UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarterly period ended September 30, 2012

or

o	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the transition period from ___ to ___

Commission File Number 001-33055

BreitBurn Energy Partners L.P.

(Exact name of registrant as specified in its charter)

Delaware	74-3169953
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification Number)
515 South Flower Street, Suite 4800
Los Angeles, California	90071
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (213) 225-5900

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x   No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one):

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o     No x

As of November 6, 2012, the registrant had 80,644,046 Common Units outstanding.

INDEX

		Page No.
	Cautionary Statement Regarding Forward-Looking Information	1
	PART I
	FINANCIAL INFORMATION
Item 1.	Financial Statements
	– Unaudited Consolidated Balance Sheets at September 30, 2012 and December 31, 2011	2
	– Unaudited Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2012 and 2011	3
	– Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011	4
	– Notes to Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	32
	PART II
	OTHER INFORMATION
Item 1.	Legal Proceedings	33
Item 1A.	Risk Factors	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3.	Defaults Upon Senior Securities	33
Item 4.	Mine Safety Disclosures	33
Item 5.	Other Information	33
Item 6.	Exhibits	33
Signatures		35

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Forward-looking statements are included in this report and may be included in other public filings, press releases, our website and oral and written presentations by management.  Statements other than historical facts are forward-looking and may be identified by words such as "believe," "estimate," "impact," "future," "affect," "result," "engage," "will," variations of such words and words of similar meaning.  These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict.  Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements.  The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report.

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are changes in crude oil and natural gas prices; a continuation of depressed natural gas prices; delays in planned or expected drilling; changes in costs and availability of drilling, completion and production equipment and related services and labor; the discovery of previously unknown environmental issues; the competitiveness of alternate energy sources or product substitutes; technological developments; potential disruption or interruption of our net production due to accidents or severe weather; changes in governmental regulations, including the regulation of derivatives and the oil and natural gas industry; the effects of changes in accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; integration and other risks associated with our acquisitions; and the factors set forth under "Cautionary Statement Regarding Forward-Looking Information" and Part I—Item 1A "—Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2011 (our "Annual Report"), Part II—Item 1A of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012 and Part II—Item 1A of this report.  Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

All forward-looking statements, expressed or implied, included in this report and attributable to us are expressly qualified in their entirety by this cautionary statement.  This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

We undertake no obligation to update the forward-looking statements in this report to reflect future events or circumstances.

1

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Balance Sheets

Thousands	September 30, 2012			December 31, 2011
ASSETS
Current assets
Cash	$	4,374		$	5,328
Accounts and other receivables, net	69,788			73,018
Derivative instruments (note 3)	39,375			83,452
Related party receivables (note 4)	1,916			4,245
Inventory (note 5)	3,516			4,724
Prepaid expenses	3,378			2,053
Total current assets	122,347			172,820
Equity investments	7,135			7,491
Property, plant and equipment
Oil and gas properties	2,987,032			2,583,993
Other assets	14,123			13,431
	3,001,155			2,597,424
Accumulated depletion and depreciation (note 7)	(627,842		)	(524,665		)
Net property, plant and equipment	2,373,313			2,072,759
Other long-term assets
Derivative instruments (note 3)	46,029			55,337
Other long-term assets	30,156			22,442
Total assets	$	2,578,980		$	2,330,849
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	33,896		$	27,203
Derivative instruments (note 3)	5,200			8,881
Revenue and royalties payable	17,173			19,641
Salaries and wages payable	10,156			13,655
Accrued interest payable	28,512			6,291
Accrued liabilities	20,423			14,218
Total current liabilities	115,360			89,889
Credit facility (note 8)	23,000			520,000
Senior notes, net (note 8)	755,696			300,613
Deferred income taxes (note 10)	2,300			2,803
Asset retirement obligation (note 11)	86,499			82,397
Derivative instruments (note 3)	2,016			3,084
Other long-term liabilities	4,697			4,849
Total liabilities	989,568			1,003,635
Commitments and contingencies (note 12)
Equity
Partners' equity (80,644 units and 59,864 units issued and outstanding at September 30, 2012 and December 31, 2011, respectively) (note 13)	1,589,412			1,326,764
Noncontrolling interest (note 14)	—			450
Total equity	1,589,412			1,327,214
Total liabilities and equity	$	2,578,980		$	2,330,849

See accompanying notes to consolidated financial statements.

2

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Statements of Operations

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands of dollars, except per unit amounts	2012			2011			2012			2011
Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	111,700		$	97,356		$	300,688		$	284,673
Gain (loss) on commodity derivative instruments, net (note 3)	(69,418		)	178,826			1,865			119,132
Other revenue, net	796			1,375			2,848			3,416
Total revenues and other income items	43,078			277,557			305,401			407,221
Operating costs and expenses
Operating costs	50,048			46,446			142,203			119,465
Depletion, depreciation and amortization (note 7)	37,270			26,688			109,068			76,354
General and administrative expenses	13,721			13,999			40,321			38,126
Loss (gain) on sale of assets	68			(94		)	222			(40		)
Total operating costs and expenses	101,107			87,039			291,814			233,905
Operating income (loss)	(58,029		)	190,518			13,587			173,316
Interest expense, net of capitalized interest	15,362			9,270			43,231			27,770
Loss on interest rate swaps (note 3)	242			1,143			926			3,020
Other expense (income), net	17			(17		)	36			(20		)
Income (loss) before taxes	(73,650		)	180,122			(30,606		)	142,546
Income tax expense (benefit) (note 10)	(647		)	1,895			(201		)	1,509
Net income (loss)	(73,003		)	178,227			(30,405		)	141,037
Less: Net income attributable to noncontrolling interest	—			(46		)	(62		)	(148		)
Net income (loss) attributable to the partnership	$	(73,003	)	$	178,181		$	(30,467	)	$	140,889
Basic net income (loss) per unit (note 13)	$	(1.00	)	$	2.87		$	(0.44	)	$	2.30
Diluted net income (loss) per unit (note 13)	$	(1.00	)	$	2.87		$	(0.44	)	$	2.29

See accompanying notes to consolidated financial statements.

3

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Statements of Cash Flows

	Nine Months Ended
	September 30,
Thousands of dollars	2012			2011
Cash flows from operating activities
Net income (loss)	$	(30,405	)	$	141,037
Adjustments to reconcile to cash flow from operating activities
Depletion, depreciation and amortization	109,068			76,354
Unit-based compensation expense	16,855			16,334
Unrealized (gain) loss on derivative instruments	61,938			(106,488		)
Income from equity affiliates, net	356			169
Deferred income taxes	(503		)	1,313
Loss (gain) on sale of assets	222			(40		)
Other	3,366			417
Changes in net assets and liabilities
Accounts receivable and other assets	(10,425		)	(9,858		)
Inventory	1,208			2,638
Net change in related party receivables and payables	2,329			932
Accounts payable and other liabilities	12,267			5,976
Net cash provided by operating activities	166,276			128,784
Cash flows from investing activities
Capital expenditures	(77,699		)	(61,264		)
Proceeds from sale of assets	863			1,118
Deposit for oil and gas properties	—			(14,250		)
Property acquisitions	(313,404		)	(57,380		)
Net cash used in investing activities	(390,240		)	(131,776		)
Cash flows from financing activities
Issuance of common units	370,504			99,826
Distributions	(93,734		)	(75,690		)
Proceeds from borrowings	1,066,885			283,500
Repayments of debt	(1,109,000		)	(300,500		)
Change in bank overdraft	(2,299		)	141
Debt issuance costs	(9,346		)	(3,138		)
Net cash provided by financing activities	223,010			4,139
Increase (decrease) in cash	(954		)	1,147
Cash beginning of period	5,328			3,630
Cash end of period	$	4,374		$	4,777

See accompanying notes to consolidated financial statements.

4

Notes to Consolidated Financial Statements

1.  Organization and Basis of Presentation

The accompanying unaudited consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our Annual Report.  The financial statements have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X.  In the opinion of management, all adjustments considered necessary for a fair statement of our financial position at September 30, 2012, our operating results for the three months and nine months ended September 30, 2012 and 2011, and our cash flows for the nine months ended September 30, 2012 and 2011 have been included.  Operating results for the three months and nine months ended September 30, 2012 are not necessarily indicative of the results that may be expected for the year ended December 31, 2012.  The consolidated balance sheet at December 31, 2011 has been derived from the audited consolidated financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements.  For further information, refer to the consolidated financial statements and footnotes thereto included in our Annual Report.

We follow the successful efforts method of accounting for oil and gas activities.  Depletion, depreciation and amortization of proved oil and gas properties is computed using the units-of-production method, net of any estimated residual salvage values.

2.  Accounting Standards

In May 2011, the Financial Accounting Standards Board ("FASB") issued an Accounting Standards Update ("ASU") to improve comparability between GAAP and International Financial Reporting Standards fair value measurement and disclosure requirements. This amendment changes the wording used to describe many of the requirements in 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 and 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 that requires a company to disclose information about financial instruments that have been offset and related arrangements to enable users of a company's financial statements to understand the effect of those arrangements on the company's 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.

3.  Financial Instruments

Our risk management programs are intended to reduce our exposure to commodity prices and interest rates and to assist with stabilizing cash flow and distributions.  Routinely, we utilize derivative financial instruments to reduce this volatility. To the extent we have hedged a significant portion of our expected production through commodity derivative instruments and the cost for goods and services increases, our margins would be adversely affected.

Commodity Activities

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

5

We had the following commodity derivative contracts in place at September 30, 2012:

	Year
	2012		2013		2014		2015		2016		2017
Oil Positions:
Fixed Price Swaps - NYMEX WTI
Hedged Volume (Bbl/d)	4,009		3,879		3,314		3,689		1,611		222
Average Price ($/Bbl)	$	90.90	$	90.74	$	93.21	$	97.50	$	91.50	$	88.12
Fixed Price Swaps - IPE Brent
Hedged Volume (Bbl/d)	2,339		3,900		3,500		2,000		1,500		—
Average Price ($/Bbl)	$	105.37	$	97.23	$	96.86	$	96.46	$	93.75	$	—
Collars - NYMEX WTI
Hedged Volume (Bbl/d)	2,346		500		1,000		1,000		—		—
Average Floor Price ($/Bbl)	$	110.00	$	77.00	$	90.00	$	90.00	$	—	$	—
Average Ceiling Price ($/Bbl)	$	145.50	$	103.10	$	112.00	$	113.50	$	—	$	—
Collars - IPE 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)	—		500		—		—		—		—
Average Price ($/Bbl)	$	—	$	90.00	$	—	$	—	$	—	$	—
Total:
Hedged Volume (Bbl/d)	8,694		8,779		7,814		7,189		3,611		222
Average Price ($/Bbl)	$	99.94	$	92.80	$	94.43	$	95.65	$	92.22	$	88.12
Gas Positions:
Fixed Price Swaps - Mich Con City-Gate
Hedged Volume (MMBtu/d)	18,678		37,000		7,500		7,500		7,000		—
Average Price ($/MMBtu)	$	7.28	$	6.50	$	6.00	$	6.00	$	4.51	$	—
Fixed Price Swaps - Henry Hub
Hedged Volume (MMBtu/d)	16,000		19,000		36,000		40,500		13,000		—
Average Price ($/MMBtu)	$	4.88	$	4.90	$	4.86	$	4.88	$	4.18	$	—
Collars - Mich Con City-Gate
Hedged Volume (MMBtu/d)	18,680		—		—		—		—		—
Average Floor Price ($/MMBtu)	$	9.00	$	—	$	—	$	—	$	—	$	—
Average Ceiling Price ($/MMBtu)	$	12.25	$	—	$	—	$	—	$	—	$	—
Puts - Henry Hub
Hedged Volume (MMBtu/d)	—		—		6,000		1,500		—		—
Average Price ($/MMBtu)	$	—	$	—	$	5.00	$	5.00	$	—	$	—
Total:
Hedged Volume (MMBtu/d)	53,358		56,000		49,500		49,500		20,000		—
Average Price ($/MMBtu)	$	7.16	$	5.96	$	5.05	$	5.05	$	4.30	$	—
Calls - Henry Hub
Hedged Volume (MMBtu/d)	—		30,000		15,000		—		—		—
Average Price ($/MMBtu)	$	—	$	8.00	$	9.00	$	—	$	—	$	—
Premium ($/MMBtu)	$	—	$	0.08	$	0.12	$	—	$	—	$	—

6

Included in the above table are natural gas swaps and put options 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, and crude oil option contracts we entered into in August 2012, hedging a total of 182,500 barrels from January 1, 2013 to December 31, 2013, at a weighted average NYMEX price of $90.00 per barrel, for which we paid premiums of approximately $1.3 million.

In July 2012, we exercised contracts and paid premiums of $2.5 million for swaption contracts entered into in April 2012 that provided options to hedge a total of 510,168 barrels of future crude oil production associated with the NiMin Energy Corp. ("NiMin") acquisition at then-current NYMEX WTI market prices, ranging from $104.80 per barrel in 2012 to $88.45 per barrel in 2017.  In July 2012, we also exercised contracts and paid premiums of $2.6 million for swaption contracts entered into in May 2012 that provided options to hedge a total of 634,485 barrels of future crude oil production associated with the Element Petroleum, LP ("Element") and CrownRock, L.P. ("CrownRock") acquisitions at then-current NYMEX WTI market prices, ranging from $98.35 per barrel in 2012 to $87.80 per barrel in 2017. See Note 6 for a discussion of these acquisitions. These contracts are reflected in the above table.

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 derivative contracts in place at September 30, 2012 that fix interest rates for the floating LIBOR-based portion of debt under our credit facility:

Notional amounts in thousands of dollars	Notional Amount		Fixed Rate
Period Covered
October 1, 2012 to December 20, 2012	$	100,000	1.1550	%
October 1, 2012 to January 20, 2014	$	100,000	2.4800	%

7

Fair Value of Financial Instruments

Fair value of derivative instruments not designated as hedging instruments as recorded on our consolidated balance sheet:

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 September 30, 2012
Assets
Current assets - derivative instruments	$	3,556		$	48,291	$	—		$	(12,472	)	$	39,375
Other long-term assets - derivative instruments	13,816			34,436		—			(2,223		)	46,029
Total assets	17,372			82,727		—			(14,695		)	85,404
Liabilities
Current liabilities - derivative instruments	(15,301		)	—		(2,371		)	12,472			(5,200		)
Long-term liabilities - derivative instruments	(3,590		)	—		(649		)	2,223			(2,016		)
Total liabilities	(18,891		)	—		(3,020		)	14,695			(7,216		)
Net assets (liabilities)	$	(1,519	)	$	82,727	$	(3,020	)	$	—		$	78,188
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 our consolidated balance sheets.

8

Gains and losses on derivative instruments not designated as hedging instruments as reflected on our consolidated statements of operations:

Thousands of dollars	Oil Commodity Derivatives (a)			Natural Gas Commodity Derivatives (a)			Interest Rate Derivatives (b)			Total Financial Instruments
Three Months Ended September 30, 2012
Realized gain (loss)	$	2,004		$	20,492		$	(813	)	$	21,683
Unrealized gain (loss)	(55,184		)	(36,730		)	571			(91,343		)
Net loss	$	(53,180	)	$	(16,238	)	$	(242	)	$	(69,660	)
Three Months Ended September 30, 2011
Realized gain (loss)	$	(4,901	)	$	12,993		$	(1,072	)	$	7,020
Unrealized gain (loss)	161,208			9,526			(71		)	170,663
Net gain (loss)	$	156,307		$	22,519		$	(1,143	)	$	177,683
Nine Months Ended September 30, 2012
Realized gain (loss)	$	(846	)	$	65,996		$	(2,274	)	$	62,876
Unrealized gain (loss)	(7,142		)	(56,143		)	1,348			(61,937		)
Net gain (loss)	$	(7,988	)	$	9,853		$	(926	)	$	939
Nine Months Ended September 30, 2011
Realized gain (loss)	$	(25,446	)	$	38,230		$	(3,160	)	$	9,624
Unrealized gain (loss)	117,267			(10,919		)	140			106,488
Net gain (loss)	$	91,821		$	27,311		$	(3,020	)	$	116,112

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

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

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 September 30, 2012 and December 31, 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 three months or nine months ended September 30, 2012 and September 30, 2011. Our policy is to recognize transfers between levels as of the end of the period.

9

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

The model we utilize to calculate the fair value of our commodity derivative instruments is a standard option pricing model.  Inputs to the option pricing model include fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity forward price curves, volatility, interest rate factors and time to expiry.  Model inputs are obtained from our counterparties and third party data providers and are verified 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 before counterparty netting under derivative netting agreements.  

Thousands of dollars	Level 1		Level 2			Level 3			Total
As of September 30, 2012
Assets (liabilities)
Oil swaps	$	—	$	(11,050	)	$	—		$	(11,050	)
Oil collars	—		—			9,531			9,531
Natural gas swaps	—		71,891			—			71,891
Natural gas collars	—		—			9,339			9,339
Natural gas calls	—		—			(1,433		)	(1,433		)
Natural gas puts	—		—			2,930			2,930
Interest rate swaps	—		(3,020		)	—			(3,020		)
Net assets	$	—	$	57,821		$	20,367		$	78,188
As of December 31, 2011
Assets (liabilities)
Oil swaps	$	—	$	(9,234	)	$	—		$	(9,234	)
Oil collars	—		—			8,509			8,509
Natural gas swaps	—		94,868			—			94,868
Natural gas collars	—		—			38,366			38,366
Natural gas calls	—		—			(1,317		)	(1,317		)
Interest rate swaps	—		(4,368		)	—			(4,368		)
Net assets	$	—	$	81,266		$	45,558		$	126,824

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Thousands of dollars	2012			2011		2012			2011
Beginning balance	$	44,304		$	63,681	$	45,558		$	86,253
Realized gain (a)	14,483			13,778		42,568			30,268
Unrealized gain (loss) (a)	(39,672		)	5,438		(72,789		)	(33,624		)
Purchases (b)	1,252			—		5,030			—
Ending balance	$	20,367		$	82,897	$	20,367		$	82,897

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

(b) Relates to premiums paid for natural gas put options entered into in June 2012 and crude oil options entered into in August 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 September 30, 2012, the significant unobservable inputs used in the fair value measurements were as follows:

	Fair Value at			Valuation
Thousands of dollars	September 30, 2012			Technique	Unobservable Input	Range
Oil collars	$	9,531		Option pricing model	Oil forward commodity prices	$86.63/Bbl - $111.99/Bbl
					Oil volatility	20.05% - 31.35%
					Own credit risk	5%
Natural gas collars	9,339			Option pricing model	Gas forward commodity prices	$3.02/MMBtu - $5.01/MMBtu
Natural gas calls	(1,433		)		Gas volatility	20.15% - 40.70%
Natural gas puts	2,930				Own credit risk	5%
Total	$	20,367

Credit and Counterparty Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of derivatives and accounts receivable.  Our derivatives expose us to credit risk from counterparties.  As of September 30, 2012, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, U.S Bank National Association and Toronto-Dominion Bank.  Our counterparties are all lenders under our bank credit facility. We periodically obtain credit default swap information on our counterparties.  As of September 30, 2012, each of these financial institutions had an investment grade credit rating.  Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default.  As of September 30, 2012, our largest derivative asset balances were with Credit Suisse Energy LLC, Wells Fargo Bank National Association and JP Morgan Chase Bank N.A., which accounted for approximately 18%, 17% and 16% of our derivative asset balances, respectively.  As of September 30, 2012, our largest derivative liability balances were with The Royal Bank of Scotland plc, Citibank N.A and The Bank of Nova Scotia, which accounted for approximately 39%, 30% and 22% of our derivative liability balances, respectively.

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4.  Related Party Transactions

BreitBurn Management Company, LLC ("BreitBurn Management"), our wholly-owned subsidiary, operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering.  All of our employees, including our executives, are employees of BreitBurn Management.

BreitBurn Management also provides administrative services to Pacific Coast Energy Company L.P., formerly named BreitBurn Energy Company L.P. ("PCEC"), our predecessor, under an administrative services agreement, in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses, including incentive compensation plan costs and direct payroll and administrative costs related to PCEC's properties and operations.  

On May 8, 2012, Pacific Coast Oil Trust (the "Trust"), which was formed by PCEC, 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 (as described below). 

Prior to April 1, 2012, we owned the limited partner interest (99%) of BreitBurn Energy Partners I, L.P. ("BEPI").  BEPI's general partner interest was held by PCEC, and PCEC also 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 in the properties during the second quarter of 2012.  PCEC operated the East Coyote and Sawtelle Fields until April 1, 2012 under the limited partnership agreement for the benefit of itself and the Partnership.  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, effective April 1, 2012, PCEC's ownership interest in these properties increased, and our ownership in the properties was reduced from approximately 95% to approximately 62%. PCEC agreed to pay a development fee equal to 5% of the cost of development of the properties, and upon termination of the Third Amended and Restated Services Agreement (as described below), an operating fee of 15% of the cost of operating the properties.

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 September 30, 2012 and December 31, 2011, we had current receivables of $1.4 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.  For the three months and nine months ended September 30, 2012, the monthly charges to PCEC for indirect expenses totaled $2.1 million and $5.9 million, respectively, and charges for direct expenses including direct payroll and administrative costs totaled $2.3 million and $6.3 million, respectively. For the three months and nine months ended September 30, 2011, the monthly charges to PCEC for indirect expenses totaled $1.4 million and $4.3 million, respectively, and charges for direct expenses including direct payroll and administrative costs totaled $2.3 million and $5.9 million, respectively.  For the three months and nine months ended September 30, 2012, total net oil and gas sales made by us on PCEC's behalf were approximately $3.3 million and $3.5 million. For the three months and nine months ended September 30, 2011, total net oil and gas sales made by PCEC on our behalf were approximately $3.8 million and $10.6 million, respectively.

At September 30, 2012 and December 31, 2011, we had receivables of $0.5 million and $1.4 million, respectively, due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management

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fees due from them and operational expenses incurred on their behalf.

5.  Inventory

Our crude oil inventory from our Florida operations was $3.5 million at September 30, 2012 and $4.7 million at December 31, 2011.  During the nine months ended September 30, 2012, we sold 652 gross MBbls and produced 623 gross MBbls of crude oil from our Florida operations.  Crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter.  Crude oil inventory additions are valued at the lower of cost or market, with cost based on our actual production costs.  We match production expenses with crude oil sales.  Production expenses associated with unsold crude oil inventory are recorded to inventory.

6. Acquisitions

On July 2, 2012, we completed the Element and CrownRock acquisitions to acquire oil and natural gas properties located in the Permian Basin in Texas with an effective date of March 1, 2012 for approximately $148 million and $70 million, respectively, subject to customary post-closing adjustments. The properties are 56% oil and produced approximately1,635 Boe/day in the three months ended September 30, 2012. The preliminary purchase prices for these two acquisitions were allocated to the assets acquired and liabilities assumed as follows:

Thousands of dollars	Element			CrownRock
Oil and gas properties	$	147,662		$	69,270
Prepaid expenses	1,164			—
Accounts receivable	—			1,316
Accrued liabilities	(517		)	(345		)
Asset retirement obligation	(159		)	(134		)
	$	148,150		$	70,107

The preliminary purchase price allocation is subject to final closing adjustments. We will finalize the purchase price allocation within one year of the acquisition date.

Acquisition related costs for the Element and CrownRock acquisitions were $0.9 million in the aggregate and were reflected in general and administrative expenses on the consolidated statements of operations. Revenues and expenses from the Element and CrownRock properties are reflected in our consolidated statements of operations beginning July 2, 2012.

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 properties are 100% oil and produced approximately 490 Boe/d in the three months ended September 30, 2012. This acquisition was accounted for under the acquisition method of accounting. The final purchase price for this acquisition was approximately $95 million in cash and was allocated to the assets acquired and liabilities assumed as follows:

Thousands of dollars	NiMin
Oil and gas properties	$	98,619
Accrued liabilities	(1,863		)
Asset retirement obligation	(1,609		)
	$	95,147

Acquisition related costs for the NiMin Acquisition were $0.3 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.

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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.

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. The following unaudited pro forma financial information presents a summary of our combined statements of operations for the three months and nine months ended September 30, 2011, assuming the Cabot Acquisition had been completed on January 1, 2011, including adjustments to reflect the allocation of the preliminary purchase price to the acquired net assets. The pro forma financial information is not necessarily indicative of the results of operations if the acquisition had been effective January 1, 2011.

	Pro Forma
Thousands of dollars, except per unit amounts	Three Months Ended September 30, 2011		Nine Months Ended September 30, 2011
Revenues	$	290,621	$	447,901
Net income (loss) attributable to the partnership	180,829		150,573
Net income per unit:
Basic	$	2.91	$	2.46
Diluted	$	2.91	$	2.45

7.  Impairments

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

During the three months ended September 30, 2012, we recorded no impairment charges. During the nine months ended September 30, 2012, we recorded non-cash impairment charges of approximately $11.6 million primarily related to uneconomic proved properties in Michigan, Indiana and Kentucky due to a decrease in expected future natural gas prices and the Alamitos field due to a decrease in expected future crude oil prices. During the nine months ended September 30, 2011, we recorded no non-cash impairment charges.

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

8.  Long-Term Debt

Senior Notes Due 2020

On October 6, 2010, we and BreitBurn Finance Corporation (the "Issuers"), and certain of our subsidiaries as guarantors (the "Guarantors"), issued $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the "2020 Senior Notes"). The 2020 Senior Notes were 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 September 30, 2012, the 2020 Senior Notes had a carrying value of $301.0 million, net of unamortized discount of $4.0 million. Interest on the 2020 Senior Notes is payable twice a year in April and October.

As of September 30, 2012, the fair value of the 2020 Senior Notes was estimated to be $331.7 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"). The Initial Notes have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws, and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Initial Notes were resold by the Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The 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 estimated 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") (the Additional Notes and the Initial Notes collectively referred to as the "2022 Senior Notes"). The Additional Notes also have not been registered under the Securities Act, or any state securities laws, and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Additional Notes were resold by the Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act. 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 estimated 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 Securities and Exchange Commission (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 October 2012, we filed a registration statement for the exchange offer for the 2022 Senior Notes. See Note 16.

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As of September 30, 2012, the 2022 Senior Notes had a carrying value of $454.7 million, net of unamortized premium of $4.7 million. Interest on the 2022 Senior Notes is payable twice a year in April and October. As of September 30, 2012, the fair value of the 2022 Senior Notes was estimated to be $467.3 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 September 30, 2012 and December 31, 2011, we were in compliance with the covenants on our Senior Notes.

Credit Facility

BreitBurn Operating L.P. ("BOLP"), as borrower, and we and our wholly-owned subsidiaries, as guarantors, have a $1.5 billion revolving credit facility with Wells Fargo Bank National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (the "Second Amended and Restated Credit Agreement") with a maturity date of May 9, 2016. 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 events that constitute an Event of Default (as defined in the Second Amended and Restated Credit Agreement) include: payment defaults, misrepresentations, breaches of covenants, cross-default and cross-acceleration to certain other indebtedness, adverse judgments against us in excess of a specified amount, changes in management or control, loss of permits, certain insolvency events and assertion of certain environmental claims.

As of September 30, 2012 and December 31, 2011, we were in compliance with our credit facility's covenants.

As of December 31, 2011, our borrowing base was $850 million. In January 2012, in connection with the issuance of the Initial Notes, our borrowing base was automatically reduced to $787.5 million in accordance with the terms of our credit facility. In April 2012, our borrowing base was redetermined and increased from $787.5 million to $850.0 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. In September 2012, in connection with the issuance of the Additional Notes, our borrowing base was automatically reduced to $800 million in accordance with the terms of our credit facility. Our semi-annual borrowing base redetermination occurred in October 2012. See Note 16.

As of September 30, 2012 and December 31, 2011, we had $23 million and $520 million, respectively, in indebtedness outstanding under our credit facility. At September 30, 2012, the one-month LIBOR interest rate plus an applicable spread was 1.990% on the one-month LIBOR portion of $20 million and the prime rate plus an applicable spread was 4.00% on the

prime debt portion of $3 million.

The amounts reported on our consolidated balance sheets for our credit facility debt approximate fair value due to the variable nature of our interest rates. Our credit facility can be repaid at any time without penalty. Interest is generally fixed for 30-day increments at LIBOR plus a stipulated margin for the amount utilized and at a stipulated percentage as a commitment fee for the portion not utilized or fixed daily at the Prime rate plus a stipulated margin. We use a market approach to ensure the terms of our credit facility are in line with market rates for similar credit facilities, which are considered to be Level 2 inputs.

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Our interest and other financing costs, as reflected in interest expense, net of capitalized interest on the consolidated statements of operations, are detailed in the following table:

	Three Months Ended					Nine Months Ended
	September 30,					June 30,
Thousands of dollars	2012			2011		2012			2011
Credit agreement (including commitment fees)	$	2,804		$	1,602	$	5,846		$	4,619
Senior notes	11,557			6,576		33,843			19,583
Amortization of discounts/premiums and deferred issuance costs	1,041			1,092		3,582			3,645
Capitalized interest	(40		)	—		(40		)	(77		)
Total	$	15,362		$	9,270	$	43,231		$	27,770

9. Condensed Consolidating Financial Statements

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

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

10.  Income Taxes

Our deferred income tax liability was $2.3 million and $2.8 million at September 30, 2012 and December 31, 2011, respectively.  The following table presents our income tax expense (benefit) for the three months and nine months ended September 30, 2012 and 2011: 

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands of dollars	2012			2011			2012			2011
Federal income tax expense (benefit)
Current	$	(65	)	$	(10	)	$	199		$	116
Deferred (a)	(629		)	1,831			(503		)	1,313
State income tax expense (b)	47			74			103			80
Total	$	(647	)	$	1,895		$	(201	)	$	1,509

(a) Related to Phoenix Production Company, a tax-paying corporation and our wholly-owned subsidiary.

(b) Primarily in California, Texas and Michigan.

11.  Asset Retirement Obligation

Our asset retirement obligation is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities together with our estimate of the future timing of the costs to be incurred.  Payments to settle asset retirement obligations occur over the operating lives of the assets, estimated to be from less than one year to 50 years.  Estimated cash flows have been discounted at our average credit-adjusted risk-free rate, which approximates 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.

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

Changes in the asset retirement obligation for the nine months ended September 30, 2012 and the year ended December 31, 2011 are presented in the following table:

	Nine Months Ended			Year Ended
Thousands of dollars	September 30, 2012			December 31, 2011
Carrying amount, beginning of period	$	82,397		$	47,429
Acquisitions (a)	1,902			10,980
Liabilities incurred	716			5,701
Liabilities settled	(598		)	(5,301		)
Revisions (b)	(2,266		)	20,005
Accretion expense	4,348			3,583
Carrying amount, end of period	$	86,499		$	82,397

(a) Primarily relates to the NiMin, Element and CrownRock acquisitions in 2012 and the Cabot Acquisition in 2011.

(b) 2011 revisions relate to increased cost estimates and revisions to reserve life. 2012 revisions relate to the change in working interest ownership in two California fields.

12.  Commitments and Contingencies

Surety Bonds and Letters of Credit

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit.  These obligations primarily cover self-insurance and other programs where governmental organizations require such support.  These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon.  At September 30, 2012 and December 31, 2011, we had surety bonds for $16.1 million and $22.1 million, respectively.  At each of September 30, 2012 and December 31, 2011, we had approximately $0.3 million in letters of credit outstanding.

13.  Partners’ Equity

In February 2012, we sold 9.2 million of our limited partnership units ("Common 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.

During the first nine months of 2012, we issued less than 0.1 million Common Units to outside directors for phantom units and Restricted Phantom Units ("RPUs") that were granted in 2009 and 2011 and vested in January 2012.

At September 30, 2012 and December 31, 2011, we had approximately 80.6 million and 59.9 million Common Units outstanding, respectively.  At September 30, 2012 and December 31, 2011, there were approximately 2.6 million and 1.7 million, respectively, of units outstanding under the First Amended and Restated 2006 Long-Term Incentive Plan, as amended ("LTIP"), that were eligible to be paid in Common Units upon vesting.

Cash Distributions

On February 14, 2012, we paid a cash distribution of approximately $27.0 million to our common unitholders of record as of the close of business on February 6, 2012. The distribution that was paid to unitholders was $0.4500 per Common Unit. On May 14, 2012, we paid a cash distribution of approximately $31.5 million to our common unitholders of record as of the close of business on May 7, 2012. The distribution that was paid to unitholders was $0.4550 per Common Unit. On August 14, 2012, we paid a cash distribution of approximately $31.8 million to our common unitholders of record as of the close of business on August 10, 2012. The distribution that was paid to unitholders was $0.4600 per Common Unit. During the three months and nine months ended September 30, 2012, we also paid $1.2 million and $3.5 million in cash at a rate

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equal to the distributions paid to our unitholders, to holders of outstanding unvested RPUs and Convertible Phantom Units ("CPUs") issued under our LTIP.

On February 11, 2011, we paid a cash distribution of approximately $22.4 million to our common unitholders of record as of the close of business on February 8, 2011. The distribution that was paid to unitholders was $0.4125 per Common Unit. On May 13, 2011, we paid a cash distribution of approximately $24.6 million to our common unitholders of record as of the close of business on May 10, 2011. The distribution that was paid to unitholders was $0.4175 per Common Unit. On August 12, 2011, we paid a cash distribution of approximately $24.9 million to our common unitholders of record as of the close of business on August 9, 2011. The distribution that was paid to unitholders was $0.4225 per Common Unit. During the three months and nine months ended September 30, 2011, we also paid $1.3 million and $3.8 million in cash, at a rate equal to the distributions paid to our unitholders, to holders of outstanding unvested RPUs and CPUs.

Earnings per Unit

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

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Thousands, except per unit amounts	2012			2011		2012			2011
Net income (loss) attributable to the partnership	$	(73,003	)	$	178,181	$	(30,467	)	$	140,889
Distributions on participating units not expected to vest	—			25		—			26
Net income (loss) attributable to common unitholders and participating securities	$	(73,003	)	$	178,206	$	(30,467	)	$	140,915
Weighted average number of units used to calculate basic and diluted net income (loss) per unit:
Common Units	72,894			59,040		69,363			58,297
Participating securities (a)	—			3,015		—			2,976
Denominator for basic earnings per common unit	72,894			62,055		69,363			61,273
Dilutive units (b)	—			136		—			133
Denominator for diluted earnings per common unit	72,894			62,191		69,363			61,406
Net income (loss) per common unit
Basic	$	(1.00	)	$	2.87	$	(0.44	)	$	2.30
Diluted	$	(1.00	)	$	2.87	$	(0.44	)	$	2.29

(a) The three months and nine months ended September 30, 2012 exclude 2,557 and 2,513, respectively, of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.

(b) The three months and nine months ended September 30, 2012 exclude 59 and 57 of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit.

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14.  Noncontrolling Interest

FASB Accounting Standardsrequire 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.

On May 25, 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.  BEPI’s general partner interest was held by a wholly-owned subsidiary of PCEC. At December 31, 2011, the amount of this noncontrolling interest was $0.5 million.  

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, effective April 1, 2012, 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 September 30, 2012, the amount of the noncontrolling interest was zero.

15.  Unit and Other Valuation-Based Compensation Plans

Unit-based compensation expense for the three months and nine months ended September 30, 2012 was $5.7 million and $16.9 million, respectively, and for the three months and nine months ended September 30, 2011, it was $5.4 million and $16.3 million, respectively. During the nine months ended September 30, 2012, the board of directors of BreitBurn GP, LLC (our "General Partner") granted approximately 0.9 million RPUs to employees of BreitBurn Management under the LTIP.  Our outside directors were granted less than 0.1 million RPUs under our LTIP during the nine months ended September 30, 2012.  The fair market value of the RPUs granted during 2012 for computing compensation expense under FASB Accounting Standards averaged $19.60 per unit.

During the three months and nine months ended September 30, 2012, we paid nothing for taxes withheld on RPUs vested during the period.  During the three months and nine months ended September 30, 2011, we paid nothing and $1.4 million, respectively, for taxes withheld on RPUs vested during the period.  

As of September 30, 2012, we had $22.9 million of total unrecognized compensation costs for all outstanding awards.  This amount is expected to be recognized over the period from October 1, 2012 to December 31, 2014. For detailed information on our LTIP, see Note 17 to the consolidated financial statements included in our Annual Report.

On May 18, 2012, we filed a registration statement on Form S-8 to register approximately 3.0 million Common Units available for issuance under our LTIP that were not previously registered.

16.  Subsequent Events

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.

In connection with the exchange offer relating to the 2022 Senior Notes, on October 18, 2012, the Issuers filed a registration statement on Form S-4 with the SEC with respect to an offer to exchange the 2022 Senior Notes for substantially identical notes that are registered under the Securities Act. We have not yet commenced the exchange offer.

Distribution

On October 31, 2012, we announced a cash distribution to unitholders for the third quarter of 2012 at the rate of $0.4650 per Common Unit, to be paid on November 14, 2012 to our common unitholders of record as of the close of business on November 9, 2012.

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis in conjunction with Management’s Discussion and Analysis in Part II—Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2011 (the "Annual Report") and the consolidated financial statements and related notes therein.  Our Annual Report contains a discussion of other matters not included herein, such as disclosures regarding critical accounting policies and estimates and contractual obligations.  You should also read the following discussion and analysis together with Part II—Item 1A "—Risk Factors" of this report, the "Cautionary Statement Regarding Forward-Looking Information" in this report and in our Annual Report and Part I—Item 1A "—Risk Factors" of our Annual Report.

Overview

We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States.  Our assets consist primarily of producing and non-producing crude oil and natural gas reserves located primarily in the Antrim Shale and other non-Antrim formations in Michigan, the Evanston and Green River Basins in southwestern Wyoming, the Wind River and Big Horn Basins in central Wyoming, the Powder River Basin in eastern Wyoming, the Los Angeles Basin in California, the Permian Basin in Texas, the Sunniland Trend in Florida and the New Albany Shale in Indiana and Kentucky.

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 core investment strategies include:

• 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.

Consistent with our long-term business strategy, we intend to continue to actively pursue oil and natural gas acquisition opportunities in 2012.

2012 Acquisitions

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 Energy Corp. ("NiMin"), with an effective date of April 1, 2012. The properties are 100% oil and produced approximately 490 Boe/d in the third quarter of 2012. The purchase price for this acquisition was approximately $95 million.

On July 2, 2012, we completed the Element and CrownRock acquisitions to acquire oil and natural gas properties located in the Permian Basin in Texas with an effective date of March 1, 2012 for approximately $148 million and $70 million, respectively, subject to customary post-closing adjustments. The properties are 56% oil and produced approximately 1,635 Boe/day in the third quarter of 2012.

2012 Highlights

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 bank credit facility.

In February 2012, we sold approximately 9.2 million of our limited partnership units ("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 bank credit facility.

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In April 2012, our borrowing base was redetermined and increased from $787.5 million to $850.0 million.

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 bank 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 bank credit facility.

In September 2012, in connection with the issuance of the Additional Notes, our borrowing base was automatically reduced to $800 million in accordance with the terms of our credit facility.

In connection with the exchange offer relating to the 2022 Senior Notes, in October 2012, the Issuers filed a registration statement on Form S-4 with the SEC with respect to an offer to exchange the 2022 Senior Notes for substantially identical notes that are registered under the Securities Act. We have not commenced the exchange offer yet.

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 provides us with the ability to increase our total commitments up to the $1 billion borrowing base upon lender approval.

2012 Distributions

On February 14, 2012, we paid a cash distribution for the fourth quarter of 2011 of approximately $27.0 million to our common unitholders of record as of the close of business on February 6, 2012. The distribution that was paid to unitholders was $0.4500 per Common Unit. On May 14, 2012, we paid a cash distribution for the first quarter of 2012 of approximately $31.5 million to our common unitholders of record as of the close of business on May 7, 2012. The distribution that was paid to unitholders was $0.4550 per Common Unit. On August 14, 2012, we paid a cash distribution for the second quarter of 2012 of approximately $31.8 million to our common unitholders of record as of the close of business on August 10, 2012. The distribution that was paid to unitholders was $0.4600 per Common Unit. On October 31, 2012, we announced a cash distribution to unitholders for the third quarter of 2012 at the rate of $0.4650 per Common Unit, to be paid on November 14, 2012 to our common unitholders of record as of the close of business on November 9, 2012.

Operational Focus and Capital Expenditures

 In the first nine months of 2012, our oil and natural gas capital expenditures totaled $93 million, compared to approximately $59 million in the first nine months of 2011.  We spent approximately $30 million in Florida, $29 million in California, $18 million in Wyoming, $9 million in Michigan, Indiana and Kentucky and $7 million in Texas.  In the first nine months of 2012, we drilled and completed 13 wells in Wyoming, 12 wells in California, five wells in Michigan, four wells in Texas and three wells in Florida and completed 22 workovers in Michigan, 15 workovers in Wyoming and five workovers in California. In the first nine months of 2012, we also completed two facility optimization projects in California, three in Michigan and one in Indiana.

In 2012, our crude oil and natural gas capital spending program, including projects for our properties acquired in 2012, is expected to be approximately $151.6 million, compared to $75 million in 2011. This reflects our original capital program of $68 million, a $37.1 million increase to our California capital program to pursue attractive oil drilling opportunities where we receive Brent-based pricing, which has been above WTI for the past year, approximately $30 million to develop our recently acquired properties in the Permian Basin in Texas and the Big Horn Basin in Wyoming and $17.6 million for our legacy properties in Florida, Wyoming and Michigan. Based on our revised capital spending program, we expect our 2012 production to be between approximately 8.3 MMBoe and 8.6 MMBoe.

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Commodity Prices

In the third quarter of 2012, the WTI spot price averaged $92 per barrel, compared with approximately $89 per barrel in the third quarter of 2011.  In the first nine months of 2012, the WTI spot price averaged $96 per barrel, compared with $95 per barrel a year earlier.  The average WTI spot price in October 2012 was approximately $89 per barrel.  In 2011, the WTI spot price averaged approximately $95 per barrel.

In the third quarter of 2012, the Henry Hub natural gas spot price averaged $2.88 per MMBtu compared with approximately $4.06 per MMBtu in the third quarter of 2011.  In the first nine months of 2012, the Henry Hub natural gas price averaged $2.54 per MMBtu, compared with $4.21 per MMBtu a year earlier. The Henry Hub natural gas spot price in October 2012 averaged approximately $3.32 per MMBtu.  In 2011, the Henry Hub natural gas spot price averaged $4.00 per MMBtu and ranged from a low of $2.84 per MMBtu to a high of $4.92 per MMBtu.

Natural gas prices have declined substantially in the last year. We have hedged more than two-thirds of our expected 2012 natural gas production at an average price of $7.16 per MMBtu. See Note 3 to the consolidated financial statements for a summary of our natural gas derivative contracts through 2016. Sustained low prices for natural gas may reduce the amounts that we would otherwise have available to pay expenses, make distributions to our unitholders and service our indebtedness.

BreitBurn Management

BreitBurn Management Company, LLC ("BreitBurn Management"), our wholly-owned subsidiary, operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering.  All of our employees, including our executives, are employees of BreitBurn Management.

BreitBurn Management also manages the operations of Pacific Coast Energy Company L.P. ("PCEC"), our predecessor, and provides administrative services to PCEC under an administrative services agreement. These services include operational functions such as exploitation and technical services, petroleum and reserves engineering and executive management, and administrative services such as accounting, information technology, audit, human resources, land, business development, finance and legal. These services are provided in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses, including incentive compensation plan costs and direct payroll and administrative costs related to PCEC's properties and operations. 

On May 8, 2012, Pacific Coast Oil Trust (the "Trust"), which was formed by PCEC, 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, which was expected to result in an increase in PCEC's ownership interests in the properties during the second quarter of 2012. 

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.

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Results of Operations

The table below summarizes certain of our results of operations for the periods indicated.  The data for the periods reflect our results as they are presented in the consolidated financial statements in this report.

Thousands of dollars, except as	Three Months Ended September 30,					Increase/					Nine Months Ended September 30,					Increase/
indicated	2012			2011		Decrease			%		2012			2011		Decrease			%
Total production (MBoe)	2,166			1,681		485			29	%	6,106			4,972		1,134			23	%
Oil and NGLs (MBoe)	973			829		144			17	%	2,647			2,384		263			11	%
Natural gas (MMcf)	7,161			5,114		2,047			40	%	20,754			15,529		5,225			34	%
Average daily production (Boe/d)	23,545			18,273		5,272			29	%	22,284			18,212		4,072			22	%
Sales volumes (MBoe)	2,219			1,723		496			29	%	6,131			5,026		1,105			22	%
Average realized sales price (per Boe) (a) (b)	$	60.40		$	61.08	$	(0.68	)	(1	)%	$	59.58		$	59.09	$	0.49		1	%
Oil and NGLs (per Boe) (a) (b)	89.55			81.50		8.05			10	%	90.61			78.28		12.33			16	%
Natural gas (per Mcf) (a)	5.89			6.72		(0.83		)	(12	)%	5.94			6.83		(0.89		)	(13	)%
Oil, natural gas and NGLs sales	$	111,700		$	97,356	$	14,344		15	%	$	300,688		$	284,673	$	16,015		6	%
Realized gain (loss) on commodity derivative instruments	22,496			8,092		14,404			178	%	65,150			12,784		52,366			n/a
Unrealized gain (loss) on commodity derivative instruments	(91,914		)	170,734		(262,648		)	(154	)%	(63,285		)	106,348		(169,633		)	(160	)%
Other revenues, net	796			1,375		(579		)	(42	)%	2,848			3,416		(568		)	(17	)%
Total revenues	43,078			277,557		(234,479		)	(84	)%	305,401			407,221		(101,820		)	(25	)%
Lease operating expenses before taxes (c)	40,325			37,835		2,490			7	%	117,520			98,348		19,172			19	%
Production and property taxes (d)	8,574			6,689		1,885			28	%	22,672			18,653		4,019			22	%
Total lease operating expenses	48,899			44,524		4,375			10	%	140,192			117,001		23,191			20	%
Purchases and other operating costs	293			329		(36		)	(11	)%	1,310			751		559			74	%
Change in inventory	856			1,593		(737		)	(46	)%	701			1,713		(1,012		)	(59	)%
Total operating costs	$	50,048		$	46,446	$	3,602		8	%	$	142,203		$	119,465	$	22,738		19	%
Lease operating expenses before taxes per Boe	$	18.62		$	22.51	$	(3.89	)	(17	)%	$	19.25		$	19.78	$	(0.53	)	(3	)%
Production and property taxes per Boe	3.96			3.98		(0.02		)	(1	)%	3.71			3.75		(0.04		)	(1	)%
Total lease operating expenses per Boe	22.58			26.49		(3.91		)	(12	)%	22.96			23.53		(0.57		)	1	%
Depletion, depreciation and amortization ("DD&A")	$	37,270		$	26,688	$	10,582		40	%	$	109,068		$	76,354	$	32,714		43	%
DD&A per Boe	17.21			15.88		1.33			8	%	17.86			15.36		2.50			16	%
(a) Includes realized gain (loss) on commodity derivative instruments.
(b) Includes crude oil purchases.
(c) Includes lease operating expenses, district expenses, transportation expenses and processing fees.
(d) Includes ad valorem and severance taxes.

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Comparison of Results for the Three Months and Nine Months Ended September 30, 2012 and 2011

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

Production

For the three months ended September 30, 2012, production was 2,166 MBoe compared to 1,681 MBoe for the same period a year ago, primarily due to 376 MBoe from our southwestern Wyoming properties acquired in October 2011, 149 MBoe from our Texas properties acquired in July 2012, 45 MBoe from our northern Wyoming properties acquired in June 2012, and a 24 MBoe increase reflecting a full quarter of production from our eastern Wyoming properties acquired in July 2011, partially offset by 94 MBoe lower Michigan production primarily related to lower natural gas production due to natural field declines. California production was in-line with the prior year primarily due to a 27 MBoe decrease in production at the East Coyote and Sawtelle Fields principally as a result of a reduction in our working interests from 95% to 62% attributable to a payout reversion that was effective April 1, 2012, offset by an increase in Santa Fe Springs production.

For the nine months ended September 30, 2012, production was 6,106 MBoe compared to 4,972 MBoe for the same period a year ago, primarily due to 1,104 MBoe from our southwestern Wyoming properties acquired in October 2011, 149 MBoe from our Texas properties acquired in July 2012, a 149 MBoe increase reflecting a full nine months of production from our eastern Wyoming properties acquired in July 2011, 46 MBoe from our northern Wyoming properties acquired in June 2012 and 39 MBoe higher Florida oil production primarily from our West Felda field, partially offset by 302 MBoe lower Michigan production and 31 MBoe lower production from our legacy Wyoming properties due to natural field declines.

Revenues

Total oil, natural gas liquids ("NGLs") and natural gas sales revenues increased$14.3 million for the three months ended September 30, 2012 compared to the three months ended September 30, 2011. Crude oil and NGLs revenues increased $14.0 million due to 156 MBoe higher crude oil and NGLs sales volumes, primarily due to higher oil production from our Wyoming and Texas properties acquired in 2011 and 2012 and slightly higher oil prices, partially offset by $3.1 million lower East Coyote and Sawtelle Fields revenue primarily due to a decrease in our working interests from 95% to 62% attributable to a payout reversion that was effective April 1, 2012. Natural gas revenue increased $0.3 million primarily due to 40% higher sales volumes driven by production from our southwestern Wyoming and Texas properties, partially offset by lower natural gas prices.

Realized gains from commodity derivative instruments during the three months ended September 30, 2012 were $22.5 million compared to realized gains of $8.1 million during the three months ended September 30, 2011, which primarily reflects lower natural gas prices and higher average crude oil hedge prices during the three months ended September 30, 2012 compared to the three months ended September 30, 2011.   

Unrealized losses on commodity derivative instruments during the three months ended September 30, 2012 were $91.9 million compared to unrealized gains of $170.7 million during the three months ended September 30, 2011.  Crude oil unrealized losses of $55.2 million during the three months ended September 30, 2012 were primarily due to an increase in crude oil futures prices and the effect those prices had on the valuation of our derivative contracts, compared to unrealized gains of $161.2 million during the three months ended September 30, 2011 primarily due to a decrease in crude oil futures prices during the period. Natural gas unrealized losses of $36.7 million and unrealized gains of $9.5 million during the three months ended September 30, 2012 and September 30, 2011, respectively, were primarily due to an increase in natural gas futures prices during the three months ended September 30, 2012 compared to a decrease during the three months ended September 30, 2011.

Realized prices for crude oil and NGLs, including realized gains and losses on crude oil derivative instruments, increased $8.05 per Boe, or 10%, in the three months ended September 30, 2012 compared to the three months ended September 30, 2011. Realized prices for natural gas, including realized gains and losses on natural gas derivative instruments, decreased $0.83 per Mcf, or 12%, in the three months ended September 30, 2012 compared to the three months ended September 30, 2011.

Total oil, NGLs and natural gas sales revenues increased $16.0 million for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. Crude oil and NGLs revenues increased $26.7 million due to higher sales volumes, primarily due to oil production from our Wyoming and Texas properties acquired in 2011 and 2012 and

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slightly higher crude oil prices, partially offset by $6.3 million lower East Coyote and Sawtelle Fields revenue primarily due to a decrease in our working interests from 95% to 62% attributable to a payout reversion that was effective April 1, 2012. Natural gas revenues decreased $10.7 million primarily due to lower natural gas prices partially offset by 34% higher sales volumes primarily due to production from our southwestern Wyoming and Texas properties.

Realized gains from commodity derivative instruments during the nine months ended September 30, 2012 were $65.2 million compared to realized gains of $12.8 million during the nine months ended September 30, 2011, which primarily reflects lower natural gas prices and higher average crude oil hedge prices during the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.   

Unrealized losses on commodity derivative instruments during the nine months ended September 30, 2012 were $63.3 million compared to unrealized gains of $106.3 million during the nine months ended September 30, 2011.  Crude oil unrealized losses of $7.1 million during the nine months ended September 30, 2012 were primarily due to an increase in crude oil futures prices and the effect those prices had on the valuation of our derivative contracts, compared to unrealized gains of $117.2 million during the nine months ended September 30, 2011 primarily due to a decrease in crude oil futures prices during the period. Natural gas unrealized losses were $56.2 million during the nine months ended September 30, 2012 primarily due to an increase in natural gas futures prices during the period. Natural gas unrealized losses were $10.9 million during the nine months ended September 30, 2011 primarily due to contracts that settled during the period, partially offset by unrealized gains due to a decrease in natural gas futures prices during the period.

Realized prices for crude oil and NGLs, including realized gains and losses on crude oil derivative instruments, increased $12.33 per Boe, or 16%, in the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. Realized prices for natural gas, including realized gains and losses on natural gas derivative instruments, decreased $0.89 per Mcf, or 13%, in the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.

Lease operating expenses

Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the three months ended September 30, 2012 increased $2.5 million compared to the three months ended September 30, 2011.  The increase in pre-tax lease operating expenses reflects a $5.1 million increase in lease operating expenses for our newly acquired properties in Wyoming and Texas, partially offset by lower Michigan maintenance costs and lower California expenses primarily due to lower routine lease operating expenses at East Coyote and Sawtelle Fields as a result of a 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, pre-tax lease operating expenses were $18.62 per Boe for the three months ended September 30, 2012 compared to $22.51 per Boe for the three months ended September 30, 2011.

Production and property taxes for the three months ended September 30, 2012 totaled $8.6 million, which was $1.9 million higher than the three months ended September 30, 2011, primarily due to higher crude oil and natural gas production chiefly attributable to the activity from our new properties in Wyoming and Texas and slightly higher oil prices, partially offset by lower natural gas prices.  On a per Boe basis, production and property taxes for the three months ended September 30, 2012 were $3.96 per Boe, which was 1% lower than the three months ended September 30, 2011.

Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the nine months ended September 30, 2012 increased $19.2 million compared to the nine months ended September 30, 2011.  The increase in pre-tax lease operating expenses reflects our newly acquired Wyoming and Texas properties, higher California well service costs and higher Florida fuel and utilities costs. The increase in California well services was partially offset by lower routine lease operating expenses at the East Coyote and Sawtelle Fields as a result of a 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, pre-tax lease operating expenses were $19.25 per Boe for the nine months ended September 30, 2012 compared to $19.78 per Boe for the nine months ended September 30, 2011.

Production and property taxes for the nine months ended September 30, 2012 totaled $22.7 million, which was $4.0 million higher than the nine months ended September 30, 2011, primarily due to higher crude oil and natural gas production relating to our acquired properties in Wyoming and Texas, partially offset by lower natural gas prices during the nine months ended September 30, 2012.  On a per Boe basis, production and property taxes for the nine months ended September 30, 2012 were $3.71 per Boe, which was 1% lower than the nine months ended September 30, 2011.

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Change in inventory

In Florida, our crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter.  Sales occur on average every six to eight weeks.  We match production expenses with crude oil sales.  Production expenses associated with unsold crude oil inventory are credited to operating costs through the change in inventory account.  Production expenses are charged to operating costs through the change in inventory account when they are sold.  

For the three months ended September 30, 2012 and 2011, the change in inventory account amounted to charges of $0.9 million and $1.6 million, respectively.  The charges to the change in inventory account during the three months ended September 30, 2012 and September 30, 2011 reflect the higher amount of barrels sold than produced during the periods due to the timing of Florida sales. The decrease in the change in inventory account charge year over year is primarily due to an increase in change in inventory account costs during the third quarter of 2012.

For the nine months ended September 30, 2012 and 2011, the change in inventory account amounted to charges of $0.7 million and $1.7 million, respectively.  The charges to the change in inventory account during the nine months ended September 30, 2012 and September 30, 2011 reflect the higher amount of barrels sold than produced during the periods. The decrease in the change in inventory account charge year over year is primarily due to a higher volume going into inventory for the nine months ended September 30, 2012 and an increase in inventory costs during the third quarter of 2012.

Depletion, depreciation and amortization

Depletion, depreciation and amortization ("DD&A") expense totaled $37.3 million during the three months ended September 30, 2012, an increase of approximately 40% from the same period a year ago.  The increase in DD&A expense compared to last year was primarily due to higher crude oil and natural gas production from 2011 and 2012 acquisitions. On a per Boe basis, DD&A expense was $17.21, an 8% increase from the same period a year ago.

DD&A expense totaled $109.1 million ($17.86 per Boe) during the nine months ended September 30, 2012, an increase of approximately 43% from the same period a year ago.  The increase in DD&A expense compared to last year was primarily due to higher crude oil and natural gas production from 2011 and 2012 acquisitions, as well as $12.2 million in impairments and write-offs recognized during the first nine months of 2012, primarily related to uneconomic proved properties primarily in Michigan, Indiana and Kentucky due to lower natural gas prices and $2.3 million related to a field in California due to lower crude oil prices. On a per Boe basis, excluding impairments and write-offs, DD&A expense was $15.87, a 3% increase from the same period a year ago.

General and administrative expenses

Our general and administrative ("G&A") expenses totaled $13.7 million and $14.0 million for the three months ended September 30, 2012 and 2011, respectively.  This included $5.7 million and $5.4 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans.  G&A expenses, excluding non-cash unit-based compensation, were $8.0 million and $8.6 million for the three months ended September 30, 2012 and 2011, respectively.  The decrease was primarily due to higher acquisition costs in the third quarter of 2011, including legal and other professional fees, and higher management fee recovery in the third quarter of 2012. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $3.73 and $5.09 for the three months ended September 30, 2012 and 2011, respectively.

Our G&A expenses totaled $40.3 million and $38.1 million for the nine months ended September 30, 2012 and 2011, respectively.  This included $16.9 million and $16.3 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans.  G&A expenses, excluding non-cash unit-based compensation, were $23.4 million and $21.8 million for the nine months ended September 30, 2012 and 2011, respectively.  The increase was primarily due to additional costs attributable to our 2011 and 2012 acquisitions partially offset by higher 2012 management fee recoveries. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $3.84 and $4.39 for the nine months ended September 30, 2012 and 2011, respectively.

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Interest expense, net of amounts capitalized

Our interest expense totaled $15.4 million and $9.3 million for the three months ended September 30, 2012 and 2011, respectively.  The increase in interest expense was primarily due to $4.9 million of interest related to the Initial Notes issued in January 2012 and higher average 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 Note 3 to the consolidated financial statements in this report for a discussion of our interest rate derivative contracts.  We had realized losses of $0.8 million and $1.1 million for the three months ended September 30, 2012 and 2011, respectively, relating to our interest rate derivative contracts.  We had unrealized gains of $0.6 million and unrealized losses of $0.1 million for the three months ended September 30, 2012 and 2011, respectively, relating to our interest rate derivative contracts.

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 $15.1 million and $9.3 million for the three months ended September 30, 2012 and 2011, respectively. 

Our interest expense totaled $43.2 million and $27.8 million for the nine months ended September 30, 2012 and 2011, respectively.  The increase in interest expense was primarily due to $14.1 million of interest related to the Initial Notes issued in January 2012 and higher average credit facility debt balance. We had realized losses of $2.3 million and $3.2 million for the nine months ended September 30, 2012 and 2011, respectively, relating to our interest rate derivative contracts.  We had unrealized gains of $1.3 million and $0.1 million for the nine months ended September 30, 2012 and 2011, respectively, relating to our interest rate derivative contracts.

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 $41.9 million and $27.3 million for the nine months ended September 30, 2012 and 2011, respectively.

Credit and Counterparty Risk

Our derivative financial instruments are exposed to credit risk from counterparties.  See Note 3 to the consolidated financial statements in this report for a discussion of our derivative contracts and counterparties.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations and amounts available under our bank credit facility.  Our primary uses of cash have been for our operating expenses, capital expenditures and cash distributions to unitholders.  To fund certain acquisition transactions, we have historically used borrowings under our bank credit facility, accessed the private placement markets and issued equity as partial consideration for the acquisition of oil and gas properties.  As market conditions have permitted, we have also engaged in asset sale transactions and equity and debt offerings.  In the future, we intend to access the public and private capital markets to fund certain acquisitions and refinancing transactions.

On June 28, 2012, we completed an acquisition from NiMin of oil properties located in Park County in the Big Horn Basin of Wyoming with an effective date of April 1, 2012 for approximately $95 million. We used borrowings under our credit facility to fund the acquisition.

On July 2, 2012, we completed the Element and CrownRock acquisitions to acquire oil and natural gas properties located in the Permian Basin in Texas with an effective date of March 1, 2012 for approximately $148 million and $70 million, respectively, subject to customary post-closing adjustments.

In 2012, our crude oil and natural gas capital spending program, including projects for our properties acquired in 2012, is expected to be approximately $151.6 million, which is an increase of approximately $83.6 million from the program discussed in our Annual Report. This compares with approximately $75 million in 2011. The additions to our 2012 capital spending program are primarily to develop our recently acquired properties in the Permian Basin in Texas and the Big Horn Basin in Wyoming and to pursue attractive project opportunities in our legacy properties.

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Equity Offering

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

In September 2012, we sold approximately 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 bank credit facility.

Distributions

On February 14, 2012, we paid a cash distribution of approximately $27.0 million for the fourth quarter of 2011 to our common unitholders of record as of the close of business on February 6, 2012 at the rate of $0.4500 per Common Unit. On May 14, 2012, we paid a cash distribution for the first quarter of 2012 of approximately $31.5 million to our common unitholders of record as of the close of business on May 7, 2012 at the rate of $0.4550 per Common Unit. On August 14, 2012, we paid a cash distribution for the second quarter of 2012 of approximately $31.8 million to our common unitholders of record as of the close of business on August 10, 2012 at the rate of $0.4600 per Common Unit. On October 31, 2012, we announced a cash distribution to unitholders for the third quarter of 2012 at the rate of $0.4650 per Common Unit, to be paid on November 14, 2012 to our common unitholders of record as of the close of business on November 9, 2012.

Cash Flows

Operating activities.  Our cash flow from operating activities for the nine months ended September 30, 2012 was $166.3 million, compared to $128.8 million for the nine months ended September 30, 2011. The increase in cash flow from operating activities was primarily due to higher realized gains on commodity derivative instruments, the effect of our 2011 and 2012 acquisitions on operating income and collection of a $10 million settlement receivable from our insurance companies, partially offset by $13.3 million in premiums paid for natural gas swaps and put options during the nine months ended September 30, 2012.

Investing activities.  Net cash used in investing activities during the nine months ended September 30, 2012 and September 30, 2011 was $390.2 million and $131.8 million, respectively. During the nine months ended September 30, 2012 and 2011, we spent $78 million and $61 million, respectively, on capital expenditures, primarily for drilling and completion activities.  During the nine months ended September 30, 2012, we paid $95 million, $148 million and $70 million for the NiMin, Element and CrownRock acquisitions, respectively.

Financing activities.  Net cash provided by financing activities for the nine months ended September 30, 2012 and September 30, 2011 was $223.0 million and $4.1 million, respectively.  During the nine months ended September 30, 2012, we reduced our outstanding borrowings under our bank credit facility by approximately $497 million, primarily using net proceeds from the issuances of the 2022 Senior Notes in January and September 2012 and the offerings of Common Units in February and September 2012. We had total outstanding borrowings, net of unamortized discount on our senior notes, of $779 million at September 30, 2012 and $821 million at December 31, 2011.  For the nine months ended September 30, 2012, we received $371 million from the issuance of Common Units, made cash distributions of $94 million, borrowed $1,067 million and repaid $1,109 million under our bank credit facility.  For the nine months ended September 30, 2011, we received $100 million from the issuance of Common Units, made cash distributions of $76 million, borrowed $284 million and repaid $301 million under our bank credit facility.  

Senior Notes

In October 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 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 reduce borrowings under our bank credit facility.

In January 2012, we issued the Initial Notes, $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 bank credit facility.

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In September 2012, we issued an additional $200 million aggregate principal amount of our 7.875% Senior Notes due 2022. The Additional Notes were offered as an addition to our existing senior notes due 2022 at a price 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 bank credit facility.

In connection with the exchange offer relating to the 2022 Senior Notes, in October 2012, the Issuers filed a registration statement on Form S-4 with the SEC with respect to an offer to exchange the 2022 Senior Notes for substantially identical notes that are registered under the Securities Act. We have not commenced the exchange offer yet.

Interest on our senior notes is payable twice a year in April and October.

Credit Agreement

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 $850.0 million.

In January 2012, in connection with the issuance of the Initial Notes, our borrowing base was automatically reduced to $787.5 million in accordance with the terms of our credit facility. In connection with our semi-annual borrowing base redetermination in April 2012, our borrowing base was increased to $850.0 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 September 2012, in connection with the issuance of the Additional Notes, our borrowing base was automatically reduced to $800 million in accordance with the terms of our bank credit facility.

As of September 30, 2012, we had $23.0 million in indebtedness outstanding under the Second Amended and Restated Credit Agreement and a borrowing base of $800 million.

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 provides us with the ability to increase our total commitments up to the $1 billion borrowing base upon lender approval. As of November 6, 2012, we had $45.0 million in indebtedness outstanding under the Second Amended and Restated Credit Agreement.

As of November 6, 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 8.0% 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 a 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 12-month basis, of no more than 4.00 to 1.00 and a current ratio as of the last day of each quarter of not less than 1.00 to 1.00. As of September 30, 2012, we were in compliance with these covenants.

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EBITDAX is not a defined GAAP measure. The Second Amended and Restated Credit Agreement defines EBITDAX as consolidated net income plus exploration expense, interest expense, income tax provision, depletion, depreciation and amortization, unrealized loss or gain on derivative instruments, non-cash charges, including non-cash unit-based compensation expense, loss or gain on sale of assets (excluding gain or loss on monetization of derivative instruments 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.

Contractual Obligations

Except for the issuance of the 2022 Senior Notes, the pay down of debt under our credit facility and the Fifth and Sixth Amendments to the Second Amended and Restated Credit Agreement, we had no material changes to our financial contractual obligations during the nine months ended September 30, 2012.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of September 30, 2012 and December 31, 2011.  

New Accounting Standards

See Note 2 to the consolidated financial statements in this report for a discussion of new accounting standards applicable to us.

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Part II—Item 7A in our Annual Report.  Also, see Note 3 to the consolidated financial statements in this report for additional discussion related to our financial instruments, including a summary of our derivative contracts as of September 30, 2012.

Changes in Fair Value

The fair value of our outstanding oil and gas commodity derivative instruments was a net asset of approximately $81.2 million and $131.2 million at September 30, 2012 and December 31, 2011, respectively.  With a $10.00 per barrel increase in the price of oil, and a corresponding $1.00 per Mcf increase in the price of natural gas, our net commodity derivative instrument asset at September 30, 2012 would have decreased by approximately $169 million. With a $10.00 per barrel decrease in the price of oil, and a corresponding $1.00 per Mcf decrease in the price of natural gas, our net commodity derivative instrument asset at September 30, 2012 would have increased by approximately $172 million.

Price risk sensitivities were calculated by assuming across-the-board increases in price of $10.00 per barrel for oil and $1.00 per Mcf for natural gas regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price.  In the event of actual changes in prompt month prices equal to the assumptions, the fair value of our derivative portfolio would typically change by less than the amounts given due to decreasing volatility for longer dated contracts.

The fair value of our outstanding interest rate derivative instruments was a net liability of approximately $3.0 million and $4.4 million at September 30, 2012 and December 31, 2011, respectively.  With a 1% increase in the LIBOR rate, our net interest rate derivative instrument liability at September 30, 2012 would have decreased by approximately $2 million. With a 1% decrease in the LIBOR rate to a minimum rate of zero, our net liability at September 30, 2012 would have increased by less than $1 million.

Item 4.  Controls and Procedures

Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), we have evaluated, under the supervision and with the participation of our management, including our General Partner's principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our General Partner's principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based upon the evaluation, our General Partner's principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2012 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2012 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

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

Item 1A.  Risk Factors

There have been no material changes to the Risk Factors disclosed in Part I—Item 1A "—Risk Factors" of our Annual Report.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

There were no sales of unregistered equity securities during the period covered by this report.

Item 3.  Defaults Upon Senior Securities

None.

Item 4.  Mine Safety Disclosures

Not applicable.

Item 5.  Other Information

None.

Item 6.  Exhibits

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

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NUMBER	DOCUMENT
4.2	Indenture, dated as of January 13, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and U.S. National Bank Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 13, 2012).
4.3	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 (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).
4.4	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	Sixth Amendment to the Second Amended and Restated Credit Agreement, dated 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).
31.1*	Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
101††	Interactive Data Files.

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		BREITBURN ENERGY PARTNERS L.P.
		By:	BREITBURN GP, LLC,
			its General Partner
Dated:	November 6, 2012	By:	/s/ Halbert S. Washburn
			Halbert S. Washburn
			Chief Executive Officer
Dated:	November 6, 2012	By:	/s/ James G. Jackson
			James G. Jackson
			Chief Financial Officer

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INDEX TO EXHIBITS

NUMBER	DOCUMENT
3.1	First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2006).
3.2	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
3.3	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2009).
3.4	Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 1, 2009).
3.5	Amendment No.4 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. dated as of April 5, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
3.6	Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC 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, 2010).
3.7	Amendment No. 1 to the Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC dated as of December 30, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
4.1	Indenture, dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and U.S. National Bank Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010).
4.2	Indenture, dated as of January 13, 2012, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors named therein and U.S. National Bank Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 13, 2012).
4.3	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 (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).
4.4	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	Sixth Amendment to the Second Amended and Restated Credit Agreement, dated 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).
31.1*	Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
101††	Interactive Data Files.

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

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