Breitburn Energy Partners LP - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - Breitburn Energy Partners LP	Financial_Report.xls
EX-3.2 - EXHIBIT 3.2 - Breitburn Energy Partners LP	q1201510-qex32.htm
EX-10.1 - EXHIBIT 10.1 - Breitburn Energy Partners LP	q1201510qex101.htm
EX-31.2 - EXHIBIT 31.2 - Breitburn Energy Partners LP	q1201510-qex312.htm
EX-32.2 - EXHIBIT 32.2 - Breitburn Energy Partners LP	q1201510-qex322.htm
EX-31.1 - EXHIBIT 31.1 - Breitburn Energy Partners LP	q1201510-qex311.htm
EX-32.1 - EXHIBIT 32.1 - Breitburn Energy Partners LP	q1201510-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 March 31, 2015



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 May 4, 2015, the registrant had 210,951,820 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 March 31, 2015 and December 31, 2014	2
	– Consolidated Statements of Operations for the Three Months Ended March 31, 2015 and 2014	3
	– Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014	5
	– Notes to Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	32

	PART II
	OTHER INFORMATION

Item 1.	Legal Proceedings	33
Item 1A.	Risk Factors	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3.	Defaults Upon Senior Securities	33
Item 4.	Mine Safety Disclosures	33
Item 5.	Other Information	33
Item 6.	Exhibits	34

Signatures		36

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 are 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; ability to integrate successfully the businesses we acquire; 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, 2014 (our “2014 Annual Report”) 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	March 31, 2015			December 31, 2014
ASSETS
Current assets
Cash	$	8,690		$	12,628
Accounts and other receivables, net	136,360			166,436
Derivative instruments (note 3)	411,391			408,151
Related party receivables (note 4)	—			2,462
Inventory	3,912			3,727
Prepaid expenses	3,532			7,304
Total current assets	563,885			600,708
Equity investments	6,138			6,463
Property, plant and equipment
Oil and natural gas properties	7,804,213			7,736,409
Other property, plant and equipment (note 2)	133,429			60,533
	7,937,642			7,796,942
Accumulated depletion and depreciation (note 5)	(1,505,141		)	(1,342,741		)
Net property, plant and equipment	6,432,501			6,454,201
Other long-term assets
Intangibles (note 6)	7,616			8,336
Goodwill (note 2)	95,947			92,024
Derivative instruments (note 3)	326,788			319,560
Other long-term assets (note 6)	108,194			157,042
Total assets	$	7,541,069		$	7,638,334
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	102,448		$	129,270
Current portion of long-term debt (note 7)	—			105,000
Derivative instruments (note 3)	5,339			5,457
Distributions payable	734			733
Current portion of asset retirement obligation (note 9)	4,388			4,948
Revenue and royalties payable	36,065			40,452
Wages and salaries payable	14,178			22,322
Accrued interest payable	42,882			20,672
Production and property taxes payable	25,980			25,207
Other current liabilities	6,422			7,495
Total current liabilities	238,436			361,556
Credit facility	2,218,000			2,089,500
Senior notes, net	1,156,532			1,156,560
Other long-term debt	2,700			1,100
Total long-term debt (note 7)	3,377,232			3,247,160
Deferred income taxes	2,743			2,575
Asset retirement obligation (note 9)	239,039			233,463
Derivative instruments (note 3)	2,378			2,269
Other long-term liabilities (note 10)	25,122			25,135
Total liabilities	3,884,950			3,872,158
Commitments and contingencies (note 11)
Equity
Series A preferred units, 8.0 million units issued and outstanding at each of March 31, 2015 and December 31, 2014 (note 12)	193,215			193,215
Common units, 210.9 million units issued and outstanding at each of March 31, 2015 and December 31, 2014 (note 12)	3,456,330			3,566,468
Accumulated other comprehensive income (loss) (note 13)	(289		)	(392		)
Total partners' equity	3,649,256			3,759,291
Noncontrolling interest	6,863			6,885
Total equity	3,656,119			3,766,176

Total liabilities and equity	$	7,541,069		$	7,638,334

See accompanying notes to consolidated financial statements.

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Operations

(Unaudited)



	Three Months Ended
	March 31,
Thousands of dollars, except per unit amounts	2015			2014
Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	162,623		$	223,556
Gain (loss) on commodity derivative instruments, net (note 3)	137,192			(40,228		)
Other revenue, net	6,469			1,584
Total revenues and other income items	306,284			184,912
Operating costs and expenses
Operating costs	117,978			82,197
Depletion, depreciation and amortization	109,824			63,501
Impairments (note 5)	59,113			—
General and administrative expenses	32,262			18,729
Restructuring costs (note 15)	4,918			—
Loss on sale of assets	15			86
Total operating costs and expenses	324,110			164,513

Operating income (loss)	(17,826		)	20,399

Interest expense, net of capitalized interest	39,665			30,658
Loss on interest rate swaps (note 3)	1,812			—
Other income, net	(477		)	(512		)

Loss before taxes	(58,826		)	(9,747		)

Income tax expense	92			11

Net loss	(58,918		)	(9,758		)

Less: Net loss attributable to noncontrolling interest	(93		)	—

Net loss attributable to the partnership	(58,825		)	(9,758		)

Less: distributions to preferred unitholders	4,125			—

Net loss attributable to common unitholders	$	(62,950	)	$	(9,758	)

Basic net loss per unit (note 12)	$	(0.29	)	$	(0.08	)
Diluted net loss per unit (note 12)	$	(0.29	)	$	(0.08	)

See accompanying notes to consolidated financial statements.

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Comprehensive Loss

(Unaudited)



	Three Months Ended
	March 31,
Thousands of dollars, except per unit amounts	2015			2014
Net loss	$	(58,918	)	$	(9,758	)

Other comprehensive income, net of tax:
Change in fair value of available-for-sale securities (a)	173			—
Pension and post-retirement benefits actuarial loss	—			—
Total other comprehensive income	173			—

Total comprehensive loss	(58,745		)	(9,758		)

Less: Comprehensive income attributable to noncontrolling interest	(23		)	—

Comprehensive loss attributable to the partnership	$	(58,722	)	$	(9,758	)

(a) Net of income taxes of $0.1 million for the three months ended March 31, 2015.

See accompanying notes to consolidated financial statements.

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)



	Three Months Ended
	March 31,
Thousands of dollars	2015			2014
Cash flows from operating activities
Net loss	$	(58,918	)	$	(9,758	)
Adjustments to reconcile to cash flows from operating activities:
Depletion, depreciation and amortization	109,824			63,501
Impairments	59,113			—
Unit-based compensation expense	7,741			6,549
(Gain) loss on derivative instruments	(135,380		)	40,228
Derivative instrument settlement receipts (payments)	124,904			(13,500		)
Income from equity affiliates, net	325			(107		)
Deferred income taxes	168			(33		)
Loss on sale of assets	15			86
Other	(41		)	1,800
Changes in net assets and liabilities
Accounts receivable and other assets	30,043			(20,752		)
Inventory	(185		)	5
Net change in related party receivables and payables	2,462			1,669
Accounts payable and other liabilities	1,078			46,623
Net cash provided by operating activities	141,149			116,311
Cash flows from investing activities
Property acquisitions	(13,993		)	(2,464		)
Capital expenditures	(97,230		)	(93,075		)
Other	(853		)	(2,037		)
Proceeds from sale of assets	—			1
Net cash used in investing activities	(112,076		)	(97,575		)
Cash flows from financing activities
Proceeds from issuance of common units, net	(63		)	180
Distributions to preferred unitholders	(4,125		)	—
Distributions to common unitholders	(54,122		)	(59,638		)
Proceeds from issuance of long-term debt, net	193,600			199,000
Repayments of long-term debt	(168,500		)	(157,000		)
Change in bank overdraft	199			(1,683		)
Debt issuance costs	—			(232		)
Net cash used in financing activities	(33,011		)	(19,373		)
Decrease in cash	(3,938		)	(637		)
Cash beginning of period	12,628			2,458
Cash end of period	$	8,690		$	1,821

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 2014 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 March 31, 2015, our operating results for the three months ended March 31, 2015 and 2014 and our cash flows for the three months ended March 31, 2015 and 2014 have been included. Operating results for the three months ended March 31, 2015 are not necessarily indicative of the results that may be expected for the year ended December 31, 2015. The consolidated balance sheet at December 31, 2014 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 2014 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.

Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs, which simplifies the presentation of debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. This presentation is consistent with debt discounts. The Accounting Standards Update (“ASU”) does not affect guidance for recognition and measurement for debt issuance costs. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We are evaluating the impact that ASU 2015-03 will have on our financial statements.

In May 2014, the 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 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.

2015 Acquisitions

On March 31, 2015, we completed the acquisition of certain CO₂ properties located in Harding County, New Mexico (“CO₂ Assets”), for a total preliminary purchase price of $64.2 million (the “CO₂ Acquisition”), subject to customary purchase price adjustments, of which, $14.3 million was paid during the three months ended March 31, 2015. The preliminary purchase price included $64.5 million reflected in other property, plant and equipment on the consolidated balance sheet and $0.3 million of ARO reflected in asset retirement obligation on the consolidated balance sheet.

2014 Acquisitions

QR Energy, LP

On November 19, 2014, we completed the previously announced transactions contemplated by the Agreement and Plan of Merger, dated as of July 23, 2014 (the “Merger Agreement”) with QR Energy, LP, a Delaware limited partnership (“QRE”). Pursuant to the terms of the Merger Agreement, QRE merged with a subsidiary of the Partnership, with QRE continuing as the surviving entity and as a direct wholly owned subsidiary of the Partnership (the “QRE Merger”). Immediately thereafter, the Partnership transferred 100% of the limited partner interests of QRE to Breitburn Operating LP (“BOLP”), its wholly owned subsidiary. In connection with the QRE Merger, we acquired a 59% controlling interest in East Texas Saltwater Disposal Company (“ETSWDC”) and have consolidated ETSWDC into our consolidated financial statements. The main purpose of ETSWDC is to dispose of salt water generated as a by-product from oil produced in certain East Texas oil fields.

Under the terms of the Merger Agreement, we issued a total of approximately 71.5 million common units representing limited partner interests (“common units”) to holders of outstanding QRE common units and QRE Class B Units. In addition, we paid a total of $350 million to holders of QRE Class C Units.

The initial purchase price, subject to customary purchase price adjustments, for the QRE Merger was allocated to the assets acquired and liabilities assumed as follows at March 31, 2015:



Thousands of dollars
Cash	$	5,121
Accounts and other receivables	113,398
Current derivative instrument assets	70,362
Prepaid expenses	3,123
Oil and gas properties	2,397,967
Non-oil and gas assets	17,866
Goodwill	95,947
Long-term derivative instrument assets	72,998
Other long-term assets	50,619
Accounts payable and accrued liabilities	(157,916		)
Current derivative instrument liabilities	(6,512		)
Current asset retirement obligation	(2,618		)
Credit facility debt	(790,000		)
Senior notes at fair value	(344,129		)
Long-term asset retirement obligation	(91,465		)
Long-term derivative instrument liabilities	(8,877		)
Other long-term liabilities	(10,277		)
Noncontrolling interest	(7,173		)
	$	1,408,434

The initial purchase price allocation was determined by management with the assistance of outside valuation consulting firms. While the initial valuation and purchase price allocation have been completed, circumstances may arise in the future that could lead to adjustments to the valuation and/or allocation. If adjustments are required, they would be recorded no later than one year from the acquisition date.

Acquisition-related costs for the QRE Merger were $0.1 million for the three months ended March 31, 2015 and are reflected in G&A expenses on the consolidated statements of operations.

In connection with the QRE Merger, on November 19, 2014, we entered into a Transition Services Agreement (“TSA”) with Quantum Resources Management, LLC (“QRM”). Under the terms of the TSA, each party agreed to provide certain land, administrative, accounting, IT and marketing services to the other party. The term of the TSA commenced on November 19, 2014 and terminates on the earlier of (i) six months following November 19, 2014 and (ii)(A) with respect to QRM, the date upon which we provide written notice to QRM of our desire to terminate the TSA and (B) with respect to us, the date upon which QRM provides us with written notice of its desire to terminate the TSA.

Antares Acquisition

On October 24, 2014, we 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 4.3 million Common Units and $50.0 million in cash (the “Antares Acquisition”), subject to customary purchase price adjustments, for a total preliminary purchase price of $122.3 million, which was allocated to oil and natural gas assets ($110.9 million to unproved properties, $13.1 million to proved properties and $1.7 million to ARO). 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. We expect to finalize the valuation and complete the purchase price allocation as soon as practicable but no later than one year from the acquisition date. Acquisition-related costs for the Antares Acquisition were zero for the three months ended March 31, 2015.

Pro Forma (unaudited)

The following unaudited pro forma financial information presents a summary of our combined statements of operations for the three months ended March 31, 2014 assuming the QRE Merger was completed on January 1, 2014. The pro forma results include adjustments 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 acquisition, 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 acquisition. The pro forma financial information is not necessarily indicative of the results of operations if the acquisition had been effective January 1, 2014. The Antares Acquisition in 2014 and the CO₂ Acquisition in 2015 were not included in the pro forma information as they are considered immaterial.



	Pro Forma
	Three Months Ended
Thousands of dollars, except per unit amounts	March 31, 2014
Revenues	284,370
Net loss attributable to the partnership	(17,500	)

Net loss per common unit:
Basic	(0.08	)
Diluted	(0.08	)

3. Financial Instruments and Fair Value Measurements

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 March 31, 2015:



	Year
	2015				2016		2017		2018
Oil Positions:
Fixed Price Swaps - NYMEX WTI
Volume (Bbl/d)	20,044				15,504		13,519		493
Average Price ($/Bbl)	$	93.28			$	88.07	$	85.05	$	82.20
Fixed Price Swaps - ICE Brent
Volume (Bbl/d)	3,300				4,300		298		—
Average Price ($/Bbl)	$	97.73			$	95.17	$	97.50	$	—
Collars - NYMEX WTI
Volume (Bbl/d)	2,025				1,500		—		—
Average Floor Price ($/Bbl)	$	90.00			$	80.00	$	—	$	—
Average Ceiling Price ($/Bbl)	$	111.73			$	102.00	$	—	$	—
Collars - ICE Brent
Volume (Bbl/d)	500				500		—		—
Average Floor Price ($/Bbl)	$	90.00			$	90.00	$	—	$	—
Average Ceiling Price ($/Bbl)	$	109.50			$	101.25	$	—	$	—
Puts - NYMEX WTI
Volume (Bbl/d)	500				1,000		—		—
Average Price ($/Bbl)	$	90.00			$	90.00	$	—	$	—
Total:
Volume (Bbl/d)	26,369				22,804		13,817		493
Average Price ($/Bbl)	$	93.46			$	89.01	$	85.32	$	82.20

Natural Gas Positions:
Fixed Price Swaps - MichCon City-Gate
Volume (MMBtu/d)	7,500				17,000		10,000		—
Average Price ($/MMBtu)	$	6.00			$	4.46	$	4.48	$	—
Fixed Price Swaps - Henry Hub
Volume (MMBtu/d)	54,891				36,050		19,016		1,870
Average Price ($/MMBtu)	$	4.84			$	4.24	$	4.43	$	4.15
Collars - Henry Hub
Volume (MMBtu/d)	18,000				630		595		—
Average Floor Price ($/MMBtu)	$	5.00			$	4.00	$	4.00	—
Average Ceiling Price ($/MMBtu)	$	7.48			$	5.55	$	6.15	$	—
Puts - Henry Hub
Volume (MMBtu/d)	1,920				11,350		10,445		—
Average Price ($/MMBtu)	$	4.78			$	4.00	$	4.00	$	—
Deferred Premium ($/MMBtu)	$	0.64		(a)	$	0.66	$	0.69	$	—
Total:
Volume (MMBtu/d)	82,311				65,030		40,056		1,870
Average Price ($/MMBtu)	$	4.98			$	4.25	$	4.33	$	4.15

Basis Swaps - Henry Hub
Volume (MMBtu/d)	14,400				—		—		—
Average Price ($/MMBtu)	$	(0.19	)		$	—	$	—	$	—

(a) Deferred premiums of $0.64 apply to 420 MMBtu/d of the 2015 volume.

During the three months ended March 31, 2015 and 2014, we did not enter into any derivative instruments that required pre-paid premiums.

As of March 31, 2015, premiums paid in 2012 related to oil and natural gas derivatives to be settled beyond March 31, 2015 were as follows:



	Year
Thousands of dollars	2015		2016		2017		2018
Oil	$	3,528	$	7,438	$	734	$	—
Natural gas	$	1,499	$	952	$	—	$	—

Interest Rate Activities

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. To fix a portion of our floating LIBOR-base debt under our credit facility, we had the following interest rate swaps in place at March 31, 2015 and December 31, 2014. These contracts were novated to us in November 2014 in connection with the QRE Merger:



	Year
	2015			2016
Fixed Rate Swaps - LIBOR
Notional Amount (thousands of dollars)	$	401,933		$	410,000
Average Fixed Rate	1.59		%	1.72		%

We do not currently designate any of our interest rate derivatives as hedges for financial accounting purposes.

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			Interest Rate Derivatives			Commodity Derivatives Netting (a)			Total Financial Instruments
As of March 31, 2015
Assets
Current assets - derivative instruments	$	356,587		$	55,720		$	—		$	(916	)	$	411,391
Other long-term assets - derivative instruments	295,526			36,146			11			(4,895		)	326,788
Total assets	652,113			91,866			11			(5,811		)	738,179
Liabilities
Current liabilities - derivative instruments	(82		)	(996		)	(5,177		)	916			(5,339		)
Long-term liabilities - derivative instruments	(338		)	(4,557		)	(2,378		)	4,895			(2,378		)
Total liabilities	(420		)	(5,553		)	(7,555		)	5,811			(7,717		)
Net assets (liabilities)	$	651,693		$	86,313		$	(7,544	)	$	—		$	730,462

As of December 31, 2014
Assets
Current assets - derivative instruments	$	350,351		$	58,246		$	—		$	(446	)	$	408,151
Other long-term assets - derivative instruments	296,441			29,649			210			(6,740		)	319,560
Total assets	646,792			87,895			210			(7,186		)	727,711
Liabilities
Current liabilities - derivative instruments	(214		)	(563		)	(5,126		)	446			(5,457		)
Long-term liabilities - derivative instruments	(1,520		)	(5,220		)	(2,269		)	6,740			(2,269		)
Total liabilities	(1,734		)	(5,783		)	(7,395		)	7,186			(7,726		)
Net assets (liabilities)	$	645,058		$	82,112		$	(7,185	)	$	—		$	719,985

(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 consolidated balance sheets.

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)			Interest Rate Derivatives (b)			Total Financial Instruments
Three Months Ended March 31, 2015
Net gain (loss)	$	118,514		$	18,678		$	(1,812	)	$	135,380
Three Months Ended March 31, 2014
Net loss	$	(27,892	)	$	(12,336	)	$	—		$	(40,228	)

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

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

Fair Value Measurements

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 March 31, 2015, and December 31, 2014, 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 three months ended March 31, 2015 and 2014. Our policy is to recognize transfers between levels as of the end of the period.

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.

Derivative Instruments

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 and also use a third-party validation firm for a portion of our portfolio. Any differences are resolved and any required changes are recorded prior to the issuance of our financial statements.

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

forward commodity prices and risk-free interest rates for present value discounting. We use the standard swap contract valuation method to value our interest rate derivatives, and inputs include LIBOR forward interest rates, one-month LIBOR rates and risk-free interest rates for present value discounting.

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

The fair value of the commodity and interest rate derivative instruments that were novated to us in connection with the QRE Merger are estimated using a combined income and market valuation methodology based upon forward commodity prices and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. We validate the data provided by independent pricing services by comparing such pricing against other third party pricing data.

Available for Sale Securities

The fair value of our available for sale securities are estimated using actual trade data, broker/dealer quotes, and other similar data, which are obtained from quoted market prices, independent pricing vendors, or other sources. We validate the data provided by independent pricing services to make assessments and determinations as to the ultimate valuation of its investment portfolio by comparing such pricing against other third party pricing data. We consider the inputs to the valuation of our available for sale securities to be Level 1.

Fair Value Hierarchy

The following table sets forth, by level within the hierarchy, the fair value of our financial instrument assets and liabilities that were accounted for at fair value on a recurring basis. All fair values reflected below and on the consolidated balance sheets have been adjusted for nonperformance risk.



Thousands of dollars	Level 1		Level 2			Level 3		Total

As of March 31, 2015
Assets (liabilities)
Crude Oil
Crude oil swaps	$	—	$	592,592		$	—	$	592,592
Crude oil collars	—		—			42,095		42,095
Crude oil puts	—		—			17,006		17,006
Natural Gas
Natural gas swaps	—		66,642			—		66,642
Natural gas collars	—		—			11,351		11,351
Natural gas puts	—		—			8,320		8,320
Interest rate swaps
Interest rate swaps	—		(7,544		)	—		(7,544		)
Available-for-sale securities
Equities	4,197		—			—		4,197
Mutual funds	10,679		—			—		10,679
Exchange traded funds	4,733		—			—		4,733
Net assets	$	19,609	$	651,690		$	78,772	$	750,071



Thousands of dollars	Level 1		Level 2			Level 3		Total

As of December 31, 2014
Assets (liabilities)
Crude Oil
Crude oil swaps	$	—	$	583,648		$	—	$	583,648
Crude oil collars	—		—			44,405		44,405
Crude oil puts	—		—			17,005		17,005
Natural gas commodity derivatives
Natural gas swaps	—		62,220			—		62,220
Natural gas collars	—		—			13,256		13,256
Natural gas puts	—		—			6,636		6,636
Interest rate swaps
Interest rate swaps	—		(7,185		)	—		(7,185		)
Available-for-sale securities
Equities	4,138		—			—		4,138
Mutual funds	10,577		—			—		10,577
Exchange traded funds	4,630		—			—		4,630
Net assets	$	19,345	$	638,683		$	81,302	$	739,330

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



	Three Months Ended March 31,
	2015						2014
Thousands of dollars	Oil			Natural Gas			Oil			Natural Gas
Assets (a):
Beginning balance	$	61,410		$	19,892		$	8,957		$	1,848
Derivative instrument settlements (b)	10,987			3,567			—			(57		)
Loss (b)(c)	(13,296		)	(3,788		)	(1,864		)	(639		)
Ending balance	$	59,101		$	19,671		$	7,093		$	1,152

(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 March 31, 2015, the significant unobservable inputs used in the fair value measurements were as follows:



	Fair Value at		Valuation
Thousands of dollars	March 31, 2015		Technique	Unobservable Input	Range
Oil Options	$	59,101	Option Pricing Model	Oil forward commodity prices	$47.60/Bbl - $66.68/Bbl
				Oil volatility	22.92% - 54.89%
				Own credit risk	5%
Natural Gas Options	19,671		Option Pricing Model	Gas forward commodity prices	$2.59/MMBtu - $3.55/MMBtu
				Gas volatility	18.52% - 45.86%
				Own credit risk	5%
Total	$	78,772

For Level 3 derivative instruments measured at fair value on a recurring basis as of December 31, 2014, the significant unobservable inputs used in the fair value measurements were as follows:



	Fair Value at		Valuation
Thousands of dollars	December 31, 2014		Technique	Unobservable Input	Range
Oil Options	$	61,410	Option Pricing Model	Oil forward commodity prices	$53.27/Bbl - $71.66/Bbl
				Oil volatility	29.21% - 46.16%
				Own credit risk	5%
Natural Gas Options	19,892		Option Pricing Model	Gas forward commodity prices	$2.88/MMBtu - $3.99/MMBtu
				Gas volatility	18.59% - 63.51%
				Own credit risk	5%
Total	$	81,302

Credit and Counterparty Risk

Financial instruments, which potentially subject us to concentrations of credit risk, consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of March 31, 2015, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC and Credit Suisse International, Union Bank N.A, Wells Fargo Bank, N.A., JP Morgan Chase Bank N.A., The Bank of Nova Scotia, BNP Paribas, Royal Bank of Canada, The Toronto-Dominion Bank, Merrill Lynch Commodities, Inc., Canadian Imperial Bank of Commerce, Comerica Bank, ING Capital Markets LLC, Credit Agricole Corporate and Investment Bank, and Citizens Bank, National Association. Our counterparties are all lenders under our Third Amended and Restated Credit Agreement. Our credit agreement is secured by our oil, NGL and natural gas reserves, so we are not required to post any collateral, and we conversely do not receive collateral from our counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to fail to perform in accordance with the terms of the contract. This risk is managed by diversifying our derivatives portfolio. As of March 31, 2015, each of these financial institutions had an investment grade credit rating. As of March 31, 2015, our largest derivative asset balances were with Wells Fargo Bank, Credit Suisse Energy LLC and JP Morgan, which accounted for approximately 23%, 20% and 14% 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 ended March 31, 2015 and 2014, the monthly fee paid by PCEC for indirect expenses was $700,000. As of March 31, 2015, the term of the Agreement was set to expire on June 30, 2015. On May 1 2015, the term of the Agreement was extended to December 31, 2016, at which time, the agreement is subject to renegotiation.

At March 31, 2015, we had a current payable of $0.2 million and at December 31, 2014, we had a current receivable of $2.4 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 March 31, 2015 and 2014, 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 $2.8 million and $2.5 million, respectively. At each of March 31, 2015 and December 31, 2014, we had receivables of $0.1 million due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf. The net related party payable at March 31, 2015 of $0.1 million is included in accounts payable on the consolidated balance sheet, and the net related party receivable at December 31, 2014 of $2.5 million is included in related party receivables on the consolidated balance sheet.

5. Impairments

We review our oil and gas properties for impairment periodically or when events or circumstances indicate that their carrying value may not be recoverable. Generally, management does not view temporarily low commodity prices as a sole indicator that an impairment event has occurred as crude oil and natural gas prices have a history of significant volatility. Determination as to whether and how much an asset is impaired involves subjectivity and management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, the outlook for market supply and demand conditions for oil and natural gas, and other factors.

For purposes of assessing our oil and gas properties for potential impairment, management reviews the expected undiscounted future cash flows for our total proved and risk-adjusted probable and possible reserves. The undiscounted cash flow review incudes inputs such as applicable NYMEX forward strip prices, estimated basis price differentials, expenses and capital estimates, and escalation factors. Management also considers what impact future price changes are likely to have on our future operating plans.

If we determine that an impairment charge for a property is warranted, an impairment charge is recorded for the amount that the property’s carrying value exceeds the amount of its estimated discounted future cash flows. For purposes of calculating an impairment charge, estimated discounted future cash flows are determined by using applicable basis adjusted five-year NYMEX forward strip prices and escalated along with expenses and capital starting in year six and thereafter at 2% per year. Production and development cost estimates (e.g. operating expenses and development capital) are conformed to reflect the commodity price strip used. The associated property’s expected future net cash flows are discounted using a market-based weighted average cost of capital rate that currently approximates 10%. 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 $59.1 million for the three months ended March 31, 2015, including $33.1 million for our Permian properties, $16.7 million for our Rockies natural gas properties and $9.3 million for our Mid-Continent properties, primarily due to the impact that the decrease in oil and natural gas prices during three months ended March 31, 2015 had on certain of our low margin properties.

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 this period, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.

6. Other Assets

As of March 31, 2015, and December 31, 2014, our other long-term assets were $108.2 million and $157.0 million, respectively, including $50.5 million and $52.8 million, respectively, in debt issuance costs, $19.6 million and $19.3 million, respectively, in available-for-sale securities and $9.1 million and $5.1 million, respectively in other long-term assets. At each of March 31, 2015 and December 31, 2014, we had a net profits interest obligation for the Jay Field in Florida of $18.3 million (assumed in the QRE Merger) and a property reclamation deposit for future abandonment and remediation obligations for the Jay Field of $10.7 million. In addition, we had zero and $50.8 million, respectively, in CO₂ supply advances and deposits for our Mid-Continent properties as of March 31, 2015, and December 31, 2014. In connection with the CO₂ Acquisition, we reclassified the $50.8 million of CO₂ supply advances and deposits from other long-term assets to other property, plant and equipment on the consolidated balance sheet. See Note 2 for a discussion of the CO₂ Acquisition.

7. Long-Term Debt

Our long-term debt is detailed in the following table:



	As of
Thousands of dollars	March 31, 2015		December 31, 2014
Credit facility	$	2,218,000	$	2,194,500
Promissory note	2,700		1,100
8.625% Senior Notes due 2020	305,000		305,000
7.875% Senior Notes due 2022	850,000		850,000
Net premium on Senior Notes	1,532		1,560
Total debt	3,377,232		3,352,160
Less: current portion of long-term debt	—		(105,000		)
Total long-term debt	$	3,377,232	$	3,247,160

Credit Facility

As of March 31, 2015, BOLP, our wholly-owned subsidiary, as borrower, and we and our wholly-owned subsidiaries, as guarantors, had a $5.0 billion revolving credit facility with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (the “Third Amended and Restated Credit Agreement”) with a maturity date of November 19, 2019.

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. Historically, our borrowing base has been redetermined semi-annually. As of March 31, 2015, our borrowing base was $2.5 billion. At December 31, 2014, our borrowing base was $2.5 billion. Our next borrowing base redetermination was scheduled for April 2015. See Note 16 for a discussion of the First Amendment to the Third Amended and Restated Credit Agreement, which established a revised borrowing base of $1.8 billion.

As of March 31, 2015 and December 31, 2014, we had $2.22 billion and $2.19 billion, respectively, in indebtedness outstanding under our credit facility. At March 31, 2015, the 1-month LIBOR interest rate plus an applicable spread was 2.4135% on the 1-month LIBOR portion of $2.196 billion and the prime rate plus an applicable spread was 4.50% on the prime portion of $22.0 million. At March 31, 2015 and December 31, 2014, we had $32.0 million and $33.5 million, respectively, of unamortized debt issuance costs related to our credit facility.

As of March 31, 2015 and December 31, 2014, we were in compliance with our credit facility’s covenants.

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 $302.2 million, net of unamortized discount of $2.8 million, as of March 31, 2015. 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 $854.3 million, net of unamortized premium of $4.3 million, as of March 31, 2015. At March 31, 2015 and December 31, 2014, we had $18.5 million and $19.3 million, respectively, 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 March 31, 2015, the fair value of our 2020 Senior Notes and 2022 Senior Notes were estimated to be $229.0 million and $615.5 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 March 31, 2015 and December 31, 2014, we were in compliance with the covenants under our Senior Notes.

See Note 16 for a discussion of our senior secured second lien notes issued in April 2015.

Interest Expense

Our interest expense is detailed as follows:



	Three Months Ended
	March 31,
Thousands of dollars	2015		2014
Credit agreement (including commitment fees)	$	13,965	$	5,260
Senior notes	23,311		23,311
Amortization of net premium and deferred issuance costs	2,389		2,148
Capitalized interest	—		(61		)
Total	$	39,665	$	30,658

8. 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 two of our subsidiaries have guaranteed our Senior Notes, and our only non-guarantor subsidiaries, Breitburn Collingwood Utica LLC and ETSWDC, are minor subsidiaries.

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.

9. 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 approximately 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 March 31, 2015, and the year ended December 31, 2014 are presented in the following table:



	Three Months Ended			Year Ended
Thousands of dollars	March 31, 2015			December 31, 2014
Carrying amount, beginning of period	$	238,411		$	123,769
Acquisitions	267			95,800
Liabilities incurred	1,882			4,020
Liabilities settled	(2,436		)	(1,708		)
Revisions	1,184			6,770
Accretion expense	4,119			9,760
Carrying amount, end of period	243,427			238,411
Less: current portion of ARO	(4,388		)	(4,948		)
Non-current portion of ARO	$	239,039		$	233,463

10. Pensions and Postretirement Benefits

ETSWDC sponsors a non-contributory defined benefit pension plan and a contributory postretirement benefit plan covering substantially all ETSWDC employees who were employed prior to March 31, 2008.

The components of net periodic benefit costs are reflected in our consolidated statements of operations for the three months ended March 31, 2015 consist of the following:



Thousands of dollars	Pension Benefits			Postretirement Benefits
Service cost	$	67		$	9
Interest cost	254			39
Expected return on plan assets	(336		)	(25		)
Net periodic benefit costs (income)	$	(15	)	$	23

11. 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 relate to abandonments, environmental and other responsibilities where governmental and other 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 March 31, 2015 and December 31, 2014, we had

approximately $22.5 million and $21.1 million, respectively, of surety bonds. At each of March 31, 2015 and December 31, 2014, we had approximately $26.5 million in letters of credit outstanding.

Legal Proceedings

On January 31, 2014, BOLP received a Notice of Violation from the South Coast Air Quality Management District (“District”) alleging violations of the District’s truck loading limits for crude oil at our Santa Fe Springs facility. We have been engaged in discussions with the District to reach a resolution of this matter and expect to settle the matter for the payment of no more than $170,000. We do not believe that the outcome of this matter will materially impact the Partnership’s liquidity, financial position or future results of operations. Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings.

12. Partners’ Equity

Preferred Units

On May 21, 2014, we sold 8.0 million 8.25% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”) in a public offering at a price of $25.00 per Series A Preferred Unit, resulting in proceeds of $193.2 million net of underwriting discount and offering expenses of $6.8 million. The Series A Preferred Units rank senior to the Common Units with respect to the payment of current distributions. We pay cumulative distributions in cash on the Series A Preferred Units on a monthly basis at a monthly rate of $0.171875 per Series A Preferred Unit. During the three months ended March 31, 2015, we recognized $4.1 million of accrued distributions on the Series A Preferred Units, which are included in distributions to preferred unitholders on the consolidated statements of operations.

See Note 16 for a discussion of Series B perpetual convertible preferred units issued in April 2015.

Common Units

At each of March 31, 2015 and December 31, 2014, we had approximately 210.9 million Common Units outstanding.

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, we sold 25,300 Common Units under the Equity Distribution Agreement for net proceeds of $0.5 million. We did not sell any common units under this agreement during the three months ended March 31, 2015.

During each of the three months ended March 31, 2015 and 2014, we issued less than 0.1 million Common Units, respectively, to non-employee directors for Restricted Phantom Units (“RPUs”) that vested in January 2015 and January 2014, respectively.

At March 31, 2015 and December 31, 2014, there were approximately 6.3 million and 1.8 million, respectively, of units outstanding under our Long-Term Incentive Plan (“LTIP”) that were eligible to be paid in Common Units upon vesting.

During the three months ended March 31, 2015, we paid three monthly cash distributions totaling approximately $52.7 million, or $0.2499 per Common Unit.

During the three months ended March 31, 2014, we paid cash distributions of approximately $58.7 million, or $0.4926 per Common Unit.

During the three months ended March 31, 2015, we paid $1.4 million 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 ended March 31, 2014, we paid $0.9 million 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.

Earnings per Common Unit

FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of common unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable 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 loss per common unit.

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



	Three Months Ended
	March 31,
Thousands, except per unit amounts	2015			2014
Net loss attributable to the partnership	$	(58,825	)	$	(9,758	)
Less:
Net loss attributable to participating units	(1,432		)	(138		)
Distributions to preferred unitholders	4,125			—
Net loss attributable to Common Unitholders	$	(61,518	)	$	(9,620	)

Weighted average number of units used to calculate basic and diluted net loss per unit:
Common Units	210,931			119,206
Dilutive units (a)	—			—
Denominator for diluted net loss per unit	210,931			119,206

Net loss per common unit
Basic	$	(0.29	)	$	(0.08	)
Diluted	$	(0.29	)	$	(0.08	)

(a) The three months ended March 31, 2015 and 2014, exclude 706 and 680, respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position.

13. Accumulated Other Comprehensive Loss

Changes in accumulated other comprehensive loss by component, net of tax, were as follows:



	Gain (loss) on
Thousands of dollars	Available-For-Sale Securities			Postretirement Benefits			Total
Accumulated comprehensive loss attributable to the partnership as of December 31, 2014	$	(112	)	$	(280	)	$	(392	)

Other comprehensive income before reclassification	195			—			195
Amounts reclassified from accumulated other comprehensive loss (a)	(22		)	—			(22		)
Net current period other comprehensive income	173			—			173
Less: noncontrolling interest	70			—			70
Accumulated comprehensive loss attributable to the Partnership	$	(9	)	$	(280	)	$	(289	)

(a) Amounts were reclassified from accumulated other comprehensive loss to other income, net on the consolidated statements of operations.

14. Unit Based Compensation Plans

Unit-based compensation expense for the three months ended March 31, 2015 and 2014 was $7.7 million and $6.5 million, respectively. Unit based compensation expense for the three months ended March 31, 2015 included $6.9 million included in general and administrative expenses and $0.8 million included in restructuring costs (see Note 15).

During the three months ended March 31, 2015, the board of directors of Breitburn GP LLC, our general partner (“General Partner”) approved the grant of approximately 4.6 million RPUs and CPUs to employees of Breitburn Management under our LTIP. Our outside directors were issued 0.2 million RPUs under our LTIP during the three months ended March 31, 2015. The fair market value of the RPUs granted during 2015 for computing compensation expense under FASB Accounting Standards averaged $6.56 per unit.

During the three months ended March 31, 2015 and 2014, we paid $0.7 million and $0.9 million for taxes withheld on RPUs.

As of March 31, 2015, we had $44.5 million of unrecognized compensation costs for all outstanding awards, which is expected to be recognized over the period from April 1, 2015 to December 31, 2017.

For detailed information on our various compensation plans, see Note 18 to the consolidated financial statements included in our 2014 Annual Report.

15. Restructuring Costs

In the first quarter of 2015, we executed a workforce reduction plan as part of a company-wide reorganization effort intended to reduce costs, due in part to lower commodity prices. The reduction was communicated to affected employees on various dates during March, and all such notifications were completed by March 31, 2015. The plan resulted in a reduction of approximately 37 employees. In connection with the reduction, we incurred a total cost of approximately $5.6 million, of which $4.9 million was incurred in the first quarter of 2015, which includes severance cash payments, accelerated vesting of LTIP grants for certain individuals and other employee-related termination costs. In April 2015, we communicated further reductions to an additional 8 employees, and the related costs for these employees will be recognized in the second quarter of 2015. Total workforce reductions in 2015 as a result of the workforce reduction plan, voluntary resignations and early retirement exceed 60 positions.



Thousands of dollars	2015
Beginning Balance	$	—
Severance payments	3,815
Unit-based compensation expense	814
Other termination costs	289
Ending Balance	$	4,918

16. Subsequent Events

Financing and Related Party Transactions with EIG Global Energy Partners

On April 8, 2015 (the “Closing Date”), we issued in private offerings $350 million of 8.0% Series B perpetual convertible preferred units (“Series B Preferred Units”) to EIG Redwood Equity Aggregator, LP (“EIG Equity”), ACMO BBEP Corp. (“ACMO”) and certain other purchasers at an issue price of $7.50 per unit and $650 million of 9.25% senior secured second lien notes due 2020 (“Senior Secured Notes”) to EIG Redwood Debt Aggregator, LP and certain other purchasers at a purchase price of 97% of the principal amount. We received approximately $946 million from these offerings, net of fees and estimated expenses, $930 million of which we used to repay borrowings under our credit facility.

Effective on the Closing Date, Kurt A. Talbot, Vice Chairman and Co-Head of the Investment Committee of EIG Global Energy Partners (“EIG”), was appointed to the board of our General Partner. We paid EIG Management Company, LLC, an

affiliate of EIG, a transaction fee of $7 million with respect to the purchase of the Series B Preferred Units and a transaction fee of $13 million with respect to the purchase of the Senior Secured Notes.

On the Closing Date, the Partnership entered into a registration rights agreement (“Registration Rights Agreement”) with purchasers of the Series B Preferred Units, including EIG Equity, relating to the registered resale of (1) the Series B Preferred Units, including paid in kind units, and (2) common units issuable upon conversion of the Series B Preferred Units, including paid in kind units. In certain circumstances, the purchasers of Series B Preferred Units will have piggyback registration rights and rights to request an underwritten offering as described in the Registration Rights Agreement.

First Amendment to Third Amended and Restated Credit Agreement

In connection with these offerings, on the Closing Date, we entered into the First Amendment to the Third Amended and Restated Credit Agreement. Among other changes, the First Amendment: (i) establishes a borrowing base of $1.8 billion until the April 1, 2016 scheduled redetermination date subject, starting with the October 1, 2015 scheduled redetermination date, to our having liquidity (inclusive of borrowing base availability) of 10% of the borrowing base; (ii) permits $650 million of second lien indebtedness; (iii) increases the base rate and LIBOR margins by 0.25%; (iv) adds a requirement that we have liquidity (inclusive of borrowing base availability) of 10% of the borrowing base after giving effect to any distribution on our common units or voluntary prepayment of second lien indebtedness; and (v) adds a requirement that we have liquidity (inclusive of borrowing base availability) of 5% of the borrowing base after giving effect to any distribution on our Series B Preferred Units. Our credit facility borrowings as of May 4, 2015 were $1.32 billion.

Distributions

On April 1, 2015, we announced a cash distribution to holders of Common Units for the first monthly payment attributable to the first quarter of 2015 at the rate of $0.04166 per Common Unit, which was paid on April 17, 2015 to the unitholders of record at the close of business on April 13, 2015. On April 24, 2015, we announced a cash distribution to unitholders for the second monthly payment attributable to the first quarter of 2015 at the rate of $0.04166 per Common Unit, to be paid on May 15, 2015 to the unitholders of record at the close of business on May 11, 2015.

On April 1, 2015, we declared a cash distribution for our Series A Preferred Units of $0.171875 per Series A Preferred Unit, which is expected to be paid on May 15, 2015 to record holders of our Series A Preferred Units at the close of business on April 30, 2015. On April 24, 2015, we declared a cash distribution for our Series A Preferred Units of $0.171875 per Series A Preferred Unit, which is expected to be paid on June 15, 2015 to record holders of our Series A Preferred Units at the close of business on May 29, 2015. The monthly distribution rate is equal to an annual distribution of $2.0625 per Series A Preferred Unit. On April 24, 2015, we also declared a distribution on our Series B Preferred Units (which we elected to pay in kind by issuing additional Series B Preferred Units) of 0.008222 Series B Preferred Unit per unit, payable on May 15, 2015, to record holders of our Series B Preferred Units at the close of business on April 30, 2015.

Amendment No. 5 to Administrative Services Agreement

On May 1, 2015, Breitburn Management and PCEC entered into Amendment No. 5 to the Administrative Services Agreement (“ASA”), extending the term of the ASA to December 31, 2016; provided, however, in the event PCEC has not received certain permits by December 31, 2015, PCEC may terminate the ASA effective as of June 30, 2016 by giving prior written notice to Breitburn Management of its intention to terminate the ASA by December 31, 2015.

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 2014 Annual Report and the consolidated financial statements and related notes therein. Our 2014 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 2014 Annual Report and Part I—Item 1A “—Risk Factors” of our 2014 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 oil, NGL and natural gas reserves located in seven producing areas:


•	Ark-La-Tex (Arkansas, Louisiana and East Texas);


•	Michigan, Indiana and Kentucky (“MI/IN/KY”);


•	Permian Basin in Texas and New Mexico;


•	Mid-Continent (Oklahoma, Kansas and the Texas Panhandle);


•	Rockies (Wyoming);


•	Florida (and Alabama); and


•	California.

2015 Highlights

During the three months ended March 31, 2015, we paid three monthly cash distributions at the rate of $0.0833 per Common Unit per month, totaling approximately $52.7 million, or $0.2499 per Common Unit. On April 1, 2015 and April 24, 2015, we announced cash distribution to holders of Common Units for the first and second monthly payments attributable to the first quarter of 2015, respectively, at the rate of $0.04166 per Common Unit per month.

During the three months ended March 31, 2015, we recognized $4.1 million of accrued distributions on the Series A Preferred Units. On April 1, 2015 and April 24, 2015, we declared cash distributions for our Series A Preferred Units of $0.171875 per Series A Preferred Unit, which are expected to be paid on May 15, 2015 and June 15, 2015, respectively.

On March 31, 2015, we completed the acquisition of certain CO₂ properties located in Harding County, New Mexico for a total preliminary purchase price of $64.2 million, subject to customary purchase price adjustments, of which, $14.3 million was paid during the three months ended March 31, 2015.

On April 8, 2015, we issued $350 million of Series B Perpetual Convertible Preferred Units (“Series B Preferred Units”) and $650 million of 9.25% Senior Secured Second Lien Notes due 2020 (“Senior Secured Notes”) in private offerings to investment funds managed by EIG and other purchasers. We received approximately $946 million from these offerings, net of fees and estimated expenses, $930 million of which we used to repay borrowings under our credit facility. On April 24, 2015, we declared a distribution on our Series B Preferred Units (which we elected to pay in kind by issuing additional Series B Preferred Units) of 0.008222 Series B Preferred Unit per unit.

On April 8, 2015, in connection with the offerings mentioned above, we entered into the First Amendment to the Third Amended and Restated Credit Agreement, to allow for the issuance of the Senior Secured Notes and to establish a revised borrowing base of $1.8 billion through April 2016, subject to limited exceptions.

Operational Focus and Capital Expenditures

In the first three months of 2015, our oil, NGL and natural gas capital expenditures, including capitalized engineering costs, totaled $73 million, compared to approximately $79 million in the first three months of 2014. We spent approximately $28 million in the Permian Basin, $16 million in Florida, $15 million in Ark-La-Tex, $6 million in Mid-Continent, $6 million in California, $1 million in the Rockies and $1 million in MI/IN/KY. In the first three months of 2015, we drilled and completed four operated productive wells and participated in the drilling of 16 non-operated wells in the Permian Basin,

drilled and completed seven productive wells in Ark-La-Tex, five productive wells in California, two productive wells in the Rockies and one productive well in Mid-Continent. We also performed workovers on 14 wells in Ark-La-Tex, two wells in California, two wells in Florida and one well in the Permian Basin.

In 2015, our crude oil, NGL and natural gas capital spending program, including capitalized engineering costs and excluding acquisitions, is expected to be approximately $200 million. This compares with approximately $389 million in 2014. In 2015, we anticipate spending approximately 89% principally on oil projects in Mid-Continent, Ark-La-Tex, Florida and the Permian Basin and approximately 11% principally on oil projects in California, the Rockies and MI/IN/KY. We anticipate 84% of our total capital spending will be focused on drilling and rate-generating projects and CO₂ purchases that are designed to increase or add to production or reserves. In 2015, we plan to drill 53 wells in Mid-Continent, Ark-La-Tex, Florida and the Permian Basin.

In the first quarter of 2015, we completed a workforce reduction plan as part of a company-wide reorganization effort intended to reduce costs, due in part to lower commodity prices. The reduction was communicated to affected employees on various dates during March, and all such notifications were completed by March 31, 2015. The plan resulted in a reduction of approximately 37 employees, primarily in administrative and support positions. In April 2015, we communicated further reductions to an additional 8 employees. Total workforce reductions in 2015 as a result of the workforce reduction plan, voluntary resignations and early retirement exceed 60 positions.

Commodity Prices

In the first quarter of 2015, the NYMEX WTI spot price averaged $48 per barrel, compared with approximately $99 per barrel in the first quarter of 2014. In the first three months of 2015, the NYMEX WTI spot price ranged from a low of $43 per barrel to a high of $54 per barrel. The NYMEX WTI spot price decreased from $108 per barrel at June 20, 2014 to $43 per barrel at March 17, 2015.

In the first quarter of 2015, the Henry Hub natural gas spot price averaged $2.90 per MMBtu compared with approximately $5.18 per MMBtu in the first quarter of 2014. In the first three months of 2015, the Henry Hub natural gas spot price ranged from a low of $2.62 per MMBtu to a high of $3.32 per MMBtu. In the first quarter of 2015, the MichCon natural gas spot price averaged $3.29 per MMBtu compared with approximately $7.68 per MMBtu in the first quarter of 2014. The Henry Hub natural gas spot price decreased from $8.15 per barrel at February 10, 2014 to $2.62 per barrel at February 9, 2015.

Lower crude oil and natural gas prices prices may not only decrease our revenues, but may also reduce the amount of crude oil and natural gas that we can produce economically and therefore potentially lower our crude oil reserves.

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 ended March 31, 2015, the monthly fee paid by PCEC for indirect expenses was $700,000. The term of the Agreement is set to expire on December 31, 2016, at which time, the agreement is subject to renegotiation.

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.



	Three Months Ended March 31,					Increase/
Thousands of dollars, except as indicated	2015		2014			(Decrease)			%
Total production (MBoe)	5,051		3,219			1,832			57	%
Oil (MBbl)	2,890		1,799			1,091			61	%
NGLs (MBbl)	459		258			201			78	%
Natural gas (MMcf)	10,211		6,971			3,240			46	%
Average daily production (Boe/d)	56,122		35,768			20,354			57	%
Sales volumes (MBoe)	4,999		3,233			1,766			55	%

Average realized sales price (per Boe) (a)(b)	$	32.52	$	69.12		$	(36.60	)	(53	)%
Oil (per Bbl) (a)(b)	43.62		92.12			(48.50		)	(53	)%
NGLs (per Bbl)	16.54		42.89			(26.35		)	(61	)%
Natural gas (per Mcf) (b)	$	3.05	$	6.51		$	(3.46	)	(53	)%

Oil sales	$	123,843	$	167,086		$	(43,243	)	(26	)%
NGL sales	7,591		11,065			(3,474		)	(31	)%
Natural gas sales	31,189		45,405			(14,216		)	(31	)%
Gain (loss) on commodity derivative instruments	137,192		(40,228		)	177,420			n/a
Other revenues, net (c)	6,469		1,584			4,885			n/a
Total revenues	306,284		184,912			121,372			66	%

Lease operating expenses before taxes (d)	100,079		66,990			33,089			49	%
Production and property taxes (e)	13,544		15,659			(2,115		)	(14	)%
Total lease operating expenses	113,623		82,649			30,974			37	%

Purchases and other operating costs	158		214			(56		)	(26	)%
Salt water disposal costs	4,021		—			4,021			n/a
Change in inventory	176		(666		)	842			n/a
Total operating costs	$	117,978	$	82,197		$	35,781		44	%

Lease operating expenses before taxes per Boe	$	19.81	$	20.81		$	(1.00	)	(5	)%
Production and property taxes per Boe	2.68		4.86			(2.18		)	(45	)%
Total lease operating expenses per Boe	$	22.49	$	25.67		$	(3.18	)	(12	)%

Depletion, depreciation and amortization (“DD&A”)	$	109,824	$	63,501		$	46,323		73	%
DD&A per Boe	21.74		19.73			2.01			10	%
Impairments	59,113		—			59,113			n/a

G&A excluding unit based compensation	$	25,335	$	12,180		$	13,155		108	%
G&A excluding unit based compensation per Boe	$	5.02	$	3.78		$	1.24		33	%

(a) Includes the per Boe price effect of crude oil purchases.
(b) Excludes the effect of commodity derivative settlements.
(c) Includes salt water disposal revenues, gas processing fees, earnings from equity investments and other operating revenues.
(d) Includes district expenses, transportation expenses and processing fees.
(e) Includes ad valorem and severance taxes.

Comparison of Results for the Three Months Ended March 31, 2015 and 2014

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

Production

For the three months ended March 31, 2015, total production was 5,051 MBoe compared to 3,219 MBoe for the three months ended March 31, 2014, an increase of 57%, primarily due to 1,867 MBoe of production from our properties acquired in the QRE Merger in November 2014 (“the “QRE properties”), slightly offset by lower production from other properties due to natural field declines.

Oil, NGL and natural gas sales

Total oil, NGL and natural gas sales revenues decreased $60.9 million for the three months ended March 31, 2015, compared to the three months ended March 31, 2014. Crude oil revenues decreased $43.2 million due to lower average crude oil prices, partially offset by production from the QRE properties. NGL revenues decreased $3.5 million due to lower average NGL prices, partially offset by production from the QRE properties. Natural gas revenues decreased $14.2 million, primarily due to lower average natural gas prices, partially offset by production from the QRE properties.

Realized prices for crude oil, excluding the effect of derivative instruments, decreased $48.50 per Boe, or 53%, for the three months ended March 31, 2015 compared to the three months ended March 31, 2014. Realized prices for NGLs, excluding the effect of derivative instruments, decreased $26.35 per Boe, or 61% for the three months ended March 31, 2015 compared to the three months ended March 31, 2014. Realized prices for natural gas, excluding the effect of derivative instruments, decreased $3.46 per Mcf, or 53%, for the three months ended March 31, 2015 compared to the three months ended March 31, 2014.

Other revenues, net

Other revenues increased $4.9 million for the three months ended March 31, 2015, compared to the three months ended March 31, 2014, primarily due to $4.1 million of salt water disposal and related revenue from the QRE properties and $0.6 million of sulfur sales revenue from the QRE properties.

Gain (loss) on commodity derivative instruments

Gain on commodity derivative instruments for the three months ended March 31, 2015 was $137.2 million compared to a loss of $40.2 million during the three months ended March 31, 2014. Oil and natural gas derivative instrument settlement receipts net of payments totaled $126.4 million for the three months ended March 31, 2015 due to significantly lower commodity prices compared to our average hedge prices. Oil and natural gas derivative instrument settlement payments net of receipts for the three months ended March 31, 2014 totaled of $13.5 million due to higher commodity prices compared to our average hedge prices.

Mark-to-market gain on commodity derivative instruments for the three months ended March 31, 2015 was $10.8 million compared to a mark-to-market loss of $26.7 million for the three months ended March 31, 2014, primarily due to a significant decrease in commodity future prices during the three months ended March 31, 2015 compared to an increase in commodity future prices during three months ended March 31, 2014.

Lease operating expenses

Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the three months ended March 31, 2015 increased $33.1 million compared to the three months ended March 31, 2014. The increase in pre-tax lease operating expenses primarily reflects lease operating costs from the QRE properties. On a per Boe basis, pre-tax lease operating expenses were 5% lower than the three months ended March 31, 2014 at $19.81 per Boe, primarily due to lower commodity prices and lower well service expenses.

Production and property taxes for the three months ended March 31, 2015 totaled $13.5 million, which was $2.1 million lower than the three months ended March 31, 2014, primarily due to lower crude oil and natural gas prices, partially offset by

higher production. On a per Boe basis, production and property taxes for the three months ended March 31, 2015 were $2.68 per Boe, which was 45% lower than the three months ended March 31, 2014, due to lower commodity 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 March 31, 2015, the change in inventory account amounted to a charge of $0.2 million compared to a credit of $0.7 million during the same period in 2014. The charge to inventory during the three months ended March 31, 2015 reflects the lower cost of oil produced during the quarter compared to the oil sold during the quarter, primarily due to the effect of decreasing commodity prices on operating costs and lower well services. The credit during the three months ended March 31, 2014 reflects the higher cost of oil produced during the quarter compared to the oil sold during the quarter, primarily due to higher well repairs. In the three months ended March 31, 2015, we sold 131 gross MBbls and produced 183 gross MBbls of crude oil from our Florida operations.

Depletion, depreciation and amortization

DD&A totaled $109.8 million, or $21.74 per Boe, during the three months ended March 31, 2015, an increase of approximately 10% per Boe from the same period a year ago. The increase in DD&A per Boe compared to the three months ended March 31, 2014 was primarily due to lower oil and natural gas prices, and the effect those prices had on our reserve volumes, as well the mark-up of QRE properties to fair value and capital expenditures incurred during the twelve months ended March 31, 2015.

Asset impairments

General and administrative expenses

Our general and administrative (“G&A”) expenses totaled $32.3 million and $18.7 million for the three months ended March 31, 2015 and 2014, respectively. This included $6.9 million and $6.5 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans. G&A expenses, excluding non-cash unit-based compensation, were $25.3 million and $12.2 million for the three months ended March 31, 2015 and 2014, respectively. The increase was primarily due to higher payroll expenses for additional personnel attributable to the QRE Merger, $4.6 million higher integration costs and $1.3 million higher legal costs. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $5.02 and $3.78 for the three months ended March 31, 2015 and 2014, respectively. The increase in G&A expenses per Boe was primarily due to higher integration costs and higher legal costs. The increase in unit-based compensation expense was primarily due to additional personnel.

Restructuring costs

In the first quarter of 2015, we completed a workforce reduction plan as part of a company-wide reorganization effort intended to reduce costs, due in part to lower commodity prices. The reduction was communicated to affected employees on various dates during March, and all such notifications were completed by March 31, 2015. The plan resulted in a reduction of approximately 37 employees, primarily in administrative and support positions. In connection with the reduction, we incurred a total cost of approximately $5.6 million, of which $4.9 million was incurred in the first quarter of 2015, which includes severance cash payments, accelerated vesting of LTIP grants for certain individuals and other employee-related termination costs.

Interest expense, net of amounts capitalized

Our interest expense totaled $39.7 million and $30.7 million for the three months ended March 31, 2015 and 2014, respectively. The increase in interest expense was primarily due to $8.7 million higher credit facility interest expense as a result of higher borrowings related to the QRE Merger. Interest expense, excluding debt amortization, totaled $37.3 million and $28.5 million for the three months ended March 31, 2015 and 2014, respectively.

Loss on interest rate swaps

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. In order to mitigate our interest rate exposure, as of March 31, 2015, we had interest rate swaps, indexed to 1-month LIBOR, to fix a portion of floating LIBOR-base debt under our credit facility for 2015 and 2016, for notional amounts of $401.9 million and $410.0 million, respectively, with average fixed rates of 1.59% and 1.72%, respectively, that were assumed as part of the QRE Merger. As of March 31, 2014, we had no interest rate swaps in place. Loss on interest swaps for the three months ended March 31, 2015 and 2014 were $1.8 million and zero, respectively. The loss on interest rate swaps for the three months ended March 31, 2015 included settlement payments of $1.5 million and a mark-to-market loss of $0.3 million.

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 equity and debt offerings and asset sale transactions. In the future, we anticipate accessing the public and private capital markets to fund certain acquisitions and refinancing transactions.

Cash Flows

Operating activities. Our cash flows from operating activities for the three months ended March 31, 2015 were $141.1 million compared to $116.3 million for the three months ended March 31, 2014. The increase in cash flows from operating activities was primarily due to higher operating income in 2015 driven by 57% higher production (primarily due to 1,867 MBoe of production from the QRE properties) and higher commodity derivative settlement receipts, partially offset by lower sales revenue driven by lower commodity prices, and higher operating costs.

Investing activities. Net cash flows used in investing activities during the three months ended March 31, 2015 and 2014 were $112.1 million and $97.6 million, respectively. During the three months ended March 31, 2015, we spent $97.2 million on capital expenditures, primarily for drilling and completion activities, $14.0 million on property acquisitions, primarily CO₂ properties from the CO₂ Acquisition and $0.9 million on CO₂ advances. During the three months ended March 31, 2014, we spent $93.1 million on capital expenditures, primarily for drilling and completion activities, $2.5 million on property acquisitions and $2.0 million on CO₂ advances and GHG emission allowances.

Financing activities. Net cash flows used in financing activities for the three months ended March 31, 2015 and 2014 were $33.0 million and $19.4 million, respectively. During the three months ended March 31, 2015, we increased our outstanding borrowings under our credit facility by approximately $128.5 million. We had total outstanding borrowings, net of unamortized discount on our senior notes, of approximately $3.38 billion at March 31, 2015 and $3.35 billion at December 31, 2014. During the three months ended March 31, 2015, we made cash distributions of $54.1 million and $4.1 million for Common Units and Series A Preferred Units, respectively, borrowed $193.6 million and repaid $168.5 million on our credit facility and other long-term debt. During the three months ended March 31, 2014, we made cash distributions of $59.6 million for Common Units, borrowed $199.0 million and repaid $157.0 million under our credit facility.

Preferred Units

In May 2014, we sold 8.0 million Series A Preferred Units at a price to the public of $25.00 per Series A Preferred Unit, resulting in proceeds of $193.2 million, net of underwriting discount and offering expenses of $6.8 million. The monthly distribution rate is $0.171875 per Series A Preferred Unit, which is equal to an annual distribution of $2.0625 per Series A Preferred Unit.

On April 8, 2015, we issued $350 million of Series B Preferred Units in a private offering to an investment fund managed by EIG and other purchasers.

On April 24, 2015, we declared a per unit distribution on our Series B Preferred Units (which we elected to pay in kind by issuing additional Series B Units) of 0.008222 Series B Unit, payable on May 15, 2015, to record holders of Series B Preferred Units at the close of business on April 30, 2015.

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.

Senior Notes and Senior Secured Notes

As of March 31, 2015, we had $305 million in 2020 Senior Notes and $850 million in 2022 Senior Notes. See Note 7 to the consolidated financial statements within this report for a discussion of our Senior Notes.

On April 8, 2015, we issued $650 million of Senior Secured Notes in a private offering to an investment fund managed by EIG and other purchasers. See note 16 to the consolidated financial statements within this report for a discussion of our Senior Secured Notes.

Credit Agreement

At each of March 31, 2015 and December 31, 2014, we had a $5.0 billion credit facility with a maturity date of November 19, 2019. At March 31, 2015 and December 31, 2014, our borrowing base was $2.5 billion at each date and the aggregate commitment of all lenders was $2.5 billion at each date.

In connection with the Series B Preferred Units and Senior Secured Notes offerings, on April 8, 2015 we entered into the First Amendment to the Third Amended and Restated Credit Agreement. Among other changes, the First Amendment: (i) establishes a borrowing base of $1.8 billion until the April 1, 2016 scheduled redetermination date subject, starting with the October 1, 2015 scheduled redetermination date, to our having liquidity (inclusive of borrowing base availability) of 10% of the borrowing base; (ii) permits $650 million of second lien indebtedness; (iii) increases the base rate and LIBOR margins by 0.25%; (iv) adds a requirement that we have liquidity (inclusive of borrowing base availability) of 10% of the borrowing base after giving effect to any distribution on our common units or voluntary prepayment of second lien indebtedness; and (v) adds a requirement that we have liquidity (inclusive of borrowing base availability) of 5% of the borrowing base after giving effect to any distribution on our Series B Preferred Units. Our credit facility borrowing as of May 4, 2015 and March 31, 2015, were $1.32 billion and $2.22 billion, respectively.

Our borrowing base is automatically reduced by an amount equal to 25% of the principal of newly issued senior unsecured notes and second lien indebtedness, except if the proceeds of such indebtedness are used to refinance certain existing indebtedness. Loans under the Third Amended and Restated Credit Agreement will bear interest by reference to a Base Rate, LIBOR or a LIBOR Market Index Rate (each as defined in the Third Amended and Restated Credit Agreement), plus an applicable margin that is determined pursuant to a pricing grid which varies between 75 and 175 basis points (in the case of Base Rate loans) and between 175 and 275 basis points (in the case of LIBOR and LIBOR Market Index Rate loans) based on a ratio of loans and letters of credit outstanding to the borrowing base.

As of March 31, 2015, the lending group under the Third Amended and Restated Credit Agreement included 35 banks. Of the $2.5 billion in total commitments under our credit facility, Wells Fargo Bank, National Association held approximately 5% of the commitments, with the remaining 34 banks holding between 1% and 4.2% of the commitments. In addition to our relationships with these institutions under the credit facility, from time to time we engage in other transactions with a number of these institutions. Such institutions or their affiliates may serve as underwriter or initial purchaser of our debt and equity securities and/or serve as counterparties to our commodity and interest rate derivative agreements.

The Third 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 Third 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 March 31, 2015 and May 4, 2015 we were in compliance with our debt covenants.

The events that constitute an event of default under the Third 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.

EBITDAX is not a defined US GAAP measure. The Third Amended and Restated Credit Agreement defines EBITDAX as consolidated net income plus exploration expense, interest expense, income tax provision, DD&A, unrealized loss or gain on derivative instruments, non-cash charges, including non-cash unit-based compensation expense, loss or gain on sale of assets (excluding gain or loss on monetization of derivative instruments for the following twelve months), cumulative effect of changes in accounting principles, cash distributions received from our unrestricted entities (as defined in the Third Amended and Restated Credit Agreement) and excluding income from our unrestricted entities. If any acquisition or disposition was consummated during an applicable quarter, all calculations of EBITDAX shall be determined on a pro forma basis.

Contractual Obligations and Commitments

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 March 31, 2015, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC and Credit Suisse International, Union Bank N.A, Wells Fargo Bank, N.A., JP Morgan Chase Bank N.A., The Bank of Nova Scotia, BNP Paribas, Royal Bank of Canada, The Toronto-Dominion Bank, Merrill Lynch Commodities, Inc., Canadian Imperial Bank of Commerce, Comerica Bank, ING Capital Markets LLC, Credit Agricole Corporate and Investment Bank, and Citizens Bank, National Association. Our counterparties are all lenders who participate in our Third Amended and Restated Credit Agreement. Future volatility could adversely affect the financial condition of our derivative counterparties. On all transactions where we are exposed to counterparty risks, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. As of March 31, 2015, 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 March 31, 2015, our largest derivative asset balances were with Wells Fargo Bank, Credit Suisse Energy LLC and JP Morgan, which accounted for approximately 23%, 20% and 14% of our derivative asset balances, respectively.

Except as discussed above, we had no material changes to our financial contractual obligations during the three months ended March 31, 2015.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of March 31, 2015 and December 31, 2014.

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 2014 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 March 31, 2015.

Changes in Fair Value

The fair value of our outstanding oil and natural gas commodity derivative instruments was a net asset of approximately $738.0 million and $727.2 million at March 31, 2015 and December 31, 2014, 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 March 31, 2015 would have decreased by approximately $256 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 March 31, 2015 would have increased by approximately $270 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.

The fair value of our outstanding interest rate derivative instruments was a net liability of approximately $7.5 million and $7.2 million at March 31, 2015 and December 31, 2014, respectively. With a 100 basis point increase in the LIBOR rate, our outstanding interest rate derivative instruments net liability at March 31, 2015 would have decreased by approximately $7 million. With a 100 basis points decrease in the LIBOR rate to a minimum rate of zero, our net liability at March 31, 2015 would have increased by approximately $4 million.

Item 4. Controls and Procedures

Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our General Partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file 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 March 31, 2015 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 March 31, 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

There have been no material changes to the Risk Factors disclosed in Part I—Item 1A “—Risk Factors” of our 2014 Annual Report.

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

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

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits



NUMBER		DOCUMENT
3.1		Certificate of Limited Partnership of Breitburn Energy Partners LP (incorporated herein by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 (File No. 333-134049) filed on July 13, 2006).
3.2*		Certificate of Amendment to Certificate of Limited Partnership of Breitburn Energy Partners LP.
3.3		Third 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 April 14, 2015).
3.4		Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC dated as of April 5, 2010 (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2011).
3.5		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).
3.6		Amendment No. 2 to the Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC (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).
4.1		Indenture, dated as of October 6, 2010, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010).
4.2		Indenture, dated as of January 13, 2012, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 13, 2012).
4.3		Indenture, dated as of April 8, 2015, by and among Breitburn Energy Partners LP, Breitburn Operating LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).
4.4		First Supplemental Indenture, dated as of August 8, 2013, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association, to the Indenture, dated as of October 6, 2010 (incorporated herein by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-33055) filed on November 22, 2013).
4.5		First Supplemental Indenture, dated as of August 8, 2013, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association, to the Indenture dated as of January 13, 2012 (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on November 22, 2013).
4.6		Second Supplemental Indenture, dated as of November 24, 2014, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association, to the Indenture, dated as of October 6, 2010 (incorporated herein by reference to Exhibit 4.8 to Post-Effective Amendment No. 2 to Form S-3 (File No. 001-181531) filed on November 24, 2014).
4.7		Second Supplemental Indenture, dated as of November 24, 2014, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association, to the Indenture dated as of January 13, 2012 (incorporated herein by reference to Post-Effective Amendment No. 2 to Form S-3 (File No. 001-181531) filed on November 24, 2014).
4.8		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 herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by QR Energy, LP on July 29, 2014).
4.9		Registration Rights Agreement, dated April 8, 2015, by and among Breitburn Energy Partners LP and the purchasers listed on Schedule A thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April 14, 2015).
10.1*		Amendment No. 5 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated May 1, 2015.
10.2		Amended and Restated Series B Preferred Unit Purchase Agreement, dated as of April 8, 2015, by and among Breitburn Energy Partners LP, EIG Redwood Equity Aggregator, LP, ACMO BBEP Corp. and the other purchasers listed on Schedule A thereto (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).



10.3		Board Representation and Standstill Agreement, dated as of April 8, 2015, by and among Breitburn GP LLC, Breitburn Energy Partners LP and EIG Redwood Equity Aggregator, LP (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).
10.4		Amended and Restated Purchase Agreement, dated as of April 8, 2015, by and among Breitburn Energy Partners LP, Breitburn Operating LP, Breitburn Finance Corporation, the guarantors party thereto and the purchasers listed on Schedule I thereto (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).
10.5		Security Agreement, dated as of April 8. 2015, by and among Breitburn Operating LP, Breitburn Energy Partners LP, Breitburn Finance Corporation, each of the subsidiary entities named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).
10.6		Intercreditor Agreement, dated as of April 8, 2015, by and among Wells Fargo Bank, National Association, U.S. Bank National Association, Breitburn Energy Partners LP, Breitburn Finance Corporation, Breitburn Operating LP and each of the subsidiary entities named therein (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).
10.7		First Amendment to Third Amended and Restated Credit Agreement, dated as of April 8. 2015, by and among Breitburn Operating LP, as borrower, Breitburn Energy Partners LP, as parent guarantor, Breitburn GP LLC, Breitburn Operating GP LLC, the subsidiary guarantors named therein, each lender signatory thereto and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).
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:	May 5, 2015	By:	/s/ Halbert S. Washburn
			Halbert S. Washburn
			Chief Executive Officer

Dated:	May 5, 2015	By:	/s/ James G. Jackson
			James G. Jackson
			Chief Financial Officer

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