acquisition on June 28, 2012 for approximately $95 million, the Element and CrownRock acquisitions on July 2, 2012 for approximately $148 million and $70 million, respectively, the AEO Acquisition on November 30, 2012 for approximately $38 million in cash and approximately 3 million Common Units, and the CrownRock II and Lynden acquisitions on December 28, 2012 for approximately $167 million and approximately $25 million, respectively. See Note 4 to the consolidated financial statements in this report for further details about our 2011 and 2012 acquisitions. Effective April 1, 2012, our ownership interest in properties at two California fields decreased from approximately 95% to approximately 62%. See Note 16 to the consolidated financial statements in this report.

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 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.

Selected Financial Data



	Year Ended December 31,
Thousands of dollars, except per unit amounts	2012			2011			2010			2009			2008
Statement of Operations Data:
Oil, natural gas and natural gas liquid sales	$	413,867		$	394,393		$	317,738		$	254,917		$	467,381
Gain (loss) on commodity derivative instruments, net	5,580			81,667			35,112			(51,437		)	332,102
Other revenue, net	3,548			4,310			2,498			1,382			2,920
Total revenue	422,995			480,370			355,348			204,862			802,403

Operating income (loss)	21,700			153,809			63,743			(82,811		)	429,354

Net income (loss)	(40,739		)	110,698			34,913			(107,257		)	378,424
Less: Net income attributable to noncontrolling interest	(62		)	(201		)	(162		)	(33		)	(188		)
Net income (loss) attributable to the partnership	$	(40,801	)	$	110,497		$	34,751		$	(107,290	)	$	378,236
Basic net income (loss) per unit	$	(0.56	)	$	1.80		$	0.61		$	(2.03	)	$	6.29
Diluted net income (loss) per unit	$	(0.56	)	$	1.79		$	0.61		$	(2.03	)	$	6.28

Cash Flow Data:
Net cash provided by operating activities	$	191,782		$	128,543		$	182,022		$	224,358		$	226,696
Net cash used in investing activities	(697,159		)	(414,573		)	(68,286		)	(6,229		)	(141,039		)
Net cash provided by (used in) financing activities	504,556			287,728			(115,872		)	(214,909		)	(89,040		)

Balance Sheet Data (at period end):
Cash	$	4,507		$	5,328		$	3,630		$	5,766		$	2,546
Other current assets	109,158			167,492			121,674			136,675			138,020
Net property, plant and equipment	2,711,893			2,072,759			1,722,295			1,741,089			1,840,341
Other assets	89,936			85,270			82,568			87,499			235,927
Total assets	$	2,915,494		$	2,330,849		$	1,930,167		$	1,971,029		$	2,216,834

Current liabilities	115,240			89,889			101,317			91,890			79,990
Long-term debt	1,100,696			820,613			528,116			559,000			736,000
Other long-term liabilities	110,022			93,133			91,477			91,338			47,413
Partners' equity	1,589,536			1,326,764			1,208,803			1,228,373			1,352,892
Noncontrolling interest	—			450			454			428			539
Total liabilities and partners' equity	$	2,915,494		$	2,330,849		$	1,930,167		$	1,971,029		$	2,216,834

Cash dividends declared per unit outstanding:	$	1.8300		$	1.6875		$	1.1475		$	0.5200		$	1.9925

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	2012			2011			2010				2009			2008
Reconciliation of consolidated net income (loss) to Adjusted EBITDA:
Net income (loss) attributable to the partnership	$	(40,801	)	$	110,497		$	34,751			$	(107,290	)	$	378,236
Unrealized (gain) loss on commodity derivative instruments	82,025			(97,734		)	39,713				219,120			(388,048		)
Depletion, depreciation and amortization expense (a)	149,565			107,503			102,758				106,843			179,933
Write-down of crude oil inventory	—			—			—			—	—			1,172
Interest expense and other financing costs	66,675			42,422			35,639				31,942			31,868
Unrealized (gain) loss on interest rate derivatives	(4,368		)	(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	486			(111		)	14				5,965			—
Income tax expense (benefit)	84			1,188			(204		)		(1,528		)	1,939
Amortization of intangibles	—			—			495				2,771			3,131
Non-cash unit based compensation	22,184			22,002			20,331				13,619			7,481
Net operating cash flow from acquisitions, effective date through closing date	19,914			2,886			—				—			—
Adjusted EBITDA	$	295,764		$	224,952		$	226,900			$	194,986		$	233,026

(a) 2012, 2011 and 2010 include impairments of $12.3 million, $0.6 million and $6.3 million, respectively. 2008 includes impairments and price-related depletion, depreciation and amortization expense adjustments of $86.4 million.

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 Green River, Wind River, Big Horn and Powder River Basins in Wyoming, the Los Angeles and San Joaquin Basins in California, the Permian Basin in Texas, the Sunniland Trend in Florida and the New Albany Shale in Indiana and Kentucky.

Our core investment strategy includes the following principles:


•	acquire long-lived assets with low-risk exploitation and development opportunities;


•	use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;


•	reduce cash flow volatility through commodity price and interest rate derivatives; and


•	maximize asset value and cash flow stability through operating and technical expertise.

2012 Acquisitions

In June 2012, we completed the NiMin Acquisition, to acquire oil properties located in Park County in the Big Horn Basin of Wyoming for approximately $95 million in cash. The properties are 100% oil.

In July 2012, we completed the acquisitions of oil and natural gas properties in the Permian Basin in Texas from Element and CrownRock for approximately $148 million and $70 million in cash, respectively. In December 2012, we completed the acquisitions of additional oil and natural gas properties in the Permian Basin in Texas from CrownRock, Lynden and Piedra for approximately $167 million, $25 million and $10 million, respectively. The Permian Basin properties were approximately 79% oil as of December 31, 2012.

In November 2012, we completed the AEO Acquisition to acquire principally oil properties located in the Belridge Field in Kern County, California for approximately $38 million in cash and approximately 3 million Common Units valued at $56 million. The properties were approximately 85% oil as of December 31, 2012

During 2012, we completed other smaller acquisitions of oil and natural gas properties located in California and Michigan. In the aggregate, we paid approximately $9.6 million in total consideration for these properties.

We used borrowings under our credit facility to fund the cash portion of our 2012 acquisitions.

2012 Highlights

In 2012, we paid cash distributions to unitholders totaling $127.7 million. On February 14, 2013, we paid a cash distribution to unitholders of $39.8 million for the fourth quarter of 2012. We increased our quarterly cash distributions from $0.4500 per Common Unit for the fourth quarter of 2011 to $0.4700 per Common Unit for the fourth quarter of 2012.

In 2012, our oil and natural gas capital expenditures, including capitalized engineering costs and excluding acquisitions, totaled approximately $153 million, compared with approximately $75 million in 2011. We spent approximately $47 million in California, $46 million in Florida, $32 million in Wyoming, $16 million in Texas and $12 million in Michigan, Indiana and Kentucky. We drilled and completed 11 new wells, 27 recompletions and six workovers in Michigan and Indiana. We drilled and completed 20 new wells, 20 workovers and six recompletions in Wyoming. We drilled and completed 20 new wells, 14 workovers and one recompletion in California, 18 new wells in Texas and four new wells in Florida. Primarily as a result of our 2012 acquisitions and our capital spending, our 2012 production was 8,318 MMBoe, which was 18% higher than our 2011 production.

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 (the “Initial Notes”) at a price of 99.154%. We received net proceeds of approximately $242.3 million and used the proceeds to reduce borrowings under our credit facility.

In February 2012, we sold 9.2 million Common Units at a price to the public of $18.80, resulting in proceeds net of underwriting discounts and estimated offering expenses of $166.0 million, which we used to reduce borrowings under our credit facility.

In May 2012, we entered into the Fifth Amendment to our $1.5 billion bank credit facility (the “Second Amended and Restated Credit Agreement”), which increased the permitted amount of senior unsecured notes we may issue from $700 million to $1 billion.

In September 2012, we sold 11.5 million of our Common Units at a price to the public of $18.51 per Common Unit, resulting in proceeds net of underwriting discount and offering expenses of $204.1 million, which we used to reduce borrowings under our credit facility.

In September 2012, we issued an additional $200 million aggregate principal amount of our 7.875% Senior Notes due 2022 (the “Additional Notes”) (the Additional Notes and the Initial Notes collectively referred to as the “2022 Senior Notes”). The Additional Notes were issued at a premium of 103.500%, or $207.0 million. We used the net proceeds from the Additional Notes offering of approximately $202.8 million, after financing fees and expenses, to reduce borrowings under our credit facility.

In October 2012, we entered into the Sixth Amendment to the Second Amended and Restated Credit Agreement (the “Sixth Amendment”), which increased our borrowing base to $1 billion and increased our total commitments from existing lenders to $900 million. The Sixth Amendment also provided us with the ability to increase our total commitments up to the $1 billion borrowing base upon lender approval.

In December 2012, we filed a registration statement for the offer to exchange the 2022 Senior Notes for substantially identical notes that are registered under the Securities Act of 1933, as amended. On December 27, 2012, the exchange registration statement became effective, and we commenced the exchange offer, which was completed on February 7, 2013.

Outlook

In 2013, our crude oil and natural gas capital spending program, including capitalized engineering costs and excluding acquisitions, is expected to be approximately $261 million, compared with approximately $153 million in 2012. In 2013, we anticipate spending approximately 84% principally on oil projects in California, Florida and Texas and approximately 16% principally on oil projects in Michigan, Wyoming, Indiana and Kentucky. We anticipate 89% of

our total capital spending will be focused on drilling and rate-generating projects that are designed to increase or add to production or reserves. Without considering potential acquisitions, we expect our 2013 production to be approximately 9.8 MMBoe.

Commodity 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 27, 2013, we had hedged approximately 77% of our expected 2013 production. For 2013, we had 11,038 Bbl/d of oil and 58,100 MMBtu/d of natural gas hedged at average prices of approximately $92.93 and $5.87, respectively. For 2014, we had 11,114 Bbl/d of oil and 52,100 MMBtu/d of natural gas hedged at average prices of approximately $95.17 and $4.99, respectively. For 2015, we had 9,489 Bbl/d of oil and 52,200 MMBtu/d of natural gas hedged at average prices of approximately $95.61 and $5.00, respectively. For 2016, we had 5,911 Bbl/d of oil and 25,200 MMBtu/d of natural gas hedged at average prices of approximately $93.15 and $4.30, respectively. For 2017, we had 1,769 Bbl/d of oil and 5,571 MMBtu/d hedged at average prices of approximately $88.20 and $4.51, respectively.

Consistent with our long-term business strategy, we intend to continue to actively pursue oil and natural gas acquisition opportunities in 2013.

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, operating expenses and general and administrative expenses (”G&A”).

Our total estimated reserve additions in 2012 from acquisitions of 33.7 MMBoe were offset by reserve revisions of 27.1 MMBoe and 8.3 MMBoe of production, resulting in a net decrease of 1.7 MMBoe from 2011. The decrease in 2012 was primarily the result of a 30.9MMBoe (185.6 Bcf) decrease in natural gas reserves driven primarily by a decrease in natural gas prices. Price-related reserve revisions were partially offset by drilling, recompletions, workovers, addition of new drilling locations and revised estimates of existing reserves. 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, 2012 were $94.71 per Bbl of oil and $2.76 per MMBtu of natural gas, compared to $95.97 per Bbl of oil and $4.12 per MMBtu of gas in 2011. 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, 2010 were $79.40 per Bbl of oil $4.38 per MMBtu of gas.

Of our total estimated proved reserves as of December 31, 2012, 35% were located in Michigan, 26% in Wyoming, 17% in California, 15% in Texas and 7% in Florida, with less than 1% in Indiana and Kentucky. On a net production basis, we operated approximately 84% of our production in 2012.

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 2012, the NYMEX WTI spot price averaged approximately $94 per Bbl, compared with approximately $95 per Bbl a year earlier. In 2012, crude oil prices ranged from a monthly average low of $82 per Bbl in June to a monthly average high of $106 per Bbl in March. In 2011, prices ranged from a monthly average low of $86 per Bbl in September to a monthly average high of $110 per Bbl in April. In 2013 to date, the NYMEX WTI spot price averaged $95 per Bbl.

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. Natural gas prices are also

typically higher during the winter period when demand for heating is greatest in the U.S. Since January 2010, monthly average natural gas spot prices at Henry Hub ranged from a low of $1.95 per MMBtu in April 2012 to a high of $5.83 per MMBtu in January 2010. During 2012, the natural gas spot price at Henry Hub ranged from a low of $1.82 per MMBtu to a high of $3.77 per MMBtu, with the monthly average ranging from a low of $1.95 per MMBtu in April to a high of $3.54 per MMBtu in November, and averaged approximately $2.75 per MMBtu for the year. 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, and averaged approximately $4.00 per MMBtu. In 2013 to date, the natural gas spot price at Henry Hub averaged approximately $3.32 per MMBtu.

Excluding the effect of derivatives, our average realized oil and NGL price for 2012 decreased $0.15 per Boe to $89.77 per Boe as compared to $89.92 per Boe in 2011. Including the effects of derivative instruments but excluding the effects of hedge terminations, our realized average oil and NGL price increased $11.02 per Boe to $90.82 per Boe as compared to $79.80 per Boe in 2011, primarily due to higher average crude oil hedge price. Our realized natural gas price for 2012 decreased $1.18 per Mcf to $3.00 per Mcf as compared to $4.18 per Mcf in 2011. Including the effects of derivative instruments, our realized natural gas price decreased $0.59 per Mcf to $5.99 per Mcf compared to $6.58 per Mcf in 2011.

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 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 $19.15 per Boe in 2012 and $19.39 per Boe in 2011. The decrease in per Boe lease operating expenses was primarily due to lower operating costs from our acquisitions in Wyoming and Texas.

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 9% 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.

G&A, excluding unit based compensation, was $4.00 per Boe in 2012 and $4.45 per Boe in 2011. The decrease in per Boe G&A, excluding unit based compensation, was primarily due to additional production from our 2012 acquisitions.

BreitBurn Management

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 by the Trust. On May 8, 2012, the Trust completed its initial public offering (the “Trust IPO”). We have no direct or indirect ownership interest in PCEC or the Trust. As part of the Trust IPO, PCEC conveyed 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. Prior to the Trust IPO, PCEC operated the East Coyote and Sawtelle Fields for the benefit of itself and us, who owned the non-operated interests in the East Coyote and Sawtelle Fields. PCEC owned an average working interest of approximately 5% in the two fields and held a reversionary interest in both fields.

Effective April 1, 2012 and pursuant to an agreement with us, PCEC’s ownership interest in these properties was increased. As a result of that agreement, our average working interest in the properties decreased from approximately 95% to approximately 62%.

On May 8, 2012, BreitBurn Management entered into the Third Amended and Restated Administrative Services Agreement with PCEC, pursuant to which the parties agreed to increase the monthly fee charged by BreitBurn Management to PCEC for indirect costs.

Prior to the Trust IPO, the 2012 monthly fee charged by BreitBurn Management to PCEC for indirect costs was set at $571,000, and the two parties agreed to increase that monthly fee to $700,000. The new monthly fee will be in effect from April 1, 2012 through August 31, 2014 and will be redetermined biannually thereafter. In connection with the Trust IPO, we also amended the Omnibus Agreement with PCEC to remove our right of first offer with respect to the sale of assets by PCEC.

For 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 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	2012			2011			2010			2012-2011		2011-2010
Total production (MBoe) (a)	8,318			7,037			6,699			18	%	5	%
Oil and NGL (MBoe)	3,652			3,255			3,157			12	%	3	%
Natural gas (MMcf)	27,997			22,697			21,251			23	%	7	%
Average daily production (Boe/d)	22,726			19,281			18,354			18	%	5	%
Sales volumes (MBoe)	8,334			7,106			6,663			17	%	7	%
Average realized sales price (per Boe) (b) (c)
Including realized gain (loss) on derivative instruments	$	60.09		$	58.33		$	58.94		3	%	(1	)%
Oil and NGL (per Boe) (b) (c)	90.82			79.80			74.31			14	%	7	%
Natural gas (per Mcf) (b)	5.99			6.58			7.57			(9	)%	(13	)%
Excluding realized gain (loss) on derivative instruments (c)	$	49.57		$	55.41		$	47.71		(11	)%	16	%
Oil and NGL (per Boe) (c)	89.77			89.92			70.71			—	%	27	%
Natural gas (per Mcf)	3.00			4.18			4.57			(28	)%	(9	)%
Oil, natural gas and NGL sales (d)	$	413,867		$	394,393		$	317,738		5	%	24	%
Realized gain (loss) on derivative instruments (e)	87,605			(16,067		)	74,825			n/a		(121	)%
Unrealized gain (loss) on derivative instruments (e)	(82,025		)	97,734			(39,713		)	n/a		n/a
Other revenues, net	3,548			4,310			2,498			(18	)%	73	%
Total revenues	422,995			480,370			355,348			(12	)%	35	%
Lease operating expenses including processing fees	159,289			136,441			122,512			17	%	11	%
Production and property taxes (f)	33,634			26,599			20,510			26	%	30	%
Total lease operating expenses	192,923			157,787			138,964			22	%	14	%
Purchases and other operating costs	1,577			961			328			64	%	193	%
Change in inventory	1,279			1,968			(825		)	(35	)%	n/a
Total operating costs	$	195,779		$	165,969		$	142,525		18	%	16	%
Lease operating expenses pre-taxes per Boe (g)	$	19.15		$	19.39		$	18.29		(1	)%	6	%
Production and property taxes per Boe	4.04			3.78			3.06			7	%	23	%
Total lease operating expenses per Boe	23.19			23.17			21.35			—	%	9	%
Depletion, depreciation and amortization	$	149,565		$	107,503		$	102,758		39	%	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.
(b) Excludes the effect of the early termination of commodity derivative contracts terminated in 2011 for a cost of $36,779.
(c) Includes the per Boe price effect of crude oil purchases. For 2010, amount excludes the per Boe price effect of amortization of an intangible asset related to crude oil sales contracts.
(d) 2010 amount includes $495 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.
(f) Includes ad valorem and severance taxes.
(g) Includes lease operating expenses, district expenses, transportation expenses and processing fees.

Comparison of Results of Operations for the Years Ended December 31, 2012, 2011 and 2010

The variances in our results of operations were due to the following components:

Production

For the year ended December 31, 2012 compared to the year ended December 31, 2011, production volumes increased by 1,281 MBoe, or 18%, primarily due to a 1,112 MBoe increase from a full year of production from our southwest Wyoming properties acquired in October 2011, a 155 MBoe increase from a full year of production from our eastern Wyoming properties acquired in July 2011, 315 MBoe from our Permian Basin properties acquired in July and December 2012, 92 MBbl of oil from our central Wyoming properties acquired in June 2012, 28 MBoe from our properties in the San Joaquin Basin in California acquired in November 2012 and 42 MBbl higher Florida production from new wells partially offset by 411 MBoe lower Michigan production due to lower natural gas prices and natural field declines. The remaining decrease was primarily due to natural field declines at our legacy Wyoming properties, and a reduction in our ownership interest in two California fields, partially offset by higher production from a field in California due to additional drilling. In 2012, natural gas, crude oil and natural gas liquids accounted for 56%, 42% and 2% of our production, respectively.

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 in October 2011, 88 MBoe from our eastern Wyoming properties acquired in July 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.

Revenues

Total revenues decreased by $57.4 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. Realized gains from commodity derivative instruments were $87.6 million in 2012 compared to realized losses of $16.1 million in 2011. Unrealized losses from commodity derivative instruments for the year ended December 31, 2012 were $82.0 million primarily reflecting an increase in crude oil and natural gas futures prices during 2012. 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 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. For 2012 compared to 2011, higher sales volumes, primarily from acquisitions, increased total sales revenues by approximately $68 million, and lower natural gas prices and slightly lower crude oil prices decreased total sales revenues by approximately $49 million.

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. 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.

Lease operating expenses

Pre-tax lease operating expenses, including processing fees, for the year ended December 31, 2012 totaled $159.3 million, $22.8 million higher than 2011. The increase in pre-tax lease operating expenses reflects our newly acquired Wyoming and Texas properties, higher California well service costs, higher Florida fuel and utilities costs and higher transportation expenses. The increase in California well services was partially offset by lower lease operating expenses at the East Coyote and Sawtelle fields as a result of the reduction in our working interests from 95% to 62% attributable

to a payout reversion that was effective April 1, 2012. On a per Boe basis, lease operating expenses were 1% lower than 2011.

Production and property taxes for the year ended December 31, 2012 totaled $33.6 million, or $4.04 per Boe, which was 7% higher per Boe than the year ended December 31, 2011. The per Boe increase in production and property taxes compared to 2011 was primarily due to higher per Boe production and property taxes on our newly acquired Permian Basin assets and an increase in per Boe Florida taxes.

Pre-tax lease operating expenses, including processing fees, for the year ended December 31, 2011 totaled $136.4 million or $19.39 per Boe, which was 6% 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 and higher transportation expenses, well services, compression repairs and maintenance.

Production and property taxes for the year ended December 31, 2011 totaled $26.6 million, or $3.78 per Boe, which was 23% higher per Boe than the year ended December 31, 2010. The per Boe increase in production and property taxes compared to 2010 was primarily due to higher commodity prices in 2011.

Change in inventory

In Florida, our crude oil sales are a function of the number and size of crude oil shipments in each year and thus crude oil sales do not always coincide with volumes produced in a given year. Sales occur on average every six to eight weeks. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are credited to operating costs through the change in inventory account. Production expenses are charged to operating costs through the change in inventory account when they are sold. In 2012 and 2011, the change in inventory account amounted to a charge of $1.3 million and $2.0 million, respectively, reflecting the higher amount of barrels sold than produced during the periods, compared to a credit of $0.8 million in 2010, reflecting the higher amount of barrels produced than sold during the period.

Depletion, depreciation and amortization

Depletion, depreciation and amortization (“DD&A”) expense totaled $149.6 million, or $17.98 per Boe, for the year ended December 31, 2012, compared to DD&A of $15.28 per Boe for the year ended December 31, 2011. Included in DD&A for the year ended December 31, 2012 are $12.3 million in impairments primarily related to uneconomic proved properties in Michigan, Indiana and Kentucky due to a decrease in expected future natural gas prices. Included in DD&A for the year ended December 31, 2011 are $0.6 million in impairments related to uneconomic proved properties in Michigan. Excluding the impact of impairments, DD&A per Boe for 2012 and 2011 was $16.50 and $15.18, respectively. The increase in DD&A excluding impairments was primarily due to higher DD&A rates on our newly acquired properties.

DD&A expense totaled $107.5 million, or $15.28 per Boe, for the year ended December 31, 2011, which was in line with DD&A of $15.34 per Boe for the year ended December 31, 2010. Included in DD&A for the year ended December 31, 2011 are $0.6 million in impairments related to uneconomic proved properties in Michigan. Included in DD&A for the year ended December 31, 2010 are $6.3 million in impairments related to our Eastern region properties, including a $4.2 million write-down of uneconomic proved properties and a $2.1 million write-down of expired unproved lease properties. Excluding the impact of impairments, DD&A per Boe for 2011 and 2010 was $15.18 and $14.40, respectively. The increase in DD&A per Boe excluding impairments was primarily due to higher DD&A rates reflecting lower natural gas reserves as a result of a decrease in natural gas prices, and investment additions related to new wells in Florida.

General and administrative expenses

Our G&A expenses totaled $55.5 million and $53.3 million in 2012 and 2011, respectively. This included $22.2 million and $22.0 million, respectively, in unit-based compensation expense related to employee incentive plans. For 2012, G&A expenses, excluding unit-based compensation, were $33.3 million, which was $2.0 million higher than 2011.

The increase was primarily due to additional activity related to our 2012 acquisitions. On a per Boe basis, G&A expenses, excluding unit-based compensation, were $4.00, a 10% decrease from the prior year.

Our G&A expenses totaled $53.3 million and $44.9 million in 2011 and 2010, respectively, including $22.0 million and $20.4 million, respectively, in unit-based compensation expense related to employee incentive plans. The increase in non-cash unit-based compensation expense was primarily due to new equity awards granted in the first quarter of 2011. For 2011, G&A expenses, excluding unit-based compensation, were $31.3 million, which was $6.8 million higher than 2010. The increase was primarily due to acquisition and integration costs related to our 2011 acquisitions, higher employee related costs and higher short-term incentive compensation expense.

Interest expense, net of amounts capitalized

Our interest expense totaled $61.2 million for the year ended December 31, 2012, net of less than $0.1 million of capitalized interest, an increase of $22.0 million from 2011. This increase in interest expense was primarily attributable to an additional $23.0 million associated with our 2022 Senior Notes and slightly higher amortization of debt issuance costs, partially offset by $1.2 million lower interest expense on our credit facility due to a lower credit facility debt balance.

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. See Part II—Item 7A “—Quantitative and Qualitative Disclosures About Market Risk” in this report for a discussion of our interest rate risk. We had realized losses of $5.5 million for the year ended December 31, 2012 compared to realized losses of $3.3 million for the year ended December 31, 2011 and unrealized gains of $4.4 million for the year ended December 31, 2012 compared to unrealized gains of $0.5 million for the year ended December 31, 2011, relating to our interest rate swaps. In the fourth quarter of 2012, we terminated an interest rate swap at a cost of $2.5 million, which is reflected in realized and unrealized gains and losses on interest rate derivative instruments for the year ended December 31, 2012. Interest expense, including realized losses on interest rate derivative contracts and excluding debt amortization and unrealized gains or losses on interest rate derivative contracts, totaled $61.8 million and $37.7 million for the years ended December 31, 2012 and 2011, respectively.

Our interest expense totaled $39.2 million for the year ended December 31, 2011 net of $0.1 million of capitalized interest, an increase of $14.6 million from 2010. This increase in interest expense was primarily attributable to an additional $19.9 million in interest expense associated with our 2020 Senior Notes, partially offset by $4.8 million lower interest expense on our credit facility due to a lower credit facility debt balance and $0.7 million lower amortization of debt issuance costs.

We had realized losses of $3.3 million for the year ended December 31, 2011, compared to realized losses of $11.1 million for the year ended December 31, 2010 and unrealized gains of $0.5 million for the year ended December 31, 2011 compared to unrealized gains of $6.6 million for the year ended December 31, 2010, relating to our interest rate swaps. Interest expense, including realized losses on interest rate derivative contracts and excluding debt amortization and unrealized gains or losses on interest rate derivative contracts, totaled $37.7 million and $30.2 million for the years ended December 31, 2011 and 2010, respectively.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations, amounts available under our credit facility and cash from the issuance of unsecured long-term debt and partnership units. Historically, our primary uses of cash have been for our operating expenses, capital expenditures, cash distributions to unitholders and unit repurchase transactions. To fund certain acquisition transactions, we have also sourced the private placement markets and have issued equity as partial consideration for the acquisition of oil and natural gas properties. As market conditions have permitted, we have also engaged in asset sale transactions.

Natural gas prices have fluctuated substantially in the last two years from a high monthly average Henry Hub price of $4.54 per MMBtu in June 2011 to a low of $1.95 per MMBtu in April 2012, with an average of $3.32 in 2013 to date. Henry Hub prices averaged $4.00 and $2.75 in 2011 and 2012, respectively. We have hedged more than 68% of our expected natural gas production in 2013 and 2014 at average prices of $5.87 and $4.99, respectively. As of February 27,

2013, we had approximately $77.0 million in borrowings outstanding under our credit facility and total lender commitments of $900 million. However, sustained low prices for natural gas may reduce the amounts we would otherwise have available to pay expenses, make distributions to our unitholders and service our indebtedness.

In 2013, our crude oil and natural gas capital spending program, including capitalized engineering and excluding acquisitions, is expected to be approximately $261 million.

In 2012, we spent $562.4 million on acquisitions in Texas, Wyoming and California and issued approximately 3 million Common Units.

Equity Offerings

In February 2011, we sold approximately 4.9 million Common Units at a price to the public of $21.25, resulting in proceeds net of underwriting discounts and expenses of $100 million. In February 2012, we sold 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 $166.0 million. In September 2012, we sold 11.5 million of our Common Units at a price to the public of $18.51 per Common Unit, resulting in proceeds, net of underwriting discount and offering expenses, of $204.1 million. In February 2013, we sold 14.95 million Common Units at a price to the public of $19.86, resulting in proceeds net of underwriting discounts and expenses of $285.0 million. We used the proceeds from these offerings to reduce borrowings under our credit facility.

Senior Notes

On October 6, 2010, we and BreitBurn Finance Corporation, and certain of our subsidiaries as guarantors, issued $305 million in aggregate principal amount of 8.625% senior notes due 2020 at a price of 98.358%. We received net proceeds of approximately $291.2 million, after deducting estimated fees and offering expenses, and used $290 million of the net proceeds to repay amounts outstanding under our credit facility.

On January 13, 2012, we and BreitBurn Finance Corporation, and certain of our subsidiaries, as guarantors, issued $250 million in aggregate principal amount of 7.875% senior notes due 2022 at a price of 99.154%. We received net proceeds of approximately $242.3 million, after deducting estimated fees and offering expenses, and used the proceeds to reduce borrowings under our credit facility.

In September 2012, we issued an additional $200 million aggregate principal amount of our 7.875% Senior Notes due 2022. These notes were offered as an addition to our existing 7.875% Senior Notes due 2022 at a premium of 103.500%. We received net proceeds of approximately $202.8 million, after deducting estimated fees and offering expenses, and used the proceeds to reduce borrowings under our credit facility.

The use of proceeds from the issuance of these senior notes to repay amounts outstanding under our credit facility increased the borrowing availability under our credit facility, which gives us additional flexibility to finance future acquisitions.

Credit Facility

As of December 31, 2011, our Second Amended and Restated Credit Agreement had a maturity date of May 9, 2016 and a borrowing base of $850 million.

In May 2012, we entered into the Fifth Amendment to the Second Amended and Restated Credit Agreement, which increased the permitted amount of senior unsecured notes we may issue from $700 million to $1 billion.

In October 2012, we entered into the Sixth Amendment to the Second Amended and Restated Credit Agreement, which increased our borrowing base to $1.0 billion and increased our total commitments from existing lenders to $900 million. The Sixth Amendment also provided us with the ability to increase our total commitments up to the $1 billion borrowing base upon lender approval.

We had outstanding borrowings under our credit facility of $345.0 million as of December 31, 2012 and $77.0 million as of February 27, 2013.

As of December 31, 2012, the lending group under the Second Amended and Restated Credit Agreement included 14 banks. Of the $900 million in total commitments under the credit facility, Wells Fargo Bank National Association held approximately 18.8% of the commitments. Ten banks held between 5% and 8% of the commitments, including Union Bank, N.A., Bank of Montreal, The Bank of Nova Scotia, Houston Branch, Citibank, N.A., Royal Bank of Canada, U.S. Bank National Association, Bank of Scotland plc, Barclays Bank PLC, The Royal Bank of Scotland plc and Credit Suisse AG, Cayman Islands Branch, with each of the remaining lenders holding less than 5% of the commitments. In addition to our relationships with these institutions under the credit facility, from time to time we engage in other transactions with a number of these institutions. Such institutions or their affiliates may serve as underwriter or initial purchaser of our debt and equity securities and/or serve as counterparties to our commodity and interest rate derivative agreements.

The Second Amended and Restated Credit Agreement contains customary covenants, including restrictions on our ability to: incur additional indebtedness, make certain investments, loans or advances, make distributions to our unitholders or repurchase units, make dispositions or enter into sales and leasebacks, or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.

The Second Amended and Restated Credit Agreement includes the restriction on our ability to make distributions unless after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility. In addition, the Second Amended and Restated Credit Agreement requires us to maintain a leverage ratio (defined as the ratio of total debt to EBITDAX) as of the last day of each quarter, on a last twelve month basis of no more than 4.00 to 1.00 and a current ratio as of the last day of each quarter, of not less than 1.00 to 1.00. As of December 31, 2012, we were in compliance with these covenants.

EBITDAX is not a defined GAAP measure. The Second Amended and Restated Credit Agreement defines EBITDAX as consolidated net income plus exploration expense, interest expense, income tax provision, DD&A, unrealized loss or gain on derivative instruments, non-cash charges, including non-cash unit-based compensation expense, loss or gain on sale of assets (excluding gain or loss on monetization of derivative instruments for the following twelve months), pro forma impact of acquisitions and disposition, cumulative effect of changes in accounting principles, cash distributions received from our unrestricted entities (as defined in the Second Amended and Restated Credit Agreement) and excluding income from our unrestricted entities.

The events that constitute an Event of Default (as defined in the Second Amended and Restated Credit Agreement) include: payment defaults, misrepresentations, breaches of covenants, cross-default and cross-acceleration to certain other indebtedness, adverse judgments against us in excess of a specified amount, changes in management or control, loss of permits, certain insolvency events and assertion of certain environmental claims.

Please see Part I—Item 1A “—Risk Factors”— “Risks Related to Our Business — Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions” in this report for more information on the effect of an event of default under the Second Amended and Restated Credit Facility.

Distributions

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. The following table provides a summary of distributions paid during the years ended December 31, 2012, 2011 and 2010:



	Total		Cash Distribution		Date
Thousands of dollars, except per unit amounts	Distribution		Per Common Unit		Paid
Fourth Quarter 2012	$	39,823	$	0.4700	2/14/2013
Third Quarter 2012	37,499		0.4650		11/14/2012
Second Quarter 2012	31,806		0.4600		8/14/2012
First Quarter 2012	31,461		0.4550		5/14/2012
Fourth Quarter 2011	26,988		0.4500		2/14/2012
Third Quarter 2011	25,682		0.4350		11/14/2011
Second Quarter 2011	24,944		0.4225		8/12/2011
First Quarter 2011	24,649		0.4175		5/13/2011
Fourth Quarter 2010	22,314		0.4125		2/11/2011
Third Quarter 2010	20,790		0.3900		11/12/2010
Second Quarter 2010	20,385		0.3825		8/13/2010
First Quarter 2010	19,985		0.3750		5/14/2010

Cash Flows

Operating activities. Our cash flow from operating activities in 2012 was $191.8 million compared to $128.5 million in 2011. The increase in cash flow from operating activities was primarily due to higher crude oil sales revenue and higher realized gains on commodity derivatives, partially offset by higher operating costs and higher interest expense. We paid $30.0 million in premiums on commodity derivative contracts in 2012 and paid $2.5 million to terminate an interest rate contract. See Note 5 to the consolidated financial statements in this report for more information regarding our derivatives.

Our cash flow from operating activities in 2011 was $128.5 million compared to $182.0 million in 2010. The decrease in cash flow from operating activities was primarily due to higher operating costs, higher overall cash interest expense and $36.8 million in net payments during 2011 related to the termination of commodity derivative contracts.

Investing activities. Net cash used in investing activities for the year ended December 31, 2012 was $697.2 million, which was predominantly spent on property acquisitions. Property acquisitions of $562.4 million in 2012 included $420 million for the Permian Basin Acquisitions, $95 million for the NiMin Acquisition and $38 million for the AEO Acquisition. We also spent $135.9 million for capital expenditures, primarily for drilling and completions. Net cash used in investing activities for the year ended December 31, 2011 was $414.6 million, including $280.6 million for the Cabot Acquisition, $57.4 million for the Greasewood Acquisition and $78.1 million for capital expenditures, primarily for drilling and completions.

Net cash used in investing activities for the year ended December 31, 2010 was $68.3 million, which was predominantly spent on drilling and completions, including drilling of the Raccoon Point wells in Florida.

Financing activities. Net cash provided by financing activities for the year ended December 31, 2012 was $504.6 million compared to $287.7 million for the year ended December 31, 2011. Our long-term debt increased by approximately $275 million in 2012 compared to $292 million in 2011. The increase in our debt in 2012 and 2011 was primarily due to borrowings for property acquisitions. In addition, for the year ended December 31, 2012, we received net cash proceeds from the issuance of Common Units of $370.2 million, made cash distributions of $132.4 million and

paid $10.0 million in debt issuance costs. For the year ended December 31, 2011, we received net cash proceeds from the issuance of Common Units of $99.4 million, made cash distributions of $102.7 million and paid $3.7 million in debt issuance costs.

Net cash used in financing activities for the year ended December 31, 2010 was $115.9 million. We reduced our long-term debt by approximately $26.0 million, made cash distributions of $65.2 million and paid $20.7 million in debt issuance costs.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of December 31, 2012.

Contractual Obligations and Commitments

The following table summarizes our financial contractual obligations as of December 31, 2012. Some of these contractual obligations are reflected in the balance sheet, while others are disclosed as future obligations under GAAP.



	Payments Due by Year
Thousands of dollars	2013		2014		2015		2016		2017		after 2017		Total
Credit facility (a)	$	—	$	—	$	—	$	345,000	$	—	$	—	$	345,000
Credit facility commitment fees	2,109		2,109		2,109		746		—		—		7,073
Senior Notes (b)	—		—		—		—		—		755,000		755,000
Estimated interest payments (c)	69,488		69,488		69,488		64,481		61,744		225,524		560,213
Operating lease obligations	4,713		4,323		3,902		2,843		2,441		396		18,618
Asset retirement obligations	709		5		—		57		422		97,287		98,480
Deferred premiums	898		657		—		—		—		—		1,555
Purchase obligations	183		—		—		—		—		—		183
Total	$	78,100	$	76,582	$	75,499	$	413,127	$	64,607	$	1,078,207	$	1,786,122

(a) Credit facility matures on May 9, 2016.
(b) Represents 8.625% senior notes due 2020 with a face value of $305,000 and 7.875% Senior Notes due 2022 with a face value of $450,000.
(c) Based on debt balance and interest rates in effect at December 31, 2012.

Surety Bonds and Letters of Credit

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At December 31, 2012, we had obtained various surety bonds for $16.2 million and $0.3 million in letters of credit outstanding. At December 31, 2011, we had $22.1 million in surety bonds and $0.3 million in letters of credit outstanding.

Credit and Counterparty Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives are exposed to credit risk from counterparties. As of December 31, 2012 and February 27, 2013, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, Toronto-Dominion Bank and the Royal Bank of Canada. Our counterparties are all lenders who participate in our Second Amended and Restated Credit Agreement. During 2008 and 2009, there was extreme volatility and disruption in the capital and credit markets. While the market has become more stable, future volatility could adversely affect the financial condition of our derivative counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to

entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. As of December 31, 2012 and February 27, 2013, each of these financial institutions had an investment grade credit rating. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default. As of December 31, 2012, our largest derivative asset balances were with Credit Suisse Energy LLC, Wells Fargo Bank National Association and The Royal Bank of Scotland plc which accounted for approximately 21%, 20% and 12% of our derivative asset balances, respectively. See Note 5 to the consolidated financial statements in this report for more information regarding our derivatives.

Accounts receivable are primarily from purchasers of oil and natural gas products. We have a portfolio of crude oil and natural gas sales contracts with large, established refiners and utilities. Because our products are commodity products sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. During the year ended December 31, 2012, our largest purchasers were ConocoPhillips, Plains Marketing & Transportation LLC and Marathon Oil Company which accounted for approximately 31%, 17% and 14% of net sales revenues, respectively.

ConocoPhillips, Plains Marketing & Transportation LLC and Marathon Oil Company comprised 10% or more of our outstanding trade receivables, and together comprised approximately 45% of our outstanding trade receivables as of December 31, 2012.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. The development, selection and disclosure of each of these policies is reviewed by our audit committee. We believe these accounting policies reflect the more significant estimates and assumptions used in preparation of our financial statements. See Note 2 to the consolidated financial statements in this report for a discussion of additional accounting policies and estimates made by management.

Successful Efforts Method of Accounting

We account for oil and gas properties using the successful efforts method. Under this method of accounting, leasehold acquisition costs are capitalized. Subsequently, if proved reserves are found on unproved property, the leasehold costs are transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.

DD&A of producing oil and gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves.

Geological, geophysical and dry hole costs on oil and gas properties relating to unsuccessful exploratory wells are charged to expense as incurred.

Oil and gas properties are reviewed for impairment periodically and when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and gas properties by

comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. For purposes of performing an impairment test, the undiscounted cash flows are forecast using five-year NYMEX forward strip prices at the end of the period and escalated thereafter at 2.5%. For impairment charges, the associated proved properties’ expected future net cash flows are discounted using a weighted average cost of capital which approximated 10% at December 31, 2012. Unproved properties are assessed for impairment along with proved properties and if considered impaired are charged to expense when such impairment is deemed to have occurred.

During the year ended December 31, 2012, we recorded impairments of approximately $12.3 million primarily related to uneconomic proved natural gas properties in Michigan. During the year ended December 31, 2011, we recorded impairments of approximately $0.6 million related to uneconomic proved natural gas properties in Michigan. During the year ended December 31, 2010, we recorded impairments of approximately $6.3 million related to our Michigan, Indiana and Kentucky properties, including a $4.2 million write-down of uneconomic proved properties and a $2.1 million write-down of expired unproved lease properties. Price declines may in the future result in additional impairment charges, which could have a material adverse effect on our results of operations in the period incurred.

We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. During 2012 and 2011 and 2010, interest of less than $0.1 million, $0.1 million and $0.3 million, respectively, was capitalized and included in our capital expenditures.

Business combinations

We account for all business combinations using the acquisition method. Under the acquisition method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if material, is recognized as a gain at the time of acquisition. All purchase price allocations are finalized within one year from the acquisition date. We have not recognized any goodwill from any business combinations.

Oil and Gas Reserve Quantities

The estimates of our proved reserves are based on the quantities of oil and gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Annually, Netherland, Sewell & Associates, Inc. and Schlumberger PetroTechnical Services prepare reserve and economic evaluations of all our properties on a well-by-well basis.

Estimated proved reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our disclosures for reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firms described above adhere to the same guidelines when preparing their reserve reports. The accuracy of the reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.

Our estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of oil and gas producing properties for impairment. For example, if the SEC prices used for our December 31, 2012 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, 2012 would have decreased by approximately $501.7 million, from $1,989.9 million to $1,488.2 million.

Please see Part I—Item 1A —“Risk Factors” — “Risks Related to Our Business — Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves.”

Asset Retirement Obligations

Estimated asset retirement obligation (“ARO”) costs are recognized when the asset is placed in service and are amortized over proved reserves using the units of production method. The engineers of BreitBurn Management estimate asset retirement costs using existing regulatory requirements and anticipated future inflation rates. Projecting future ARO cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of future oil and gas reserves, future labor and equipment rates, future inflation rates, and our credit adjusted risk free interest rate. Because of the intrinsic uncertainties present when estimating asset retirement costs as well as asset retirement settlement dates, our ARO estimates are subject to ongoing volatility.

Derivative Instruments

We use derivative financial instruments to achieve more predictable cash flow from our oil and natural gas production by reducing their exposure to price fluctuations. Currently, these instruments include swaps, collars and options. Additionally, we may use derivative financial instruments in the form of interest rate swaps to mitigate interest rate exposure. Derivative instruments (including certain derivative instruments embedded in other contracts) are recorded at fair market value and are included in the balance sheet as assets or liabilities. The accounting for changes in the fair market value of a derivative instrument depends on the intended use of the derivative instrument and the resulting designation, which is established at the inception of a derivative instrument. We do not account for our derivative instruments as cash flow hedges for financial accounting purposes and are recognizing changes in the fair value of our derivative instruments immediately in net income. See Part II—Item 7A “—Quantitative and Qualitative Disclosures About Market Risk” and Note 5 to the consolidated financial statements in this report for additional information related to our financial instruments.

New Accounting Standards

See Note 3 to the consolidated financial statements in this report for a discussion of new accounting standards.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. See “Cautionary Statement Regarding Forward-Looking Information” in Part I—Item 1 “—Business” in this report.

See Note 5 to the consolidated financial statements in this report for additional information related to our financial instruments, including summaries of our commodity and interest rate derivative contracts at December 31, 2012 and a discussion of credit and counterparty risk.

Commodity Price Risk

Due to the historical volatility of crude oil and natural gas prices, we have entered into various derivative instruments to manage exposure to volatility in the market price of crude oil and natural gas to achieve more predictable cash flows. We use swaps, collars and options for managing risk relating to commodity prices. All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement. While this strategy may result in us having lower revenues than we would otherwise have if we had not utilized these instruments in times of higher oil and natural gas prices, management believes that the resulting reduced volatility of prices and cash flow is beneficial. While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash 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. Please see Part I—Item 1A — “Risk Factors” — “Risks Related to Our Business — Our derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders. To the extent we have hedged a significant portion of our expected production and actual production is lower than expected or the costs of goods and services increase, our profitability would be adversely affected.” The use of derivatives also involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.

Our commodity derivative instruments provide for monthly settlement based on the differential between the agreement price and the actual ICE Brent crude oil price, NYMEX WTI crude oil price, NYMEX Henry Hub natural gas price or MichCon City-Gate natural gas price.

We do not currently designate any of our derivative instruments as hedges for financial accounting purposes. In order to qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge effectiveness must be measured, at minimum, on a quarterly basis. Hedge accounting must be discontinued prospectively when a hedge instrument is no longer considered to be highly effective. Many of our commodity derivative instruments would not qualify for hedge accounting due to the ineffectiveness created by variability in our price discounts or differentials.

Our Los Angeles Basin crude oil is generally medium gravity crude. Because of its proximity to the extensive Los Angeles refinery market, it trades at a premium to NYMEX WTI. Historically, WTI oil prices and ICE Brent oil prices have fluctuated together, but recently WTI and ICE Brent oil prices have diverged. Management believes that ICE Brent pricing will better correlate with local California prices we receive in the future. In 2012, ICE 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. In 2012, our Florida crude oil traded at a premium to NYMEX WTI. Our Texas crude oil traded at a discount to NYMEX due to the deduction of transportation costs and benchmarking to WTI posted prices.

Our Michigan properties have favorable natural gas supply/demand characteristics as the state has been importing an increasing percentage of its natural gas. To the extent our production is not hedged, the supply/demand situation has allowed us to sell our natural gas production with little or no discount to industry MichCon City-Gate prices. Our Wyoming natural gas trades at a discount to Henry Hub due to its relative location and the regional supply/demand market balances. Our Texas natural gas traded at a premium to Henry Hub primarily due to its high BTU content.

During 2012, the average differentials per barrel to NYMEX WTI benchmark prices were a $13.30 premium for our California-based oil production, a $17.55 discount for our Wyoming-based oil production, a $4.91 discount for our Texas-based oil production and a $2.91 premium for our Florida-based oil production, excluding transportation costs. During 2012, the average differentials per Mcf to Henry Hub benchmark prices were a $0.21 premium for our Michigan-based natural gas production, an $0.18 premium for our Wyoming-based natural gas production and a $1.78 premium for out Texas-based natural gas production.

During 2011, the average differentials per barrel to NYMEX WTI benchmark prices were a $13.88 premium for our California-based oil production, a $15.42 discount for our Wyoming-based oil production and a $14.46 discount for our Florida-based oil production, including approximately $7.50 in transportation costs. During 2011, the average differentials per Mcf to Henry Hub benchmark prices were a $0.27 premium for our Michigan-based natural gas production and a $0.01 discount for our Wyoming-based natural gas production.

During 2010, the average discounts we received for our crude oil production relative to NYMEX WTI benchmark prices per barrel were $0.25 for California-based production, $13.24 for Wyoming-based production, and $16.15 for Florida-based production, including approximately $7.50 in transportation costs. During 2010, the average premium we received for our natural gas production relative to Henry Hub benchmark prices per Mcf was $0.17 for our Michigan-based production.

All of our derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or confirmed by the counterparty. Changes in the fair value of our commodity derivatives were recorded in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations, as a loss of $82.0 million for 2012 and a gain of $97.7 million for 2011.

Interest Rate Risk

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. At December 31, 2012, LIBOR based long-term debt outstanding under our credit facility was $345.0 million. For the year ended December 31, 2012, our weighted average credit facility debt balance was $217 million and, excluding the impact of interest rate swaps, if interest rates on our LIBOR based debt increased or decreased by 1%, our annual interest cost would have increased or decreased by approximately $2.2 million.

Changes in Fair Value

The fair value of our outstanding oil and gas commodity derivative instruments at December 31, 2012 was a net asset of approximately $79.2 million. The fair value of our outstanding oil and gas commodity derivative instruments at December 31, 2011 was a net asset of approximately $131.2 million.

As of December 31, 2012, assuming a $10 per barrel increase in the price of oil and a corresponding $1 per Mcf increase in natural gas, our net commodity derivative instrument asset at December 31, 2012 would have decreased by approximately $176 million. Assuming a $10 per barrel decrease in the price of oil and a corresponding $1 per Mcf decrease in natural gas, our net commodity derivative instrument asset at December 31, 2012 would have increased by approximately $180 million.

Price risk sensitivities were calculated by assuming across-the-board increases in price of $10 per barrel for oil and $1 per Mcf for natural gas regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of actual changes in prompt month prices equal to the assumptions, the

fair value of our derivative portfolio would typically change by less than the amounts given due to lower volatility in out-month prices.

Changes in derivative instruments since December 31, 2012

In February 2013, we entered into NYMEX WTI and ICE Brent fixed price crude oil swaps covering a total of approximately 2.2 million barrels of future production in 2013 through 2017 at a weighted average hedge price of $96.02 per Bbl. Also in February 2013, we entered into Henry Hub fixed price natural gas swaps covering a total of approximately 2,375 BBtu of future production in 2016 and 2017 at a weighted average hedge price of $4.47 per MMBtu.

Item 8. Financial Statements and Supplementary Data.

The information required by this Item 8 is incorporated herein by reference from the consolidated financial statements beginning on page F-1.

Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our General Partner's principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our General Partner's principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon the evaluation, our General Partner's principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2012 at the reasonable assurance level.

Management’s Report on Internal Control Over Financial Reporting

The information required by this Item is incorporated by reference from “Management’s Report on Internal Control Over Financial Reporting” located on page F-2.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2012 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2012 that has not previously been reported.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Information concerning our directors, executive officers and corporate governance required by this Item is incorporated by reference to the material appearing in our Proxy Statement for the 2013 Annual Meeting of Unitholders (“2013 Proxy Statement”). The 2013 Annual Meeting of Unitholders is to be held on June 19, 2013.

The Board has established an audit committee and determined which members are our “audit committee financial experts.” Information concerning our audit committee required by this Item is incorporated by reference to the material appearing in our 2013 Proxy Statement.

We have adopted a Code of Ethics for Chief Executive Officers and Senior Officers. It is available on our website at http://ir.breitburn.com/documentdisplay.cfm?DocumentID=804.

Directors and Executive Officers of BreitBurn GP, LLC

The following table sets forth certain information with respect to the members of the board of directors and the executive officers of our General Partner. Executive officers and directors will serve until their successors are duly appointed or elected.



Name	Age	Position with BreitBurn GP, LLC
Halbert S. Washburn	52	Chief Executive Officer, Director
Mark L. Pease	56	President and Chief Operating Officer
James G. Jackson	48	Executive Vice President and Chief Financial Officer
Gregory C. Brown	61	Executive Vice President, General Counsel and Chief Administrative Officer
Chris E. Williamson	55	Senior Vice President
W. Jackson Washburn	50	Senior Vice President
David D. Baker	40	Vice President
Bruce D. McFarland	56	Vice President and Treasurer
Lawrence C. Smith	59	Vice President and Controller
John R. Butler, Jr.*	74	Chairman of the Board
Randall H. Breitenbach	52	Vice Chairman of the Board
David B. Kilpatrick*	63	Director
Gregory J. Moroney*	61	Director
Charles S. Weiss*	60	Director

* Independent Directors

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the directors and executive officers of our General Partner, and persons who own more than 10% of a registered class of our equity securities (collectively, “Insiders”), to file reports of beneficial ownership on Form 3 and reports of changes in beneficial ownership on Form 4 or Form 5 with the SEC. Based solely on our review of the reporting forms and written representations provided to us from the individuals required to file reports, we believe that each of our executive officers and directors has complied with the applicable reporting requirements for transactions in our securities during the fiscal year ended December 31, 2012.

Item 11. Executive Compensation.

Information required by this Item is incorporated by reference to the material appearing in our 2013 Proxy Statement.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

Information required by this Item is incorporated by reference to the material appearing in our 2013 Proxy Statement.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth certain information with respect to our equity compensation plans as of December 31, 2012.



Plan category, thousands	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted- average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders	—		—		—
Equity compensation plans not approved by security holders - Partnership LTIP	942	⁽¹⁾	N/A	⁽²⁾	5,466	⁽³⁾
Total	942		N/A		5,466

(1) Represents the number of units issued under the Partnership First Amended and Restated 2006 Long-Term Incentive Plan (“Partnership LTIP”).
(2) Unit awards under the Partnership LTIP and the BreitBurn Management Long Term Incentive Plan vest without payment by recipients.
(3) The Partnership LTIP provides that the Board or a committee of the Board may award restricted units, performance units, unit appreciation rights or other unit-based awards and unit awards.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Information required by this Item is incorporated by reference to the material appearing in our 2013 Proxy Statement.

Item 14. Principal Accounting Fees and Services.

Information required by this Item is incorporated by reference to the material appearing in our 2013 Proxy Statement.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) (1) Financial Statements

See “Index to the Consolidated Financial Statements” set forth on Page F-1.

(2) Financial Statement Schedules

All schedules are omitted because they are not applicable or the required information is presented in the consolidated financial statements or notes thereto.

(3) Exhibits



NUMBER		DOCUMENT
3.1		Certificate of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 (File No. 333-134049) filed on July 13, 2006).
3.2		First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2006).
3.3		Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
3.4		Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed April 9, 2009).
3.5		Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed September 1, 2009).
3.6		Amendment No.4 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
3.7		Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC dated as of April 5, 2010 (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2011).
3.8		Amendment No. 1 to the Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC dated as of December 30, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
4.1		Registration Rights Agreement, dated as of November 1, 2007, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).
4.2		First Amendment to the Registration Rights Agreement, dated as of April 5, 2010, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
4.3		Indenture, dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010).
4.4		Registration Rights Agreement, dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010).
4.5		Indenture, dated as of January 13, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 13, 2012).



NUMBER		DOCUMENT
4.6		Registration Rights Agreement, dated as of January 13, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and Wells Fargo Securities, LLC as representative of the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on January 13, 2012).
4.7		Registration Rights Agreement, dated as of September 27, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and Wells Fargo Securities, LLC, as representative of the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on September 28, 2012).
10.1*		Seventh Amendment to the Second Amended and Restated Credit Agreement of BreitBurn Energy Partners L.P. dated February 26, 2013.
10.2		Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners I, L.P. dated May 5, 2003 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on May 29, 2007).
10.3†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Executive Form) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on March 11, 2008).
10.4†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Executive Form) (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on March 11, 2008).
10.5†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Units Directors’ Award Agreement (incorporated herein by reference to Exhibit 10.35 to the Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-33055) and filed on March 17, 2008).
10.6		Amendment No. 1 to the Operations and Proceeds Agreement, relating to the Dominguez Field and dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.7		Amendment No. 1 to the Surface Operating Agreement dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and its predecessor BreitBurn Energy Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.8†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement (Employment Agreement Form) (incorporated herein by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the period ended June 30, 2008 (File No. 001-33055) and filed on August 11, 2008).
10.9†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement (Non-Employment Agreement Form) (incorporated herein by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the period ended June 30, 2008 and (File No. 001-33055) filed on August 11, 2008).
10.10		Second Amended and Restated Administrative Services Agreement dated August 26, 2008 by and between BreitBurn Energy Company L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 02, 2008).
10.11		Omnibus Agreement, dated August 26, 2008, by and among BreitBurn Energy Holdings LLC, BEC (GP) LLC, BreitBurn Energy Company L.P, BreitBurn GP, LLC, BreitBurn Management Company, LLC and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on September 02, 2008).
10.12		Indemnity Agreement between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Halbert S. Washburn, together with a schedule identifying other substantially identical agreements between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and each of its executive officers and non-employee directors identified on the schedule (incorporated herein by reference to Exhibit 10.1 to the Current Report on form 8-K (File No. 001-33055) filed on November 4, 2009).
10.13†		First Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.2 to the Current Report on form 8-K (File No. 001-33055) filed on November 4, 2009).
10.14†		First Amended and Restated BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan effective as of October 29, 2009 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the period ended September 30, 2009 (File No. 001-33055) filed on November 6, 2009).



NUMBER		DOCUMENT
10.15		Settlement Agreement as of April 5, 2010 by and among Quicksilver Resources Inc., BreitBurn Energy Partners L.P., BreitBurn GP LLC, Provident Energy Trust, Randall H. Breitenbach and Halbert S. Washburn (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 9, 2010).
10.16†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Executive Form) (incorporated herein by reference to Exhibit 10.21 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011).
10.17†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Executive Form) (incorporated herein by reference to Exhibit 10.22 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011).
10.18†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Director Form) (incorporated herein by reference to Exhibit 10.23 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011).
10.19†		Form of Second Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.24 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011).
10.20†		Form of Third Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.25 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011).
10.21		Third Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Halbert S. Washburn (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
10.22		Third Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
10.23		Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Mark L. Pease (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
10.24		Second Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and James G. Jackson (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
10.25		Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Gregory C. Brown (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
10.26		Second Amended and Restated Credit Agreement, dated May 7, 2010, by and among BreitBurn Operating L.P, as borrower, BreitBurn Energy Partners L.P., as parent guarantor, and Wells Fargo Bank, N.A., as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the period ended March 31, 2010 (File No. 001-33055) filed on May 10, 2010).
10.27		First Amendment dated September 17, 2010 to the Second Amended and Restated Credit Agreement dated May 7, 2010, by and among BreitBurn Operating L.P, as borrower, BreitBurn Energy Partners L.P., as parent guarantor, and Wells Fargo Bank, N.A., as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 23, 2010).
10.28		Second Amendment to the Second Amended and Restated Credit Agreement dated May 9, 2011 (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 001-33055) filed on May 10, 2011).



NUMBER		DOCUMENT
10.29		Asset Purchase Agreement, dated as of July 26, 2011, between Cabot Oil & Gas Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on July 29, 2011).
10.30		Third Amendment to the Second Amended and Restated Credit Agreement dated August 3, 2011 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-33055) filed on August 8, 2011).
10.31		Fourth Amendment to the Second Amended and Restated Credit Agreement dated October 5, 2011 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2011).
10.32		Dissolution Agreement, dated May 8, 2012, by and among BreitBurn Energy Partners L.P., Pacific Coast Energy Company LP, BEP (GP) I, LLC and BreitBurn Energy Partners I, L.P. (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 (File No. 001-33055) filed on August 8, 2012).
10.33		Amendment No. 1 to BEPI Partnership Agreement, dated May 8, 2012, by and between BEP (GP) I, LLC and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 (File No. 001-33055) filed on August 8, 2012).
10.34		Third Amended and Restated Administrative Services Agreement, dated May 8, 2012, by and between Pacific Coast Energy Company L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 (File No. 001-33055) filed on August 8, 2012).
10.35		First Amendment to Omnibus Agreement, dated May 8, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn GP, LLC, BreitBurn Management Company, LLC, Pacific Coast Energy Company L.P., Pacific Coast Energy Holdings LLC and PCEC (GP) LLC (incorporated herein by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 (File No. 001-33055) filed on August 8, 2012).
10.36		Purchase and Sale Agreement, dated April 24, 2012, among Legacy Energy, Inc., NiMin Energy Corp. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 27, 2012).
10.37		Purchase and Sale Agreement, dated May 9, 2012, between Element Petroleum, L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on May 11, 2012).
10.38		Purchase and Sale Agreement, dated May 9, 2012, between CrownRock, L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on May 11, 2012).
10.39		First Amendment to Purchase and Sale Agreement, dated as of June 28, 2012, among Legacy Energy, Inc., NiMin Energy Corp. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 29, 2012).
10.40		Fifth Amendment to the Second Amended and Restated Credit Agreement, dated as of May 25, 2012 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on June 29, 2012).
10.41		Sixth Amendment to the Second Amended and Restated Credit Agreement, dated as of October 11, 2012 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2012).
10.42		Contribution Agreement, dated November 21, 2012, among American Energy Operations, Inc., BreitBurn Energy Partners L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on November 27, 2012).
10.43†		Retirement Agreement, dated as of November 30, 2012, among BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on December 6, 2012).
10.44†		Omnibus First Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreements, dated as of November 30, 2012, among BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.2 to the Current Report on form 8-K (File No. 001-33055) filed on December 6, 2012).



NUMBER		DOCUMENT
10.45†		Fourth Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement, dated as of November 30, 2012, among BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.3 to the Current Report on form 8-K (File No. 001-33055) filed on December 6, 2012).
10.46		Purchase and Sale Agreement, dated December 11, 2012, between CrownRock, L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on December 12, 2012).
10.47		Purchase and Sale Agreement, dated December 11, 2012, between Lynden USA Inc. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on December 12, 2012).
10.48†		Form of First Amendment to BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Director Form) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on December 14, 2012).
10.49†		Form of Fourth Amendment to BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Convertible Phantom Unit Agreement (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on December 14, 2012).
14.1		BreitBurn Energy Partners L.P. and BreitBurn GP, LLC Code of Ethics for Chief Executive Officers and Senior Officers (as amended and restated on February 28, 2007) (incorporated herein by reference to Exhibit 14.1 to the Current Report on Form 8-K filed on March 5, 2007).
21.1*		List of subsidiaries of BreitBurn Energy Partners L.P.
23.1*		Consent of PricewaterhouseCoopers LLP.
23.2*		Consent of Netherland, Sewell & Associates, Inc.
23.3*		Consent of Schlumberger PetroTechnical Services.
31.1*		Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*		Netherland, Sewell & Associates, Inc. reserve report for certain properties located in Wyoming.
99.2*		Netherland, Sewell & Associates, Inc. reserve report for certain properties located in California, Florida, and Texas.
99.3*		Schlumberger PetroTechnical Services reserve report.
101††		Interactive Data Files



*		Filed herewith.
**		Furnished herewith.
†		Management contract or compensatory plan or arrangement.
††		The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under these sections.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	BREITBURN ENERGY PARTNERS L.P.

	By:	BREITBURN GP, LLC,
		its General Partner

Dated: February 28, 2013	By:	/s/ Halbert S. Washburn
		Halbert S. Washburn
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Name	Title	Date


/s/ Halbert S. Washburn	Chief Executive Officer and Director of	February 28, 2013
Halbert S. Washburn	BreitBurn GP, LLC
	(Principal Executive Officer)

/s/ James G. Jackson	Chief Financial Officer of	February 28, 2013
James G. Jackson	BreitBurn GP, LLC
	(Principal Financial Officer)

/s/ Lawrence C. Smith	Vice President and Controller of	February 28, 2013
Lawrence C. Smith	BreitBurn GP, LLC
	(Principal Accounting Officer)

/s/ John R. Butler, Jr.	Chairman of the Board of	February 28, 2013
John R. Butler, Jr.	BreitBurn GP, LLC


/s/ Randall H. Breitenbach	Vice Chairman of the Board	February 28, 2013
Randall H. Breitenbach	BreitBurn GP, LLC


/s/ David B. Kilpatrick	Director of	February 28, 2013
David B. Kilpatrick	BreitBurn GP, LLC


/s/ Gregory J. Moroney	Director of	February 28, 2013
Gregory J. Moroney	BreitBurn GP, LLC


/s/ Charles S. Weiss	Director of	February 28, 2013
Charles S. Weiss	BreitBurn GP, LLC

BREITBURN ENERGY PARTNERS L.P. AND SUBSIDIARIES

INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS



Management's Report on Internal Control Over Financial Reporting	F-2

Report of Independent Registered Public Accounting Firm	F-3

Consolidated Balance Sheets	F-4

Consolidated Statements of Operations	F-5

Consolidated Statements of Cash Flows	F-6

Consolidated Statements of Partners’ Equity	F-7

Notes to Consolidated Financial Statements	F-8

Supplemental Information	F-36

Exhibit Index	F-42

F-1

Management’s Report on Internal Control Over Financial Reporting

The management of BreitBurn Energy Partners, L.P. (the “Partnership”) is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. The term “internal control over financial reporting” is defined as a process designed by, or under the supervision of, the Partnership’s principal executive and principal financial officers, or persons performing similar functions, and effected by the Partnership’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Partnership; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Partnership are being made only in accordance with authorizations of management and directors of the Partnership; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Partnership’s assets that could have a material effect on the financial statements.

Internal control over financial reporting, no matter how well designed, has inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

As required by Rule 13a-15(c) under the Exchange Act, the Partnership’s management, with the participation of the General Partner’s principal executive officers and principal financial officer, assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2012. In making this assessment, the Partnership’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control Integrated Framework. Based on this assessment, the Partnership’s management, including the general partner’s principal executive officers and principal financial officer, concluded that, as of December 31, 2012, the Partnership’s internal control over financial reporting was effective based on those criteria.

Management excluded from its assessment of the effectiveness of the Partnership's internal control over financial reporting the properties acquired in the AEO, CrownRock II, Lynden and Piedra acquisitions (as further described in Note 4 to the consolidated financial statements) because they were acquired in the fourth quarter of 2012. The assets acquired from AEO, CrownRock II, Lynden and Piedra in total represented approximately 10% of the Partnership's total assets as of December 31, 2012 and revenue from these assets represented less than 1% of the Partnership's total revenue for the year ended December 31, 2012.

PricewaterhouseCoopers LLP, the independent registered public accounting firm who audited the consolidated financial statements included in this Annual Report on Form 10-K, has issued a report on the Partnership’s internal control over financial reporting as of December 31, 2012, which appears on page F-3.



/s/ Halbert S. Washburn		/s/ James G. Jackson
Halbert S. Washburn		James G. Jackson
Chief Executive Officer of BreitBurn GP, LLC		Chief Financial Officer of BreitBurn GP, LLC

F-2

Report of Independent Registered Public Accounting Firm

To the Board of Directors of BreitBurn GP, LLC and

Unitholders of BreitBurn Energy Partners L.P.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners' equity and cash flows present fairly, in all material respects, the financial position of BreitBurn Energy Partners L.P. and its subsidiaries (the Partnership) at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As described in Management's Report on Internal Control Over Financial Reporting, management has excluded the oil and natural gas properties acquired from American Energy Operations, Inc., CrownRock, L.P., Lynden USA Inc., and Piedra Energy I, LLC (together, the Acquired Properties) from its assessment of internal control over financial reporting as of December 31, 2012 because the assets were acquired by the Partnership in November and December 2012. We have also excluded the Acquired Properties from our audit of internal control over financial reporting. Combined total assets and total revenues of the Acquired Properties represent 10% and less than 1%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2012.

/s/ PricewaterhouseCoopers LLP

February 28, 2013

F-3

BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Balance Sheets



	December 31,
Thousands	2012			2011
ASSETS
Current assets
Cash	$	4,507		$	5,328
Accounts and other receivables, net (note 2)	67,862			73,018
Derivative instruments (note 5)	34,018			83,452
Related party receivables (note 6)	1,413			4,245
Inventory (note 7)	3,086			4,724
Prepaid expenses	2,779			2,053
Total current assets	113,665			172,820
Equity investments (note 8)	7,004			7,491
Property, plant and equipment
Oil and gas properties	3,363,946			2,583,993
Other assets	14,367			13,431
	3,378,313			2,597,424
Accumulated depletion and depreciation (note 9)	(666,420		)	(524,665		)
Net property, plant and equipment	2,711,893			2,072,759
Other long-term assets
Derivative instruments (note 5)	55,210			55,337
Other long-term assets	27,722			22,442

Total assets	$	2,915,494		$	2,330,849

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	42,497		$	27,203
Derivative instruments (note 5)	5,625			8,881
Revenue and royalties payable	22,262			19,641
Salaries and wages payable	10,857			13,655
Accrued interest payable	13,002			6,291
Accrued liabilities	20,997			14,218
Total current liabilities	115,240			89,889

Credit facility (note 10)	345,000			520,000
Senior notes, net (note 10)	755,696			300,613
Deferred income taxes (note 12)	2,487			2,803
Asset retirement obligation (note 13)	98,480			82,397
Derivative instruments (note 5)	4,393			3,084
Other long-term liabilities	4,662			4,849
Total liabilities	1,325,958			1,003,635

Commitments and contingencies (note 14)

Equity:
Partners' equity (note 15)	1,589,536			1,326,764
Noncontrolling interest (note 16)	—			450
Total equity	1,589,536			1,327,214

Total liabilities and equity	$	2,915,494		$	2,330,849

Common units issued and outstanding	84,668			59,864

The accompanying notes are an integral part of these consolidated financial statements.

F-4

BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Statements of Operations



	Year Ended December 31,
Thousands of dollars, except per unit amounts	2012			2011			2010
Revenues and other income items:
Oil, natural gas and natural gas liquid sales	$	413,867		$	394,393		$	317,738
Gain on commodity derivative instruments, net (note 5)	5,580			81,667			35,112
Other revenue, net (note 8)	3,548			4,310			2,498
Total revenues and other income items	422,995			480,370			355,348
Operating costs and expenses:
Operating costs	195,779			165,969			142,525
Depletion, depreciation and amortization (note 9)	149,565			107,503			102,758
General and administrative expenses	55,465			53,313			44,907
(Gain) loss on sale of assets	486			(111		)	14
Unreimbursed litigation costs	—			(113		)	1,401
Total operating costs and expenses	401,295			326,561			291,605

Operating income	21,700			153,809			63,743

Interest expense, net of capitalized interest (note 10)	61,206			39,165			24,552
Loss on interest rate swaps (note 5)	1,101			2,777			4,490
Other expense (income), net	48			(19		)	(8		)

Income (loss) before taxes	(40,655		)	111,886			34,709

Income tax expense (benefit) (note 12)	84			1,188			(204		)

Net income (loss)	(40,739		)	110,698			34,913

Less: Net income attributable to noncontrolling interest (note 16)	(62		)	(201		)	(162		)

Net income (loss) attributable to the partnership	$	(40,801	)	$	110,497		$	34,751

Basic net income (loss) per unit (note 15)	$	(0.56	)	$	1.80		$	0.61
Diluted net income (loss) per unit (note 15)	$	(0.56	)	$	1.79		$	0.61

The accompanying notes are an integral part of these consolidated financial statements.

F-5

BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Statements of Cash Flows



	Year Ended December 31,
Thousands of dollars	2012			2011			2010
Cash flows from operating activities
Net income (loss)	$	(40,739	)	$	110,698		$	34,913
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization	149,565			107,503			102,758
Unit based compensation expense	22,266			22,043			20,422
Unrealized (gain) loss on derivative instruments	77,657			(98,214		)	33,116
Income from equity affiliates, net	487			210			450
Deferred income taxes	(316		)	714			(403		)
Amortization of intangibles	—			—			495
(Gain) loss on sale of assets	486			(111		)	14
Other	4,472			(312		)	3,528
Changes in net assets and liabilities
Accounts receivable and other assets	(23,284		)	(17,833		)	11,552
Inventory	1,638			2,597			(1,498		)
Net change in related party receivables and payables	2,832			100			(15,218		)
Accounts payable and other liabilities	(3,282		)	1,148			(8,107		)
Net cash provided by operating activities	191,782			128,543			182,022
Cash flows from investing activities (a)
Capital expenditures	(135,932		)	(78,107		)	(66,947		)
Proceeds from sale of assets	1,129			2,339			337
Property acquisitions	(562,356		)	(338,805		)	(1,676		)
Net cash used in investing activities	(697,159		)	(414,573		)	(68,286		)
Cash flows from financing activities
Issuance of common units, net	370,234			99,443			—
Distributions	(132,420		)	(102,686		)	(65,197		)
Proceeds from issuance of long-term debt, net	1,502,885			661,500			1,047,992
Repayments of long-term debt	(1,223,000		)	(369,500		)	(1,079,000		)
Change in bank overdraft	(3,176		)	2,636			1,025
Debt issuance costs	(9,967		)	(3,665		)	(20,692		)
Net cash provided by (used in) financing activities	504,556			287,728			(115,872		)
Increase (decrease) in cash	(821		)	1,698			(2,136		)
Cash beginning of period	5,328			3,630			5,766
Cash end of period	$	4,507		$	5,328		$	3,630

(a) Non-cash investing activities in 2012 were $56 million, reflecting the issuance of approximately 3 million Common Units for the AEO Acquisition.

The accompanying notes are an integral part of these consolidated financial statements.

F-6

BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Statements of Partners’ Equity



Thousands	Common Units	Partners' Equity
Balance, December 31, 2009	52,784	$	1,228,373
Distributions	—	(61,161		)
Distributions paid on unissued units under incentive plans	—	(4,020		)
Units issued under incentive plans	1,173	7,677
Unit-based compensation	—	3,183
Net income attributable to the partnership	—	34,751
Balance, December 31, 2010	53,957	$	1,208,803
Distributions	—	(97,590		)
Distributions paid on unissued units under incentive plans	—	(5,096		)
Issuance of common units	4,945	99,443
Units issued under incentive plans	962	11,840
Unit-based compensation	—	(1,133		)
Net income attributable to the partnership	—	110,497
Balance, December 31, 2011	59,864	$	1,326,764
Distributions	—	(127,748		)
Distributions paid on unissued units under incentive plans	—	(4,672		)
Sale of common units	20,699	370,177
Common units issued in acquisition	3,014	55,691
Units issued under incentive plans	1,091	24,381
Unit-based compensation	—	(14,314		)
Net loss attributable to the partnership	—	(40,801		)
Other	—	58
Balance, December 31, 2012	84,668	$	1,589,536

The accompanying notes are an integral part of these consolidated financial statements.

F-7

Notes to Consolidated Financial Statements

Note 1. Organization

We are a Delaware limited partnership formed on March 23, 2006. Our initial public offering was in October 2006. Pacific Coast Energy Company LP (“PCEC”), formerly BreitBurn Energy Company L.P., was our Predecessor.

Our general partner is BreitBurn GP, LLC, a Delaware limited liability company (the “General Partner”), also formed on March 23, 2006. The board of directors of our General Partner has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly owned subsidiary, BreitBurn Operating L.P, (“BOLP”) and BOLP’s general partner BreitBurn Operating GP, LLC (“BOGP”). We own all of the ownership interests in BOLP and BOGP.

Our wholly owned subsidiary, BreitBurn Management, manages our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. See Note 6 for information regarding our relationship with BreitBurn Management. Our wholly owned subsidiary, BreitBurn Finance Corporation, was incorporated on June 1, 2009 under the laws of the State of Delaware. BreitBurn Finance Corporation has no assets or liabilities. Its activities are limited to co-issuing debt securities and engaging in other activities incidental thereto. Our wholly owned subsidiary, BreitBurn Collingwood Utica LLC (“Utica”) holds certain non-producing oil and gas zones in the Collingwood-Utica shale play in Michigan and is classified as an unrestricted subsidiary under our credit facility.

During 2011, Quicksilver Resources Inc. (“Quicksilver”), a holder of 15.7 million of our limited partnership units (“Common Units”) sold 100% of its interest in the Partnership. Also in 2011, The Baupost Group, L.L.C. sold 4.4 million of our Common Units, disposing of 100% of its interest in the Partnership.

As of December 31, 2012, public unitholders owned 99.18% of our Common Units and BreitBurn Energy Corporation owned 0.7 million Common Units, representing a 0.82% limited partner interest. We own 100% of the General Partner, BreitBurn Management, BOLP, BreitBurn Finance Corporation and Utica.

2. Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. Investments in affiliated companies with a 20% or greater ownership interest, and in which we do not have control, are accounted for on the equity basis. Investments in affiliated companies with less than a 20% ownership interest, and in which we do not have control, are accounted for on the cost basis. Investments in which we own greater than 50% interest and in which we have control are consolidated. Investments in which we own less than a 50% interest but are deemed to have control, or where we have a variable interest in an entity in which we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated. The effects of all intercompany transactions have been eliminated.

Basis of presentation

Our financial statements are prepared in conformity with U.S. generally accepted accounting principles. Certain items included in the prior year financial statements were reclassified to conform to the 2012 presentation.

We recorded out-of-period adjustments in the fourth quarter and during 2012 that resulted in net reductions of net income of $2.1 million and $1.0 million, respectively. The adjustments primarily related to a correction of property tax expense and depreciation, depletion and amortization (“DD&A”). We concluded that the impact of these corrections was not material to the current year or any prior period.

F-8

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including fair value of derivative instruments, unit based compensation and oil and gas reserve quantities, which are the basis for the calculation of DD&A, asset retirement obligations and impairment of oil and gas properties.

Business segment information

We report in one segment because our oil and gas operating areas have similar economic characteristics. We acquire, exploit, develop and produce oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas.

Revenue recognition

Revenues associated with sales of our crude oil and natural gas are recognized when title passes from us to our customer. Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest (“entitlement” method of accounting). We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold. As a result, we have no material natural gas producer imbalance positions.

Accounts receivable

Our accounts receivable are primarily from purchasers of crude oil and natural gas and counterparties to our financial instruments. Crude oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2012 and 2011, we had an allowance for doubtful accounts receivable of $0.6 million and $0.2 million, respectively.

The settlement costs related to the Quicksilver lawsuit and the associated legal expenses were $13.0 million and approximately $8.7 million, respectively, of which we collected approximately $10.0 million from our insurance companies during the year ended December 31, 2010. Of the costs incurred in connection with the lawsuit, $1.4 million was estimated to be not recoverable from the insurance companies and is reflected as an expense in unreimbursed litigation costs on the consolidated statements of operations for the year ended December 31, 2010. The receivable at December 31, 2010 was $10.3 million. In 2011, we reduced the previously recorded $1.4 million provision by $0.1 million in anticipation of the final insurance recovery payment of $10.4 million, which we received in January 2012. At December 31, 2011, accounts receivable included $10.4 million due from our insurance companies related to the lawsuit.

Inventory

Oil inventories are carried at the lower of cost to produce or market price. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded as inventory.

Investments in equity affiliates

Income from equity affiliates is included as a component of operating income, as the operations of these affiliates are associated with the processing and transportation of our natural gas production.

F-9

Property, plant and equipment

Oil and gas properties

We follow the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred.

Upon sale or retirement of proved properties, the cost thereof and the accumulated depletion, depreciation and amortization are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, are generally computed on a field-by-field basis where applicable and recognized using the units of production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using straight line, generally over 20 years.

We capitalize interest costs to oil and gas properties on expenditures made in connection with drilling and completion of new oil and natural gas wells. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. During 2012, 2011 and 2010, interest of $0.1 million, $0.1 million and $0.3 million, respectively, was capitalized and included in our capital expenditures.

Non-oil and gas assets

Buildings and non-oil and gas assets are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to 10 years.

Oil and natural gas reserve quantities

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with the Securities and Exchange Commission (the “SEC”) guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports.

Asset retirement obligations

We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations. The fair value of a liability for an asset retirement obligation (“ARO”) is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and recorded on the depletion, depreciation and amortization on the consolidated statements of operations. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of crude oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance.

Impairment of assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. A long-lived asset is tested for impairment periodically and when events or circumstances

F-10

indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves, and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2.5% per year. For impairment charges, the associated property’s expected future net cash flows are discounted using a weighted average cost of capital which approximated 10% at December 31, 2012. Reserves are calculated based upon reports from third party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Unproved properties are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.

We assess our long-lived assets for impairment generally on a field-by-field basis where applicable. See Note 9 for a discussion of our impairments and price related depletion and depreciation adjustments.

Debt issuance costs

The costs incurred to obtain financing have been capitalized. Debt issuance costs are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. Amortization of debt issuance costs for the year ended December 31, 2010 included a $1.5 million write-off of debt issuance costs as a result of the reduced borrowing base under our credit facility.

Equity-based compensation

BreitBurn Management has various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 17. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period. We recognize equity-based compensation costs on a straight line basis over the annual vesting periods. Awards classified as liabilities are revalued at each reporting period and changes in the fair value of the options are recognized as compensation expense over the vesting schedules of the awards.

Fair market value of financial instruments

The carrying amount of our cash, accounts receivable, accounts payable, related party receivables and payables, and accrued expenses approximate their respective fair value due to the relatively short term of the related instruments. The carrying amount of long-term debt under our credit facility approximates fair value; however, changes in the credit markets may impact our ability to enter into future credit facilities at similar terms. See Note 10 for the fair value of our Senior Notes.

Accounting for business combinations

Concentration of credit risk

We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk. At times, such balances may be in excess of the Federal Insurance Corporation insurance limit. As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers

F-11

and pay vendors on behalf of joint owners for oil and gas services. We periodically monitor our major purchasers’ credit ratings. We enter into commodity and interest rate derivative instruments. Our derivative counterparties are all lenders under our credit facility and we periodically monitor their credit ratings.

Derivatives

Financial Accounting Standards Board (“FASB”) Accounting Standards establish accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. These standards require recognition of all derivative instruments as assets or liabilities on our balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. We currently do not designate any of our derivatives as hedges for financial accounting purposes. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities.

Fair value measurement is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date. The objective of fair value measurement is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If there is an active market for the asset or liability, the fair value measurement shall represent the price in that market whether the price is directly observable or otherwise obtained using a valuation technique.

Income taxes

Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided.

We have three wholly owned subsidiaries which are subject to corporate income taxes. Deferred income taxes are recorded under the asset and liability method. Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities.

FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial-statement comparability among different companies.

We performed evaluations as of December 31, 2012, 2011 and 2010 and concluded that there were no uncertain tax positions requiring recognition in our financial statements.

Net Income or loss per unit

FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of Common Unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”) participate in dividends on an equal basis with Common Units; therefore, there is no difference in undistributed earnings allocated to each participating security. Accordingly, our calculation is prepared on a combined basis and is presented as net income (loss) per Common Unit. See Note 15 for our earnings per Common Unit calculation.

F-12

Environmental expenditures

We review, on an annual basis, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. We do not discount these liabilities. At December 31, 2012, we had a $1.9 million environmental liability accrued that included cost estimates related to the maintenance of ground water monitoring wells associated with certain former well sites in Michigan that are no longer producing. At December 31, 2011, we had a $1.9 million environmental liability accrued.

3. Accounting Standards

In May 2011, the FASB issued an ASU to improve comparability between U.S. GAAP and International Financial Reporting Standards (“IFRS”) fair value measurement and disclosure requirements. This amendment changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements, particularly for Level 3 fair value measurements. For many of the requirements, the FASB does not intend for the amendments to result in a change in the application of the fair value measurement and disclosure requirements. Some of the amendments clarify the FASB's intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. This ASU is effective for interim and annual periods beginning after December 15, 2011. This ASU requires prospective application. We adopted this ASU on January 1, 2012. The adoption of this ASU, which expanded our fair value disclosures, did not have a material impact on our financial position, results of operations or cash flows.

In December 2011, the FASB issued an ASU which requires companies to disclose information about financial instruments that have been offset and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. Companies will be required to provide both net (offset amounts) and gross information in the notes to the financial statements for relevant assets and liabilities that are offset. This update is effective for interim and annual periods beginning on or after January 1, 2013 and requires retrospective application. We do not expect the adoption of this ASU to have a material impact on our financial position, results of operations or cash flows.

4. Acquisitions

Our purchase price allocations are based on discounted cash flows, quoted market prices and estimates made by management, the most significant assumptions related to the estimated fair values assigned to oil and gas properties with proved reserves. To estimate the fair values the properties, estimates of oil and gas reserves were prepared by management in consultation with independent engineers. We apply estimated future prices to the estimated reserve quantities acquired, and estimate future operating and development costs to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are discounted using a weighted average cost of capital which approximated 10% at December 31, 2012.

We conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred.

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement

obligations were measured using valuation techniques that convert future cash flows to a single discounted amount.

Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and

development costs, future commodity prices, estimated future cash flow and a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and are subject to change.

F-13

Our acquisitions were accounted for using the acquisition method of accounting.

AEO Acquisition

On November 30, 2012, we completed the acquisition of principally oil properties from American Energy Operations, Inc. (“AEO”) located in the Belridge Field in Kern County, California (the “AEO Acquisition”), with an effective date of November 1, 2012, for approximately $38 million in cash and 3 million Common Units. We used borrowings under our credit facility to fund the cash portion of the AEO Acquisition. The preliminary purchase price of $38 million in cash and $56 million in Common Units was allocated to the assets acquired and liabilities assumed as follows:



Thousands of dollars	AEO
Oil and gas properties	$	97,814
Asset retirement obligation	(4,014		)
Net assets acquired	$	93,800

We will finalize the purchase price allocation within one year of the acquisition date. Acquisition-related costs for the AEO Acquisition were $0.4 million and were recorded in general and administrative expenses on the consolidated statements of operations. In 2012, we recorded $2.6 million in sales revenue and $0.6 million in lease operating expenses, including production and property taxes, from the properties acquired in the AEO Acquisition.

The following unaudited pro forma financial information presents a summary of our combined statement of operations for the years ended December 31, 2012 and 2011, assuming the AEO Acquisition had been completed on January 1, 2011 and the Cabot Acquisition (as defined below) had been completed on January 1, 2010, including adjustments to reflect the allocation of the preliminary purchase price to the acquired net assets. The pro forma financial information is not necessarily indicative of the results of operations if the AEO and Cabot acquisitions had been effective January 1, 2011 and January 1, 2010, respectively.



	Pro Forma Year Ended December 31,
Thousands of dollars, except per unit amounts	2012			2011		2010
Revenues	$	452,018		$	551,860	$	520,048
Net income (loss) attributable to partnership	(25,519		)	136,129		120,195

Net income (loss) per unit:
Basic	$	(0.34	)	$	2.11	$	1.95
Diluted	$	(0.34	)	$	2.11	$	1.95

Permian Basin Acquisitions

On July 2, 2012, we completed acquisitions of oil and natural gas properties located in the Permian Basin in Texas from Element Petroleum, LP (“Element”) for approximately $148 million and from CrownRock, L.P. (“CrownRock”) for approximately $70 million. On December 28, 2012, we completed the acquisition of additional oil and natural gas properties in the Permian Basin in Texas from CrownRock for approximately $167 million (the “CrownRock II Acquisition”) and from Lynden USA Inc. (“Lynden”) for approximately $25 million (the “Lynden Acquisition”). On December 28, 2012, we also completed the acquisition from Piedra Energy I, LLC of additional net working interests in six producing properties (acquired from Element and CrownRock in July 2012) and interests in 180 proved undeveloped drilling locations for approximately $10 million (the “Piedra Acquisition”). These purchase prices are subject to customary post-closing adjustments. We used borrowings under our credit facility to fund these acquisitions. The preliminary purchase prices for the 2012 Permian Basin acquisitions (the “Permian Basin Acquisitions”) were primarily allocated to oil and gas properties, and included $52.5 million of unproved oil and gas properties.

F-14

We will finalize the purchase price allocations within one year of the acquisition dates. Acquisition-related costs for the Permian Basin Acquisitions were $1.2 million and were recorded in general and administrative expenses on the consolidated statements of operations. Revenues and expenses from the Permian Basin Acquisitions are reflected in our consolidated statements of operations beginning on the completion dates of the respective acquisitions. In 2012, we recorded $19.1 million in sales revenue and $3.6 million in lease operating expenses, including production and property taxes, from the Permian Basin Acquisitions. We have not presented pro forma financial information for the Permian Basin Acquisitions, as the impact of these acquisitions individually were not significant to our operating results for the year ended December 31, 2012.

NiMin Acquisition

On June 28, 2012, we completed the acquisition of oil properties located in Park County in the Big Horn Basin of

Wyoming from Legacy Energy, Inc., a wholly-owned subsidiary of NiMin, with an effective date of April 1, 2012 (the

“NiMin Acquisition”). We used borrowings under our credit facility to fund the acquisition. The final purchase price for this acquisition was approximately $95 million in cash, which was primarily allocated to oil and gas properties (including $36.2 million in unproved properties) and included $1.7 million of ARO. Acquisition-related costs for the NiMin Acquisition were $0.5 million and were reflected in general and administrative expenses on the consolidated statements of operations. Revenues and expenses from the NiMin properties are reflected in our consolidated statements of operations beginning June 28, 2012. In 2012, we recorded $6.6 million in sales revenue and $3.2 million in lease operating expenses, including production and property taxes, from the properties acquired in the NiMin acquisition. We have not presented pro forma financial information for the NiMin Acquisition, as the impact of the acquisition was not significant to our operating results for the year ended December 31, 2012.

2011 Acquisitions

On July 28, 2011, we completed the acquisition of crude oil properties in the Powder River Basin in eastern Wyoming with an effective date of July 1, 2011 (the “Greasewood Acquisition”). We used borrowings under our credit facility to fund the Greasewood Acquisition. The purchase price for the acquisition was approximately $57 million in cash, which was primarily allocated to oil properties. Acquisition-related costs for the Greasewood Acquisition were $0.1 million and were reflected in general and administrative expenses on the consolidated statements of operations. In 2011, we recorded $7.4 million in sales revenue and $1.9 million in lease operating expenses, including production and property taxes, from the properties acquired in the Greasewood Acquisition.

On October 6, 2011, we completed the acquisition of oil and gas properties from Cabot Oil & Gas Corporation located primarily in the Evanston and Green River Basins in southwestern Wyoming (the “Cabot Acquisition”), with an effective date of September 1, 2011. We used borrowings under our credit facility to fund the Cabot Acquisition. The assets acquired also include limited acreage and non-operated oil and gas interests in Colorado and Utah.

The final purchase price of $281 million was allocated to the assets acquired and liabilities assumed as follows:



Thousands of dollars	Cabot
Accounts receivable	$	767
Oil and gas properties	294,500
Accounts payable	(197		)
Revenue and royalties payable	(798		)
Asset retirement obligation	(10,845		)
Other long-term liabilities	(2,820		)
	$	280,607

Acquisition-related costs for the Cabot Acquisition were $0.6 million and were recorded in general and administrative expenses on the consolidated statements of operations. In 2011, we recorded $9.1 million in sales revenue

F-15

and $3.9 million in lease operating expenses, including production and property taxes, from the properties acquired in the Cabot Acquisition.

5. Financial Instruments and Fair Value Measurements

Our risk management programs are intended to reduce our exposure to commodity prices and interest rates and to assist with stabilizing cash flows.

Commodity Activities

The derivative instruments we utilize are based on index prices that may and often do differ from the actual crude oil and natural gas prices realized in our operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges under FASB Accounting Standards. Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial accounting purposes and instead recognize changes in the fair value immediately in earnings.

We had the following oil contracts in place at December 31, 2012:



	Year
	2013		2014		2015		2016		2017
Oil Positions:
Fixed Price Swaps - NYMEX WTI
Hedged Volume (Bbl/d)	4,677		3,814		4,189		1,611		222
Average Price ($/Bbl)	$	90.34	$	92.79	$	96.61	$	91.50	$	88.12
Fixed Price Swaps - ICE Brent
Hedged Volume (Bbl/d)	4,200		3,800		2,300		1,800		297
Average Price ($/Bbl)	$	97.57	$	97.26	$	97.18	$	95.13	$	97.53
Collars - NYMEX WTI
Hedged Volume (Bbl/d)	500		1,000		1,000		—		—
Average Floor Price ($/Bbl)	$	77.00	$	90.00	$	90.00	$	—	$	—
Average Ceiling Price ($/Bbl)	$	103.10	$	112.00	$	113.50	$	—	$	—
Collars - ICE Brent
Hedged Volume (Bbl/d)	—		—		500		500		—
Average Floor Price ($/Bbl)	$	—	$	—	$	90.00	$	90.00	$	—
Average Ceiling Price ($/Bbl)	$	—	$	—	$	109.50	$	101.25	$	—
Puts - NYMEX WTI
Hedged Volume (Bbl/d)	1,000		500		500		1,000		—
Average Price ($/Bbl)	$	90.00	$	90.00	$	90.00	$	90.00	$	—
Total:
Hedged Volume (Bbl/d)	10,377		9,114		8,489		4,911		519
Average Price ($/Bbl)	$	92.59	$	94.20	$	95.21	$	92.37	$	93.50

F-16

The following derivative transactions are included in the table above. In July 2012, we paid premiums of $2.5 million for crude oil swap contracts to hedge a total of 0.5 million barrels associated with the NiMin Acquisition at NYMEX WTI prices, ranging from $104.80 per Bbl in 2012 to $88.45 per Bbl in 2017. In July 2012, we also paid premiums of $2.6 million for crude oil swap contracts to hedge a total of 0.6 million barrels associated with the Element and CrownRock acquisitions at NYMEX WTI prices, ranging from $98.35 per Bbl in 2012 to $87.80 per Bbl in 2017. In August 2012, we entered into a crude oil put contract, hedging a total of 0.2 million barrels from January 1, 2013 to December 31, 2013, at a NYMEX WTI price of $90.00 per Bbl, for which we paid premiums of approximately $1.3 million. In October 2012, we entered into crude oil swap contracts hedging a total of 0.5 million barrels from January 1, 2013 to June 30, 2017, at an ICE Brent price of $102.00 per Bbl, for which we paid a premium of approximately $3.7 million. In December 2012, we entered into crude oil swap and put contracts hedging a total of 1.3 million barrels from January 1, 2013 through December 31, 2016, at a weighted average NYMEX WTI prices of $90.00 per Bbl, for which we paid premiums of approximately $13.0 million.

We had the following natural gas contracts in place at December 31, 2012:



		Year
		2013		2014		2015		2016		2017
Gas Positions:
Fixed Price Swaps - MichCon City-Gate
Hedged Volume (MMBtu/d)		37,000		7,500		7,500		7,000		—
Average Price ($/MMBtu)		$	6.50	$	6.00	$	6.00	$	4.51	$	—
Fixed Price Swaps - Henry Hub
Hedged Volume (MMBtu/d)		21,100		38,600		43,200		15,700		1,571
Average Price ($/MMBtu)		$	4.76	$	4.80	$	4.83	$	4.20	$	4.45
Puts - Henry Hub
Hedged Volume (MMBtu/d)		—		6,000		1,500		—		—
Average Price ($/MMBtu)		$	—	$	5.00	$	5.00	$	—	$	—
Total:
Hedged Volume (MMBtu/d)		58,100		52,100		52,200		22,700		1,571
Average Price ($/MMBtu)		$	5.87	$	4.99	$	5.00	$	4.30	$	4.45

Calls - Henry Hub
Hedged Volume (MMBtu/d)	—	30,000		15,000		—		—		—
Average Price ($/MMBtu)	—	$	8.00	$	9.00	$	—	$	—	$	—
Deferred Premium ($/MMBtu)		$	0.08	$	0.12	$	—	$	—	$	—

Included in the above table are natural gas swap and put contracts we entered into in June 2012, hedging a total of 18,628 BBtu from January 1, 2014 to December 31, 2016 at a weighted average Henry Hub price of $4.30 per MMBtu, for which we paid premiums of approximately $7.0 million.

Interest Rate Activities

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. In order to mitigate our interest rate exposure, we had the following interest rate swaps, indexed to 1-month LIBOR, in place at December 31, 2011, to fix a portion of floating LIBOR-base debt under our credit facility. As of December 31, 2011, we had an interest rate swap covering January 1, 2012 to December 20, 2012 for $100 million at a fixed rate of 1.1550% and an interest rate swap covering January 20, 2012 to January 20, 2014 for $100 million at 2.4800%. The first contract expired in December 2012. In the fourth quarter of 2012, we terminated the second contract and realized a loss of $2.5 million. As of December 31, 2012, we had no interest rate swaps in place. We did not designate these interest rate derivatives as hedges for financial accounting purposes.

F-17

Fair Value of Financial Instruments

FASB Accounting Standards require disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The required disclosures are detailed below.

Fair value of derivative instruments not designated as hedging instruments:



Balance sheet location, thousands of dollars	Oil Commodity Derivatives			Natural Gas Commodity Derivatives			Interest Rate Derivatives			Commodity Derivatives Netting (a)			Total Financial Instruments

As of December 31, 2012
Assets
Current assets - derivative instruments	$	4,270		$	46,724		$	—		$	(16,976	)	$	34,018
Other long-term assets - derivative instruments	38,919			33,443			—			(17,152		)	55,210
Total assets	43,189			80,167			—			(34,128		)	89,228

Liabilities
Current liabilities - derivative instruments	(21,665		)	(936		)				16,976			(5,625		)
Long-term liabilities - derivative instruments	(18,769		)	(2,776		)				17,152			(4,393		)
Total liabilities	(40,434		)	(3,712		)	—			34,128			(10,018		)

Net assets	$	2,755		$	76,455		$	—		$	—		$	79,210

As of December 31, 2011
Assets
Current assets - derivative instruments	$	11,795		$	73,312		$	—		$	(1,655	)	$	83,452
Other long-term assets - derivative instruments	6,032			58,605			—			(9,300		)	55,337
Total assets	17,827			131,917			—			(10,955		)	138,789

Liabilities
Current liabilities - derivative instruments	(8,032		)	—			(2,504		)	1,655			(8,881		)
Long-term liabilities - derivative instruments	(10,520		)	—			(1,864		)	9,300			(3,084		)
Total liabilities	(18,552		)	—			(4,368		)	10,955			(11,965		)

Net assets (liabilities)	$	(725	)	$	131,917		$	(4,368	)	$	—		$	126,824

(a) Represents counterparty netting under derivative netting agreements - these contracts are reflected net on the balance sheet.

F-18

Gains and losses on derivative instruments not designated as hedging instruments:



Location of gain/loss, thousands of dollars	Oil Commodity Derivatives (a)			Natural Gas Commodity Derivatives (a)			Interest Rate Derivatives (b)			Total Financial Instruments
Year Ended December 31, 2012
Realized gain (loss)	$	3,855		$	83,750		$	(5,469	)	$	82,136
Unrealized gain (loss)	(19,607		)	(62,418		)	4,368			(77,657		)
Net gain (loss)	$	(15,752	)	$	21,332		$	(1,101	)	$	4,479

Year Ended December 31, 2011
Realized gain (loss)	$	(70,398	)	$	54,331		$	(3,257	)	$	(19,324	)
Unrealized gain	70,430			27,304			480			98,214
Net gain (loss)	$	32		$	81,635		$	(2,777	)	$	78,890

Year Ended December 31, 2010
Realized gain (loss)	$	11,252		$	63,573		$	(11,087	)	$	63,738
Unrealized gain (loss)	(62,239		)	22,526			6,597			(33,116		)
Net gain (loss)	$	(50,987	)	$	86,099		$	(4,490	)	$	30,622

(a) Included in gain on commodity derivative instruments, net on the consolidated statements of operations.

(b) Included in loss on interest rate swaps on the consolidated statements of operations.

In the fourth quarter of 2011, in order to improve the effectiveness of our hedge portfolio, we terminated certain crude oil fixed price swaps at NYMEX WTI prices for a total termination cost of $36.8 million, included in 2011 realized losses, and entered into new crude oil fixed price swaps for the same volumes and periods at ICE Brent prices.

FASB Accounting Standards define fair value, establish a framework for measuring fair value and establish required disclosures about fair value measurements. They also establish a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are. We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third party market participants. We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements. The fair value hierarchy gives the highest priority of Level 1 to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 to unobservable inputs. We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are. The three levels of inputs are described further as follows:

Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2 – Inputs other than quoted prices that are included in Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. We consider the over the counter (“OTC”) commodity and interest rate swaps in our portfolio to be Level 2. Level 3 – Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Certain OTC derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. As of December 31, 2012 and 2011, our Level 3 derivative assets and liabilities consisted entirely of OTC commodity put and call options.

Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data. We had no transfers in or out of Levels 1, 2 or 3 during the years ended December 31, 2012, 2011 and 2010. Our policy is to recognize transfers between levels as of the end of the period.

F-19

Our Treasury/Risk Management group calculates the fair value of our commodity and interest rate swaps and options. We compare these fair value amounts to the fair value amounts that we receive from the counterparties on a monthly basis. Any differences are resolved and any required changes are recorded prior to the issuance of our financial statements.

The model we utilize to calculate the fair value of our Level 2 and Level 3 commodity derivative instruments is a standard option pricing model. Level 2 inputs to the option pricing models include fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity forward price curves, volatility and interest rate factors and time to expiry. Model inputs are obtained from our counterparties and third party data providers and are verified to published data where available (e.g., NYMEX). Additional inputs to our Level 3 derivatives include option volatility, forward commodity prices and risk-free interest rates for present value discounting. We use the standard swap contract valuation method to value our interest rate derivatives, and inputs include LIBOR forward interest rates, one-month LIBOR rates and risk-free interest rates for present value discounting.

Assumed credit risk adjustments, based on published credit ratings and credit default swap rates, are applied to our derivative instruments.

Our assessment of the significance of an input to its fair value measurement requires judgment and can affect the valuation of the assets and liabilities as well as the category within which they are classified. Financial assets and liabilities carried at fair value on a recurring basis are presented in the following tables:



Thousands of dollars	Level 1		Level 2			Level 3			Total

As of December 31, 2012
Assets (liabilities)
Oil
Oil swaps	$	—	$	(12,413	)	$	—		$	(12,413	)
Oil collars	—		—			4,024			4,024
Oil puts	—		—			11,144			11,144
Natural gas
Natural gas swaps	—		74,782			—			74,782
Natural gas calls	—		—			(1,489		)	(1,489		)
Natural gas puts	—		—			3,162			3,162
Net assets	$	—	$	62,369		$	16,841		$	79,210

As of December 31, 2011
Assets (liabilities)
Oil
Oil swaps	—		(9,234		)	—			(9,234		)
Oil collars	—		—			8,509			8,509
Natural gas
Natural gas swaps	—		94,868			—			94,868
Natural gas collars	—		—			38,366			38,366
Natural gas calls	—		—			(1,317		)	(1,317		)
Interest rate
Interest rate swaps	—		(4,368		)	—			(4,368		)
Net assets	$	—	$	72,530		$	45,558		$	118,088

F-20

The following table sets forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3:



	Year End December 31,
	2012						2011						2010
Thousands of dollars	Oil			Natural Gas			Oil			Natural Gas			Oil			Natural Gas
Assets (liabilities):
Beginning balance	$	8,509		$	37,049		$	35,443		$	50,810		$	67,025		$	35,450
Realized gain (a)	14,131			42,401			16,646			27,640			21,161			5,570
Unrealized loss (a)	(20,760		)	(81,556		)	(43,581		)	(41,400		)	(52,743		)	9,790
Purchases (b)	13,288			3,778			—			—			—			—
Ending balance	$	15,169		$	1,672		$	8,509		$	37,049		$	35,443		$	50,810

(a) Included in gain on commodity derivative instruments, net on the consolidated statements of operations.

(b) Relates to premiums paid for oil and natural gas puts entered into 2012.

During the periods presented, we had no changes in the fair value of our derivative instruments classified as Level 3 related to sales, issuances or settlements.

For Level 3 derivatives measured at fair value on a recurring basis as of December 31, 2012, the significant unobservable inputs used in the fair value measurements were as follows:



	Fair Value at		Valuation
Thousands of dollars	December 31, 2012		Technique	Unobservable Input	Range
Oil options	$	15,169	Option pricing model	Oil forward commodity prices	$86.78/Bbl - $110.46/Bbl
				Oil volatility	20.56% - 27.53%
				Own credit risk	5%
Natural gas options	1,672		Option pricing model	Gas forward commodity prices	$3.35/MMBtu - $4.87/MMBtu
				Gas volatility	20.55% - 35.88%
				Own credit risk	5%
Total	$	16,841

Credit and Counterparty Risk

Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of December 31, 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, Toronto-Dominion Bank and Royal Bank of Canada. Our counterparties are all lenders under our Amended and Restated Credit Agreement. Our credit agreement is secured by our crude oil, natural gas and NGL reserves, so we are not required to post any collateral, and we conversely do not receive collateral from our counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to fail to perform in accordance with the terms of the contract. This risk is managed by diversifying our derivatives portfolio. As of December 31, 2012, each of these financial institutions had an investment grade credit rating. As of December 31, 2012, our largest derivative asset balances were with Credit Suisse Energy LLC, Wells Fargo Bank National Association and The Royal Bank of Scotland plc which accounted for approximately 21%, 20% and 12% of our derivative asset balances, respectively.

F-21

6. Related Party Transactions

On May 8, 2012, BreitBurn Management entered into the Third Amended and Restated Administrative Services Agreement (the “Third Amended and Restated Administrative Services Agreement”) with PCEC, pursuant to which the parties agreed to increase the monthly fee charged by BreitBurn Management to PCEC for indirect costs. For the first three months of 2012, the monthly fee charged by BreitBurn Management to PCEC for indirect costs was set at $571,000, and the two parties agreed to increase that monthly fee to $700,000, effective April 1, 2012. In connection with the PCEC transactions and the Third Amended and Restated Administrative Services Agreement, PCEC also paid us a $250,000 fee.

In connection with the Trust IPO, we, BreitBurn GP, LLC and BreitBurn Management entered into the First Amendment to Omnibus Agreement, dated as of May 8, 2012, with PCEC, Pacific Coast Energy Holdings LLC, formerly known as BreitBurn Energy Holdings, LLC, and PCEC (GP) LLC, formerly known as BEC (GP) LLC (the “First Amendment to Omnibus Agreement”). Pursuant to the First Amendment to Omnibus Agreement, the parties agreed to amend the Omnibus Agreement among the parties, dated as of August 26, 2008 (the “Omnibus Agreement”), to remove Article III of the Omnibus Agreement, which contained our right of first offer with respect to the sale of assets by PCEC and its affiliates.

At December 31, 2012 and December 31, 2011, we had net current receivables of $1.2 million and $2.8 million, respectively, due from PCEC related to the applicable administrative services agreement, employee related costs and oil and gas sales made by PCEC on our behalf from certain properties. During 2012, the monthly charges to PCEC for indirect expenses totaled $8.0 million and charges for direct expenses including direct payroll and administrative costs totaled $8.6 million. During 2011, the monthly charges to PCEC for indirect expenses totaled $5.8 million and charges for direct expenses including direct payroll and administrative costs totaled $9.0 million. During 2010, the monthly charges to BEC for indirect expenses totaled $5.4 million and charges for direct expenses including direct payroll and administrative costs totaled $6.2 million.

At December 31, 2012 and December 31, 2011, we had receivables of $0.2 million and $1.4 million due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf.

F-22

7. Inventory

In Florida, crude oil inventory was $3.1 million and $4.7 million at December 31, 2012 and 2011, respectively. For the year ended December 31, 2012, we sold 849 MBbls of crude oil and produced 830 MBbls from our Florida operations. For the year ended December 31, 2011, we sold 862 MBbls of crude oil and produced 782 MBbls from our Florida operations. Crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter. Crude oil inventory additions are at cost and represent our production costs. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded to inventory.

We carry inventory at the lower of cost or market. When using lower of cost or market to value inventory, market should not exceed the net realizable value or the estimated selling price less costs of completion and disposal. We assessed our crude oil inventory at December 31, 2012 and December 31, 2011 and determined that the carrying value of our inventory was below market value and, therefore, no write-down was necessary.

For our properties in Florida, there are a limited number of alternative methods of transportation for our production. Substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs, or involuntary curtailment of our oil production, which could have a negative impact on our future consolidated financial position, results of operations and cash flows.

8. Equity Investments

We had equity investments at December 31, 2012 and December 31, 2011 totaling $7.0 million and $7.5 million, respectively, which primarily represent investments in natural gas processing facilities. For the years ended December 31, 2012 and 2011, we recorded $0.7 million and $0.7 million, respectively in earnings from equity investments and $1.2 million and $0.9 million, respectively, in dividends. For the year ended December 31, 2010, we recorded $0.7 million in earnings from equity investments and $1.2 million in dividends. Earnings from equity investments are reported in other revenue, net on the consolidated statements of operations.

At December 31, 2012, our equity investments consisted primarily of a 24.5% limited partner interest and a 25.5% general partner interest in Wilderness Energy Services LP, with a combined carrying value of $5.9 million. The remaining $1.1 million consists of smaller interests in several other investments where we have significant influence.

9. Impairments and Price Related Depletion and Depreciation Adjustments

We assess our developed and undeveloped oil and gas properties and other long-lived assets for possible impairment periodically and whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for market supply and demand conditions for crude oil and natural gas. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2.5% per year. For impairment charges, the associated property’s expected future net cash flows are discounted using a market-based weighted average cost of capital rate that currently approximates 10%. Additional inputs include crude oil and natural gas reserves, future operating and development costs and future commodity prices. We consider the inputs for our impairment calculations to be Level 3 inputs. The impairment reviews and calculations are based on assumptions that are consistent with our business plans.

F-23

During the year ended December 31, 2012, we recorded non-cash impairment charges of approximately $12.3 million primarily related to uneconomic proved properties in Michigan, Indiana and Kentucky due to a decrease in expected future natural gas prices. During the year ended December 31, 2011, we recorded impairments of approximately $0.6 million related to uneconomic proved properties in Michigan primarily due to a decrease in natural gas prices. During the year ended December 31, 2010, we recorded impairments of approximately $6.3 million related to our Eastern region properties, including a $4.2 million write-down of uneconomic proved properties and a $2.1 million write-down of expired unproved lease properties.

An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable, given the number of assumptions involved in the estimates; favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.

10. Long-Term Debt

Credit Facility

BOLP, as borrower, and we and our wholly-owned subsidiaries, as guarantors, have a $1.5 billion revolving credit facility with Wells Fargo Bank National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (the “Second Amended and Restated Credit Agreement”) with a maturity date of May 9, 2016.

As of December 31, 2011, our borrowing base was $850 million. On May 25, 2012, we entered into the Fifth Amendment to the Second Amended and Restated Credit Agreement, which increased the permitted amount of senior unsecured notes we may issue from $700 million to $1 billion. On October 11, 2012, we entered into the Sixth Amendment (the “Sixth Amendment”) to the Second Amended and Restated Credit Agreement, which increased our borrowing base to $1 billion and increased our total commitments from existing lenders to $900 million. The Sixth Amendment also provides us with the ability to increase our total commitments up to the $1 billion borrowing base upon lender approval.

Our next semi-annual borrowing base redetermination is scheduled for April 2013.

As of December 31, 2012 and December 31, 2011, we had $345.0 million and $520.0 million, respectively, in indebtedness outstanding under the credit facility. At December 31, 2012, the 1-month LIBOR interest rate plus an applicable spread was 2.214% on the 1-month LIBOR portion of $345.0 million. The amounts reported on our consolidated balance sheets for long-term debt approximate fair value due to the variable nature of our interest rates.

Borrowings under the Second Amended and Restated Credit Agreement are secured by first-priority liens on and security interests in substantially all of our and certain of our subsidiaries’ assets, representing not less than 80% of the total value of our oil and gas properties.

The Second Amended and Restated Credit Agreement contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders or repurchase units (including the restriction on our ability to make distributions unless, after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.

The Second Amended and Restated Credit Agreement also permits us to terminate derivative contracts without obtaining the consent of the lenders in the facility, provided that the net effect of such termination plus the aggregate value of all dispositions of oil and gas properties made during such period, together, does not exceed 5% of the borrowing base, and the borrowing base will be automatically reduced by an amount equal to the net effect of the termination.

The events that constitute an Event of Default (as defined in the Second Amended and Restated Credit Agreement) include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain

F-24

other indebtedness; adverse judgments against us in excess of a specified amount; changes in management or control; loss of permits; certain insolvency events; and assertion of certain environmental claims.

Senior Notes Due 2020

On October 6, 2010, we and BreitBurn Finance Corporation (the “Issuers”), and certain of our subsidiaries as guarantors (the “Guarantors”), issued $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the “2020 Senior Notes”). The 2020 Senior Notes were offered at a discount price of 98.358%, or $300 million. The $5 million discount is being amortized over the life of the 2020 Senior Notes. As of December 31, 2012 and 2011, the 2020 Senior Notes had a carrying value of $301.1 million and $300.6 million, respectively, net of unamortized discount of $3.9 million and $4.4 million, respectively. In connection with the 2020 Senior Notes, we incurred financing fees and expenses of approximately $8.8 million, which will be amortized over the life of the 2020 Senior Notes. Interest on the 2020 Senior Notes is payable twice a year in April and October.

As of December 31, 2012 and 2011, the fair value of the 2020 Senior Notes was estimated to be $330 million and $320 million. We consider the inputs to the valuation of our 2020 Senior Notes to be Level 2, as fair value was estimated based on prices quoted from third party financial institutions.

Senior Notes Due 2022

On January 10, 2012, the Issuers, and certain of our subsidiaries as Guarantors, issued $250 million in aggregate principal amount of 7.875% Senior Notes due 2022 (the “Initial Notes”), which were purchased by the initial purchasers as defined in the purchase agreement (the “Initial Purchasers”) and then resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”). The Initial Notes were issued at a discount of 99.154%, or $247.9 million. The $2.1 million discount will be amortized over the life of the Initial Notes. In connection with the Initial Notes, our financing fees and expenses were approximately $5.6 million, which will be amortized over the life of the Initial Notes.

On September 27, 2012 we issued an additional $200 million aggregate principal amount of our 7.875% Senior Notes due 2022 (the “Additional Notes”), which were purchased by the Initial Purchasers and then resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act (the Additional Notes and the Initial Notes are collectively referred to as the “2022 Senior Notes”). The Additional Notes have identical terms, other than the issue date and initial interest payment date, and constitute part of the same series as and are fungible with the Initial Notes. The Additional Notes were issued at a premium of 103.500%, or $207.0 million. The $7.0 million premium will be amortized over the life of the Additional Notes. In connection with the Additional Notes, our financing fees and expenses were approximately $4.2 million, which will be amortized over the life of the Additional Notes.

In connection with the issuance of the 2022 Senior Notes, we entered into Registration Rights Agreements (the “Registration Rights Agreements”) with the Guarantors and Initial Purchasers. Under the Registration Rights Agreements, the Issuers and the Guarantors agreed to cause to be filed with the SEC a registration statement with respect to an offer to exchange the 2022 Senior Notes for substantially identical notes that are registered under the Securities Act. The Issuers and the Guarantors agreed to use their commercially reasonable efforts to cause such exchange offer registration statement to become effective under the Securities Act. In addition, the Issuers and the Guarantors agreed to use their commercially reasonable efforts to cause the exchange offer to be consummated not later than 400 days after January 13, 2012. In December 2012, we filed a registration statement for the exchange offer for the 2022 Senior Notes. On December 27, 2012, the exchange registration statement became effective and we commenced the exchange offer, which was completed on February 7, 2013.

As of December 31, 2012, the 2022 Senior Notes had a carrying value of $454.6 million, net of unamortized premium of $4.6 million. Interest on the 2022 Senior Notes is payable twice a year in April and October. As of December 31, 2012, the fair value of the 2022 Senior Notes was estimated to be $468 million. We consider the inputs to the valuation of our 2022 Senior Notes to be Level 2, as fair value was estimated based on prices quoted from third party financial institutions.

As of December 31, 2012 and December 31, 2011, we were in compliance with the covenants on our Senior Notes.

F-25

Interest Expense

Our interest expense is detailed in the following table:



	Year Ended December 31,
Thousands of dollars	2012			2011			2010
Credit facility (including commitment fees)	$	7,114		$	8,266		$	13,060
Senior notes	49,279			26,233			6,284
Amortization of discount and deferred issuance costs	4,867			4,743			5,478
Capitalized interest	(54		)	(77		)	(270		)
Total	$	61,206		$	39,165		$	24,552
Cash paid for interest	$	55,151		$	37,756		$	23,755

11. Condensed Consolidating Financial Statements

We and BreitBurn Finance Corporation as co-issuers, and certain of our subsidiaries as guarantors, issued the 2020 Senior Notes and the 2022 Senior Notes. Effective April 1, 2012, we and PCEC agreed to dissolve BEPI. With the dissolution of BEPI, all but one of our subsidiaries have guaranteed our senior notes and our only remaining non-guarantor subsidiary, BreitBurn Collingwood Utica LLC, is a minor subsidiary.

In accordance with Rule 3-10 of Regulation S-X, we are not presenting condensed consolidating financial statements as we have no independent assets or operations; BreitBurn Finance Corporation, the subsidiary co-issuer which does not guarantee our senior notes, is a 100% owned finance subsidiary; all of our material subsidiaries are 100% owned, have guaranteed our senior notes, and all of the guarantees are full, unconditional, joint and several.

Each guarantee of each of the 2020 Senior Notes and the 2022 Senior Notes is subject to release in the following customary circumstances:


(1)	a disposition of all or substantially all the assets of the guarantor subsidiary (including by way or merger or consolidation), to a third person, provided the disposition complies with the applicable indenture,


(2)	a disposition of the capital stock of the guarantor subsidiary to a third person, if the disposition complies with the applicable indenture and as a result the guarantor subsidiary ceases to be our subsidiary,


(3)	the designation by us of the guarantor subsidiary as an Unrestricted Subsidiary in accordance with the applicable indenture,


(4)	legal or covenant defeasance of such series of Senior Notes or satisfaction and discharge of the related indenture,


(5)	the liquidation or dissolution of the guarantor subsidiary, provided no default under the applicable indenture exists, or


(6)	the guarantor subsidiary ceases both (a) to guarantee any other indebtedness of ours or any other guarantor subsidiary and (b) to be an obligor under any bank credit facility.

12. Income Taxes

We, and all of our subsidiaries, with the exception of Phoenix Production Company (“Phoenix”), Alamitos Company, BreitBurn Management and BreitBurn Finance Corporation, are partnerships or limited liability companies treated as partnerships for federal and state income tax purposes. Essentially all of our taxable income or loss, which may differ considerably from the net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our partners. As such, we have not recorded any federal income tax expense for those pass-through entities.

F-26

The consolidated income tax expense (benefit) attributable to our tax-paying entities consisted of the following:



	Year Ended December 31,
Thousands of dollars	2012			2011		2010
Federal income tax expense (benefit)
Current	$	223		$	378	$	347
Deferred (a)	(316		)	714		(403		)
State income tax expense (benefit) (b)	177			96		(148		)
Total	$	84		$	1,188	$	(204	)

(a) Related to Phoenix, our wholly owned subsidiary.

(b) Primarily in California, Texas and Michigan.

The following is a reconciliation of federal income taxes at the statutory rates to federal income tax expense (benefit) for Phoenix:



	Year Ended December 31,
Thousands of dollars	2012			2011			2010
Income (loss) subject to federal income tax	$	(705	)	$	3,329		$	(565	)
Federal income tax rate	34		%	34		%	34		%
Income tax at statutory rate	(240		)	1,132			(192		)
Statutory depletion from prior year	(248		)	—			—
Other	—			—			(13		)
Income tax expense (benefit)	$	(488	)	$	1,132		$	(205	)

At December 31, 2012 and 2011, net deferred federal income tax liabilities of $2.5 million and $2.8 million, respectively, were reported in our consolidated balance sheet for Phoenix. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and the amount used for income tax purposes. Significant components of our net deferred tax liabilities are presented in the following table:



	December 31,
Thousands of dollars	2012			2011
Deferred tax assets:
Asset retirement obligation	$	470		$	431
Unrealized hedge loss	82			—
Deferred realized hedge loss	149			—
Other	571			368
Deferred tax liabilities:
Depreciation, depletion and intangible drilling costs	(3,759		)	(3,199		)
Unrealized hedge gain	—			(326		)
Deferred realized hedge gain	—			(77		)
Net deferred tax liability	$	(2,487	)	$	(2,803	)

At December 31, 2012, we had an insignificant amount of estimated unused operating loss carryforwards. As of December 31, 2012 and 2011, we had $0.5 million and $0.4 million, respectively, of estimated unused minimum tax credit carryforward. We did not provide a valuation allowance against this deferred tax asset as we expect to use the minimum tax credit carryforward in the future.

F-27

On a consolidated basis, cash paid for federal and state income taxes totaled $0.8 million, $0.3 million and $0.2 million in 2012, 2011 and 2010, respectively.

FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. FASB Accounting Standards also provide guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial statement comparability among different companies.

We performed evaluations as of December 31, 2012, 2011 and 2010 and concluded that there were no uncertain tax positions requiring recognition in our financial statements.

13. Asset Retirement Obligation

Our asset retirement obligation is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities as well as our estimate of the future timing of the costs to be incurred. Payments to settle asset retirement obligations occur over the operating lives of the assets, estimated to be from less than one year to 50 years. We expect our cash settlements to be approximately $0.7 million, $0.1 million and $0.4 million for the years 2013, 2016 and 2017, respectively. Cash settlements for the years after 2017 are expected to be $97.3 million. Our estimated asset retirement obligation has been discounted at our credit adjusted risk free rate of 7% and adjusted for inflation using a rate of 2%. Our credit adjusted risk free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk. Each year we review and, to the extent necessary, revise our asset retirement obligation estimates. During 2012 and 2011, we obtained new estimates to evaluate the cost of abandoning our properties. As a result, we increased our ARO estimate by $20.0 million in 2011 to reflect recent increases in the costs incurred for plugging and abandonment activities primarily in California. 2012 revisions of $1.6 million reflect increases in estimated costs for plugging and abandonment, primarily in Wyoming and Florida, partially offset by a decrease in ARO related to the change in working interest ownership in two California fields.

We consider the inputs to our asset retirement obligation valuation to be Level 3 as fair value is determined using discounted cash flow methodologies based on standardized inputs that are not readily observable in public markets.

Changes in the asset retirement obligation are presented in the following table:



	Year Ended December 31,
Thousands of dollars	2012			2011
Carrying amount, beginning of period	$	82,397		$	47,429
Acquisitions	6,279			10,980
Liabilities incurred	2,468			5,701
Liabilities settled	(86		)	(5,301		)
Revisions	1,553			20,005
Accretion expense	5,869			3,583
Carrying amount, end of period	$	98,480		$	82,397

F-28

14. Commitments and Contingencies

Lease Rental and Purchase Obligations

We have operating leases for office space and other property and equipment having initial or remaining non-cancelable lease terms in excess of one year. Our future minimum rental payments for operating leases at December 31, 2012 are presented below:



	Payments Due by Year
Thousands of dollars	2013		2014		2015		2016		2017		after 2017		Total
Operating leases	$	4,713	$	4,323	$	3,902	$	2,843	$	2,441	$	396	$	18,618

Net rental expense under non-cancelable operating leases was $3.7 million, $3.4 million and $3.0 million in 2012, 2011 and 2010, respectively.

At December 31, 2012, we had purchase obligations of $0.2 million in 2013.

Surety Bonds and Letters of Credit

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At December 31, 2012, we had $16.2 million in surety bonds and $0.3 million in letters of credit outstanding. At December 31, 2011, we had $22.1 million in surety bonds and $0.3 million in letters of credit outstanding.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we are subject.

15. Partners’ Equity

At December 31, 2012 and 2011, we had 84.7 million and 59.9 million Common Units outstanding, respectively.

At December 31, 2012 and December 31, 2011, we had 9.7 million and 9.7 million, respectively, of units authorized for issuance under our long-term incentive compensation plans and there were 0.9 million and 1.7 million, respectively, of units outstanding under grants that are eligible to be paid in Common Units upon vesting.

During the years ended December 31, 2012, 2011 and 2010, approximately 1.0 million, 1.0 million and 1.2 million Common Units, respectively, were issued to employees and outside directors pursuant to vested grants under our First Amended and Restated 2006 Long Term Incentive Plan (“LTIP”).

In February 2012, we sold 9.2 million of our limited partnership units at a price to the public of $18.80 per Common Unit, resulting in proceeds net of underwriting discount and offering expenses of $166.0 million. In September 2012, we sold 11.5 million of our Common Units at a price to the public of $18.51 per Common Unit, resulting in proceeds net of underwriting discount and offering expenses of $204.1 million. In November 2012, we issued 3 million Common Units to AEO as partial consideration for the AEO Acquisition. The fair value of the units on the date of the acquisitions was $18.48 per unit, or $56 million.

F-29

Earnings per common unit

FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of common unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable distribution rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested RPUs and CPUs participate in distributions on an equal basis with Common Units. Accordingly, the presentation below is prepared on a combined basis and is presented as net income (loss) per common unit.

The following is a reconciliation of net income (loss) and weighted average units for calculating basic net income (loss) per common unit and diluted net income (loss) per common unit.



	Year Ended December 31,
Thousands, except per unit amounts	2012			2011		2010
Net income (loss) attributable to limited partners	$	(40,801	)	$	110,497	$	34,751
Distributions on participating units not expected to vest	82			29		15
Net income (loss) attributable to common unitholders and participating securities	$	(40,719	)	$	110,526	$	34,766

Weighted average number of units used to calculate basic and diluted net income (loss) per unit:
Common Units	72,745			58,522		53,302
Participating securities (a)	—			2,948		3,454
Denominator for basic earnings per common unit	72,745			61,470		56,756
Dilutive units (b)	—			134		137
Denominator for diluted earnings per common unit	72,745			61,604		56,893

Net income (loss) per common unit
Basic	$	(0.56	)	$	1.80	$	0.61
Diluted	$	(0.56	)	$	1.79	$	0.61

(a) The year ended December 31, 2012 excludes 2,452 of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.

(b) The year ended December 31, 2012 excludes 55 weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position.

Cash Distributions

The partnership agreement requires us to distribute all of our available cash quarterly. Available cash is cash on hand, including cash from borrowings, at the end of a quarter after the payment of expenses and the establishment of reserves for future capital expenditures and operational needs. We may fund a portion of capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. The partnership agreement does not restrict our ability to borrow to pay distributions. The cash distribution policy reflects a basic judgment that unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it.

Distributions are not cumulative. Consequently, if distributions on Common Units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future. Distributions are paid within 45 days of the end of each fiscal quarter to holders of record on or about the first or second

F-30

week of each such month. If the distribution date does not fall on a business day, the distribution will be made on the business day immediately preceding the indicated distribution date.

We do not have a legal obligation to pay distributions at any rate except as provided in the partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under the partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves the General Partner determines is necessary or appropriate to provide for the conduct of the business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters. The partnership agreement provides that any determination made by the General Partner in its capacity as general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity.

During the years ended December 31, 2012, 2011 and 2010, we paid cash distributions of approximately $127.7 million, $97.6 million and $61.2 million. respectively, to our common unitholders. The distributions that were paid to unitholders totaled $1.83, $1.69 and $1.15 per Common Unit, respectively. We also paid cash equivalent to the distribution paid to our unitholders of $4.7 million, $5.1 million and $4.0 million, respectively, to holders of outstanding RPUs and CPUs issued under our LTIP.

16. Noncontrolling interest

FASB Accounting Standards require that noncontrolling interests be classified as a component of equity and establish reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.

In 2007, we acquired the limited partner interest (99%) of BEPI. As such, we were fully consolidating the results of BEPI and were recognizing a noncontrolling interest representing the book value of BEPI’s general partner’s interests.

Prior to April 1, 2012, BEPI’s general partner interest was held by PCEC, and PCEC held a 35% reversionary interest under the limited partnership agreement applicable to the East Coyote and Sawtelle Fields, which was expected to result in an increase in PCEC’s ownership and a corresponding decrease in our ownership in the properties during the second quarter of 2012. We and PCEC agreed to dissolve BEPI and liquidate the properties and assets of BEPI as of April 1, 2012. As a result of such agreement, PCEC’s ownership interest in both of these properties increased, and our ownership in the properties has decreased from approximately 95% to approximately 62%. As of December 31, 2012, the amount of the noncontrolling interest was zero. At December 31, 2011, the amount of the noncontrolling interest was $0.5 million.

17. Unit and Other Valuation-Based Compensation Plans

Effective on the initial public offering date of October 10, 2006, BreitBurn Management adopted the existing Long-Term Incentive Plan (“BreitBurn Management LTIP”) and the Unit Appreciation Rights Plan (“UAR plan”) of the predecessor as previously amended. The predecessor’s Executive Phantom Option Plan, Unit Appreciation Plan for Officers and Key Individuals (“Founders Plan”), and the Performance Trust Units awarded to the Chief Financial Officer during 2006 under the BreitBurn Management LTIP, were adopted by BreitBurn Management with amendments at the initial public offering date as described in the subject plan discussions below.

In 2007, we entered into the First Amended and Restated 2006 Long-Term Incentive Plan (“LTIP”).

We may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. We also have the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the Common Units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire when units are no longer available under the plan for grants or, if earlier, it is terminated by us.

F-31

Unit Based Compensation

FASB Accounting Standards establish requirements for charging compensation expenses based on fair value provisions. At December 31, 2012, the Restricted Phantom Units (“RPUs”) and the Convertible Phantom Units (“CPUs”) granted under our LTIP as well as the outstanding Directors RPUs discussed below were all classified as equity awards. These awards are being recognized as compensation expense on a straight line basis over the annual vesting periods as prescribed in the award agreements.

All the outstanding Founders Plan awards as presented in the table below were classified as liabilities. The awards were revalued at each reporting period using the Black-Scholes option pricing model and changes in the fair value of the options were recognized as compensation expense over the vesting schedules of the awards. These awards were settled in cash or had the option of being settled in cash or units at the choice of the holder, and were indexed to our Common Units. The liability-classified option awards were distribution-protected awards because the holders received cumulative distribution amounts upon vesting equal to the actual distribution amounts per Common Unit of the underlying notional Units.

We recognized $22.2 million, $22.0 million and $20.4 million of compensation expense related to our various plans for the years ended December 31, 2012, 2011 and 2010, respectively.

Restricted Phantom Units

RPUs are phantom equity awards that, to the extent vested, represent the right to receive actual partnership units upon specified payment events. Certain of our employees including our executives are eligible to receive RPU awards. We believe that RPUs properly incentivize holders of these awards to grow stable distributions for our common unitholders. RPUs generally vest in three equal annual installments on each anniversary of the vesting commencement date of the award. In addition, each RPU is granted in tandem with a distribution equivalent right that will remain outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitles the grantee to receive payment of amounts equal to distributions paid to each holder of an actual partnership unit during such period. RPUs that do not vest for any reason are forfeited upon a grantee’s termination of employment.

The fair value of the RPUs is determined based on the fair market value of our units on the date of grant. RPU awards were granted to BreitBurn Management employees during the years ended December 31, 2012, 2011 and 2010 as shown in the table below. We recorded compensation expense of $17.4 million, $16.9 million and $15.6 million in 2012, 2011 and 2010, respectively, related to the amortization of outstanding RPUs over their related vesting periods. As of December 31, 2012, there was $16.5 million of total unrecognized compensation cost remaining for the unvested RPUs. This amount is expected to be recognized over the next two years. The total fair value of units that vested during the years ended December 31, 2012, 2011 and 2010 was $17.4 million, $21.5 million, and $16.9 million, respectively.

The following table summarizes information about RPUs:



	Year Ended December 31,
	2012				2011				2010
	Number		Weighted		Number		Weighted		Number		Weighted
	of		Average		of		Average		of		Average
Thousands, except per unit amounts	RPUs		Fair Value		RPUs		Fair Value		RPUs		Fair Value
Outstanding, beginning of period	983		$	18.35	1,747		$	13.40	1,575		$	12.82
Granted	887		19.61		758		21.60		1,482		13.77
Exercised	(1,005	)	17.33		(1,505	)	14.26		(1,289	)	13.13
Canceled	(48	)	19.06		(17	)	16.68		(21	)	12.80
Outstanding, end of period	817		$	20.92	983		$	18.35	1,747		$	13.40

Exercisable, end of period	—		$	—	—		$	—	—		$	—

F-32

Convertible Phantom Units

In December 2007, seven executives, Halbert Washburn, Randall Breitenbach, Mark Pease, James Jackson, Gregory Brown, Thurmon Andress and Jackson Washburn, received 0.7 million units of CPUs at a grant price of $30.29 per Common Unit. Each of the awards has the vesting commencement date of January 1, 2008. CPUs are significantly tied to the amount of distributions we make to holders of our Common Units. As discussed further below, the number of CPUs ultimately awarded to each of these senior executives will be based upon the level of distributions to common unitholders achieved during the term of the CPUs. The CPU grants vest over a longer-term period of up to five years. Therefore, these grants will not be made on an annual basis. New grants could be made at the Board’s discretion at a future date after the present CPU grants have vested.

CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the holder’s employment agreement, if applicable). Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management. Prior to vesting, a holder of a CPU is entitled to receive payments equal to the amount of distributions made by us with respect to each of the Common Units multiplied by the number of Common Unit equivalents underlying the CPUs at the time of the distribution.

Under the original CPU Agreements, one Common Unit Equivalent (CUE) underlies each CPU at the time it was awarded to the grantee. However, the number of CUEs underlying the CPUs would increase at a compounded rate of 25% upon the achievement of each 5% compounded increase in the distributions paid by us to our common unitholders. Conversely, the number of CUEs underlying the CPUs would decrease at a compounded rate of 25% if the distributions paid by us to our common unitholders decreases at a compounded rate of 5%.

On October 29, 2009, the Compensation and Governance Committee approved an amendment to each of the existing CPU Agreements entered into with each named executive. Originally under the CPU Agreements, the number of CUEs per CPU could be reduced over the five year life of the agreement to a minimum of zero, or be multiplied by a maximum of 4.77 times, based on our distribution levels. We suspended the payment of distributions in April 2009; therefore, holders of CPUs did not receive any distributions under the CPU Agreements as long as distributions were suspended. Under the original chart, if the CPUs were to vest currently – for instance in the case of the death or disability of a holder – zero units would have vested to that holder. The Committee determined that the elimination of multipliers between zero and one best represented the original incentive and retention purpose of the CPU Agreements. With this modification to the CPU Agreements, the number of CUEs per CPU can no longer be less than one, regardless of Common Unit distribution levels.

On January 29, 2010, the Committee approved an amendment to each of the existing CPU Agreements entered into with each named executive. Under these agreements, each CPU entitles its holder to receive (i) a number of our Common Units at the time of vesting equal to the number of “common unit equivalents” (“CUEs”) underlying the CPU at vesting, and (ii) current distributions on Common Units during the vesting period based on the number of CUEs underlying the CPU at the time of such distribution. The number of CUEs underlying each CPU is determined by reference to Common Unit distribution levels during the applicable vesting period, generally calculated based upon the aggregate amount of distributions made per Common Unit for the four quarters preceding vesting. The amendment to the CPU agreements limited the multiplier for 20% of the total number of CPUs and related CUEs granted in each award to one.”

On January 28, 2011, the Committee approved an amendment to each of the existing CPU Agreements entered into with each of named executives. This amendment to the CPU agreements now limits the multiplier for 40% of the total number of CPUs and related CUEs granted in each award to one instead of 20% in the prior amendment approved on January 29, 2010. As a result at vesting, CPUs for 40% of each award will convert to Common Units on a one to one basis, and with respect to that portion of the award, holders will lose the ability to earn additional Common Units based on increased distributions on Common Units. No other modification was made to the CPU Agreements under this amendment. The Committee determined that this cap on 40% of the CPUs was appropriate in light of the overall long-term incentive grants made to BreitBurn’s executive officers in 2011. Because we were accruing compensation expense

F-33

assuming a CUE multiplier of one, all of these amendments had no impact on compensation expense recorded. Compensation expense will be adjusted upon such time it deems probable that the CUE would increase due to increased distributions.

On December 13, 2012, certain of our executive officers entered into an amendment to their grants of CPUs, that provided that such grants could vest on December 28, 2012 instead of January 1, 2013.

In the event that the CPUs vested on December 28, 2012 or January 1, 2013 or if the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award was greater than $3.10 per Common Unit, the CPUs would have converted into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time (calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters subject to the 60% limitation put in place on January 28, 2011 as noted above). After January 1, 2011, under the terms of the CPU Agreements, all unvested CPUs would fully vest in the event of a termination without cause or good reason and upon death or disability.

We recorded compensation expense for CPUs of $4.1 million in 2012, $4.1 million in 2011 and $4.1 million in 2010. Approximately 0.6 million units vested on December 28, 2012 at a fair market value as of the grant date of $18.3 million. They were converted to Common Units on a one to one basis. The remaining 0.1 million units vested on January 1, 2013 at a fair market value as of the grant date of $2.3 million and were converted to Common Units on a one to one basis.

Founders Plan Awards

Under the Founders Plan, participants received unit appreciation rights which provide cash compensation in relation to the appreciation in the value of a specified number of underlying notional phantom units. The value of the unit appreciation rights was determined on the basis of a valuation of the predecessor at the end of the fiscal period plus distributions during the period less the value of the predecessor at the beginning of the period. The base price and vesting terms were determined by BreitBurn Management at the time of the grant. Outstanding unit appreciation rights vest in the following manner: one-third vest three years after the grant date, one-third vest four years after the grant date and one-third vest five years after the grant date and are subject to specified service requirements. The award is liability-classified and is being charged to us as compensation expense over the remaining vesting schedule.

The founders plan ceased to exist at the end of 2011. We recorded less than $0.1 million for compensation expense under the plan for each of the years ended December 31, 2011 and December 31, 2010. At December 31, 2010, we had less than 10,000 unit appreciation rights outstanding, at a weighted average exercise price of $18.50 per unit, all of which were exercised during 2011.

Director Restricted Phantom Units

Effective with the initial public offering until 2011, we also made grants of Restricted Phantom Units in the Partnership to the non-employee directors of our General Partner. Each phantom unit was accompanied by a distribution equivalent unit right entitling the holder to an additional number of phantom units with a value equal to the amount of distributions paid on each of our Common Units until settlement. Since 2010, the phantom units were paid in Common Units upon vesting, and the unit-settled awards are classified as equity. The estimated fair value associated with these phantom units is expensed in the statement of income over the vesting period. Since 2011, we have made grants of RPUs to the non-employee directors of our General Partner that are substantially similar to the ones granted to employees.

We recorded compensation expense for the director’s phantom units of approximately $0.6 million, $1.0 million and, $0.6 million in 2012, 2011 and 2010, respectively. As of December 31, 2012, there was $0.6 million of total unrecognized compensation cost for the unvested Director Performance Units and such cost is expected to be recognized over the next two years.

F-34

The following table summarizes information about the Director Restricted Phantom Units:



	Year Ended December 31,
	2012				2011				2010
	Number		Weighted		Number		Weighted		Number		Weighted
	of		Average		of		Average		of		Average
Thousands, except per unit amounts	Units		Fair Value		Units		Fair Value		Units		Fair Value
Outstanding, beginning of period	132		$	13.45	131		$	13.05	81		$	13.80
Granted	29		19.63		41		21.68		60		13.94
Exercised	(113	)	12.11		(40	)	20.55		(10	)	24.10
Outstanding, end of period	48		$	20.43	132		$	13.45	131		$	13.05

Exercisable, end of period	—		$	—	—		$	—	—		$	—

18. Retirement Plan

BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. BreitBurn Management has a defined contribution retirement plan, which covers substantially all of its employees on the first day of the month following the month of hire. The plan provides for BreitBurn Management to make regular contributions based on employee contributions as provided for in the plan agreement. Employees fully vest in BreitBurn Management’s contributions after five years of service. PCEC is charged for a portion of the matching contributions made by BreitBurn Management. For the years ended December 31, 2012, 2011 and 2010, we recognized expense related to matching contributions of $1.3 million, $1.1 million and $1.0 million, respectively.

19. Significant Customers

We sell oil, natural gas and natural gas liquids primarily to large domestic refiners. For the year ended December 31, 2012, purchasers that accounted for 10% or more of our net sales were ConocoPhillips, Plains Marketing & Transportation LLC, and Marathon Oil Company, which accounted for approximately 31%, 17%, and 14% of net sales, respectively.

For the year ended December 31, 2011, purchasers that accounted for 10% or more of our net sales were ConocoPhillips, Plains Marketing & Transportation LLC, and Marathon Oil Company, which accounted for 30%, 16%, and 15% of net sales, respectively.

For the year ended December 31, 2010, purchasers that accounted for 10% or more of our net sales were ConocoPhillips, Marathon Oil Company, Plains Marketing & Transportation LLC and Sunoco Partners Marketing and Terminals L.P., which accounted for 30%, 16%, 12% and 10% of net sales, respectively.

20. Subsequent Events

On January 29, 2013, we announced a cash distribution to unitholders for the fourth quarter of 2012 at the rate of $0.4700 per Common Unit, which was paid on February 14, 2013 to the record holders of common units at the close of business on February 11, 2013.

In February 2013, we sold 14.95 million Common Units at a price to the public of $19.86, resulting in proceeds net of underwriting discounts and estimated offering expenses of $285.0 million, which we used to repay outstanding debt under our credit facility.

F-35

per Bbl. Also in February 2013, we entered into Henry Hub fixed price natural gas swaps covering a total of approximately 2,375 BBtu of future production in 2016 and 2017 at a weighted average hedge price of $4.47 per MMBtu.

In February 2013, we entered into the Seventh Amendment to the Second Amended and Restated Credit Agreement, which increased the percentage of expected oil and gas production volume that we are permitted to hedge under the terms of the credit facility.

Supplemental Information

A. Oil and Natural Gas Activities (Unaudited)

We calculate total estimated proved reserves and disclose our oil and natural gas activities in accordance with SEC guidelines. The definition of proved reserves incorporates a definition of “reasonable certainty” using the PRMS (Petroleum Resource Management System) standard of “high degree of confidence” for deterministic method estimates, or a 90% recovery probability for probabilistic methods used in estimating proved reserves. While SEC guidelines permit a company to establish undeveloped reserves as proved with appropriate degrees of reasonable certainty established absent actual production tests and without artificially limiting such reserves to spacing units adjacent to a producing well, we have elected not to add such undeveloped reserves as proved. For reserve reporting purposes we use unweighted average first-day-of-the-month pricing for the 12 calendar months. Costs associated with reserves are measured on the last day of the fiscal year.

Costs incurred

Our oil and natural gas activities are conducted in the United States. The following table summarizes our costs incurred for the past three years:



	Year Ended December 31,
Thousands of dollars	2012		2011		2010
Property acquisition costs
Proved	$	530,532	$	341,602	$	1,676
Unproved	89,725		1,073		2,877
Asset retirement costs	6,279		10,980		—
Development costs	152,820		75,635		64,951
Asset retirement costs - development	4,021		25,706		10,120
Total costs incurred	$	783,377	$	454,996	$	79,624

Capitalized costs

The following table presents the aggregate capitalized costs subject to DD&A relating to oil and gas activities, and the aggregate related accumulated allowance:



	December 31,
Thousands of dollars	2012			2011
Proved properties and related producing assets	$	3,001,018		$	2,319,857
Pipelines and processing facilities	165,320			152,551
Unproved properties	197,608			111,585
Accumulated depreciation, depletion and amortization	(655,607		)	(516,214		)
Net capitalized costs	$	2,708,339		$	2,067,779

F-36

The average DD&A rate per equivalent unit of production for the year ended December 31, 2012, excluding non-oil and gas related DD&A, was $17.68 per Boe. The average DD&A rate per equivalent unit of production for the year ended December 31, 2011, excluding non-oil and gas related DD&A, was $14.90 per Boe.

Results of operations for oil and gas producing activities

The results of operations from oil and gas producing activities below exclude general and administrative expenses, interest expenses and interest income:



	Year Ended December 31,
Thousands of dollars	2012			2011			2010
Oil, natural gas and NGL sales	$	413,867		$	394,393		$	317,738
Gain (loss) on commodity derivative instruments, net	5,580			81,667			35,112
Operating costs	(195,779		)	(165,969		)	(142,525		)
Depreciation, depletion, and amortization	(147,059		)	(105,066		)	(100,183		)
Income tax (expense) benefit	(84		)	(1,188		)	204
Results of operations from producing activities (a)	$	76,525		$	203,837		$	110,346

(a) Excludes (gain) loss on sale of assets of $486, $(111) and $14 for the years ended December 31, 2012, 2011, and 2010, respectively.

Supplemental reserve information

The following information summarizes our estimated proved reserves of oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the years ended December 31, 2012, 2011 and 2010. The following reserve information is based upon reports by Netherland, Sewell & Associates, Inc. (“NSAI”) and Schlumberger PetroTechnical Services (“SLB”), independent petroleum engineering firms. NSAI provides reserve data for our California, Wyoming and Florida properties, and SLB provides reserve data for our Michigan, Kentucky and Indiana properties. The estimates are prepared in accordance with SEC regulations. We only utilize large, widely known, highly regarded, and reputable engineering consulting firms. Not only the firms, but the technical persons that sign and seal the reports are licensed and certify that they meet all professional requirements. Licensing requirements formally require mandatory continuing education and professional qualifications. They are independent petroleum engineers, geologists, geophysicists and petrophysicists.

Our reserve estimation process involves petroleum engineers and geoscientists. As part of this process, all reserves volumes are estimated using a forecast of production rates, current operating costs and projected capital expenditures. Reserves are based upon the unweighted average first-day-of-the-month prices for each year. Price differentials are then applied to adjust these prices to the expected realized field price. Specifics of each operating agreement are then used to estimate the net reserves. Production rate forecasts are derived by a number of methods, including decline curve analyses, volumetrics, material balance or computer simulation of the reservoir performance. Operating costs and capital costs are forecast using current costs combined with expectations of future costs for specific reservoirs. In many cases, activity-based cost models for a reservoir are utilized to project operating costs as production rates and the number of wells for production and injection vary.

The technical person primarily responsible for overseeing preparation of the reserves estimates and the third party reserve reports is Mark L. Pease, the President and Chief Operating Officer of our General Partner. Mr. Pease received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines in 1979. Prior to joining our General Partner, Mr. Pease was Senior Vice President, E&P Technology & Services for Anadarko Petroleum Corporation. Mr. Pease has over 30 years of experience working in various capacities in the energy industry, including acquisition analysis, reserve estimation, reservoir engineering and operations engineering. Mr. Pease consults with NSAI and SLB during the reserve estimation process to review properties, assumptions and relevant data.

F-37

Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report included in this report as exhibits 99.1 and 99.2 are Mr. J. Carter Henson, Jr. and Mr. Mike K. Norton. J. Carter Henson, Jr. has been practicing consulting petroleum engineering at NSAI since 1989. Carter is a Licensed Professional Engineer in the State of Texas (License No. 73964) and has over 30 years of practical experience in petroleum engineering, with over 22 years experience in the estimation and evaluation of reserves. He graduated from Rice University in 1981 with a Bachelor of Science Degree in Mechanical Engineering. Mike Norton has been practicing consulting petroleum geology at NSAI since 1989. Mike is a Licensed Petroleum Geologist in the State of Texas (License No. 441) and has over 34 years of practical experience in petroleum geosciences, with over 29 years experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Within SLB, the technical person primarily responsible for preparing the reserves estimates set forth in the SLB reserves report including in this report as exhibit 99.3 is Mr. Charles M. Boyer II, who has been with PetroTechnical Services (PTS) Division of SLB since 1998. He attended The Pennsylvania State University and graduated with a Bachelor of Science Degree in Geological Sciences in 1976; he is a Certified Petroleum Geologist of the American Association of Petroleum Geologists (Reg. No. 5733); he is a Registered Professional Geologist in the Commonwealth of Pennsylvania (Reg. No. PG004509) and has in excess of 20 years’ experience in the conduct of evaluation and engineering studies relating to oil and gas interests.

Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation methods and procedures consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of the estimated proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure of discounted net future cash flows shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Decreases in the prices of oil and natural gas and increases in operating expenses have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and revenues, profitability and cash flow.

F-38

The following table sets forth certain data pertaining to our estimated proved and proved developed reserves for the years ended December 31, 2012, 2011 and 2010.



	Year Ended December 31,
	2012						2011						2010
	Total (MBoe)		Oil (MBbl)		Gas (MMcf)		Total (MBoe)		Oil (MBbl)		Gas (MMcf)		Total (MBoe)		Oil (MBbl)		Gas (MMcf)
Proved Reserves
Beginning balance	151,106		52,682		590,543		118,908		41,659		463,491		111,301		38,846		434,730
Revision of previous estimates	(27,086	)	3,852		(185,627	)	7,037		10,074		(18,222	)	12,819		5,900		41,510
Purchase of reserves in-place	33,696		26,092		45,625		32,198		4,204		167,971		1,487		70		8,502
Production	(8,318	)	(3,652	)	(27,997	)	(7,037	)	(3,255	)	(22,697	)	(6,699	)	(3,157	)	(21,251	)
Ending balance	149,398		78,974		422,545		151,106		52,682		590,543		118,908		41,659		463,491
Proved Developed Reserves
Beginning balance	131,462		47,813		501,891		108,283		38,719		417,381		100,968		34,436		399,190
Ending balance	119,721		59,158		363,378		131,462		47,813		501,891		108,283		38,719		417,381
Proved Undeveloped Reserves
Beginning balance	19,644		4,869		88,652		10,625		2,940		46,110		10,333		4,410		35,540
Ending balance	29,677		19,816		59,167		19,644		4,869		88,652		10,625		2,940		46,110

Revisions of Previous Estimates

In 2012, we had negative revisions of 27.1 MMBoe, primarily related to a decrease in natural gas prices. Unweighted average first-day-of-the-month crude oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2012 were $94.71 per Bbl of oil and $2.76 per MMBtu of gas, compared to $95.97 per Bbl of oil and $4.12 per MMBtu of gas in 2011. In 2011, we had positive revisions of 7.0 MMBoe, primarily related to an increase in oil prices partially offset by a decrease in natural gas prices.

Unweighted average first-day-of-the-month market prices for the reserve reports for the year ended December 31, 2010 were $79.40 per Bbl of oil and $4.38 per MMBtu of gas. In 2010, we had positive revisions of 12.8 MMBoe, primarily related to an increase in oil and natural gas prices.

Conversion of Proved Undeveloped Reserves

During the years ended December 31, 2012, 2011 and 2010 , we incurred $21.6 million, $15.4 million and $32.6 million in capital expenditures, respectively, and drilled 20 wells, 28 wells and 16 wells, respectively, related to the conversion of proved undeveloped to proved developed reserves. During the years ended December 31, 2012, 2011 and 2010, we converted 2.3 MMBoe, 1.0 MMBoe and 3.2 MMBoe, respectively, from proved undeveloped to proved developed reserves. As of December 31, 2012, 2011 and 2010, we had no proved undeveloped reserves that have remained undeveloped for more than five years. The increase in proved undeveloped reserves during the year ended December 31, 2012 was primarily due to the Permian Basin Acquisitions, the NiMin Acquisition and the AEO Acquisition, which added 12.9 MMBoe, 2.4 MMBoe and 1.4 MMBoe of proved undeveloped reserves, respectively, partially offset by economic revisions and the conversion of proved undeveloped to proved developed reserves. The increase in proved undeveloped reserves during the year ended December 31, 2011 was primarily due to the acquisition of 10.3 MMBoe and 1.9 MMBoe of proved undeveloped reserves in the Cabot Acquisition and the Greasewood Acquisition, respectively. The increase in proved undeveloped reserves during the year ended December 31, 2010 was not material.

F-39

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows relating to our estimated proved crude oil and natural gas reserves as of December 31, 2012, 2011 and 2010 is presented below:



	December 31,
Thousands of dollars	2012			2011			2010
Future cash inflows	$	8,512,019		$	7,338,443		$	5,097,644
Future development costs	(728,577		)	(338,273		)	(251,181		)
Future production expense	(3,950,308		)	(3,531,192		)	(2,618,470		)
Future net cash flows	3,833,134			3,468,978			2,227,993
Discounted at 10% per year	(1,843,238		)	(1,809,677		)	(1,163,069		)
Standardized measure of discounted future net cash flows	$	1,989,895		$	1,659,301		$	1,064,924

The standardized measure of discounted future net cash flows discounted at 10% from production of proved reserves was developed as follows:


1.	An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our estimated proved properties and the present value thereof are made using unweighted average first-day-of-the-month oil and gas sales prices and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. We have entered into various derivative instruments to fix or limit the prices relating to a portion of our oil and gas production. Derivative instruments in effect at December 31, 2012 and 2011 are discussed in Note 5. Such derivative instruments are not reflected in the reserve reports. Representative unweighted average first-day-of-the-month market prices for the reserve reports for the year ended December 31, 2012 were $94.71 per Bbl of oil and $2.76 per MMBtu of gas, compared to $95.97 per Bbl of oil and $4.12 per MMBtu of gas in 2011. Unweighted average first-day-of-the-month market prices for the reserve reports for the year ended December 31, 2010 were $79.40 per Bbl of oil and $4.38 per MMBtu of gas.

The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs. Future net cash flows assume no future income tax expense as we are essentially a non-taxable entity except for four tax-paying corporations whose future income tax liabilities on a discounted basis are insignificant.

The principal sources of changes in the standardized measure of the future net cash flows for the years ended December 31, 2012, 2011 and 2010 are presented below:



	Year Ended December 31,
Thousands of dollars	2012			2011			2010
Beginning balance	$	1,659,301		$	1,064,924		$	759,622
Sales, net of production expense	(218,088		)	(228,424		)	(175,213		)
Net change in sales and transfer prices, net of production expense	(320,533		)	393,183			306,311
Previously estimated development costs incurred during year	61,767			39,665			47,732
Changes in estimated future development costs	(41,372		)	(35,886		)	(105,207		)
Purchase of reserves in place	530,532			342,675			1,676
Revision of quantity estimates and timing of estimated production	152,358			(23,328		)	154,041
Accretion of discount	165,930			106,492			75,962
Ending balance	$	1,989,895		$	1,659,301		$	1,064,924

F-40

B. Quarterly Financial Data (Unaudited)



	Year ended December 31, 2012
	First			Second		Third			Fourth
Thousands of dollars except per unit amounts	Quarter			Quarter		Quarter			Quarter
Oil, natural gas and natural gas liquid sales	$	94,007		$	94,981	$	111,700		$	113,179
Gain (loss) on derivative instruments, net	(36,005		)	107,288		(69,418		)	3,715
Other revenue, net	1,145			907		796			700
Total revenue	59,147			203,176		43,078			117,594

Operating income (loss)	(36,194		)	107,810		(58,029		)	8,113

Net income (loss)	$	(49,925	)	$	92,523	$	(73,003	)	$	(10,334	)

Basic net income (loss) per limited partner unit (a)	$	(0.76	)	$	1.29	$	(1.00	)	$	(0.13	)
Diluted net income (loss) per limited partner unit (a)	$	(0.76	)	$	1.29	$	(1.00	)	$	(0.13	)



	Year ended December 31, 2011
	First			Second		Third		Fourth
Thousands of dollars except per unit amounts	Quarter			Quarter		Quarter		Quarter
Oil, natural gas and natural gas liquid sales	$	92,575		$	94,742	$	97,356	$	109,720
Gain (loss) on derivative instruments, net	(106,177		)	46,483		178,826		(37,465		)
Other revenue, net	898			1,143		1,375		894
Total revenue	(12,704		)	142,368		277,557		73,149

Operating income (loss)	(86,641		)	69,439		190,518		(19,507		)

Net income (loss)	$	(94,713	)	$	57,523	$	178,227	$	(30,339	)

Basic net income (loss) per limited partner unit (a)	$	(1.67	)	$	0.93	$	2.87	$	(0.51	)
Diluted net income (loss) per limited partner unit (a)	$	(1.67	)	$	0.92	$	2.87	$	(0.51	)

(a) Due to changes in the number of weighted average common units outstanding that may occur each quarter, the earnings per unit amounts for certain quarters may not be additive.

F-41

EXHIBIT INDEX



NUMBER		DOCUMENT
3.1		Certificate of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 (File No. 333-134049) filed on July 13, 2006).
3.2		First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2006).
3.3		Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
3.4		Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed April 9, 2009).
3.5		Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed September 1, 2009).
3.6		Amendment No.4 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
3.7		Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC dated as of April 5, 2010 (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2011).
3.8		Amendment No. 1 to the Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC dated as of December 30, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
4.1		Registration Rights Agreement, dated as of November 1, 2007, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).
4.2		First Amendment to the Registration Rights Agreement, dated as of April 5, 2010, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
4.3		Indenture, dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010).
4.4		Registration Rights Agreement, dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010).
4.5		Indenture, dated as of January 13, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 13, 2012).
4.6		Registration Rights Agreement, dated as of January 13, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and Wells Fargo Securities, LLC as representative of the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on January 13, 2012).
4.7		Registration Rights Agreement, dated as of September 27, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and Wells Fargo Securities, LLC, as representative of the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on September 28, 2012).
10.1*		Seventh Amendment to the Second Amended and Restated Credit Agreement of BreitBurn Energy Partners L.P. dated February 26, 2013.
10.2		Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners I, L.P. dated May 5, 2003 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on May 29, 2007).

F-42



NUMBER		DOCUMENT
10.3†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Executive Form) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on March 11, 2008).
10.4†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Executive Form) (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on March 11, 2008).
10.5†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Units Directors’ Award Agreement (incorporated herein by reference to Exhibit 10.35 to the Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-33055) and filed on March 17, 2008).
10.6		Amendment No. 1 to the Operations and Proceeds Agreement, relating to the Dominguez Field and dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.7		Amendment No. 1 to the Surface Operating Agreement dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and its predecessor BreitBurn Energy Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.8†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement (Employment Agreement Form) (incorporated herein by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the period ended June 30, 2008 (File No. 001-33055) and filed on August 11, 2008).
10.9†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement (Non-Employment Agreement Form) (incorporated herein by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the period ended June 30, 2008 and (File No. 001-33055) filed on August 11, 2008).
10.10		Second Amended and Restated Administrative Services Agreement dated August 26, 2008 by and between BreitBurn Energy Company L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 02, 2008).
10.11		Omnibus Agreement, dated August 26, 2008, by and among BreitBurn Energy Holdings LLC, BEC (GP) LLC, BreitBurn Energy Company L.P, BreitBurn GP, LLC, BreitBurn Management Company, LLC and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on September 02, 2008).
10.12		Indemnity Agreement between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Halbert S. Washburn, together with a schedule identifying other substantially identical agreements between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and each of its executive officers and non-employee directors identified on the schedule (incorporated herein by reference to Exhibit 10.1 to the Current Report on form 8-K (File No. 001-33055) filed on November 4, 2009).
10.13†		First Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.2 to the Current Report on form 8-K (File No. 001-33055) filed on November 4, 2009).
10.14†		First Amended and Restated BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan effective as of October 29, 2009 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the period ended September 30, 2009 (File No. 001-33055) filed on November 6, 2009).
10.15		Settlement Agreement as of April 5, 2010 by and among Quicksilver Resources Inc., BreitBurn Energy Partners L.P., BreitBurn GP LLC, Provident Energy Trust, Randall H. Breitenbach and Halbert S. Washburn (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 9, 2010).
10.16†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Executive Form) (incorporated herein by reference to Exhibit 10.21 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011).
10.17†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Executive Form) (incorporated herein by reference to Exhibit 10.22 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011).

F-43



NUMBER		DOCUMENT
10.18†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Director Form) (incorporated herein by reference to Exhibit 10.23 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011).
10.19†		Form of Second Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.24 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011).
10.20†		Form of Third Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.25 to the Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 0001-33055) filed on March 9, 2011).
10.21		Third Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Halbert S. Washburn (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
10.22		Third Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
10.23		Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Mark L. Pease (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
10.24		Second Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and James G. Jackson (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
10.25		Amended and Restated Employment Agreement dated December 30, 2010 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and Gregory C. Brown (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
10.26		Second Amended and Restated Credit Agreement, dated May 7, 2010, by and among BreitBurn Operating L.P, as borrower, BreitBurn Energy Partners L.P., as parent guarantor, and Wells Fargo Bank, N.A., as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the period ended March 31, 2010 (File No. 001-33055) filed on May 10, 2010).
10.27		First Amendment dated September 17, 2010 to the Second Amended and Restated Credit Agreement dated May 7, 2010, by and among BreitBurn Operating L.P, as borrower, BreitBurn Energy Partners L.P., as parent guarantor, and Wells Fargo Bank, N.A., as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 23, 2010).
10.28		Second Amendment to the Second Amended and Restated Credit Agreement dated May 9, 2011 (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 001-33055) filed on May 10, 2011).
10.29		Asset Purchase Agreement, dated as of July 26, 2011, between Cabot Oil & Gas Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on July 29, 2011).
10.3		Third Amendment to the Second Amended and Restated Credit Agreement dated August 3, 2011 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-33055) filed on August 8, 2011).
10.31		Fourth Amendment to the Second Amended and Restated Credit Agreement dated October 5, 2011 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2011).
10.32		Dissolution Agreement, dated May 8, 2012, by and among BreitBurn Energy Partners L.P., Pacific Coast Energy Company LP, BEP (GP) I, LLC and BreitBurn Energy Partners I, L.P. (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 (File No. 001-33055) filed on August 8, 2012).

F-44



NUMBER		DOCUMENT
10.33		Amendment No. 1 to BEPI Partnership Agreement, dated May 8, 2012, by and between BEP (GP) I, LLC and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 (File No. 001-33055) filed on August 8, 2012).
10.34		Third Amended and Restated Administrative Services Agreement, dated May 8, 2012, by and between Pacific Coast Energy Company L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 (File No. 001-33055) filed on August 8, 2012).
10.35		First Amendment to Omnibus Agreement, dated May 8, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn GP, LLC, BreitBurn Management Company, LLC, Pacific Coast Energy Company L.P., Pacific Coast Energy Holdings LLC and PCEC (GP) LLC (incorporated herein by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 (File No. 001-33055) filed on August 8, 2012).
10.36		Purchase and Sale Agreement, dated April 24, 2012, among Legacy Energy, Inc., NiMin Energy Corp. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 27, 2012).
10.37		Purchase and Sale Agreement, dated May 9, 2012, between Element Petroleum, L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on May 11, 2012).
10.38		Purchase and Sale Agreement, dated May 9, 2012, between CrownRock, L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on May 11, 2012).
10.39		First Amendment to Purchase and Sale Agreement, dated as of June 28, 2012, among Legacy Energy, Inc., NiMin Energy Corp. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 29, 2012).
10.40		Fifth Amendment to the Second Amended and Restated Credit Agreement, dated as of May 25, 2012 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on June 29, 2012).
10.41		Sixth Amendment to the Second Amended and Restated Credit Agreement, dated as of October 11, 2012 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2012).
10.42		Contribution Agreement, dated November 21, 2012, among American Energy Operations, Inc., BreitBurn Energy Partners L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on November 27, 2012).
10.43†		Retirement Agreement, dated as of November 30, 2012, among BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on December 6, 2012).
10.44†		Omnibus First Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreements, dated as of November 30, 2012, among BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.2 to the Current Report on form 8-K (File No. 001-33055) filed on December 6, 2012).
10.45†		Fourth Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement, dated as of November 30, 2012, among BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.3 to the Current Report on form 8-K (File No. 001-33055) filed on December 6, 2012).
10.46		Purchase and Sale Agreement, dated December 11, 2012, between CrownRock, L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on December 12, 2012).
10.47		Purchase and Sale Agreement, dated December 11, 2012, between Lynden USA Inc. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on December 12, 2012).
10.48†		Form of First Amendment to BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Director Form) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on December 14, 2012).
10.49†		Form of Fourth Amendment to BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Convertible Phantom Unit Agreement (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on December 14, 2012).

F-45



NUMBER		DOCUMENT
14.1		BreitBurn Energy Partners L.P. and BreitBurn GP, LLC Code of Ethics for Chief Executive Officers and Senior Officers (as amended and restated on February 28, 2007) (incorporated herein by reference to Exhibit 14.1 to the Current Report on Form 8-K filed on March 5, 2007).
21.1*		List of subsidiaries of BreitBurn Energy Partners L.P.
23.1*		Consent of PricewaterhouseCoopers LLP.
23.2*		Consent of Netherland, Sewell & Associates, Inc.
23.3*		Consent of Schlumberger PetroTechnical Services.
31.1*		Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*		Netherland, Sewell & Associates, Inc. reserve report for certain properties located in Wyoming.
99.2*		Netherland, Sewell & Associates, Inc. reserve report for certain properties located in California, Florida, and Texas.
99.3*		Schlumberger PetroTechnical Services reserve report.
101††		Interactive Data Files



*		Filed herewith.
**		Furnished herewith.
†		Management contract or compensatory plan or arrangement.
††		The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under these sections.

F-46