Breitburn Energy Partners LP - FORM 10-Q

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EX-10.2 - EXHIBIT - Breitburn Energy Partners LP	q3201410-qex102.htm
EX-10.1 - EXHIBIT - Breitburn Energy Partners LP	q3201410-qex101.htm
EX-10.3 - EXHIBIT - Breitburn Energy Partners LP	q3201410-qex103.htm
EXCEL - IDEA: XBRL DOCUMENT - Breitburn Energy Partners LP	Financial_Report.xls
EX-31.2 - EXHIBIT - Breitburn Energy Partners LP	q3201410-qex312.htm
EX-31.1 - EXHIBIT - Breitburn Energy Partners LP	q3201410-qex311.htm
EX-32.2 - EXHIBIT - Breitburn Energy Partners LP	q3201410-qex322.htm
EX-32.1 - EXHIBIT - Breitburn Energy Partners LP	q3201410-qex321.htm

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, 2014



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 LP

(Exact name of registrant as specified in its charter)



Delaware	74-3169953
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification Number)

515 South Flower Street, Suite 4800
Los Angeles, California	90071
(Address of principal executive offices)	(Zip Code)

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

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

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

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



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

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

Yes o No x

As of November 4, 2014, the registrant had 138,773,366 Common Units outstanding.

INDEX



		Page No.
	Cautionary Statement Regarding Forward-Looking Information	1

	PART I
	FINANCIAL INFORMATION

Item 1.	Financial Statements
	– Consolidated Balance Sheets at September 30, 2014 and December 31, 2013	2
	– Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2014 and 2013	3
	– Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2014 and 2013	4
	– Notes to Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4.	Controls and Procedures	34

	PART II
	OTHER INFORMATION

Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3.	Defaults Upon Senior Securities	35
Item 4.	Mine Safety Disclosures	35
Item 5.	Other Information	35
Item 6.	Exhibits	36

Signatures		37
Exhibit Index		38

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Forward-looking statements are included in this report and may be included in other public filings, press releases, our website and oral and written presentations by management. Statements other than historical facts are forward-looking and may be identified by words such as “believe,” “estimate,” “impact,” “intend,” “future,” “affect,” “expect,” “will,” “projected,” “plan,” “anticipate,” “should,” “could,” “would,” 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 is the ability to obtain unitholder approval of the proposed merger with QR Energy, LP (“QR Energy”); the ability to complete the proposed merger with QR Energy on anticipated terms and timetable; our ability to successfully integrate the business and operations of QR Energy with our own after the transaction and achieve anticipated benefits from the proposed merger; the possibility that various closing conditions for the merger may not be satisfied or waived; risks relating to any unforeseen liabilities of QR Energy; changes in crude oil, natural gas liquids (“NGL”) and natural gas prices; delays in planned or expected drilling; changes in costs and availability of drilling, completion and production equipment and related services and labor; the ability to obtain sufficient quantities of carbon dioxide (“CO₂”) necessary to carry out enhanced oil recovery projects; the discovery of previously unknown environmental issues; federal, state and local initiatives and efforts relating to the regulation of hydraulic fracturing; 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; the level of success in exploitation, development and production activities; the timing of exploitation and development expenditures; inaccuracies of reserve estimates or assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; impacts to financial statements as a result of impairment write-downs; risks related to level of indebtedness and periodic redeterminations of the borrowing base under our credit agreement; ability to generate sufficient cash flows from operations to meet the internally funded portion of any capital expenditures budget; ability to obtain external capital to finance exploitation and development operations and acquisitions; the impacts of hedging on results of operations; failure of properties to yield oil or natural gas in commercially viable quantities; uninsured or underinsured losses resulting from oil and natural gas operations; inability to access oil and natural gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing oil and natural gas operations; changes in governmental regulations, including the regulation of derivative instruments and the oil and natural gas industry; ability to replace oil and natural gas reserves; any loss of senior management or technical personnel; competition in the oil and natural gas industry; risks arising out of hedging transactions; the effects of changes in accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; 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, 2013 (our “2013 Annual Report”), in Part II—Item 1A of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2014 and June 30, 2014 and in Part II—Item 1A of this report. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

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

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Breitburn Energy Partners LP and Subsidiaries

Consolidated Balance Sheets

(Unaudited)



Thousands of dollars	September 30, 2014			December 31, 2013
ASSETS
Current assets
Cash	$	3,227		$	2,458
Accounts and other receivables, net	98,360			96,862
Derivative instruments (note 3)	44,256			7,914
Related party receivables (note 4)	1,509			2,604
Inventory (note 5)	4,418			3,890
Prepaid expenses	3,831			3,334
Total current assets	155,601			117,062
Equity investments	6,551			6,641
Property, plant and equipment
Oil and natural gas properties	5,102,392			4,818,639
Non-oil and natural gas assets	36,138			21,338
	5,138,530			4,839,977
Accumulated depletion and depreciation (note 6)	(1,148,185		)	(924,601		)
Net property, plant and equipment	3,990,345			3,915,376
Other long-term assets
Intangibles (note 7)	9,286			11,679
Derivative instruments (note 3)	25,863			71,319
Other long-term assets (note 7)	76,008			74,205
Total assets	$	4,263,654		$	4,196,282
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	64,199		$	69,809
Derivative instruments (note 3)	7			24,876
Distributions payable	733			—
Revenue and royalties payable	32,401			26,233
Wages and salaries payable	12,173			15,359
Accrued interest payable	42,856			19,690
Accrued liabilities	32,604			26,922
Total current liabilities	184,973			182,889
Credit facility (note 8)	719,000			733,000
Senior notes, net (note 8)	1,156,589			1,156,675
Deferred income taxes (note 10)	2,902			2,749
Asset retirement obligation (note 11)	133,216			123,769
Derivative instruments (note 3)	5,145			2,560
Other long-term liabilities	5,530			4,820
Total liabilities	2,207,355			2,206,462
Commitments and contingencies (note 12)
Equity
Series A cumulative redeemable preferred units, 8.0 million units issued and outstanding at September 30, 2014 and 0 at December 31, 2013 (note 13)	193,215			—
Common units, 120.5 million units issued and outstanding at September 30, 2014 and 119.2 million at December 31, 2013 (note 13)	1,863,084			1,989,820
Total equity	2,056,299			1,989,820

Total liabilities and equity	$	4,263,654		$	4,196,282

See accompanying notes to consolidated financial statements.

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Operations

(Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands of dollars, except per unit amounts	2014			2013			2014			2013
Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	216,146		$	197,413		$	658,753		$	467,061
Gain (loss) on commodity derivative instruments, net (note 3)	146,171			(54,765		)	(21,057		)	(11,948		)
Other revenue, net	1,585			737			4,240			2,197
Total revenues and other income items	363,902			143,385			641,936			457,310
Operating costs and expenses
Operating costs	82,904			68,502			248,161			181,889
Depletion, depreciation and amortization	72,671			59,764			204,417			154,095
Impairments (note 6)	29,434			361			29,434			361
General and administrative expenses	18,737			16,116			53,886			44,695
Loss (gain) on sale of assets	(63		)	77			357			139
Total operating costs and expenses	203,683			144,820			536,255			381,179

Operating income (loss)	160,219			(1,435		)	105,681			76,131

Interest expense, net of capitalized interest	29,494			23,548			90,360			60,387
Other expense (income), net	(450		)	4			(1,223		)	(5		)

Income (loss) before taxes	131,175			(24,987		)	16,544			15,749

Income tax expense (note 10)	532			24			384			628

Net income (loss)	130,643			(25,011		)	16,160			15,121

Less: distributions to preferred unitholders	4,125			—			5,958			—

Net income (loss) attributable to common unitholders	$	126,518		$	(25,011	)	$	10,202		$	15,121

Basic net income (loss) per unit (note 13)	$	1.03		$	(0.25	)	$	0.08		$	0.15
Diluted net income (loss) per unit (note 13)	$	1.03		$	(0.25	)	$	0.08		$	0.15

See accompanying notes to consolidated financial statements.

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)



	Nine Months Ended
	September 30,
Thousands of dollars	2014			2013
Cash flows from operating activities
Net income	$	16,160		$	15,121
Adjustments to reconcile to cash flows from operating activities:
Depletion, depreciation and amortization	204,417			154,095
Impairments	29,434			361
Unit-based compensation expense	18,440			14,700
Loss on derivative instruments	21,057			11,948
Derivative instrument settlement receipts (payments)	(34,228		)	3,633
Income from equity affiliates, net	90			(122		)
Deferred income taxes	153			252
Loss on sale of assets	357			139
Other	5,172			3,989
Changes in net assets and liabilities
Accounts receivable and other assets	(3,345		)	(62,882		)
Inventory	(528		)	(8,032		)
Net change in related party receivables and payables	1,095			883
Accounts payable and other liabilities	36,642			32,857
Net cash provided by operating activities	294,916			166,942
Cash flows from investing activities
Property acquisitions	(6,422		)	(861,601		)
Capital expenditures	(293,275		)	(191,472		)
Proceeds from sale of assets	366			226
Other	(9,242		)	—
Net cash used in investing activities	(308,573		)	(1,052,847		)
Cash flows from financing activities
Proceeds from issuance of preferred units, net	193,215			—
Proceeds from issuance of common units, net	25,917			285,011
Distributions to preferred unitholders	(5,225		)	—
Distributions to common unitholders	(181,430		)	(137,447		)
Proceeds from long-term debt	693,000			1,381,000
Repayments of long-term debt	(707,000		)	(636,000		)
Change in bank overdraft	(2,417		)	(316		)
Debt issuance costs	(1,634		)	(8,032		)
Net cash provided by financing activities	14,426			884,216
Increase (decrease) in cash	769			(1,689		)
Cash beginning of period	2,458			4,507
Cash end of period	$	3,227		$	2,818

See accompanying notes to consolidated financial statements.

Notes to Consolidated Financial Statements

1. Organization and Basis of Presentation

The accompanying unaudited consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our 2013 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, 2014, our operating results for the three months and nine months ended September 30, 2014 and 2013 and our cash flows for the nine months ended September 30, 2014 and 2013 have been included. Operating results for the three months and nine months ended September 30, 2014 are not necessarily indicative of the results that may be expected for the year ended December 31, 2014. The consolidated balance sheet at December 31, 2013 has been derived from the audited consolidated financial statements at that date but does not include all of the information and notes required by GAAP for complete financial statements. For further information, refer to the consolidated financial statements and notes thereto included in our 2013 Annual Report.

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

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers. The ASU will supersede most of the existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The pronouncement is effective for annual and interim reporting periods beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted. We are evaluating the impact, if any, that ASU 2014-09 will have on our financial statements.

2. Acquisitions

We account for all business combinations using the acquisition method of accounting. The initial accounting applied to our acquisitions at the time of the purchase may not be complete and adjustment to provisional accounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date prior to concluding the final purchase price of an acquisition.

Our purchase price allocations are based on discounted cash flows, quoted market prices and estimates made by management, and the most significant assumptions are those related to the estimated fair values assigned to oil and natural gas properties with proved reserves. To estimate the fair values of acquired properties, estimates of oil and natural gas reserves are prepared by management in consultation with independent engineers. We apply estimated future prices to the estimated reserve quantities acquired and estimate future operating and development costs to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted average cost of capital. We also periodically employ third-party valuation firms to assist in the valuation of complex facilities, including pipelines, gathering lines and processing facilities.

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

The fair value measurements of oil and natural gas properties, other assets and asset retirement obligations (“ARO”) are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties, other assets and ARO were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and a market-based weighted average cost of capital rate. ARO assumptions include inputs such as expected economic recoveries of oil and natural gas and time to

abandonment. These inputs require significant judgments and estimates by management at the time of the valuation and are subject to change.

Pending Merger with QR Energy

On July 23, 2014, we, Breitburn GP LLC (our “General Partner”) and Boom Merger Sub, LLC, a direct wholly owned subsidiary of the Partnership (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) with QR Energy and QRE GP, LLC. Pursuant to the Merger Agreement, we will acquire QR Energy in exchange for common units representing limited partner interests in Breitburn Energy Partners LP (“Breitburn” or the “Partnership”) (“Common Units”), including the assumption of approximately $1.01 billion of QR Energy’s existing net debt and the payment of $350 million in cash to the holders of the outstanding Class C Convertible Preferred Units of QR Energy (each, a “Class C Unit”). The Merger Agreement provides that, upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will be merged with and into QR Energy, with QR Energy continuing as the surviving entity and a direct wholly owned subsidiary of the Partnership (the “Merger”).

Under the terms of the Merger Agreement, each outstanding common unit representing a limited partner interest in QR Energy (a “QR Energy Common Unit”) and each Class B Unit representing a limited partner interest in QR Energy (a “Class B Unit”) will be converted into the right to receive 0.9856 newly issued Common Units (the “Merger Consideration”). A number of Class B Units issuable upon a change of control of QR Energy equal to (i) 6,748,067, minus (ii) the excess of (A) the number of performance units that vest and are settled in QR Energy Common Units in connection with the Merger over (B) 383,900 will be issued and treated as outstanding Class B Units and converted into the right to receive the Merger Consideration. Each outstanding Class C Unit of QR Energy will be converted into the right to receive cash in an amount equal to $350 million divided by the number of Class C Units outstanding immediately prior to the effective time of the Merger. In no event will we be obligated to issue in excess of 72,001,686 Common Units as part of the Merger Consideration.

On July 23, 2014, we also entered into a Registration Rights Agreement (“Registration Rights Agreement”) with each of QR Energy Holdings (QRE), LLC, QR Energy Holdings, LLC, Quantum Resources B, LP, Quantum Resources A1, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC (the “QR Energy Unitholders”). Under the Registration Rights Agreement, we are required to file or cause to be filed with the Securities and Exchange Commission (the “SEC”) a registration statement with respect to the public resale of our Common Units issued to the QR Energy Unitholders as part of the Merger Consideration. We are required to file or cause to be filed the registration statement within 90 days following the closing under the Merger Agreement and are required to cause the registration statement to become effective as soon as reasonably practicable thereafter but in no event later than 120 days after the closing under the Merger Agreement.

The completion of the Merger is subject to satisfaction or waiver of customary closing conditions, including (1) the adoption of the Merger Agreement by holders of a majority of the outstanding QR Energy Common Units, Class B Units and Class C Units, voting as a single class, (2) the approval for listing of the Common Units issued as a part of the Merger Consideration on the NASDAQ Global Select Market (the “NASDAQ”), and (3) other customary conditions. On August 19, 2014, we received notification of early termination of the waiting period under the Hart-Scott-Rodino Act for the Merger.

A special meeting of QR Energy unitholders to vote on the adoption of the Merger Agreement is scheduled to be held on November 18, 2014. The Merger Agreement requires that the Merger close within three business days of the meeting of QR Energy unitholders.

Merger-related costs for the QR Energy Merger of $1.5 million for the three months and nine months ended September 30, 2014, were included in general and administrative (“G&A”) expenses on the consolidated statements of operations.

2013 Acquisitions

Oklahoma Panhandle Acquisitions

On July 15, 2013, we completed the acquisition of certain oil and natural gas and midstream assets located in Oklahoma, New Mexico and Texas, certain CO₂ supply contracts, certain crude oil swaps and interests in certain entities from Whiting Oil and Gas Corporation (“Whiting”) for approximately $845 million in cash (the “Whiting Acquisition”), including post-closing adjustments.

The purchase price for this acquisition was allocated to the assets acquired and liabilities assumed as follows:



Thousands of dollars
Oil and natural gas properties - proved	$	700,963
Oil and natural gas properties - unproved	43,492
Pipeline and processing facilities	74,537
Derivative assets - current	15
Intangibles	14,739
Derivative assets - long-term	16,183
Other long-term assets	10,936
Derivative liabilities - current	(6,347		)
Accrued liabilities	(1,115		)
Asset retirement obligations	(8,102		)
	$	845,301

Whiting novated to us derivative contracts, with a counterparty that is a participant in our current credit facility, consisting of NYMEX West Texas Intermediate (“WTI”) fixed price crude oil swaps covering a total of approximately 5.4 million barrels of future production in 2013 through 2016 at a weighted average hedge price of $95.44 per Bbl, which were valued as a net asset of $9.9 million at the acquisition date. The purchase price allocation also included finite-lived intangibles valued at $14.7 million relating to two CO₂ purchase contracts that we received in the acquisition. We amortize the CO₂ contracts based on the amount of CO₂ purchases made in each period over the contracts’ respective lives.

During the three months and nine months ended September 30, 2014, we recorded $1.0 million and $3.0 million, respectively, in amortization for these contracts. We were also novated a $10.9 million long-term advance relating to future CO₂ supply contract arrangements.

We also completed the acquisition of additional interests in certain of the acquired assets in the Oklahoma Panhandle from other sellers for an additional $30 million in July 2013, subject to customary post-closing adjustments (together with the Whiting Acquisition, the “Oklahoma Panhandle Acquisitions”). The additional interests were allocated $17.8 million to oil and natural gas properties and $12.4 million to pipeline facilities.

We used borrowings under our credit facility to fund the Oklahoma Panhandle Acquisitions.

Acquisition-related costs for the Oklahoma Panhandle Acquisitions of $3.3 million ($3.2 million recorded in 2013), were included in G&A expenses on the consolidated statements of operations. During the three months and nine months ended September 30, 2014, we recorded approximately $50.4 million and $159.9 million, respectively, in revenue and approximately $15.7 million and $48.2 million, respectively, in lease operating expenses, including production and property taxes, from our Oklahoma Panhandle Acquisitions.

Permian Basin Acquisitions

On December 30, 2013, we completed acquisitions of oil and natural gas properties located in the Permian Basin in Texas from CrownRock, L.P. for approximately $282 million in cash (the “CrownRock III Acquisition”). We also completed the acquisition of additional interests in certain of the acquired assets in the Permian Basin from other sellers for an additional $20 million in December 2013 (together with the CrownRock III Acquisition, the “Permian Basin Acquisitions”).

The purchase price for the Permian Basin Acquisitions was allocated to the assets acquired and liabilities assumed as follows:



Thousands of dollars
Oil and natural gas properties - proved	$	258,728
Oil and natural gas properties - unproved	44,451
Asset retirement obligation	(1,069		)
	$	302,110

During the three months and nine months ended September 30, 2014, we recorded acquisition-related costs for the Permian Basin Acquisitions of $0.1 million and $0.6 million, respectively, which were included in G&A expenses on the consolidated statements of operations. During the three months and nine months ended September 30, 2014, we recorded approximately $17.1 million and $48.6 million, respectively, in sales revenue and approximately $4.1 million and $11.0 million, respectively, in lease operating expenses, including production and property taxes, from the Permian Basin Acquisitions.

Pro Forma

The following unaudited pro forma financial information presents a summary of our combined statements of operations for the three months and nine months ended September 30, 2013, assuming the Oklahoma Panhandle Acquisitions and the Permian Basin Acquisitions had been completed on January 1, 2013. The pro forma results reflect the results of combining our statements of operations with the results of operations from all of our 2013 acquisitions, adjusted for (1) the assumption of ARO and accretion expense for the properties acquired, (2) depletion and depreciation expense applied to the adjusted purchase price of the properties acquired, (3) interest expense on additional borrowings necessary to finance the acquisitions, including the amortization of debt issuance costs, and (4) the effect on the denominator for calculating net income (loss) per unit of common unit issuances necessary to finance the acquisitions. The pro forma financial information is not necessarily indicative of the results of operations if these acquisitions had been effective January 1, 2013.



	2013 Pro Forma
	Three Months Ended			Nine Months Ended
Thousands of dollars, except per unit amounts	September 30, 2013			September 30, 2013
Revenues	$	174,550		$	631,809
Net income	(11,392		)	77,694

Net income per common unit:
Basic	$	(0.11	)	$	0.78
Diluted	$	(0.11	)	$	0.78

3. Financial Instruments

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

Commodity Activities

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

We had the following commodity derivative contracts in place at September 30, 2014:



	Year
	2014		2015		2016		2017		2018
Oil Positions:
Fixed Price Swaps - NYMEX WTI
Hedged Volume (Bbl/d)	14,811		13,059		9,211		7,971		493
Average Price ($/Bbl)	$	92.59	$	93.05	$	86.73	$	84.23	$	82.20
Fixed Price Swaps - ICE Brent
Hedged Volume (Bbl/d)	4,950		3,374		4,300		298		—
Average Price ($/Bbl)	$	98.89	$	97.89	$	95.17	$	97.50	$	—
Collars - NYMEX WTI
Hedged Volume (Bbl/d)	1,000		1,000		—		—		—
Average Floor Price ($/Bbl)	$	90.00	$	90.00	$	—	$	—	$	—
Average Ceiling Price ($/Bbl)	$	112.00	$	113.50	$	—	$	—	$	—
Collars - ICE Brent
Hedged Volume (Bbl/d)	—		500		500		—		—
Average Floor Price ($/Bbl)	$	—	$	90.00	$	90.00	$	—	$	—
Average Ceiling Price ($/Bbl)	$	—	$	109.50	$	101.25	$	—	$	—
Puts - NYMEX WTI
Hedged Volume (Bbl/d)	500		500		1,000		—		—
Average Price ($/Bbl)	$	90.00	$	90.00	$	90.00	$	—	$	—
Total:
Hedged Volume (Bbl/d)	21,261		18,433		15,011		8,269		493
Average Price ($/Bbl)	$	93.87	$	93.61	$	89.48	$	84.71	$	82.20

Natural Gas Positions:
Fixed Price Swaps - MichCon City-Gate
Hedged Volume (MMBtu/d)	7,500		7,500		17,000		10,000		—
Average Price ($/MMBtu)	$	6.00	$	6.00	$	4.46	$	4.48	$	—
Fixed Price Swaps - Henry Hub
Hedged Volume (MMBtu/d)	41,600		47,700		24,700		8,571		1,870
Average Price ($/MMBtu)	$	4.75	$	4.77	$	4.23	$	4.39	$	4.15
Puts - Henry Hub
Hedged Volume (MMBtu/d)	6,000		1,500		—		—		—
Average Price ($/MMBtu)	$	5.00	$	5.00	$	—	$	—	$	—
Total:
Hedged Volume (MMBtu/d)	55,100		56,700		41,700		18,571		1,870
Average Price ($/MMBtu)	$	4.95	$	4.94	$	4.32	$	4.44	$	4.15

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

During the three months and nine months ended September 30, 2014 and 2013, we did not enter into any derivative instruments that required pre-paid premiums.

As of September 30, 2014, premiums paid in 2012 related to oil and natural gas derivatives to be settled in the fourth quarter of 2014 and beyond were as follows:



	Year
Thousands of dollars	2014		2015		2016		2017		2018
Oil	$	1,129	$	4,683	$	7,438	$	734	$	—
Natural gas	$	1,012	$	1,989	$	952	$	—	$	—

Fair Value of Financial Instruments

The following table presents the fair value of our derivative instruments, none of which are designated as hedging instruments:



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

As of September 30, 2014
Assets
Current assets - derivative instruments	$	30,334		$	18,529		$	(4,607	)	$	44,256
Other long-term assets - derivative instruments	22,656			10,362			(7,155		)	25,863
Total assets	52,990			28,891			(11,762		)	70,119

Liabilities
Current liabilities - derivative instruments	(4,304		)	(310		)	4,607			(7		)
Long-term liabilities - derivative instruments	(11,964		)	(336		)	7,155			(5,145		)
Total liabilities	(16,268		)	(646		)	11,762			(5,152		)

Net assets	$	36,722		$	28,245		$	—		$	64,967

As of December 31, 2013
Assets
Current assets - derivative instruments	$	4,373		$	15,419		$	(11,878	)	$	7,914
Other long-term assets - derivative instruments	59,412			23,750			(11,843		)	71,319
Total assets	63,785			39,169			(23,721		)	79,233

Liabilities
Current liabilities - derivative instruments	(35,634		)	(1,120		)	11,878			(24,876		)
Long-term liabilities - derivative instruments	(13,620		)	(783		)	11,843			(2,560		)
Total liabilities	(49,254		)	(1,903		)	23,721			(27,436		)

Net assets	$	14,531		$	37,266		$	—		$	51,797

(a) Represents counterparty netting under derivative master agreements. The agreements allow for netting of oil and natural gas commodity derivative instruments. These derivative instruments are reflected net on the balance sheet.

The following table presents gains and losses on derivative instruments not designated as hedging instruments:



Thousands of dollars	Oil Commodity Derivatives (a)			Natural Gas Commodity Derivatives (a)			Total Financial Instruments
Three Months Ended September 30, 2014
Net gain	$	133,666		$	12,505		$	146,171
Three Months Ended September 30, 2013
Net gain (loss)	$	(62,770	)	$	8,005		$	(54,765	)
Nine Months Ended September 30, 2014
Net loss	$	(15,553	)	$	(5,504	)	$	(21,057	)
Nine Months Ended September 30, 2013
Net gain (loss)	$	(22,072	)	$	10,124		$	(11,948	)

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

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

Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2 – Inputs that are observable other than quoted prices that are included within Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. We consider the over-the-counter (“OTC”) commodity and interest rate swaps in our portfolio to be Level 2. Level 3 – Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Certain OTC derivative instruments that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. As of September 30, 2014, and December 31, 2013, our Level 3 derivative assets and liabilities consisted entirely of OTC commodity put and call options.

Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data. We had no transfers in or out of Levels 1, 2 or 3 during the three months and nine months ended September 30, 2014 and 2013. Our policy is to recognize transfers between levels as of the end of the period.

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

The model we utilize to calculate the fair value of our commodity derivative instruments is a standard option pricing model. Inputs to the option pricing model include fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity forward price curves, volatility, interest rate factors and time to expiry. Model inputs are obtained from our counterparties and third-party data providers and are verified against published data when available (e.g., NYMEX). Additional inputs to our Level 3 derivative instruments include option volatility, forward commodity prices and risk-free interest rates for present value discounting. We use the standard swap contract valuation method to value our interest rate derivative instruments, and inputs include LIBOR forward interest rates, 1-month LIBOR rates and risk-free interest rates for present value discounting.

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

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



Thousands of dollars	Level 1		Level 2		Level 3			Total

As of September 30, 2014
Assets (liabilities)
Crude Oil
Crude oil swaps	$	—	$	29,653	$	—		$	29,653
Crude oil collars	—		—		2,407			2,407
Crude oil puts	—		—		4,662			4,662
Natural Gas
Natural gas swaps	—		27,280		—			27,280
Natural gas calls	—		—		(157		)	(157		)
Natural gas puts	—		—		1,122			1,122
Net assets	$	—	$	56,933	$	8,034		$	64,967

As of December 31, 2013
Assets (liabilities)
Crude Oil
Crude oil swaps	$	—	$	5,573	$	—		$	5,573
Crude oil collars	—		—		2,683			2,683
Crude oil puts	—		—		6,275			6,275
Natural Gas
Natural gas swaps	—		35,419		—			35,419
Natural gas calls	—		—		(650		)	(650		)
Natural gas puts	—		—		2,497			2,497
Net assets	$	—	$	40,992	$	10,805		$	51,797

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



	Three Months Ended September 30,
	2014						2013
Thousands of dollars	Oil			Natural Gas			Oil			Natural Gas
Assets (a):
Beginning balance	$	1,540		$	840		$	15,412		$	2,054
Derivative instrument settlements (b)	—			347			(125		)	(225		)
Gain (loss) (b)(c)	5,529			(222		)	(4,744		)	528
Ending balance	$	7,069		$	965		$	10,543		$	2,357

	Nine Months Ended September 30,
	2014						2013
Thousands of dollars	Oil			Natural Gas			Oil			Natural Gas
Assets (a):
Beginning balance	$	8,957		$	1,848		$	15,169		$	1,672
Derivative instrument settlements (b)	—			389			(125		)	(667		)
Gain (loss) (b)(c)	(1,888		)	(1,272		)	(4,501		)	1,352
Ending balance	$	7,069		$	965		$	10,543		$	2,357

(a) We had no changes in fair value of our derivative instruments classified as Level 3 related to sales, purchases or issuances.

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

For Level 3 derivative instruments measured at fair value on a recurring basis as of September 30, 2014, the significant unobservable inputs used in the fair value measurements were as follows:



	Fair Value at		Valuation
Thousands of dollars	September 30, 2014		Technique	Unobservable Input	Range
Oil Options	$	7,069	Option Pricing Model	Oil forward commodity prices	$85.32/Bbl - $97.48/Bbl
				Oil volatility	14.98% - 20.70%
				Own credit risk	5%
Natural Gas Options	965		Option Pricing Model	Gas forward commodity prices	$3.85/MMBtu - $4.25/MMBtu
				Gas volatility	24.80% - 40.08%
				Own credit risk	5%
Total	$	8,034

For Level 3 derivative instruments measured at fair value on a recurring basis as of December 31, 2013, the significant unobservable inputs used in the fair value measurements were as follows:



	Fair Value at		Valuation
Thousands of dollars	December 31, 2013		Technique	Unobservable Input	Range
Oil Options	$	8,957	Option Pricing Model	Oil forward commodity prices	$81.95/Bbl - $105.14/Bbl
				Oil volatility	15.51% - 17.59%
				Own credit risk	5%
Natural Gas Options	1,848		Option Pricing Model	Gas forward commodity prices	$4.01/MMBtu - $4.41/MMBtu
				Gas volatility	18.87% - 35.13%
				Own credit risk	5%
Total	$	10,805

Credit and Counterparty Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of derivative instruments and accounts receivable. Our derivative instruments expose us to credit risk from counterparties. As of September 30, 2014, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank, National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, Royal Bank of Canada and Toronto-Dominion Bank. We periodically obtain credit default swap information on our counterparties. As of September 30, 2014, 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, 2014, our largest derivative asset balances were with Wells Fargo Bank, Credit Suisse Energy LLC and Citibank, which accounted for approximately 38%, 22% and 11% of our net derivative asset balances, respectively.

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 LP, formerly named BreitBurn Energy Company L.P. (“PCEC”), our predecessor, under an administrative services agreement, in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses, including incentive compensation plan costs and direct payroll and administrative costs related to PCEC properties and operations. For the three months and nine months ended September 30, 2014, the monthly fee paid by PCEC for indirect expenses was $700,000. In August 2014, the expiration of the term for the current monthly fee of $700,000 was extended to June 30, 2015, and thereafter, the monthly fee will be redetermined biannually.

At September 30, 2014 and December 31, 2013, we had current receivables of $1.3 million and $2.5 million, respectively, due from PCEC related to the administrative services agreement, employee-related costs and oil and natural gas sales made by PCEC on our behalf from certain properties. For the three months ended September 30, 2014 and 2013, the monthly charges to PCEC for indirect expenses totaled $2.1 million and $2.1 million, respectively, and charges for direct expenses including payroll and administrative costs totaled $3.8 million and $2.9 million, respectively. For the nine months ended September 30, 2014 and 2013, the monthly charges to PCEC for indirect expenses totaled $6.3 million and $6.3 million, respectively, and charges for direct expenses including payroll and administrative costs totaled $8.9 million and $7.3 million, respectively.

At September 30, 2014 and December 31, 2013, we had receivables of $0.2 million and $0.1 million, respectively, due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf.

5. Inventory

Our crude oil inventory from our Florida operations was $4.4 million and $3.9 million at September 30, 2014 and December 31, 2013, respectively. In the nine months ended September 30, 2014, we sold 514 gross MBbls and produced 522 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. Impairments

We assess our developed and undeveloped oil and natural 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 oil and natural gas properties, significant downward revisions of estimated proved reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for market supply and demand conditions for 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 9%. Additional inputs include 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.

Impairments of proved properties totaled $29.4 million for the three months and nine months ended September 30, 2014, including $19.9 million in Florida, $6.5 million in Michigan and $3.0 million in Wyoming. The Florida impairments are due to reserve adjustments primarily related to well performance and lower crude oil prices. The Michigan impairments relate to the write-off of investments associated with expiring leases that we have elected not to renew. The Wyoming impairments are due to reserve adjustments related to a combination of well performance, lower commodity prices and higher expense projections. Impairments totaled $0.4 million for the three months and nine months ended September 30, 2013, including $0.2 million in Florida and $0.2 million in Michigan.

Given the number of assumptions involved in the estimates, 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. 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.

7. Other Assets

Intangible Assets

In connection with the Whiting Acquisition in July 2013, we acquired two CO₂ purchase contracts, priced below market, which were valued at $14.7 million at the acquisition date. These contracts were recorded as finite-lived intangibles. We amortize intangible assets with finite lives over their estimated useful lives. We are amortizing these contracts based on the amount of CO₂ purchases made in each period over the contracts’ respective lives. The contracts expire in December 2015 and September 2023, respectively. For the three months and nine months ended September 30, 2014, we recorded $1.0 million and $3.0 million respectively, in amortization expense related to these contracts. As of September 30, 2014, and December 31, 2013, we had a remaining unamortized value of $8.2 million and $11.2 million, respectively.

In connection with our compliance with the California Greenhouse Gas (“GHG”) Cap-and-Trade Regulation, as of September 30, 2014 and December 31, 2013, we had $1.1 million and $0.5 million, respectively, of GHG allowances,

purchased at auction. We recognize the purchase of these allowances as intangibles until they are surrendered in compliance with regulations promulgated by the California Air Resources Board.

Other long-term assets

As of September 30, 2014, and December 31, 2013, our other long-term assets were $76.0 million and $74.2 million, respectively, including $31.3 million and $35.6 million, respectively, in debt issuance costs, $43.3 million and $36.6 million, respectively, in CO₂ supply advances and deposits for our Oklahoma properties and $1.4 million and $2.0 million, respectively, in other long-term assets.

8. Long-Term Debt

Credit Facility

As of September 30, 2014, Breitburn Operating LP (“BOLP”), our wholly-owned subsidiary, as borrower, and we and our wholly-owned subsidiaries, as guarantors, had a $3.0 billion revolving credit facility with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (as amended, the “Second Amended and Restated Credit Agreement”).

On April 25, 2014, in connection with the regularly scheduled borrowing base redetermination, we entered into the Twelfth Amendment to the Second Amended and Restated Credit Agreement, which provides for an increased borrowing base of $1.6 billion with a total lender commitment of $1.4 billion and an extension of the term of the credit facility for one year until May 9, 2017.

Our credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. The borrowing base is redetermined semi-annually. As of September 30, 2014, our borrowing base for our credit facility was $1.6 billion and the aggregate commitment of all lenders was $1.4 billion, with the ability to increase our total commitments up to the $1.6 billion borrowing base upon lender approval. At December 31, 2013, our borrowing base was $1.5 billion, and the aggregate commitment of all lenders was $1.4 billion.

As of September 30, 2014, and December 31, 2013, we had $719.0 million and $733.0 million, respectively, in indebtedness outstanding under our credit facility. At September 30, 2014, the 1-month LIBOR interest rate plus an applicable spread was 2.4041% on the 1-month LIBOR portion of $714 million and the prime rate plus an applicable spread was 4.50% on the prime portion of $5 million. At September 30, 2014, we had $11.4 million of unamortized debt issuance costs related to our credit facility.

As of September 30, 2014, and December 31, 2013, we were in compliance with our credit facility’s covenants.

In connection with the pending Merger with QR Energy, we received a firm commitment from Wells Fargo Bank, N.A. to increase the borrowing base under our credit facility to $2.5 billion. We expect our next regularly scheduled borrowing base redetermination under our new amended and restated credit facility to be in April 2015.

Senior Notes

We have $305 million in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”), which had a carrying value of $302.0 million, net of unamortized discount of $3.0 million, as of September 30, 2014. In addition, we have $850 million in aggregate principal amount of 7.875% senior notes due 2022 (the “2022 Senior Notes” and together with the 2020 Notes, the “Senior Notes”), which had a carrying value of $854.6 million, net of unamortized premium of $4.6 million, as of September 30, 2014. At September 30, 2014, we had $19.9 million of unamortized debt issuance costs related to the Senior Notes.

Interest on our Senior Notes is payable twice a year in April and October.

As of September 30, 2014, the fair value of our 2020 Senior Notes and 2022 Senior Notes was estimated to be $319.0 million and $862.0 million, respectively, based on prices quoted from third-party financial institutions. We consider the

inputs to the valuation of our Senior Notes to be Level 2, as fair value was estimated based on prices quoted from third-party financial institutions.

As of September 30, 2014 and December 31, 2013, we were in compliance with the covenants under our Senior Notes.

Interest Expense

Our interest expense is detailed as follows:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands of dollars	2014			2013			2014			2013
Credit agreement (including commitment fees)	$	4,539		$	6,313		$	14,886		$	9,718
Senior notes	23,311			15,436			69,933			46,308
Amortization of net premium and deferred issuance costs	1,765			1,826			5,779			4,423
Capitalized interest	(121		)	(27		)	(238		)	(62		)
Total	$	29,494		$	23,548		$	90,360		$	60,387

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. All but one of our subsidiaries have guaranteed our Senior Notes, and our only non-guarantor subsidiary, Breitburn Collingwood Utica LLC, is a minor subsidiary.

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

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


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


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


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


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


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


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

10. Income Taxes

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

Our deferred federal income tax liability was $2.9 million and $2.7 million as of September 30, 2014, and December 31, 2013, respectively. The following table presents our income tax expense (benefit) for the three months and nine months ended September 30, 2014 and 2013:



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Thousands of dollars	2014		2013			2014			2013
Federal income tax expense (benefit)
Current	$	87	$	41		$	243		$	67
Deferred (a)	434		(45		)	153			252
State income tax expense (benefit) (b)	11		28			(12		)	309
Total	$	532	$	24		$	384		$	628

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

(b) Primarily in California and Michigan.

11. Asset Retirement Obligations

ARO is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities together with our estimate of the future timing of the costs to be incurred. Payments to settle ARO occur over the operating lives of the assets, estimated to range from less than one year to 50 years. Estimated cash flows have been discounted at our credit-adjusted risk-free rate of 7% and adjusted for inflation using a rate of 2%. Our credit-adjusted risk-free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk.

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

Changes in ARO for the period ended September 30, 2014, and the year ended December 31, 2013 are presented in the following table:



	Nine Months Ended			Year Ended
Thousands of dollars	September 30, 2014			December 31, 2013
Carrying amount, beginning of period	$	123,769		$	98,480
Acquisitions	—			9,287
Liabilities incurred	3,391			5,313
Liabilities settled	(584		)	(893		)
Revisions	—			4,299
Accretion expense	6,640			7,283
Carrying amount, end of period	$	133,216		$	123,769

12. Commitments and Contingencies

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At September 30, 2014 and December 31, 2013, we had approximately $17.4 million and $17.5 million, respectively, of surety bonds and approximately $3.0 million and $2.8 million, respectively, in letters of credit outstanding.

Purchase Contracts

On July 15, 2013, we completed the acquisition of the Whiting Assets. The Whiting Assets include the Postle Field, which currently has active CO₂ enhanced recovery projects, and the Northeast Hardesty Unit, both of which are located in

Texas County, Oklahoma. We have a contracted supply of CO₂ in the Bravo Dome Field in New Mexico, with step-in rights, for 129 Bcf over 10 to 15 years, which we expect to provide volumes in excess of those required to produce our estimated proved reserves when coupled with recycled CO₂. Under the take-or-pay provisions of these purchase agreements, we are committed to buying certain volumes of CO₂ for use in our enhanced recovery project being carried out at the Postle field. We are obligated to purchase a minimum daily volume of CO₂ (as calculated on an annual basis) or else pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. The CO₂ volumes planned for use in our enhanced recovery projects in the Postle Field currently exceed the minimum daily volumes specified in these agreements. Therefore, we expect to avoid any payments for deficiencies. The table below shows our future minimum commitments under these purchase agreements as of September 30, 2014:



	Three Months Ending		Year Ending December 31,
Thousands of dollars	December 31, 2014		2015		2016		2017		2018		Thereafter		Total
Purchase contracts	$	3,844	$	28,942	$	14,638	$	15,663	$	21,487	$	45,353	$	129,927

13. Partners’ Equity

Preferred Units

On May 21, 2014, we sold 8.0 million 8.25% Series A Cumulative Redeemable Perpetual Preferred Units (“Preferred Units”) in a public offering at a price of $25.00 per Preferred Unit, resulting in proceeds of $193.2 million net of underwriting discount and offering expenses of $6.8 million. We used the net proceeds from this offering to repay indebtedness outstanding under our credit facility.

The Preferred Units rank senior to the Common Units with respect to the payment of current distributions. Distributions on Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our board of directors out of legally available funds for such purpose. We will pay cumulative distributions in cash on the Preferred Units on a monthly basis at a monthly rate of $0.171875 per Preferred Unit. During the three months and nine months ended September 30, 2014, we recognized $4.1 million and $6.0 million, respectively, of accrued distributions on the Preferred Units, which are included in the distributions to preferred unitholders on the consolidated statements of operations.

The Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into Common Units in connection with a change in control. At any time on or after May 15, 2019, we may, at our option, redeem the Preferred Units, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption. In addition, we may redeem the Preferred Units at the same redemption price following certain changes of control, as described in the Partnership Agreement (as defined below); if we do not exercise this option, then the holders of the Preferred Units have the option to convert the Series A Preferred Units into a number of Common Units per Preferred Unit as set forth in the Partnership Agreement. If we exercise the right to redeem all outstanding Preferred Units, the holders of Preferred Units will not have the conversion right described above.

Common Units

Pursuant to an Equity Distribution Agreement dated as of March 19, 2014 (the “Equity Distribution Agreement”), we may sell, from time to time up to $200 million in Common Units. We intend to use the net proceeds of any sales pursuant to the Equity Distribution Agreement, after deducting commissions and offering expenses, for general purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. The Common Units to be issued are registered under a previously filed shelf registration statement on Form S-3, which was declared effective by the SEC on January 22, 2014. During the three months ended March 31, 2014, June 30, 2014 and September 30, 2014, we sold 25,300 Common Units, 976,611 Common Units and 269,774 Common Units, respectively, under the Equity Distribution Agreement for net proceeds of $0.5 million, $19.7 million and $6.0 million, respectively.

During the three months and nine months ended September 30, 2014, we issued no Common Units and less than 0.1 million Common Units, respectively, to non-employee directors for Restricted Phantom Units (“RPUs”) that vested in January 2014.

At September 30, 2014 and December 31, 2013, we had approximately 120.5 million and 119.2 million Common Units outstanding, respectively. At September 30, 2014 and December 31, 2013, there were approximately 2.7 million and 1.3 million, respectively, of units outstanding under our Long-Term Incentive Plan (“LTIP”) that were eligible to be paid in Common Units upon vesting.

Pursuant to our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), we may pay distributions on our Common Units within 45 days following the end of each quarter or in three equal monthly payments within 17, 45 and 75 days following the end of each quarter. We changed our Common Unit distribution payment policy from a quarterly payment schedule to a monthly payment schedule beginning with the distributions relating to the fourth quarter of 2013.

During the three months ended September 30, 2014, we paid three monthly cash distributions totaling approximately $60.5 million, or $0.503 per Common Unit. During the nine months ended September 30, 2014, we paid nine monthly cash distributions totaling approximately $178.7 million, or $1.493 per Common Unit.

During the three months ended September 30, 2013, we paid cash distributions of approximately $47.8 million, or $0.480 per Common Unit. During the nine months ended September 30, 2013, we paid cash distributions of approximately $135.0 million, or $1.425 per Common unit.

During the three months and nine months ended September 30, 2014, we paid $0.9 million and $2.8 million, respectively, in cash at a rate equal to the distributions paid to our holders of Common Units to holders of outstanding unvested RPUs issued under our LTIP. During the three months and nine months ended September 30, 2013, we paid $0.8 million and $2.4 million, respectively, in cash at a rate equal to the distributions paid to our holders of Common Units to holders of outstanding unvested RPUs issued under our LTIP.

Income per Unit

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

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands, except per unit amounts	2014			2013			2014			2013

Net income (loss)	$	130,643		$	(25,011	)	$	16,160		$	15,121
Distributions on participating units not expected to vest	76			4			113			15
Distributions to preferred unitholders	(4,125		)	—			(5,958		)	—
Net income (loss) attributable to holders of Common Units and participating securities	$	126,594		$	(25,007	)	$	10,315		$	15,136
Weighted average number of units used to calculate basic and diluted net income per unit:
Common Units	120,473			99,680			119,806			97,982
Participating securities (a)	1,880			—			1,826			1,652
Denominator for basic income (loss) per common unit	122,353			99,680			121,632			99,634
Dilutive units (b)	777			—			738			355
Denominator for diluted income (loss) per common unit	123,130			99,680			122,370			99,989
Net income (loss) per common unit
Basic	$	1.03		$	(0.25	)	$	0.08		$	0.15
Diluted	$	1.03		$	(0.25	)	$	0.08		$	0.15

(a) The three months ended September 30, 2013 exclude 1,729 of potentially issuable weighted average RPUs from participating securities, as we were in a loss position.

(b) The three months ended September 30, 2013 exclude 384 of weighted average units from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position.

14. Unit Based Compensation Plans

Unit-based compensation expense for the three months ended September 30, 2014 and 2013 was $5.8 million and $4.9 million, respectively, and for the nine months ended September 30, 2014 and 2013 was $18.4 million and $14.7 million, respectively. Unit based compensation expense for the three months ended March 31, 2014 included $0.6 million related to an increase in the performance factor for the 2013 CPU grants from 1.0 to 1.25. The current multiplier was achieved based on the actual distribution made to common unitholders during the quarter.

During the nine months ended September 30, 2014, the board of directors of our General Partner approved the grant of approximately 1.3 million RPUs and CPUs to employees of Breitburn Management under our LTIP. Our outside directors were issued less than 0.1 million RPUs under our LTIP during the nine months ended September 30, 2014. The fair market value of the RPUs granted during 2014 for computing compensation expense under FASB Accounting Standards averaged $20.30 per unit.

During the three months ended September 30, 2014 and 2013, we paid nothing for taxes withheld on RPUs, which was the result of no units vesting during the periods. During the nine months ended September 30, 2014 and 2013, we paid nothing and $0.6 million, respectively, for taxes withheld on RPUs that vested during the period.

As of September 30, 2014, we had $33.1 million of unrecognized compensation costs for all outstanding awards, which is expected to be recognized over the period from October 1, 2014 to December 31, 2016.

For detailed information on our various compensation plans, see Note 17 to the consolidated financial statements included in our 2013 Annual Report.

15. Subsequent Events

On October 1, 2014, we announced a cash distribution to holders of Common Units for the first monthly payment attributable to the third quarter of 2014 at the rate of $0.1675 per Common Unit, which was paid on October 16, 2014 to the unitholders of record at the close of business on October 13, 2014. On October 29, 2014, we announced a cash distribution to unitholders for the second monthly payment attributable to the third quarter of 2014 at the rate of $0.1675 per Common Unit, to be paid on November 14, 2014 to the unitholders of record at the close of business on November 10, 2014.

On October 1, 2014, we declared a cash distribution for our Preferred Units of $0.171875 per Preferred Unit, which is expected to be paid on November 17, 2014 to preferred unitholders of record at the close of business on October 31, 2014. On October 29, 2014, we declared a cash distribution for our Preferred Units of $0.171875 per Preferred Unit, which is expected to be paid on December 15, 2014 to preferred unitholders of record at the close of business on November 28, 2014. The monthly distribution rate is equal to an annual distribution of $2.0625 per Preferred Unit.

On October 10, 2014, we sold 14 million Common Units at a price to the public of $18.64 per Common Unit. We used the net proceeds, net of underwriting discount and offering expenses, of $251.6 million to reduce outstanding borrowings under our credit facility.

On October 17, 2014, our registration statement on Form S-4 filed pursuant to the Merger Agreement was declared effective by the SEC. A special meeting of QR Energy unitholders is scheduled to be held on November 18, 2014.

On October 24, 2014, BOLP completed the acquisition of certain oil and gas properties located in the Midland Basin, Texas from Antares Energy Company, a Delaware corporation, in exchange for $50.0 million in cash and 4.3 million Common Units, subject to customary purchase price adjustments, for a total preliminary purchase price of $122.7 million. The number of Common Units being issued as partial consideration will not be adjusted to account for changes in the unit price or for purchase price adjustments.

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 2013 Annual Report and the consolidated financial statements and related notes therein. Our 2013 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 2013 Annual Report and Part I—Item 1A “—Risk Factors” of our 2013 Annual Report.

Overview

We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil, natural gas liquids (“NGL”) and natural gas properties in the United States. Our objective is to manage our oil and natural gas producing properties for the purpose of generating cash flows and making distributions to our unitholders. Our assets consist primarily of producing and non-producing crude oil, NGL and natural gas reserves located primarily in:

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

• the Oklahoma Panhandle;

• the Permian Basin in Texas;

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

• the Los Angeles and San Joaquin Basins in California;

• the Sunniland Trend in Florida; and

• the New Albany Shale in Indiana and Kentucky.

2014 Highlights

Preferred Units

In May 2014, we sold 8.0 million 8.25% Series A Cumulative Redeemable Perpetual Preferred Units (“Preferred Units”) in a public offering at a price of $25.00 per Preferred Unit, resulting in proceeds of $193.2 million, net of underwriting discount and offering expenses. The Preferred Units rank senior to the Common Units with respect to the payment of current distributions. We used the net proceeds from this offering to repay indebtedness outstanding under our credit facility.

Distributions on the Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our board of directors out of legally available funds for such purpose. We will pay cumulative distributions in cash on the Preferred Units on a monthly basis at a monthly rate of $0.171875 per unit. The initial distribution on the Preferred Units of $0.309375 was paid on July 15, 2014. Regular monthly distributions of $0.171875 per Preferred Unit began with the August 15, 2014 payment. The monthly distribution rate is equal to an annual distribution of $2.0625 per Preferred Unit. During the three months and nine months ended September 30, 2014, we recognized $4.1 million and $6.0 million, respectively, of accrued distributions on the Preferred Units, which are included in the distributions to preferred unitholders on the consolidated statements of operations.

Common Units

During the three months ended March 31, 2014, we paid three monthly cash distributions at the rate of $0.1642 per Common Unit per month, totaling approximately $58.7 million, or $0.4926 per Common Unit. During the three months ended June 30, 2014, we paid three monthly cash distributions at the rate of $0.1658 per Common Unit per month, totaling approximately $59.5 million, or $0.4974 per Common Unit. During the three months ended September 30, 2014, we paid three monthly cash distributions at the rate of $0.1675 per Common Unit per month, totaling approximately $60.5 million, or $0.5025 per Common Unit.

On October 1, 2014, we announced a cash distribution to unitholders for the first monthly payment attributable to the third quarter of 2014 at the rate of $0.1675 per Common Unit, which was paid on October 16, 2014 to the unitholders of record at the close of business on October 13, 2014. On October 29, 2014, we announced a cash distribution to unitholders for the second monthly payment attributable to the third quarter of 2014 at the rate of $0.1675 per Common Unit, to be paid on November 14, 2014 to the unitholders of record at the close of business on November 10, 2014.

On October 24, 2014, in connection with the Antares Acquisition (as defined below), we issued 4.3 million Common Units to Antares (as defined below) as partial consideration for the Antares Assets (as defined below).

Credit Facility

In April 2014, in connection with the regularly scheduled borrowing base redetermination, we entered into the Twelfth Amendment to the Second Amended and Restated Credit Agreement, which provides for an increased borrowing base of $1.6 billion with total lender commitments of $1.4 billion and an extension of the term of the credit facility for one year until May 9, 2017. Concurrently with the closing of the Merger, we expect to amend and restate our existing credit facility to increase the borrowing base and the aggregate commitment of all lenders under our credit facility to $2.5 billion, consistent with the commitment from Wells Fargo Bank, N.A..

Pending Merger with QR Energy

On July 23, 2014, we, our General Partner and Boom Merger Sub, LLC, a direct wholly owned subsidiary of the Partnership (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) with QR Energy, LP (“QR Energy”) and QRE GP, LLC (“QRE”). Pursuant to the Merger Agreement, we will acquire QR Energy in exchange for our Common Units, including the assumption of approximately $1.01 billion of QR Energy’s existing net debt and the payment of $350 million in cash to the holders of the outstanding Class C Convertible Preferred Units of QR Energy (each, a “Class C Unit”). The Merger Agreement provides that, upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will be merged with and into QR Energy, with QR Energy continuing as the surviving entity and a direct wholly owned subsidiary of the Partnership (the “Merger”).

Under the terms of the Merger Agreement, each outstanding common unit representing a limited partner interest in QR Energy (a “QR Energy Common Unit”) and Class B Unit representing a limited partner interest in QR Energy (a “Class B Unit”) will be converted into the right to receive 0.9856 newly issued Common Units (the “Merger Consideration”). A number of Class B Units issuable upon a change of control of QR Energy equal to (i) 6,748,067, minus (ii) the excess of (A) the number of performance units that vest and are settled in QR Energy Common Units in connection with the Merger over (B) 383,900 will be issued and treated as outstanding Class B Units and converted into the right to receive the Merger Consideration. Each outstanding Class C Unit of QR Energy will be converted into the right to receive cash in an amount equal to $350 million divided by the number of Class C Units outstanding immediately prior to the effective time of the Merger. In no event will we be obligated to issue in excess of 72,001,686 Common Units as part of the Merger Consideration.

The completion of the Merger is subject to satisfaction or waiver of customary closing conditions, including (1) the adoption of the Merger Agreement by holders of a majority of the outstanding QR Energy Common Units, Class B Units and Class C Units, voting as a single class, (2) the approval for listing of the Common Units issuable as part of the Merger Consideration on the NASDAQ, and (3) other customary conditions. On August 19, 2014, we received notification of early termination of the waiting period under the Hart-Scott-Rodino Act pursuant to the Merger.

On July 23, 2014, we also entered into a Transaction, Voting and Support Agreement (the “Voting Agreement”) with each of Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC (collectively, the “Fund Unitholders”), and each of QR Holdings (QRE), LLC and QR Energy Holdings, LLC (collectively, the “Management Unitholders” and, together with the Fund Unitholders, the “QR Energy Unitholders”) with respect to the Merger Agreement. The Voting Agreement generally requires that the QR Energy Unitholders vote or cause to be voted all QR Energy Common Units, Class B Units and Class C Units owned by such QR Energy Unitholder in favor of the merger and against alternative transactions. The Voting Agreement also provides that, upon termination of the Merger Agreement and QR Energy’s acceptance of an alternative transaction, each QR Energy Unitholder may be required to pay the Partnership a termination fee equal to the lesser of (1) such QR Energy Unitholder’s pro rata share of 2% of the equity value of such alternative transaction or (2) the excess of the aggregate consideration paid to such QR Energy Unitholder in such alternative transaction over the aggregate consideration that would have been received by such QR Energy Unitholder under the Merger Agreement. Subject to certain exceptions, the Voting Agreement will terminate upon the earlier of (i) the consummation of the Merger and (ii) the termination of the Merger Agreement.

On July 23, 2014, we also entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with each of the QR Energy Unitholders. Under the Registration Rights Agreement, we are required to file or cause to be filed with the Securities and Exchange Commission (the “SEC”) a registration statement with respect to the public resale of our Common Units issued to the QR Energy Unitholders as part of the Merger Consideration. We are required to file or cause to be filed the registration statement within 90 days following the closing under the Merger Agreement and are required to cause the registration statement to become effective as soon as reasonably practicable thereafter but in no event later than 120 days after the closing under the Merger Agreement.

In connection with the closing of the Merger, we intend to refinance the outstanding debt of QR Energy under its credit facility, which was approximately $755 million as of September 30, 2014, and QR Energy’s 9.25% senior notes due in 2020 with an aggregate principal amount of $300 million. We have received a firm commitment from Wells Fargo Bank, N.A. to increase the borrowing base under our credit facility to $2.5 billion in connection with the Merger. Concurrently with the closing of the Merger, we expect to amend and restate our existing credit facility to increase the borrowing base and the aggregate commitment of all lenders under our credit facility to $2.5 billion, consistent with the commitment from Wells Fargo Bank, N.A.

On October 17, 2014, our registration statement on Form S-4 filed pursuant to the Merger Agreement was declared effective by the SEC. A special meeting of QR Energy unitholders to vote on the adoption of the Merger Agreement is scheduled to be held on November 18, 2014. The Merger Agreement requires that the Merger close within three business days of the meeting of QR Energy unitholders.

Antares Acquisition

On October 24, 2014, we completed the acquisition of certain oil and gas properties located in the Midland Basin, Texas (“Antares Assets”) from Antares Energy Company, a Delaware corporation, in exchange for $50.0 million in cash and 4.3 million Common Units, subject to customary purchase price adjustments, for a total preliminary purchase price of $122.7 million (the “Antares Acquisition”). The number of Common Units being issued as partial consideration will not be adjusted to account for changes in the unit price or for purchase price adjustments.

Operational Focus and Capital Expenditures

In the first nine months of 2014, our oil, NGL and natural gas capital expenditures, including capitalized engineering costs, totaled $275 million, compared to approximately $198 million in the first nine months of 2013. We spent approximately $172 million in Texas, $56 million in California, $26 million in Oklahoma, $11 million in Florida, $5 million in Wyoming and $5 million in Michigan. In the first nine months of 2014, we drilled and completed 73 productive wells in Texas, 39 productive wells in California, six productive wells in Wyoming and three productive wells in Michigan. We also performed workovers on 14 wells in Michigan, 11 wells in Oklahoma, ten wells in California, two wells in Wyoming, three wells in Florida and one well in Texas.

In 2014, our crude oil, NGL and natural gas capital spending program, including capitalized engineering costs and excluding the QR Energy Merger, is expected to be between $360 million and $370 million. This compares with approximately $295 million in 2013. In 2014, we anticipate spending approximately 92% principally on oil projects in Texas, California and Oklahoma and approximately 8% principally on oil projects in Florida, Wyoming and Michigan. We anticipate 88% of our total capital spending will be focused on drilling and rate-generating projects that are designed to increase or add to production or reserves. We plan to drill 187 wells with 172 wells expected in Texas and California and 15 wells expected in Wyoming and Michigan. Without considering the QR Energy Merger, we expect our full year production to be approximately 13.3 MMBoe.

Our Texas production for the third quarter was down slightly from the previous quarter due to curtailment and steeper than anticipated production declines in recently drilled wells. To improve production results and rates of return from our Texas properties, we plan to transition to a horizontal well program and begin drilling those wells in the first quarter of 2015. However, in order to hold acreage on both our legacy and acquired Antares assets, we expect to drill 15 additional vertical wells in the Permian Basin by the end of the first quarter of 2015. We currently plan to fund the initial horizontal drilling program ourselves and will consider various options involving third parties for additional future horizontal wells. Our recently acquired Antares Assets include acreage adjacent to our existing properties in Howard County in the Permian Basin, which we believe will enhance our ability to drill horizontal wells in the area.

Commodity Prices

In the third quarter of 2014, the NYMEX WTI spot price averaged $98 per barrel, compared with approximately $106 per barrel in the third quarter of 2013. In the first nine months of 2014, the NYMEX WTI spot price averaged $100 per barrel and ranged from a low of $91 per barrel to a high of $108 per barrel. In 2013, the NYMEX WTI spot price averaged approximately $98 per barrel. In recent months, there has been a decline in crude oil prices. The NYMEX WTI spot price decreased from $106 per barrel at June 30, 2014 to $79 per barrel at November 3, 2014. Lower crude oil prices may not only decrease our revenues, but may also reduce the amount of crude oil that we can produce economically and therefore potentially lower our crude oil reserves.

In the third quarter of 2014, the Henry Hub natural gas spot price averaged $3.96 per MMBtu compared with approximately $3.55 per MMBtu in the third quarter of 2013. In the first nine months of 2014, the Henry Hub spot price averaged $4.57 and ranged from a low of $3.77 per MMBtu to a high of $8.15 per MMBtu. In 2013, the Henry Hub natural gas spot price averaged approximately $3.73 per MMBtu. In the third quarter of 2014, the MichCon natural gas spot price averaged $4.21 per MMBtu compared with approximately $3.79 per MMBtu in the third quarter of 2013.

Breitburn Management

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

Breitburn Management also 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 properties and operations. For the three months and nine months ended September 30, 2014, the monthly fee paid by PCEC for indirect expenses was $700,000. In August 2014, the expiration of the term for the current monthly fee of $700,000 was extended to June 30, 2015, and thereafter, the monthly fee will be redetermined biannually.

Hydraulic Fracturing

During 2013, the California Legislature passed SB 4, which became effective on January 1, 2014. SB 4 specifically authorizes hydraulic fracturing and certain other completion stimulation techniques throughout California, subject to additional regulatory requirements. Final regulations implementing SB 4 will not be issued until later in the year or early 2015. In November 2013, the California Department of Conservation released proposed regulations to implement SB 4 and issued currently effective interim rules. The interim rules require approval of Well Stimulation Treatment Notices before starting stimulation treatment, disclosure of the fluids used and, adoption of groundwater monitoring and water management plans. They also govern resident notifications, storage and handling of fluids and well integrity. The only hydraulic fracturing planned in California for 2014 is in the Belridge field in western Kern County. The SB4 permit implementation process delayed the issuance of permits relating to hydraulic fracturing in that field. However, we received the permits during the second quarter of 2014, and the delay was not material to the Partnership as a whole.

Several local jurisdictions in California have proposed various forms of moratoria or bans on hydraulic fracturing. In some cases, these discussed measures include broad terms which, if enacted, could affect current operations. To our knowledge, only one such local jurisdiction where we have production--the City of Los Angeles--is currently considering such a proposal. The actual language of such a proposal has not been released and thus its potential effect cannot be fully assessed at this time. However, our production within the city limits is small and does not involve hydraulic fracturing. Therefore, we do not believe that any current local proposal will have a material adverse effect on the Partnership as a whole.

Results of Operations

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



Thousands of dollars, except as	Three Months Ended September 30,					Increase/					Nine Months Ended September 30,						Increase/
indicated	2014		2013			(Decrease)			%		2014			2013			(Decrease)			%
Total production (MBoe)	3,353		3,098			255			8	%	9,945			7,897			2,048			26	%
Oil (MBbl)	1,904		1,681			223			13	%	5,604			3,946			1,658			42	%
NGLs (MBbl)	253		207			46			22	%	789			435			354			81	%
Natural gas (MMcf)	7,178		7,258			(80		)	(1	)%	21,312			21,096			216			1	%
Average daily production (Boe/d)	36,450		33,674			2,776			8	%	36,432			28,928			7,504			26	%
Sales volumes (MBoe)	3,412		3,027			385			13	%	9,934			7,825			2,109			27	%

Average realized sales price (per Boe) (a)(b)	$	63.33	$	65.14		$	(1.81	)	(3	)%	$	66.30		$	59.62		$	6.68		11	%
Oil (per Bbl) (a)(b)	90.12		100.94			(10.82		)	(11	)%	92.59			95.95			(3.36		)	(4	)%
NGLs (per Bbl)	37.87		38.11			(0.24		)	(1	)%	39.70			31.99			7.71			24	%
Natural gas (per Mcf) (b)	$	4.12	$	3.69		$	0.43		12	%	5.13			3.84			1.29			34	%

Oil sales	$	176,986	$	162,709		$	14,277		9	%	$	518,020		$	372,169		$	145,851		39	%
NGL sales	9,582		7,888			1,694			21	%	31,322			13,914			17,408			125	%
Natural gas sales	29,578		26,816			2,762			10	%	109,411			80,978			28,433			35	%
Gain (loss) on commodity derivative instruments	146,171		(54,765		)	200,936			n/a		(21,057		)	(11,948		)	(9,109		)	76	%
Other revenues, net	1,585		737			848			115	%	4,240			2,197			2,043			93	%
Total revenues	363,902		143,385			220,517			154	%	641,936			457,310			184,626			40	%

Lease operating expenses before taxes (c)	62,714		58,731			3,983			7	%	200,627			152,836			47,791			31	%
Production and property taxes (d)	16,327		14,476			1,851			13	%	47,987			34,925			13,062			37	%
Total lease operating expenses	79,041		73,207			5,834			8	%	248,614			187,761			60,853			32	%

Purchases and other operating costs	102		226			(124		)	(55	)%	426			881			(455		)	(52	)%
Change in inventory	3,761		(4,931		)	8,692			(176	)%	(879		)	(6,753		)	5,874			(87	)%
Total operating costs	$	82,904	$	68,502		$	14,402		21	%	$	248,161		$	181,889		$	66,272		36	%

Lease operating expenses before taxes per Boe	$	18.70	$	18.96		$	(0.26	)	(1	)%	$	20.17		$	19.35		$	0.82		4	%
Production and property taxes per Boe	4.87		4.67			0.20			4	%	4.83			4.42			0.41			9	%
Total lease operating expenses per Boe	$	23.57	$	23.63		$	(0.06	)	0	%	$	25.00		$	23.77		$	1.23		5	%

Depletion, depreciation and amortization (“DD&A”)	$	72,671	$	59,764		$	12,907		22	%	$	204,417		$	154,095		$	50,322		33	%
DD&A per Boe	21.67		19.41			2.26			12	%	20.55			19.51			1.04			5	%
Impairments	29,434		361			29,073			n/a		29,434			361			29,073			n/a

G&A expenses	$	18,737	$	16,116		$	2,621		16	%	$	53,886		$	44,695		$	9,191		21	%

(a) Includes crude oil purchases.
(b) Excludes the effect of commodity derivative settlements.
(c) Includes district expenses, transportation expenses and processing fees.
(d) Includes ad valorem and severance taxes.

Comparison of Results for the Three Months and Nine Months Ended September 30, 2014 and 2013

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

Production

For the three months ended September 30, 2014, total production was 3,353 MBoe compared to 3,098 MBoe for the three months ended September 30, 2013, an increase of 8%, primarily due to a 310 MBoe increase in production from our Texas properties acquired in December 2013 and 20 MBoe higher California production, primarily from our Santa Fe Springs field, partially offset by 27 MBoe and 23 MBoe lower production in Wyoming and Michigan, respectively, primarily due to natural field declines and 21 MBoe lower production in Florida primarily due to well performance.

For the nine months ended September 30, 2014, total production was 9,945 MBoe compared to 7,897 MBoe for the nine months ended September 30, 2013, an increase of 26%, primarily due to 1,248 MBoe from our Oklahoma properties acquired in July 2013, a 948 MBoe increase in production from our Texas properties acquired in December 2013 and 128 MBoe higher California production, primarily from our Santa Fe Springs field, partially offset by 124 MBoe and 78 MBoe lower production in Michigan and Wyoming, primarily due to severe winter weather and natural field declines and 64 MBoe lower production in Florida, primarily due to well performance.

Oil, NGL and natural gas sales

Total oil, NGL and natural gas sales revenues increased $18.7 million in the three months ended September 30, 2014, compared to the three months ended September 30, 2013. Crude oil revenues increased $14.3 million due to higher oil sales volumes, primarily due to production from our 2013 Texas acquisitions, in addition to higher Florida sales volumes and higher California production. NGL revenues increased $1.7 million due to higher NGL sales volumes, primarily due to production from our 2013 Texas acquisitions. Natural gas revenues increased $2.8 million, primarily due to higher realized natural gas prices.

Realized prices for crude oil, excluding the effect of derivative instruments, decreased $10.82 per Boe, or 11%, in the three months ended September 30, 2014 compared to the three months ended September 30, 2013. Realized prices for NGLs, excluding the effect of derivative instruments, decreased $0.24 per Boe in the three months ended September 30, 2014 compared to the three months ended September 30, 2013. Realized prices for natural gas, excluding the effect of derivative instruments, increased $0.43 per Mcf, or 12%, in the three months ended September 30, 2014 compared to the three months ended September 30, 2013.

Total oil, NGL and natural gas sales revenues increased $191.7 million in the nine months ended September 30, 2014, compared to the nine months ended September 30, 2013. Crude oil revenues increased $145.9 million due to higher oil sales volume primarily due to production from our 2013 Oklahoma and Texas acquisitions. NGL revenues increased $17.4 million due to higher NGL sales volumes primarily due to production from our 2013 Oklahoma and Texas acquisitions, and higher NGL prices. Natural gas revenues increased $28.4 million, primarily due to higher natural gas prices, particularly in Michigan due to severe winter weather, and slightly higher natural gas production.

Realized prices for crude oil, excluding the effect of derivative instruments, decreased $3.36 per Boe, or 4%, in the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013. Realized prices for NGLs, excluding the effect of derivative instruments, increased $7.71 per Boe, or 24%, in the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013. Realized prices for natural gas, excluding the effect of derivative instruments, increased $1.29 per Mcf, or 34%, in the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013.

Gain (loss) on commodity derivative instruments

Gain on commodity derivative instruments for the three months ended September 30, 2014 was $146.2 million compared to a loss of $54.8 million during the three months ended September 30, 2013. Commodity derivative instrument settlement payments net of receipts were $3.7 million for the three months ended September 30, 2014 compared to net payments of $6.3 million during the same period in 2013, which primarily reflects lower oil settlement payments compared to prior year due to lower average crude oil hedge prices as well as lower natural gas settlement receipts due to higher natural gas prices.

Loss on commodity derivative instruments for the nine months ended September 30, 2014 was $21.1 million compared to a loss of $11.9 million during the nine months ended September 30, 2013. Commodity derivative instrument settlement payments net of receipts were $34.2 million for the nine months ended September 30, 2014 compared to net receipts of $3.6 million during the same period in 2013, which primarily reflects lower natural gas settlement receipts due to higher natural gas prices as well as higher oil settlement payments compared to prior year due to lower average crude oil hedge prices.

Lease operating expenses

Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the three months ended September 30, 2014 increased $4.0 million compared to the three months ended September 30, 2013. The increase in pre-tax lease operating expenses reflects our 2013 Texas acquisitions acquired in December 2013. On a per Boe basis, pre-tax lease operating expenses were 1% lower than the three months ended September 30, 2013 at $18.70 per Boe.

Production and property taxes for the three months ended September 30, 2014 totaled $16.3 million, which was $1.9 million higher than the three months ended September 30, 2013, primarily from our 2013 Texas acquisitions acquired in December 2013. On a per Boe basis, production and property taxes for the three months ended September 30, 2014 were $4.87 per Boe, which was 4% higher than the three months ended September 30, 2013, primarily due to higher oil production as a percentage of total production, higher crude oil prices and higher natural gas prices, particularly in Michigan.

Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the nine months ended September 30, 2014 increased $47.8 million compared to the nine months ended September 30, 2013. The increase in pre-tax lease operating expenses reflects our 2013 Oklahoma and Texas acquisitions. On a per Boe basis, pre-tax lease operating expenses were 4% higher than the nine months ended September 30, 2013 at $20.17 per Boe, primarily due to higher well services, fuel and utility and labor costs, primarily in Oklahoma, Florida and Texas.

Production and property taxes for the nine months ended September 30, 2014 totaled $48.0 million, which was $13.1 million higher than the nine months ended September 30, 2013, primarily due to higher production and property taxes from our 2013 Oklahoma and Texas acquisitions and higher natural gas prices. On a per Boe basis, production and property taxes for the nine months ended September 30, 2014 were $4.83 per Boe, which was 9% higher than the nine months ended September 30, 2013, primarily due to higher oil production as a percentage of total production, higher crude oil prices and higher natural gas prices.

Change in inventory

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

For the three months ended September 30, 2014, the change in inventory account amounted to a charge of $3.8 million compared to a credit of $4.9 million during the same period in 2013. The charge to inventory during the three months ended September 30, 2014 reflects a higher volume of crude oil sold than produced during the period while the credit during the three months ended September 30, 2013 reflects a lower volume of crude oil sold than produced during the period due to the timing of Florida sales. In the three months ended September 30, 2014, we sold 251 gross MBbls and produced 181 gross MBbls of crude oil from our Florida operations.

For the nine months ended September 30, 2014, the change in inventory account amounted to a credit of $0.9 million compared to a credit of $6.8 million during the same period in 2013. The credit to inventory during the nine months ended September 30, 2014 and September 30, 2013 reflects a lower volume of crude oil sold than produced during the periods due to the timing of Florida sales. In the nine months ended September 30, 2014, we sold 514 gross MBbls and produced 522 gross MBbls of crude oil from our Florida operations.

Depletion, depreciation and amortization

DD&A totaled $72.7 million, or $21.67 per Boe, during the three months ended September 30, 2014, an increase of approximately 12% per Boe from the same period a year ago. The increase in DD&A per Boe compared to the three months ended September 30, 2013 was primarily due to higher oil production as a percentage of total production and higher DD&A rates in California and Texas due to increased drilling activities.

DD&A totaled $204.4 million, or $20.55 per Boe, during the nine months ended September 30, 2014, an increase of approximately 5% per Boe from the same period a year ago. The increase in DD&A per Boe compared to nine months ended September 30, 2013 was primarily due to higher oil production as a percentage of total production and higher California DD&A rates, partially offset by lower Michigan DD&A rates driven by higher reserves related to an increase in natural gas prices.

Impairments

Impairments totaled $29.4 million for the three months and nine months ended September 30, 2014, including $19.9 million in Florida, $6.5 million in Michigan and $3.0 million in Wyoming. The Florida impairments are due to reserve adjustments primarily related to well performance and lower crude oil prices. The Michigan impairments relate to the write-off of investments associated with expiring leases that we have elected not to renew. The Wyoming impairments are due to reserve adjustments related to a combination of well performance, lower commodity prices and higher expense projections. Impairments totaled $0.4 million for the three months and nine months ended September 30, 2013, including $0.2 million in Florida and $0.2 million in Michigan.

General and administrative expenses

Our general and administrative (“G&A”) expenses totaled $18.7 million and $16.1 million for the three months ended September 30, 2014 and 2013, respectively. This included $5.8 million and $4.9 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans. G&A expenses, excluding non-cash unit-based compensation, were $12.9 million and $11.2 million for the three months ended September 30, 2014 and 2013, respectively. The increase was primarily due to higher payroll expenses for additional personnel attributable to our 2013 acquisitions. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $3.85 and $3.62 for the three months ended September 30, 2014 and 2013, respectively. The increase in G&A expenses per Boe was primarily due to higher acquisition and integration costs. The increase in unit-based compensation expense was primarily due to additional personnel.

Our G&A expenses totaled $53.9 million and $44.7 million for the nine months ended September 30, 2014 and 2013, respectively. This included $18.4 million and $14.7 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans. G&A expenses, excluding non-cash unit-based compensation, were $35.4 million and $30.0 million for the nine months ended September 30, 2014 and 2013, respectively. The increase was primarily due to higher payroll expense for additional personnel attributable to our 2013 acquisitions. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $3.56 and $3.80 for the nine months ended September 30, 2014 and 2013, respectively. The decrease in G&A expenses per Boe was primarily due to lower acquisition evaluation and integration costs as well as higher production from our 2013 acquisitions. The increase in unit-based compensation expense was primarily due to additional personnel and an increase in the 2013 CPU performance factor from 1.0 to 1.25 (see Note 14 to the consolidated financial statements within this report).

Interest expense, net of amounts capitalized

Our interest expense totaled $29.5 million and $23.5 million for the three months ended September 30, 2014 and 2013, respectively. The increase in interest expense was primarily due to $7.9 million related to the 7.875% senior notes due 2022 (the “2022 Senior Notes”) issued in November 2013, partially offset by $1.8 million lower credit facility interest expense as a result of lower borrowings and lower interest rates. Interest expense, excluding debt amortization, totaled $27.7 million and $21.7 million for the three months ended September 30, 2014 and 2013, respectively.

Our interest expense totaled $90.4 million and $60.4 million for the nine months ended September 30, 2014 and 2013, respectively. The increase in interest expense was primarily due to $23.6 million related to the 2022 Senior Notes issued in November 2013 and $5.2 million in higher credit facility interest expense as a result of increased borrowings and higher

interest rates. Interest expense, excluding debt amortization, totaled $84.6 million and $56.0 million for the nine months ended September 30, 2014 and 2013, respectively.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations, amounts available under our credit facility and equity and debt offerings. Our primary uses of cash have been for our operating expenses, capital expenditures and cash distributions to unitholders. To fund certain acquisition transactions, we have historically used borrowings under our credit facility, accessed the private placement markets and issued equity as partial consideration. 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.

Preferred Units

In May 2014, we sold 8.0 million Preferred Units at a price to the public of $25.00 per Preferred Unit, resulting in proceeds of $193.2 million, net of underwriting discount and offering expenses of $6.8 million.

The initial distribution of $0.309375 per Preferred Unit was paid on July 15, 2014. Regular monthly distributions of $0.171875 per Preferred Unit began with the August 15, 2014 payment. The monthly distribution rate is equal to an annual distribution of $2.0625 per Preferred Unit.

Common Units

Our Partnership Agreement provides that, at the discretion of our General Partner, we may pay quarterly distributions on our Common Units within 45 days following the end of each quarter or in three installments within 17, 45 and 75 days following the end of each quarter. We changed our Common Unit distribution payment policy from a quarterly payment schedule to a monthly payment schedule beginning with the distributions relating to the fourth quarter of 2013.

During the three months ended September 30, 2014, we paid three monthly cash distributions at the rate of $0.1675 per Common Unit per month, totaling approximately $60.5 million, or $0.5025 per Common Unit.

During the nine months ended September 30, 2014, we paid nine monthly cash distributions, the first three distributions at the rate of $0.1642, the second three distributions at the rate of $0.1658, and the last three distributions at the rate of $0.1675 per Common Unit per month, totaling approximately $178.7 million, or $1.4925 per Common Unit.

On October 1, 2014, we announced a cash distribution to unitholders for the first monthly payment attributable to the third quarter of 2014 at the rate of $0.1675 per Common Unit, which was paid on October 16, 2014 to the record holders of Common Units at the close of business on October 13, 2014. On October 29, 2014, we announced a cash distribution to unitholders for the second monthly payment attributable to the third quarter of 2014 at the rate of $0.1675 per Common Unit, to be paid on November 14, 2014 to the record holders of Common Units at the close of business on November 10, 2014.

On October 10, 2014, we sold 14 million Common Units at a price to the public of $18.64 per Common Unit. We used the net proceeds of $251.6 million from the offering to reduce outstanding borrowings under our credit facility.

On October 24, 2014, in connection with the Antares Acquisition we issued 4.3 million Common Units to Antares as partial consideration for the Antares Assets.

Cash Flows

Operating activities. Our cash flows from operating activities for the nine months ended September 30, 2014 were $294.9 million compared to $166.9 million for the nine months ended September 30, 2013. The increase in cash flows from operating activities was primarily due to higher operating income in 2014 driven by our 2013 acquisitions and higher natural gas prices, and an increase in accounts receivable and other assets during the nine months ended September 30, 2013, which decreased 2013 cash flows from operating activities.

Investing activities. Net cash used in investing activities during the nine months ended September 30, 2014 and 2013 was $308.6 million and $1.05 billion, respectively. During the nine months ended September 30, 2014, we spent $293.3

million on capital expenditures, primarily for drilling and completion activities, $8.7 million on CO₂ advances and $6.4 million on property acquisitions. During the nine months ended September 30, 2013, we spent $861.6 million on property acquisitions and $191.5 million on capital expenditures, primarily for drilling and completion activities.

Financing activities. Net cash flows from financing activities for the nine months ended September 30, 2014 and 2013 was $14.4 million and $884.2 million, respectively. During the nine months ended September 30, 2014, we decreased our outstanding borrowings under our credit facility by approximately $14.0 million. We had total outstanding borrowings, net of unamortized discount on our senior notes, of approximately $1.88 billion at September 30, 2014 and $1.89 billion at December 31, 2013. During the nine months ended September 30, 2014, we received net proceeds of $193.2 million and $25.9 million from the issuance of Preferred Units and Common Units, respectively, made cash distributions of $181.4 million, borrowed $693.0 million and repaid $707.0 million under our credit facility. During the nine months ended September 30, 2013, we received net proceeds of $285.0 million from the issuance of Common Units, made cash distributions of $137.4 million, borrowed $1.38 billion and repaid $636.0 million under our credit facility.

Senior Notes

As of September 30, 2014, we had $305 million in 8.625% senior notes due 2020 and $850 million in 2022 Senior Notes. See Note 8 to the consolidated financial statements within this report for a discussion of our senior notes.

Credit Agreement

At each of September 30, 2014 and December 31, 2013, we had a $3.0 billion credit facility with a maturity date of May 9, 2017 and May 9, 2016, respectively. At September 30, 2014 and December 31, 2013, our borrowing base was $1.6 billion and $1.5 billion, respectively, and the aggregate commitment of all lenders was $1.4 billion at each date.

As of September 30, 2014 and November 4, 2014, we had $719 million and $590.0 million, respectively, in indebtedness outstanding under the Second Amended and Restated Credit Agreement.

As of September 30, 2014, the lending group under the Second Amended and Restated Credit Agreement included 22 banks. Of the $1.4 billion in total commitments under our credit facility, Wells Fargo Bank, National Association held approximately 12% of the commitments. Fifteen banks held between 3.5% and 6.8% of the commitments, including Bank of Montreal, The Bank of Nova Scotia, Union Bank, N.A., Barclays Bank PLC, Citibank, N.A., Royal Bank of Canada, Sovereign Bank, N.A., The Royal Bank of Scotland plc, U.S. Bank National Association, Compass Bank, Comerica Bank, Credit Suisse AG, Cayman Islands Branch, J.P. Morgan Chase, N.A., Sumitomo Mitsui Banking Group and Toronto Dominion (Texas), LLC, with each of the remaining lenders holding 2.5% of the commitments. In addition to our relationships with these institutions under our credit facility, from time to time we engage in other transactions with a number of these institutions. Such institutions or their affiliates may serve as underwriter or initial purchaser of our debt and equity securities and/or serve as counterparties to our commodity and interest rate derivative contracts.

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

The Second Amended and Restated Credit Agreement includes a restriction on our ability to make a distribution unless, after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility. As of September 30, 2014 and November 4, 2014 we were in compliance with our debt covenants.

The events that constitute an event of default under 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.

closing of the Merger, we expect to amend and restate our existing credit facility to increase the borrowing base and the aggregate commitment of all lenders under our credit facility to $2.5 billion, consistent with the commitment from Wells Fargo Bank, N.A. We expect our next regularly scheduled borrowing base redetermination under our new amended and restated credit facility to be in April 2015.

Contractual Obligations and Commitments

On July 15, 2013, we completed the acquisition of the Whiting Assets. As part of this acquisition, we assumed the obligation to purchase a minimum daily volume of CO₂ over the next 20 years. Under the take-or-pay provisions of these purchase agreements, we are committed to buying certain volumes of CO₂ for use in our enhanced recovery project being carried out at the Postle field. See Note 12 to the consolidated financial statements within this report for a discussion of our future minimum commitments under these purchase agreements.

Except for the issuance of Preferred Units and Common Units and the amendments to our credit facility, we had no material changes to our financial contractual obligations during the nine months ended September 30, 2014.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of September 30, 2014 and December 31, 2013.

New Accounting Standards

See Note 1 to the consolidated financial statements within this report for a discussion of new accounting standards applicable to us.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with “Quantitative and Qualitative Disclosures About Market Risk” included under Part II—Item 7A in our 2013 Annual Report. Also, see Note 3 to the consolidated financial statements within this report for additional discussion related to our financial instruments, including a summary of our derivative instruments as of September 30, 2014.

Changes in Fair Value

The fair value of our outstanding oil and natural gas commodity derivative instruments was a net asset of approximately $65.0 million and $51.8 million at September 30, 2014 and December 31, 2013, respectively. With a $10.00 per barrel increase in the price of oil, and a corresponding $1.00 per Mcf increase in natural gas, our net commodity derivative instrument asset at September 30, 2014 would have decreased by approximately $212 million. With a $10.00 per barrel decrease in the price of oil, and a corresponding $1.00 per Mcf decrease in natural gas, our net commodity derivative instrument asset at September 30, 2014 would have increased by approximately $216 million.

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

Item 4. Controls and Procedures

Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our General Partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. 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, 2014 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, 2014 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Following the July 24, 2014 announcement that QR Energy and Breitburn had entered into a definitive merger agreement, purported unitholders of QR Energy filed putative class action lawsuits, on behalf of the common unitholders of QR Energy, asserting claims challenging the Merger. Four purported class action lawsuits were filed in the United States District Court for the Southern District of Texas and were consolidated under the caption In re QR Energy LP Unitholder Litigation, No. 4:14-cv-02195 (the “Consolidated Unitholder Action”). Plaintiffs in the Consolidated Unitholder Action bring claims against QR Energy, QRE, the members of the QRE board of directors, the Partnership, our General Partner and Merger Sub. 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 2013 Annual Report, except as disclosed in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 and our Current Report on Form 8-K filed with the SEC on October 6, 2014, which are incorporated by reference in this 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
2.1		Agreement and Plan of Merger, dated as of July 23, 2014, by and among Breitburn Energy Partners LP, Breitburn GP LLC, Boom Merger Sub, LLC, QR Energy LP and QRE GP, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by QR Energy, LP on July 29, 2014).
3.1		Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
3.2		Amendment No. 1 to the Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC dated as of December 30, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
3.3		Amendment No. 2 to the Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC dated as of July 1, 2014 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on July 2, 2014).
3.4		Second Amended and Restated Agreement of Limited Partnership of Breitburn Energy Partners LP(incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on May 21, 2014).
3.5		Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Breitburn Energy Partners LP dated July 1, 2014 (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on July 2, 2014).
4.1		Indenture, dated as of October 6, 2010, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors and U.S. National Bank Association as trustee, in connection with the private placement of the Notes (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010).
4.2		Indenture, dated as of January 13, 2012, by and among Breitburn Energy Partners LP, 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 July 23, 2014, by and among Breitburn Energy Partners LP, QR Holdings (QRE), LLC, QR Energy Holdings, LLC, Quantum Resources B, LP, Quantum Resources A1, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by QR Energy, LP on July 29, 2014).
10.1*		Amendment No. 2 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company, LLC dated June 30, 2014.
10.2*		Amendment No. 3 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company, LLC dated July 31, 2014.
10.3*		Amendment No. 4 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company, LLC dated August 29, 2014.
10.4		Contribution Agreement, between Antares Energy Company and Breitburn Operating LP, dated as of October 24, 2014 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 28, 2014.
10.5		Transaction, Voting and Support Agreement, dated as of July 23, 2014, by and among Breitburn Energy Partners LP, Quantum Resource A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP and Black Diamond Resources, LLC, QR Holdings LLC and QR Energy Holdings, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K filed by QR Energy, LP on July 29, 2014).
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.
†		Management contract or compensatory plan or arrangement.

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 LP

		By:	BREITBURN GP LLC,
			its General Partner

Dated:	November 5, 2014	By:	/s/ Halbert S. Washburn
			Halbert S. Washburn
			Chief Executive Officer

Dated:	November 5, 2014	By:	/s/ James G. Jackson
			James G. Jackson
			Chief Financial Officer

INDEX TO EXHIBITS



NUMBER		DOCUMENT
2.1		Agreement and Plan of Merger, dated as of July 23, 2014, by and among Breitburn Energy Partners LP, Breitburn GP LLC, Boom Merger Sub, LLC, QR Energy LP and QRE GP, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by QR Energy, LP on July 29, 2014).
3.1		Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
3.2		Amendment No. 1 to the Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC dated as of December 30, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
3.3		Amendment No. 2 to the Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC dated as of July 1, 2014 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on July 2, 2014).
3.4		Second Amended and Restated Agreement of Limited Partnership of Breitburn Energy Partners LP(incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on May 21, 2014).
3.5		Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Breitburn Energy Partners LP dated July 1, 2014 (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on July 2, 2014).
4.1		Indenture, dated as of October 6, 2010, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors and U.S. National Bank Association as trustee, in connection with the private placement of the Notes (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010).
4.2		Indenture, dated as of January 13, 2012, by and among Breitburn Energy Partners LP, 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 July 23, 2014, by and among Breitburn Energy Partners LP, QR Holdings (QRE), LLC, QR Energy Holdings, LLC, Quantum Resources B, LP, Quantum Resources A1, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by QR Energy, LP on July 29, 2014).
10.1*		Amendment No. 2 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company, LLC dated June 30, 2014.
10.2*		Amendment No. 3 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company, LLC dated July 31, 2014.
10.3*		Amendment No. 4 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company, LLC dated August 29, 2014.
10.4		Contribution Agreement, between Antares Energy Company and Breitburn Operating LP, dated as of October 24, 2014 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 28, 2014.
10.5		Transaction, Voting and Support Agreement, dated as of July 23, 2014, by and among Breitburn Energy Partners LP, Quantum Resource A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP and Black Diamond Resources, LLC, QR Holdings LLC and QR Energy Holdings, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K filed by QR Energy, LP on July 29, 2014).
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.
†		Management contract or compensatory plan or arrangement.

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