Breitburn Energy Partners LP - FORM 10-Q

Attached files

file	filename
EX-31.1 - EXHIBIT 31.1 - Breitburn Energy Partners LP	q3201510-qex311.htm
EX-32.2 - EXHIBIT 32.2 - Breitburn Energy Partners LP	q3201510-qex322.htm
EX-31.2 - EXHIBIT 31.2 - Breitburn Energy Partners LP	q3201510-qex312.htm
EX-32.1 - EXHIBIT 32.1 - Breitburn Energy Partners LP	q3201510-qex321.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



x	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarterly period ended September 30, 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 November 4, 2015, the registrant had 211,884,150 Common Units outstanding.

INDEX



		Page No.
	Cautionary Statement Regarding Forward-Looking Information	1

	PART I
	FINANCIAL INFORMATION

Item 1.	Financial Statements
	– Consolidated Balance Sheets (Unaudited) at September 30, 2015 and December 31, 2014	2
	– Consolidated Statements of Operations (Unaudited) for the Three Months and Nine Months Ended September 30, 2015 and 2014	3
	– Consolidated Statements of Comprehensive (Loss) Income for the Three Months and Nine Months Ended September 30, 2015 and 2014	4
	– Consolidated Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2015 and 2014	5
	– Condensed Notes to the Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.	Controls and Procedures	41

	PART II
	OTHER INFORMATION

Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3.	Defaults Upon Senior Securities	42
Item 4.	Mine Safety Disclosures	42
Item 5.	Other Information	42
Item 6.	Exhibits	43

Signatures		45

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, including further or sustained declines in the prices we receive for our production; 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”), in Part II—Item 1A of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015 and in Part II—Item 1A of this report. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

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

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Breitburn Energy Partners LP and Subsidiaries

Consolidated Balance Sheets

(Unaudited)



Thousands of dollars	September 30, 2015			December 31, 2014
ASSETS
Current assets
Cash	$	12,091		$	12,628
Accounts and other receivables, net	135,479			166,436
Derivative instruments (note 3)	400,857			408,151
Related party receivables (note 4)	2,069			2,462
Inventory	3,371			3,727
Prepaid expenses	12,654			7,304
Total current assets	566,521			600,708
Equity investments	6,473			6,463
Property, plant and equipment
Oil and natural gas properties	7,908,709			7,736,409
Other property, plant and equipment (note 2)	141,047			60,533
	8,049,756			7,796,942
Accumulated depletion and depreciation (note 5)	(3,161,636		)	(1,342,741		)
Net property, plant and equipment	4,888,120			6,454,201
Other long-term assets
Intangibles, net	1,538			8,336
Goodwill (note 5)	—			92,024
Derivative instruments (note 3)	267,681			319,560
Other long-term assets (note 6)	119,715			157,042
Total assets	$	5,850,048		$	7,638,334
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	63,921		$	129,270
Current portion of long-term debt (note 7)	603			105,000
Derivative instruments (note 3)	5,289			5,457
Distributions payable	733			733
Current portion of asset retirement obligation (note 9)	2,390			4,948
Revenue and royalties payable	42,454			40,452
Wages and salaries payable	22,264			22,322
Accrued interest payable	42,989			20,672
Production and property taxes payable	30,838			25,207
Other current liabilities	6,644			7,495
Total current liabilities	218,125			361,556
Credit facility	1,253,000			2,089,500
Senior notes, net	1,788,466			1,156,560
Other long-term debt	2,397			1,100
Total long-term debt (note 7)	3,043,863			3,247,160
Deferred income taxes	2,269			2,575
Asset retirement obligation (note 9)	247,317			233,463
Derivative instruments (note 3)	1,421			2,269
Other long-term liabilities (note 10)	24,615			25,135
Total liabilities	3,537,610			3,872,158
Commitments and contingencies (note 11)
Equity
Series A preferred units, 8.0 million units issued and outstanding at each of September 30, 2015 and December 31, 2014 (note 12)	193,215			193,215
Series B preferred units, 48.0 million and 0 units issued and outstanding at September 30, 2015 and December 31, 2014, respectively (note 12)	347,454			—
Common units, 211.8 million and 210.9 million units issued and outstanding at September 30, 2015 and December 31, 2014, respectively (note 12)	1,765,689			3,566,468
Accumulated other comprehensive loss (note 13)	(576		)	(392		)
Total partners' equity	2,305,782			3,759,291
Noncontrolling interest	6,656			6,885
Total equity	2,312,438			3,766,176
Total liabilities and equity	$	5,850,048		$	7,638,334

See accompanying notes to consolidated financial statements.

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Operations

(Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands of dollars, except per unit amounts	2015			2014			2015			2014
Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	153,325		$	216,146		$	505,584		$	658,753
Gain (loss) on commodity derivative instruments, net (note 3)	253,012			146,171			296,772			(21,057		)
Other revenue, net	5,922			1,585			18,895			4,240
Total revenues and other income items	412,259			363,902			821,251			641,936
Operating costs and expenses
Operating costs	115,135			82,904			348,950			248,161
Depletion, depreciation and amortization	117,464			72,671			336,735			204,417
Impairment of oil and natural gas properties (note 5)	1,440,167			29,434			1,499,280			29,434
Impairment of goodwill (note 5)	—			—			95,947			—
General and administrative expenses	23,276			18,737			78,400			53,886
Restructuring costs (note 15)	(278		)	—			6,413			—
(Gain) loss on sale of assets	(7,459		)	(63		)	(7,322		)	357
Total operating costs and expenses	1,688,305			203,683			2,358,403			536,255

Operating (loss) income	(1,276,046		)	160,219			(1,537,152		)	105,681

Interest expense, net of capitalized interest	50,919			29,494			151,988			90,360
Loss on interest rate swaps (note 3)	996			—			3,411			—
Other income, net	(137		)	(450		)	(579		)	(1,223		)

(Loss) income before taxes	(1,327,824		)	131,175			(1,691,972		)	16,544

Income tax expense	14			532			365			384

Net (loss) income	(1,327,838		)	130,643			(1,692,337		)	16,160

Less: Net income attributable to noncontrolling interest	91			—			124			—

Net (loss) income attributable to the partnership	(1,327,929		)	130,643			(1,692,461		)	16,160

Less: Distributions to Series A preferred unitholders	4,125			4,125			12,375			5,958
Less: Non-cash distributions to Series B preferred unitholders	7,145			—			13,553			—
Less: Net (loss) income attributable to participating units	(31,662		)	1,868			(40,612		)	40

Net (loss) income attributable to common unitholders	$	(1,307,537	)	$	124,650		$	(1,677,777	)	$	10,162

Basic net (loss) income per common unit (note 12)	$	(6.17	)	$	1.03		$	(7.94	)	$	0.08
Diluted net (loss) income per common unit (note 12)	$	(6.17	)	$	1.03		$	(7.94	)	$	0.08

Weighted average number of units used to calculate basic and diluted net (loss) income per unit (in thousands):
Basic	211,766			120,473			211,369			119,806
Diluted	211,766			121,250			211,369			120,544

See accompanying notes to consolidated financial statements.

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Comprehensive (Loss) Income

(Unaudited)



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Thousands of dollars, except per unit amounts	2015			2014		2015			2014
Net (loss) income	$	(1,327,838	)	$	130,643	$	(1,692,337	)	$	16,160

Other comprehensive loss, net of tax:
Change in fair value of available-for-sale securities (a)	(636		)	—		(537		)	—
Total other comprehensive loss	(636		)	—		(537		)	—

Total comprehensive (loss) income	(1,328,474		)	130,643		(1,692,874		)	16,160

Less: Comprehensive loss attributable to noncontrolling interest	(303		)	—		(229		)	—

Comprehensive (loss) income attributable to the partnership	$	(1,328,171	)	$	130,643	$	(1,692,645	)	$	16,160

(a) Net of income tax benefit of $0.4 million and $0.3 million for the three months and nine months ended September 30, 2015.

See accompanying notes to consolidated financial statements.

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)



	Nine Months Ended
	September 30,
Thousands of dollars	2015			2014
Cash flows from operating activities
Net (loss) income	$	(1,692,337	)	$	16,160
Adjustments to reconcile to cash flows from operating activities:
Depletion, depreciation and amortization	336,735			204,417
Impairment of oil and natural gas properties	1,499,280			29,434
Impairment of goodwill	95,947			—
Unit-based compensation expense	20,714			18,440
(Gain) loss on derivative instruments	(293,361		)	21,057
Derivative instrument settlement receipts (payments)	351,518			(34,228		)
Income from equity affiliates, net	(10		)	90
Deferred income taxes	(306		)	153
(Gain) loss on sale of assets	(7,322		)	357
Other	14,348			5,172
Changes in net assets and liabilities
Accounts receivable and other assets	22,251			(3,345		)
Inventory	356			(528		)
Net change in related party receivables and payables	393			1,095
Accounts payable and other liabilities	2,978			36,642
Net cash provided by operating activities	351,184			294,916
Cash flows from investing activities
Property acquisitions	(17,160		)	(6,422		)
Capital expenditures	(226,718		)	(293,275		)
Proceeds from sale of assets	9,441			366
Proceeds from sale of available-for-sale securities	3,631			—
Purchases of available-for-sale securities	(3,803		)	—
Other	(853		)	(9,242		)
Net cash used in investing activities	(235,462		)	(308,573		)
Cash flows from financing activities
Proceeds from issuance of preferred units, net	337,895			193,215
Proceeds from issuance of common units, net	4,768			25,917
Distributions to preferred unitholders	(12,375		)	(5,225		)
Distributions to common unitholders	(108,283		)	(181,430		)
Proceeds from issuance of long-term debt, net	1,203,400			693,000
Repayments of long-term debt	(1,512,500		)	(707,000		)
Change in bank overdraft	(39		)	(2,417		)
Debt issuance costs	(29,125		)	(1,634		)
Net cash (used in) provided by financing activities	(116,259		)	14,426
(Decrease) increase in cash	(537		)	769
Cash beginning of period	12,628			2,458
Cash end of period	$	12,091		$	3,227

See accompanying notes to consolidated financial statements.

Condensed 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 September 30, 2015, our operating results for the three months and nine months ended September 30, 2015 and 2014 and our cash flows for the nine months ended September 30, 2015 and 2014 have been included. Operating results for the three months and nine months ended September 30, 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 Accounting Standards Update (“ASU”) 2015-03, Simplifying the Presentation of Debt Issuance Costs. The objective of ASU 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. In August 2015, the FASB issued ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This ASU amends ASU 2015-03 which had not addressed the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements. Under ASU 2015-15, a company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. ASU 2015-03 and ASU 2015-15 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and should be applied retrospectively. Early adoption is permitted. The adoption of these standards will not have an impact on our consolidated financial statements, other than balance sheet reclassifications.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. ASU 2014-09 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. These new requirements become effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for annual and interim reporting periods beginning after December 15, 2016. We are assessing the impact of these new requirements on our consolidated 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 & Other Transactions

In September 2015, we entered into an agreement to exchange certain of our non-contiguous acres in Martin County, Texas for non-operated producing assets in Weld County, Colorado and cash consideration of $4.8 million. We recorded a gain of $7.5 million on this transaction. The trade was for all future horizontal and vertical development rights in the oil and gas leases exchanged. We reserved all existing wellbores and the production therefrom in these Martin County, Texas acres.

In August 2015, we granted a three-year term assignment of our interests in certain oil and gas leases in the Mississippian, Woodford, and Hunton formations in Kingfisher County, Oklahoma for cash consideration of $3.2 million. We reserved all existing wellbores and the production therefrom and reserved an overriding royalty interest equal to the difference between existing lease burdens appearing of record and 20%.

In May 2015, we completed the acquisition of additional interests in our existing fields located in Ark-La-Tex for a total preliminary purchase price of $3.0 million, which is primarily reflected in oil and natural gas properties on the consolidated balance sheet.

On March 31, 2015, we completed the acquisition of certain CO₂ producing properties located in Harding County, New Mexico (“CO₂ Assets”), for a total preliminary purchase price of $70.2 million (the “CO₂ Acquisition”), subject to customary purchase price adjustments, of which $14.3 million was paid in cash during the three months ended March 31, 2015, and $0.2 million was paid in cash during the three months ended June 30, 2015 and no amount was paid in cash during the three months ended September 30, 2015. The preliminary purchase price included $70.5 million reflected in other property, plant and equipment on the consolidated balance sheet (including $49.9 million of CO₂ supply advances and deposits paid in 2014 and reclassified from other long-term assets to other property, plant and equipment during the nine months ended September 30, 2015 and $5.1 million of intangibles reclassified from intangibles to other property, plant and equipment during the nine months ended September 30, 2015) 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 Salt Water 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:



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.

We recognized goodwill of $95.9 million as part of the initial purchase price allocation. See Note 5 for a discussion of impairment of goodwill.

In connection with the QRE Merger, on November 19, 2014, we entered into a Transition Services Agreement (“TSA”) with Quantum Resources Management, LLC. 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 terminated on May 19, 2015.

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”), for a total purchase price of $122.3 million. The final purchase price was allocated to oil and natural gas assets as follows: $110.9 million to unproved properties, $13.1 million to proved properties and $1.7 million to ARO.

Pro Forma (unaudited)

The following unaudited pro forma financial information presents a summary of our combined statements of operations for the three months and nine months ended September 30, 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 their results for the periods presented were immaterial.



	2014 Pro Forma
	Three Months Ended		Nine Months Ended
Thousands of dollars, except per unit amounts	September 30, 2014		September 30, 2014
Revenues	$	564,321	$	1,009,362
Net income attributable to the partnership	211,356		45,286

Net income per common unit:
Basic	$	1.00	$	0.19
Diluted	$	0.99	$	0.19

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 September 30, 2015:



	Year
	2015			2016			2017			2018		2019
Oil Positions:
Fixed Price Swaps - NYMEX WTI
Volume (Bbl/d)	20,043			15,504			13,519			493		—
Average Price ($/Bbl)	$	93.27		$	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)	26,368			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)	17,500			29,000			24,000			14,000		8,000
Average Price ($/MMBtu)	$	4.26		$	3.91		$	3.71		$	3.15	$	3.20
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	(b)	$	0.69	(c)	$	—	$	—
Total:
Volume (MMBtu/d)	92,311			77,030			54,056			15,870		8,000
Average Price ($/MMBtu)	$	4.76		$	4.08		$	4.02		$	3.26	$	3.20

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

(b) Deferred premiums of $0.66 apply to 11,350 MMBtu/d of the 2016 volume.

During the three months and nine months ended September 30, 2015 and 2014, we did not enter into any derivative instruments that required pre-paid premiums.

As of September 30, 2015, premiums paid in 2012 related to oil and natural gas derivatives to be settled beyond September 30, 2015 were as follows:



	Year
Thousands of dollars	2015		2016		2017
Oil	$	1,180	$	7,438	$	734
Natural gas	$	501	$	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 September 30, 2015. 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)	$	374,031		$	410,000
Average Fixed Rate	1.64		%	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 not designated as hedging instruments:



Balance sheet location, thousands of dollars	Oil Commodity Derivatives			Natural Gas Commodity Derivatives			Interest Rate Derivatives			Commodity Derivatives Netting (a)			Total Financial Instruments
As of September 30, 2015
Assets
Current assets - derivative instruments	$	358,741		$	44,281		$	—		$	(2,165	)	$	400,857
Other long-term assets - derivative instruments	240,177			30,886			—			(3,382		)	267,681
Total assets	598,918			75,167			—			(5,547		)	668,538
Liabilities
Current liabilities - derivative instruments	(40		)	(2,214		)	(5,200		)	2,165			(5,289		)
Long-term liabilities - derivative instruments	(43		)	(3,748		)	(1,012		)	3,382			(1,421		)
Total liabilities	(83		)	(5,962		)	(6,212		)	5,547			(6,710		)
Net assets (liabilities)	$	598,835		$	69,205		$	(6,212	)	$	—		$	661,828

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 September 30, 2015
Net gain (loss)	$	234,158		$	18,854		$	(996	)	$	252,016
Three Months Ended September 30, 2014
Net gain	$	133,666		$	12,505		$	—		$	146,171

Nine Months Ended September 30, 2015
Net gain (loss)	$	261,360		$	35,412		$	(3,411	)	$	293,361
Nine Months Ended September 30, 2014
Net loss	$	(15,553	)	$	(5,504	)	$	—		$	(21,057	)

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

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

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 September 30, 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 nine months ended September 30, 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 futures 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, futures 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 futures 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 tables set 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 September 30, 2015
Assets (liabilities)
Crude Oil
Crude oil swaps	$	—	$	548,524		$	—	$	548,524
Crude oil collars	—		—			33,477		33,477
Crude oil puts	—		—			16,835		16,835
Natural Gas
Natural gas swaps	—		55,075			—		55,075
Natural gas collars	—		—			4,490		4,490
Natural gas puts	—		—			9,639		9,639
Interest rate swaps
Interest rate swaps	—		(6,212		)	—		(6,212		)
Available-for-sale securities
Equities	2,419		—			—		2,419
Mutual funds	11,304		—			—		11,304
Exchange traded funds	4,805		—			—		4,805
Net assets	$	18,528	$	597,387		$	64,441	$	680,356



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 tables set forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3:



	Three Months Ended September 30,
	2015						2014
Thousands of dollars	Oil			Natural Gas			Oil			Natural Gas
Assets (a):
Beginning balance	$	41,001		$	15,010		$	1,540		$	840
Derivative instrument settlements (b)	11,903			4,050			—			347
(Loss) gain (b)(c)	(2,592		)	(4,931		)	5,529			(222		)
Ending balance	$	50,312		$	14,129		$	7,069		$	965

	Nine Months Ended September 30,
	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)	31,454			11,854			—			389
Loss (b)(c)	(42,552		)	(17,617		)	(1,888		)	(1,272		)
Ending balance	$	50,312		$	14,129		$	7,069		$	965

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

For Level 3 derivative instruments measured at fair value on a recurring basis as of September 30, 2015, the significant unobservable inputs used in the fair value measurements were as follows:



	Fair Value at		Valuation
Thousands of dollars	September 30, 2015		Technique	Unobservable Input	Range
Oil Options	$	50,312	Option Pricing Model	Oil forward commodity prices	$45.09/Bbl - $56.04/Bbl
				Oil volatility	27.94% - 44.82%
				Own credit risk	5%
Natural Gas Options	14,129		Option Pricing Model	Gas forward commodity prices	$2.52/MMBtu - $3.29/MMBtu
				Gas volatility	22.58% - 58.91%
				Own credit risk	5%
Total	$	64,441

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 September 30, 2015, our derivative counterparties were Bank of Montreal, Barclays Bank PLC, BNP Paribas, Canadian Imperial Bank of Commerce, Citibank, N.A, Citizens Bank, National Association, Comerica Bank, Credit Agricole Corporate and Investment Bank, Credit Suisse Energy LLC, Credit Suisse International, ING Capital Markets LLC, JP Morgan Chase Bank N.A., Merrill Lynch Commodities, Inc., Morgan Stanley Capital Group Inc., Royal Bank of Canada, The Bank of Nova Scotia, The Toronto-Dominion Bank, Union Bank N.A. and Wells Fargo Bank, N.A. Our counterparties are all lenders under our Third Amended and Restated Credit Agreement. Our Third Amended and Restated 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 September 30, 2015, each of these financial institutions had an investment grade credit rating. As of September 30, 2015, our largest derivative asset balances were with Wells Fargo Bank, N.A., Credit Suisse Energy LLC, JP Morgan Chase Bank N.A. and Barclays Bank PLC, which accounted for approximately 19%, 11%, 11% and 11% of our net derivative asset balances, respectively.

4. Related Party Transactions

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

Breitburn Management also provides administrative services to Pacific Coast Energy Company LP, formerly named BreitBurn Energy Company L.P. (“PCEC”), our predecessor, under an administrative services agreement, in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses, including incentive compensation plan costs and direct payroll and administrative costs related to PCEC properties and operations. For each of the three months and nine months ended September 30, 2015 and 2014, the monthly fee paid by PCEC for indirect expenses was $700,000. 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. At December 31, 2016, the ASA is subject to renegotiation.

Effective on April 8, 2015, the closing date of private offerings of senior secured second lien notes and perpetual convertible preferred units (see Note 7 and Note 12, respectively), Kurt A. Talbot, Vice Chairman and Co-Head of the Investment Committee of EIG Global Energy Partners (“EIG”), was appointed to the board of directors of Breitburn GP LLC, our general partner (our “General Partner”). We paid EIG Management Company, LLC, an affiliate of EIG, a transaction fee of $13 million with respect to the purchase of the senior secured second lien notes and a transaction fee of $7 million with respect to the purchase of the perpetual convertible preferred units.

At September 30, 2015 and December 31, 2014, we had a current receivable of $1.6 million and $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 September 30, 2015 and 2014, the monthly charges to PCEC for indirect expenses totaled $2.1 million in each period, and charges for direct expenses including payroll and administrative costs totaled $2.3 million and $3.8 million, respectively. For the nine months ended September 30, 2015 and 2014, the monthly charges to PCEC for indirect expenses totaled $6.3 million in each period, and charges for direct expenses including payroll and administrative costs totaled $7.3 million and $8.9 million, respectively. At September 30, 2015 and December 31, 2014, we had receivables of $0.5 million and $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.

5. Impairments

Oil and Natural Gas Properties

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 includes inputs such as applicable NYMEX strip prices, estimated basis price differentials, expenses and capital estimates, and escalation factors. Management also considers the 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 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.

Non-cash impairments of proved properties totaled $1.4 billion and $1.5 billion for the three months and nine months ended September 30, 2015, respectively. For the three months ended September 30, 2015, we had non-cash impairments of $605.4 million in Michigan, $420.2 million in Florida, $262.1 million in Ark-La-Tex, $73.1 million in California, $49.7 million for our Permian properties, $17.4 million in the Rockies and $12.2 million for our Mid-Continent properties, primarily related to the impact of the drop in commodity strip prices on our projected future net revenues. For the nine months ended September 30, 2015, we had non-cash impairments of $605.4 million in Michigan, $420.2 million in Florida, $262.1 million in Ark-La-Tex, $73.1 million in California, $82.8 million for our Permian properties, $34.1 million for our Rockies natural gas properties and $21.5 million for our Mid-Continent properties primarily due to the impact of the drop in commodity strip prices on our projected future net revenues during the third quarter and the impact of the decrease in oil and natural gas prices on certain of our low operating margin properties during the first quarter. Impairments totaled $29.4 million for the three months and nine months ended September 30, 2014, including $19.9 million in Florida, $6.5 million in Michigan and $3.0 million in the Rockies. The carrying values of the properties were reduced to their estimated fair values

using level 3 inputs. Additional impairments may be recognized in the fourth quarter of 2015 should commodity prices decline further.

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.

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is not amortized, but is tested for impairment annually or whenever indicators of impairment exist and charged to impairment. The analysis of the potential impairment of goodwill is a two-step process. Step one of the impairment test consists of comparing the fair value of the reporting unit with the aggregate carrying value, including goodwill. If the carrying value of a reporting unit exceeds the reporting unit’s fair value, step two must be performed to determine the amount, if any, of the goodwill impairment.

If the fair value of the reporting unit is less than its carrying value, step two of the goodwill impairment test is performed. Step two consists of comparing the implied fair value of the reporting unit’s goodwill against the carrying value of the goodwill. Determining the implied fair value of goodwill requires the valuation of a reporting unit’s identifiable tangible and intangible assets and liabilities as if the reporting unit had been acquired in a business combination on the testing date. The fair value of the tangible and intangible assets and liabilities is based upon various assumptions including a discounted cash flow approach to value our oil and gas reserves (the “Income Approach”). The Income Approach valuation method requires projections of revenue and operating costs over a multi-year period. The valuation of assets and liabilities in step two is performed only for purposes of assessing goodwill for impairment.

As of March 31, 2015, we had $95.9 million of goodwill related to the QRE Merger (see Note 2). Due to a decrease in the price of our Common Units during the second quarter of 2015, we performed a qualitative goodwill impairment assessment. In the first step of the goodwill impairment test, we determined that the fair value of our goodwill was less than the carrying amount, primarily due to the decrease in the price of our Common Units. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there was no remaining implied fair value attributable to goodwill. Based on this assessment, we recorded a non-cash goodwill impairment charge of $95.9 million during the three months ended June 30, 2015, to reduce the carrying value of goodwill to zero.

6. Other Assets

As of September 30, 2015, and December 31, 2014, our other long-term assets were $119.7 million and $157.0 million, respectively, consisting of the following:



	As of
Thousands of dollars	September 30, 2015		December 31, 2014
Debt issuance costs	$	62,341	$	52,787
Available-for-sale securities	18,528		19,345
Deposit for Jay Field net profit interest obligation	18,263		18,263
Property reclamation deposit	10,735		10,735
CO₂ supply advances and deposits	—		50,792
Other	9,848		5,120
Total	$	119,715	$	157,042

The $62.3 million of debt issuance costs at September 30, 2015 included $21.6 million in debt issuance costs relating to the Senior Secured Notes (as defined below) issued on April 8, 2015, partially offset by the write-off of $10.6 million of debt issuance costs relating to the reduction of our borrowing base from $2.5 billion to $1.8 billion in connection with the EIG financing. See Note 7 for a discussion of the Senior Secured Notes and the EIG financing.

At each of September 30, 2015 and December 31, 2014, we had a deposit for 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.

At September 30, 2015 and December 31, 2014, we had zero and $50.8 million, respectively, in CO₂ supply advances and deposits for our Mid-Continent properties. In connection with the CO₂ Acquisition, during the nine months ended September 30, 2015, we reclassified $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	September 30, 2015			December 31, 2014
Credit facility	$	1,253,000		$	2,194,500
Promissory note	3,000			1,100
9.25% Senior Secured Notes due 2020	650,000			—
8.625% Senior Unsecured Notes due 2020	305,000			305,000
7.875% Senior Unsecured Notes due 2022	850,000			850,000
Net (discount) premium on Senior Notes	(16,534		)	1,560
Total debt	3,044,466			3,352,160
Less: current portion of long-term debt	(603		)	(105,000		)
Total long-term debt	$	3,043,863		$	3,247,160

Credit Facility

On April 8, 2015, in connection with financing and related party transactions with EIG Global Energy Partners, we entered into the First Amendment to the Third Amended and Restated Credit Agreement (the “First Amendment”). Among other changes, the First Amendment: (i) established 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) permitted $650 million of second lien indebtedness; (iii) increased the base rate and LIBOR margins by 0.25%; (iv) added 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) added 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 (as defined below).

As of September 30, 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 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 September 30, 2015 and December 31, 2014, our borrowing base was $1.8 billion and $2.5 billion, respectively. Our next borrowing base redetermination is scheduled for April 2016.

As of September 30, 2015 and December 31, 2014, we had $1.25 billion and $2.19 billion, respectively, in indebtedness outstanding under our credit facility. At September 30, 2015, the 1-month LIBOR interest rate plus an applicable spread was 2.4511% on the 1-month LIBOR portion of $1.30 billion and the prime rate plus an applicable spread was 4.50% on the prime portion of $5.0 million. At September 30, 2015 and December 31, 2014, we had $23.6 million and $33.5 million, respectively, of unamortized debt issuance costs related to our credit facility. During the three and nine months ended September 30, 2015, we had a write-off of zero and $10.6 million, respectively, of debt issuance costs, included in interest expense, net of capitalized interest on the consolidated statements of operations, relating to the reduction of our credit facility borrowing base from $2.5 billion to $1.8 billion in connection with the EIG financing.

As of September 30, 2015 and December 31, 2014, we were in compliance with our credit facility’s covenants.

in the equity or capital markets on terms we find acceptable. The cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, and reduced and, in some cases, ceased to provide any new funding. If the borrowing base determination in April 2016 results in a borrowing base deficiency and we cannot access the capital markets and repay debt under our credit facility, we may be unable to continue to pay distributions to our unitholders and may take other actions to reduce costs and to raise funds to repay debt, such as selling assets or monetizing derivative contracts.

Senior Secured Notes

On April 8, 2015, we issued $650 million of 9.25% senior secured second lien notes due 2020 (“Senior Secured Notes”) in a private offering to EIG Redwood Debt Aggregator, LP and certain other purchasers at a purchase price of 97% of the principal amount. We received approximately $606.9 million from this offering, net of fees and estimated expenses, which we primarily used to repay borrowings under our credit facility. Interest on our Senior Secured Notes is payable quarterly in March, June, September and December. As of September 30, 2015, our Senior Secured Notes had a carrying value of $631.9 million, net of unamortized discount of $18.1 million.

As of September 30, 2015, the fair value of our Senior Secured Notes was estimated to be approximately $612 million, based on quoted yields for similarly rated debt instruments currently available in the market, and we consider the valuation of our Senior Secured Notes to be Level 3.

At September 30, 2015 and December 31, 2014, we had $21.6 million and zero, respectively, of unamortized debt issuance costs related to our Senior Secured Notes.

Senior Unsecured Notes

As of September 30, 2015, we had $305 million in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”), which had a carrying value of $301.9 million, net of unamortized discount of $3.1 million. In addition, as of September 30, 2015, we had $850 million in aggregate principal amount of 7.875% senior notes due 2022 (the “2022 Senior Notes”), which had a carrying value of $854.6 million, net of unamortized premium of $4.6 million. Interest on the 2020 Senior Notes and the 2022 Senior Notes is payable twice a year in April and October.

At September 30, 2015 and December 31, 2014, we had $17.1 million and $19.3 million, respectively, of unamortized debt issuance costs related to our 2020 Senior Notes and 2022 Senior Notes (together the “Senior Unsecured Notes”).

As of September 30, 2015, the fair value of our 2020 Senior Notes and 2022 Senior Notes were estimated to be approximately $138 million and $302 million, respectively, based on prices quoted from third-party financial institutions. We consider the inputs to the valuation of our Senior Notes to be Level 2, as fair value was estimated based on prices quoted from third-party financial institutions.

As of September 30, 2015 and December 31, 2014, we were in compliance with the covenants under our Senior Unsecured Notes.

Interest Expense

Our interest expense is detailed as follows:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands of dollars	2015			2014			2015			2014
Credit agreement (including commitment fees)	$	8,828		$	4,539		$	32,422		$	14,886
Senior Unsecured Notes	23,311			23,311			69,933			69,933
Senior Secured Notes	15,031			—			28,893			—
Amortization of net discount/premium and deferred issuance costs (a)	3,816			1,765			20,885			5,779
Capitalized interest	(67		)	(121		)	(145		)	(238		)
Total	$	50,919		$	29,494		$	151,988		$	90,360

(a) The three months and nine months ended September 30, 2015 include a write-off of zero and $10.6 million, respectively, of debt issuance costs relating to the reduction of our credit facility borrowing base.

8. Condensed Consolidating Financial Statements

We and Breitburn Finance Corporation (and BOLP, with respect to the Senior Secured Notes), as co-issuers, and certain of our subsidiaries, as guarantors, issued the Senior Secured Notes and the Senior Unsecured Notes (collectively, the “Senior Notes”). All but two of our subsidiaries have guaranteed the 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 the Senior Notes, is a wholly-owned finance subsidiary; all of our material subsidiaries are wholly-owned and have guaranteed the Senior Notes; and all of the guarantees are full, unconditional, joint and several.

Each guarantee of each of the Senior Notes is subject to release in the following customary circumstances except as noted:


(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 (applicable to the Senior Unsecured Notes only),


(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 (applicable to the Senior Unsecured Notes only).

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 10% and adjusted for inflation using a rate of 2%. Our credit-adjusted risk-free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk.

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

Changes in ARO for the period ended September 30, 2015, and the year ended December 31, 2014 are presented in the following table:



	Nine Months Ended			Year Ended
Thousands of dollars	September 30, 2015			December 31, 2014
Carrying amount, beginning of period	$	238,411		$	123,769
Acquisitions	796			95,800
Divested properties	(261		)	—
Liabilities incurred	2,140			4,020
Liabilities settled	(6,679		)	(1,708		)
Revisions	2,703			6,770
Accretion expense	12,597			9,760
Carrying amount, end of period	249,707			238,411
Less: current portion of ARO	(2,390		)	(4,948		)
Non-current portion of ARO	$	247,317		$	233,463

10. Pensions and Postretirement Benefits

We acquired ETSWDC on November 19, 2014 in connection with the QRE Merger. 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 reflected in our consolidated statements of operations for the three months and nine months ended September 30, 2015 consist of the following:



	Three Months Ended September 30, 2015						Nine Months Ended September 30, 2015
Thousands of dollars	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
Service cost	$	68		$	8		$	203		$	25
Interest cost	254			39			761			117
Expected return on plan assets	(336		)	(24		)	(1,007		)	(74		)
Net periodic (income) benefit costs	$	(14	)	$	23		$	(43	)	$	68

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 September 30, 2015 and December 31, 2014, we had approximately $26.4 million and $21.1 million, respectively, of surety bonds. At each of September 30, 2015 and December 31, 2014, we had approximately $26.5 million in letters of credit outstanding.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings.

12. Partners’ Equity

Preferred Units

On April 8, 2015, 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. We received approximately $337.4 million from this offering, net of fees and estimated expenses, which we primarily used to repay borrowings under our credit facility. The Series B Preferred Units rank senior to the Common Units and on parity with the Series A Preferred Units (as defined below) with respect to the payment of current distributions.

For the three months and nine months ended September 30, 2015, we elected to pay our Series B Preferred Unit distributions in kind by issuing additional Series B Preferred Units (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) in lieu of cash. During the three months and nine months ended September 30, 2015, we declared distributions on our Series B Preferred Units of $0.02000 and $0.03489 Series B Preferred Units per unit, respectively, in the form of 786,634 and 1,361,925 Series B Preferred Units, respectively, and 163,314 and 284,898 Common Units, respectively. During the three months and nine months ended September 30, 2015, we recognized $7.2 million and $13.6 million, respectively, of accrued distributions on the Series B Preferred Units, which are included in non-cash distributions to Series B preferred unitholders on the consolidated statements of operations.

On April 8, 2015, we 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 (the “Registrable Securities”). 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. The Registrable Securities are registered under a shelf registration statement on Form S-3, which was declared effective by the SEC on September 11, 2015.

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 and on parity with the Series B Preferred 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 and nine months ended September 30, 2015, we recognized $4.1 million and $12.4 million, respectively, of accrued distributions on the Series A Preferred Units, which are included in distributions to Series A preferred unitholders on the consolidated statements of operations. During the three months and nine months ended September 30, 2014, we recognized $4.1 million and $6.0 million, respectively, of accrued distributions on the Series A Preferred Units.

Common Units

At each of September 30, 2015 and December 31, 2014, we had approximately 211.8 million and 210.9 million, respectively, of 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 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, 2015, June 30, 2015 and September 30, 2015, we sold zero, 543,845 and zero Common Units, respectively, under the Equity Distribution Agreement for net proceeds of zero, $3.4 million and zero, respectively. During the three months ended March 31, 2014, June 30, 2014 and September 30, 2014, we sold 25,300, 976,611 and 269,774 Common Units, respectively, under the Equity Distribution Agreement for net proceeds of $0.5 million, $19.7 million and $6.0 million, respectively.

During the three months and nine months ended September 30, 2015, we issued 163,314 and 284,898 Common Units, respectively, to a Series B Preferred unitholder that elected to receive its paid in kind distributions in Common Units. During each of the three months and nine months ended September 30, 2014, we issued zero Common Units related to the Series B Preferred Units paid in kind distribution.

During the three months and nine months ended September 30, 2015, we issued zero and less than 0.1 million Common Units, respectively, to non-employee directors for Restricted Phantom Units (“RPUs”) that vested in January 2015. During the three months and nine months ended September 30, 2014, we issued zero Common Units and less than 0.1 million Common Units, respectively, to non-employee directors for RPUs that vested in January 2014.

At September 30, 2015 and December 31, 2014, there were approximately 5.9 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 September 30, 2015, we paid three monthly cash distributions totaling approximately $26.5 million, or $0.1250 per Common Unit. During the nine months ended September 30, 2015, we paid nine monthly cash distributions totaling approximately $105.6 million, or $0.4999 per Common Unit.

During the three months ended September 30, 2014, we paid cash distributions of approximately $60.5 million, or $0.5025 per Common Unit. During the nine months ended September 30, 2014, we paid cash distributions of approximately $178.7 million, or $1.4925 per Common Unit.

During the three months and nine months ended September 30, 2015, in addition to the distributions paid to holders of our Common Units, we paid $0.6 million and $2.7 million, respectively, in cash at a rate equal to the distributions paid to our holders of Common Units to holders of outstanding unvested RPUs issued under our LTIP. During the three months and nine

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

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					Nine Months Ended
	September 30,					September 30,
Thousands, except per unit amounts	2015			2014		2015			2014
Net (loss) income attributable to the partnership	$	(1,327,929	)	$	130,643	$	(1,692,461	)	$	16,160
Less:
Net (loss) income attributable to participating units	(31,662		)	1,868		(40,612		)	40
Distributions to Series A preferred unitholders	4,125			4,125		12,375			5,958
Non-cash distributions to Series B preferred unitholders	7,145			—		13,553			—
Net (loss) income attributable to Common Unitholders	$	(1,307,537	)	$	124,650	$	(1,677,777	)	$	10,162

Weighted average number of units used to calculate basic and diluted net (loss) income per unit (in thousands):
Common Units	211,766			120,473		211,369			119,806
Dilutive units (a)	—			777		—			738
Denominator for diluted net (loss) income per unit	211,766			121,250		211,369			120,544

Net (loss) income per common unit
Basic	$	(6.17	)	$	1.03	$	(7.94	)	$	0.08
Diluted	$	(6.17	)	$	1.03	$	(7.94	)	$	0.08

(a) The three months and nine months ended September 30, 2015 exclude 749 and 724, 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, for the three months and nine months ended September 30, 2015 were as follows:



	Three Months Ended September 30, 2015
	Gain (loss) on
Thousands of dollars	Available-For-Sale Securities			Postretirement Benefits			Total
Accumulated comprehensive loss attributable to the partnership as of June 30, 2015	$	(53	)	$	(280	)	$	(333	)

Other comprehensive loss before reclassification	(637		)	—			(637		)
Amounts reclassified from accumulated other comprehensive loss (a)	—			—			—
Net current period other comprehensive loss	(637		)	—			(637		)
Less: noncontrolling interest	(394		)	—			(394		)
Accumulated comprehensive loss attributable to the partnership as of September 30, 2015	$	(296	)	$	(280	)	$	(576	)



	Nine Months Ended September 30, 2015
	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 loss before reclassification	(390		)	—			(390		)
Amounts reclassified from accumulated other comprehensive loss (a)	(147		)	—			(147		)
Net current period other comprehensive income	(537		)	—			(537		)
Less: noncontrolling interest	(353		)	—			(353		)
Accumulated comprehensive loss attributable to the partnership as of September 30, 2015	$	(296	)	$	(280	)	$	(576	)

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

14. Unit Based Compensation Plans

Unit-based compensation expense for the three months ended September 30, 2015 and 2014 was $6.2 million and $5.8 million, respectively, and for the nine months ended September 30, 2015 and 2014 was $20.7 million and $18.4 million respectively. Unit based compensation expense of $6.4 million for the three months ended September 30, 2015 was included in general and administrative expenses and a credit adjustment of $0.2 million was included in restructuring costs. Unit-based compensation expense of $19.4 million for the nine months ended September 30, 2015 was included in general and administrative expenses and $1.3 million was included in restructuring costs. See Note 15 for a discussion of restructuring costs.

During the three months and nine months ended September 30, 2015, the board of directors of our General Partner approved the grant of less than 0.1 million and 4.7 million RPUs and CPUs to employees of Breitburn Management under our LTIP, respectively. During the three months and nine months ended September 30, 2015, our outside directors were issued zero and 0.2 million RPUs under our LTIP, respectively. The fair market value of the RPUs granted during 2015 for computing compensation expense under FASB Accounting Standards averaged $6.52 per unit.

During each of the three months ended September 30, 2015 and 2014, we paid zero for taxes withheld on RPUs. During the nine months ended September 30, 2015 and 2014, we paid $0.7 million and $0.9 million for taxes withheld on RPUs.

As of September 30, 2015, we had $30.1 million of unrecognized compensation costs for all outstanding awards, which is expected to be recognized over the period from October 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, 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 recognized 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 incurred a total cost of approximately $1.1 million, which was 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.



	Three Months Ended		Nine Months Ended
Thousands of dollars	September 30, 2015		September 30, 2015
Severance payments	—		4,768
Unit-based compensation expense	(191	)	1,343
Other termination costs	(87	)	302
Total	(278	)	6,413

16. Subsequent Events

On October 1, 2015, we announced a cash distribution to holders of Common Units for the first monthly payment attributable to the third quarter of 2015 at the rate of $0.04166 per Common Unit, which was paid on October 16, 2015 to the unitholders of record at the close of business on October 12, 2015. On October 30, 2015, we announced a cash distribution to holders of Common Units for the second monthly payment attributable to the third quarter of 2015 at the rate of $0.04166 per Common Unit, to be paid on November 13, 2015 to the unitholders of record at the close of business on November 9, 2015.

On October 1, 2015, we also 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 November 16, 2015, to record holders of our Series A Preferred Units at the close of business on October 30, 2015. On October 30, 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 December 15, 2015 to record holders of our Series A Preferred Units at the close of business on November 30, 2015. The monthly distribution rate is equal to an annual distribution of $2.0625 per Series A Preferred Unit.

On October 1, 2015 and October 30, 2015 we declared distributions on our Series B Preferred Units, which we elected to pay in kind by issuing additional Series B Preferred Units (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) of 0.006666 Series B Preferred Unit per unit, payable on October 15, 2015 and November 16, 2015, respectively, to record holders of Series B Preferred Units at the close of business on September 30, 2015 and October 30, 2015, respectively.

In October 2015, we entered into several crude oil and natural gas swap contracts, increasing our NYMEX WTI crude oil swap portfolio by 2,000 Bbl/day for 2016 and 1,000 Bbl/day for each of 2017, 2018, and 2019 for prices ranging from $49.10 per Bbl to $56.35 per Bbl, and our Henry Hub natural gas swap portfolio by 6,000 MMBtu/day, 2,000 MMBtu/day, and 1,000 MMBtu/day for 2016, 2017 and 2018, respectively, for prices ranging from $2.67 per MMBtu to $2.99 per MMBtu and our MichCon natural gas swap portfolio by 3,500 MMBtu/day for 2018 at $2.91 per MMBtu and 2,000 MMBtu/day for 2019 at $2.95 per MMBtu.

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, Alabama 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


•	California.

2015 Highlights

On March 31, 2015, we completed the acquisition of certain CO₂ producing properties located in Harding County, New Mexico for a total preliminary purchase price of $70.2 million, subject to customary purchase price adjustments. See Note 2 to the consolidated financial statements within this report for a discussion of this acquisition.

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 $944 million from these offerings, net of fees and estimated expenses.

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.

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. During the three months ended June 30, 2015, we paid three monthly cash distributions at the rate of $0.0417 per Common Unit per month, totaling approximately $26.4 million, or $0.1250 per Common Unit. During the three months ended September 30, 2015, we paid three monthly cash distributions at the rate of $0.0417 per Common Unit per month, totaling approximately $26.5 million, or $0.1250 per Common Unit. On October 1, 2015 and October 30, 2015, we announced cash distributions to holders of Common Units for the first and second monthly payments attributable to the third quarter of 2015, at the rate of $0.0417 per Common Unit per month, paid on October 16, 2015 and payable on November 13, 2015, respectively.

During each of the three months ended March 31, 2015, June 30, 2015 and September 30, 2015, we recognized $4.1 million of accrued distributions on the Series A Preferred Units. On October 1, 2015 and October 30, 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 November 16, 2015 and December 15, 2015, respectively.

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 (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) in lieu of cash of 0.008222 Series B Preferred Unit per unit, which was paid on May 15, 2015. On May 28, 2015, July 1, 2015, July 31, 2015, August 25, 2015, October 1, 2015 and October 30, 2015, we declared distributions on our Series B Preferred Units, which we elected to pay in kind by issuing additional Series B Preferred Units (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) of 0.006666 Series B Preferred Unit per unit, paid on June 15, 2015, July 15, 2015, August 17, 2015, September 15, 2015, October 15, 2015 and payable November 16, 2015, respectively.

Operational Focus and Capital Expenditures

In the first nine months of 2015, our capital expenditures for oil and gas activities, including capitalized engineering costs, totaled $179 million, compared to approximately $275 million in the first nine months of 2014. We spent approximately $61 million in the Permian Basin, $40 million in Florida, $44 million in Ark-La-Tex, $21 million in Mid-Continent, $10 million in California, $2 million in MI/IN/KY and $1 million in the Rockies. In the first nine months of 2015, we drilled and completed 28 productive wells in the Permian Basin, drilled and completed 12 productive wells in Ark-La-Tex, five productive wells in California, two productive wells in the Rockies, and two productive wells in Florida. We also performed workovers on 79 wells in Ark-La-Tex, 12 wells in California, 19 wells in Florida, two wells in MI/IN/KY and three wells in the Permian Basin.

Our capital spending program for oil and gas activities, including capitalized engineering costs and excluding acquisitions, is expected to be approximately $200 million for the year ended December 31, 2015. This compares with approximately $389 million in 2014. We anticipate that 80% of our total capital spending will be for drilling and rate-generating projects and CO₂ purchases that are designed to increase or add to production or reserves. We anticipate to drill 13 wells during the fourth quarter of 2015.

Commodity Prices

Our revenues and net income are sensitive to oil, NGL and natural gas prices which have been and are expected to continue to be highly volatile.

In the third quarter of 2015, the NYMEX WTI spot price averaged $47 per barrel, compared with approximately $98 per barrel in the third quarter of 2014. In the first nine months of 2015, the NYMEX WTI spot price ranged from a low of $38 per barrel to a high of $61 per barrel. In the first nine months of 2014, the NYMEX WTI spot price averaged $100 per barrel and ranged from a low of $91 per barrel to a high of $108 per barrel.

In the third quarter of 2015, the Henry Hub natural gas spot price averaged $2.76 per MMBtu compared with approximately $3.96 per MMBtu in the third quarter of 2014. In the first nine months of 2015, the Henry Hub natural gas spot price averaged $2.80 and ranged from a low of $2.47 per MMBtu to a high of $3.32 per MMBtu. In the first nine months of 2014, the Henry Hub spot price averaged $4.57 and ranged from a low of $3.77 per MMBtu to a high of $8.15 per MMBtu. In the third quarter of 2015, the MichCon natural gas spot price averaged $2.89 per MMBtu compared with approximately $4.21 per MMBtu in the third quarter of 2014.

These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. We expect that further or sustained crude oil and natural gas prices will not only decrease our revenues, but will also reduce the amount of crude oil and natural gas that we can produce economically and therefore lower our crude oil and natural gas reserves.

The recent significant decline in oil and natural gas prices increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. We are unable to predict future commodity prices with any greater precision than the futures market. A prolonged period of depressed commodity prices may have a significant impact on the volumetric quantities of our proved reserve portfolio. The impact of commodity prices on our estimated proved reserves can be illustrated as follows: if the SEC-mandated 2014 beginning of the prior 12 months average prices used for our December 31, 2014 reserve report had been replaced with NYMEX, Brent, and Henry Hub Futures strip prices for the applicable commodity as of September 30, 2015 (without regard to our commodity derivative positions and without assuming any change in development plans or costs, which has historically not been the case in periods of prolonged depressed commodity prices), then the estimated proved reserves volumes as of December 31, 2014 would have decreased by approximately 18%. The prices assumed in this example were derived using NYMEX, Brent, and Henry Hub Futures strip prices at September 30, 2015 through December 31, 2021, which averaged $54.36 per Boe, $58.66 per Boe, and $3.17 per Mcf, respectively, and then held flat thereafter. The average realized blended price is $38.82 per Boe. We believe that the use of NYMEX, Brent, and Henry Hub Futures strip price may help provide investors with an understanding of the impact of sustained lower commodity price conditions on our proved reserves through an assumed period. However, the use of this pricing example does not necessarily indicate management’s overall view on future commodity prices. In addition, if revisions of proved reserves occur in the future, we could have further increases in our DD&A rates. We are unable to predict the timing and amount of future reserve revisions, nor the impact such revisions may have on our future DD&A rates.

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 LP (“PCEC”), our predecessor, and provides administrative services to PCEC under an administrative services agreement. These services include operational functions, such as exploitation and technical services, petroleum and reserves engineering and executive management, and administrative services, such as accounting, information technology, audit, human resources, land, business development, finance and legal. These services are provided in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses, including incentive compensation plan costs and direct payroll and administrative costs related to PCEC properties and operations. For the three months and nine months ended September 30, 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. In the event PCEC has not received certain permits by December 31, 2015, PCEC may terminate the agreement effective as of June 30, 2016.

Results of Operations

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



Thousands of dollars,	Three Months Ended September 30,					Increase/					Nine Months Ended September 30,					Increase/
except as indicated	2015			2014		(Decrease)			%		2015		2014			(Decrease)			%
Total production (MBoe)	5,008			3,353		1,655			49	%	15,074		9,945			5,129			52	%
Oil (MBbl)	2,741			1,904		837			44	%	8,453		5,604			2,849			51	%
NGLs (MBbl)	485			253		232			92	%	1,427		789			638			81	%
Natural gas (MMcf)	10,689			7,178		3,511			49	%	31,164		21,312			9,852			46	%
Average daily production (Boe/d)	54,435			36,450		17,985			49	%	55,216		36,432			18,784			52	%
Sales volumes (MBoe)	4,980			3,412		1,568			46	%	15,067		9,934			5,133			52	%
Average realized sales price (per Boe) (a)(b)	$	30.78		$	63.33	$	(32.55	)	(51	)%	$	33.54	$	66.30		$	(32.76	)	(49	)%
Oil (per Bbl) (a)(b)	43.38			90.12		(46.74		)	(52	)%	46.86		92.59			(45.73		)	(49	)%
NGLs (per Bbl)	12.44			37.87		(25.43		)	(67	)%	15.76		39.70			(23.94		)	(60	)%
Natural gas (per Mcf) (b)	2.76			4.12		(1.36		)	(33	)%	2.79		5.13			(2.34		)	(46	)%
Oil sales	117,743			176,986		(59,243		)	(33	)%	396,011		518,020			(122,009		)	(24	)%
NGL sales	6,032			9,582		(3,550		)	(37	)%	22,484		31,322			(8,838		)	(28	)%
Natural gas sales	29,550			29,578		(28		)	—	%	87,089		109,411			(22,322		)	(20	)%
Gain (loss) on commodity derivative instruments	253,012			146,171		106,841			73	%	296,772		(21,057		)	317,829			n/a
Other revenues, net (c)	5,922			1,585		4,337			n/a		18,895		4,240			14,655			n/a
Total revenues	412,259			363,902		48,357			13	%	821,251		641,936			179,315			28	%
Lease operating expenses before taxes (d)	99,318			62,714		36,604			58	%	293,264		200,627			92,637			46	%
Production and property taxes (e)	13,249			16,327		(3,078		)	(19	)%	42,141		47,987			(5,846		)	(12	)%
Total lease operating expenses	112,567			79,041		33,526			42	%	335,405		248,614			86,791			35	%
Purchases and other operating costs	367			102		265			n/a		937		426			511			120	%
Salt water disposal costs	4,205			—		4,205			n/a		12,279		—			12,279			n/a
Change in inventory	(2,004		)	3,761		(5,765		)	n/a		329		(879		)	1,208			(137	)%
Total operating costs	115,135			82,904		32,231			39	%	348,950		248,161			100,789			41	%
Lease operating expenses before taxes per Boe	19.83			18.70		1.13			6	%	19.45		20.17			(0.72		)	(4	)%
Production and property taxes per Boe	2.65			4.87		(2.22		)	(46	)%	2.80		4.83			(2.03		)	(42	)%
Total lease operating expenses per Boe	22.48			23.57		(1.09		)	(5	)%	22.25		25.00			(2.75		)	(11	)%
Depletion, depreciation and amortization (“DD&A”)	117,464			72,671		44,793			62	%	336,735		204,417			132,318			65	%
DD&A per Boe	23.46			21.67		1.79			8	%	22.34		20.55			1.79			9	%
Impairment of oil and natural gas properties	1,440,167			29,434		1,410,733			n/a		1,499,280		29,434			1,469,846			n/a
Impairment of goodwill	—			—		—			n/a		95,947		—			95,947			n/a
G&A excluding unit based compensation	16,916			12,908		4,008			31	%	59,029		35,446			23,583			67	%
G&A excluding unit based compensation per Boe	$	3.38		$	3.85	$	(0.47	)	(12	)%	3.92		$	3.56		$	0.36		10	%

(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 and Nine Months Ended September 30, 2015 and 2014

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

Production

For the three months ended September 30, 2015, total production was 5,008 MBoe compared to 3,353 MBoe for the three months ended September 30, 2014, an increase of 49%, primarily due to 1,918 MBoe of production from our properties acquired in the QRE Merger in November 2014 (the “QRE properties”), partially offset by lower production from our legacy properties, primarily in the Permian Basin, MI/IN/KY and the Rockies due to natural field declines.

For the nine months ended September 30, 2015, total production was 15,074 MBoe compared to 9,945 MBoe for the nine months ended September 30, 2014, an increase of 5,129 MBoe, primarily due to 5,666 MBoe of production from the QRE properties, partially offset by lower production from our legacy properties, primarily in Mid-Continent, the Permian Basin and MI/IN/KY due to natural field declines.

Oil, NGL and natural gas sales

Total oil, NGL and natural gas sales revenues decreased $62.8 million for the three months ended September 30, 2015, compared to the three months ended September 30, 2014. Crude oil revenues decreased $59.2 million due to lower average crude oil prices, partially offset by production from the QRE properties. NGL revenues decreased $3.6 million due to lower average NGL prices, partially offset by production from the QRE properties. Natural gas revenues were $29.6 million, unchanged from the prior year, reflecting higher production from the QRE properties, which was offset by lower average natural gas prices.

Realized prices for crude oil, excluding the effect of derivative instruments, decreased $46.74 per Boe, or 52%, for the three months ended September 30, 2015 compared to the three months ended September 30, 2014. Realized prices for NGLs, excluding the effect of derivative instruments, decreased $25.43 per Boe, or 67% for the three months ended September 30, 2015 compared to the three months ended September 30, 2014. Realized prices for natural gas, excluding the effect of derivative instruments, decreased $1.36 per Mcf, or 33%, for the three months ended September 30, 2015 compared to the three months ended September 30, 2014.

Total oil, NGL and natural gas sales revenues decreased $153.2 million for the nine months ended September 30, 2015, compared to the nine months ended September 30, 2014. Crude oil revenues decreased $122.0 million due to lower average crude oil prices, partially offset by production from the QRE properties. NGL revenues decreased $8.8 million due to lower average NGL prices, partially offset by production from the QRE properties. Natural gas revenues decreased $22.3 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 $45.73 per Boe, or 49%, for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014. Realized prices for NGLs, excluding the effect of derivative instruments, decreased $23.94 per Boe, or 60%, for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014. Realized prices for natural gas, excluding the effect of derivative instruments, decreased $2.34 per Mcf, or 46%, for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014.

Gain (loss) on commodity derivative instruments

Gain on commodity derivative instruments for the three months ended September 30, 2015 was $253.0 million compared to a gain of $146.2 million during the three months ended September 30, 2014. Oil and natural gas derivative instrument settlement receipts net of payments totaled $129.0 million for the three months ended September 30, 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 September 30, 2014 totaled $3.7 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 September 30, 2015 was $124.0 million compared to a mark-to-market gain of $149.9 million for the three months ended September 30, 2014, primarily due to a decrease in commodity future prices during the three months ended September 30, 2015 and 2014.

Gain on commodity derivative instruments for the nine months ended September 30, 2015 was $296.8 million compared to a loss of $21.1 million during the nine months ended September 30, 2014. Oil and natural gas derivative instrument settlement receipts net of payments totaled $355.9 million for the nine months ended September 30, 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 nine months ended September 30, 2014 totaled $34.2 million due to higher commodity prices compared to our average hedge prices.

Mark-to-market loss on commodity derivative instruments for the nine months ended September 30, 2015 was $59.1 million compared to a mark-to-market gain of $13.2 million for the nine months ended September 30, 2014, primarily due to an increase in commodity future prices during the nine months ended September 30, 2015 and a decrease in commodity futures prices for the nine months ended September 30, 2014.

Other revenues, net

Other revenues increased $4.3 million for the three months ended September 30, 2015, compared to the three months ended September 30, 2014, primarily due to $4.1 million of salt water disposal revenue and $0.5 million of sulfur sales revenue related to the QRE properties.

Other revenues increased $14.7 million for the nine months ended September 30, 2015, compared to the nine months ended September 30, 2014, primarily due to $12.2 million of salt water disposal revenue and $1.7 million of sulfur sales revenue related to the QRE properties.

Lease operating expenses

Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the three months ended September 30, 2015 increased $36.6 million compared to the three months ended September 30, 2014. The increase in pre-tax lease operating expenses primarily reflects lease operating costs for the QRE properties. On a per Boe basis, pre-tax lease operating expenses were 6% higher than the three months ended September 30, 2014 at $19.83 per Boe, primarily due to higher well service expenses.

Production and property taxes for the three months ended September 30, 2015 totaled $13.2 million, which was $3.1 million lower than the three months ended September 30, 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 September 30, 2015 were $2.65 per Boe, which was 46% lower than the three months ended September 30, 2014, due to lower commodity prices.

Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the nine months ended September 30, 2015 increased $92.6 million compared to the nine months ended September 30, 2014. The increase in pre-tax lease operating expenses primarily reflects lease operating costs for the QRE properties. On a per Boe basis, pre-tax lease operating expenses were 4% lower than the nine months ended September 30, 2014 at $19.45 per Boe, primarily due to lower commodity prices and lower well service expenses.

Production and property taxes for the nine months ended September 30, 2015 totaled $42.1 million, which was $5.8 million lower than the nine months ended September 30, 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 nine months ended September 30, 2015 were $2.80 per Boe, which was 42% lower than the nine months ended September 30, 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 September 30, 2015, the change in inventory account amounted to a credit of $2.0 million compared to a charge of $3.8 million during the same period in 2014. The credit to inventory during the three months ended September 30, 2015 primarily reflects a lower volume of crude oil sold than produced during the quarter. The charge during

the three months ended September 30, 2014 reflects a higher volume of crude oil sold than produced during the period. In the three months ended September 30, 2015, we sold 129 gross MBbls and produced 162 gross MBbls of crude oil from our Florida operations.

For the nine months ended September 30, 2015, the change in inventory account amounted to a charge of $0.3 million compared to a credit of $0.9 million during the same period in 2014. The charge to inventory during the nine months ended September 30, 2015 primarily reflects the higher volume of crude oil sold than produced during the period. The credit during the nine months ended September 30, 2014 reflects a lower volume of crude oil sold than produced during the period due to the timing of South Florida sales. In the nine months ended September 30, 2015, we sold 512 gross MBbls and produced 520 gross MBbls of crude oil from our Florida operations.

Depletion, depreciation and amortization

DD&A totaled $117.5 million, or $23.46 per Boe, during the three months ended September 30, 2015, an increase of approximately 8% per Boe from the same period a year ago. The increase in DD&A per Boe compared to the three months ended September 30, 2014 was primarily due to lower oil and natural gas prices, and the effect those prices had on our reserve volumes, as well as the addition of QRE properties acquired at higher values, and capital expenditures incurred during the twelve months ended September 30, 2015.

DD&A totaled $336.7 million, or $22.34 per Boe, during the nine months ended September 30, 2015, an increase of approximately 9% per Boe from the same period a year ago. The increase in DD&A per Boe compared to the nine months ended September 30, 2014 was primarily due to lower oil and natural gas prices, and the effect those prices had on our reserve volumes, as well the addition of QRE properties acquired at higher values, and capital expenditures incurred during the twelve months ended September 30, 2015.

Impairments

Impairments of proved properties totaled $1.4 billion for the three months ended September 30, 2015, including $605.4 million in Michigan, $420.2 million in Florida, $262.1 million in Ark-La-Tex, $73.1 million in California, $49.7 million for our Permian properties, $17.4 million in the Rockies and $12.2 million for our Mid-Continent properties. The impairments are primarily related to the impact of the drop in commodity strip prices on our projected future net revenues. Impairments of proved properties totaled $1.5 billion for the nine months ended September 30, 2015, including $605.4 million in Michigan, $420.2 million in Florida, $262.1 million in Ark-La-Tex, $73.1 million in California, $82.8 million for our Permian properties, $34.1 million for our Rockies natural gas properties and $21.5 million for our Mid-Continent properties, primarily due to the impact of the drop in commodity strip prices on our projected future net revenues during the third quarter and the impact of the decrease in oil and natural gas prices on certain of our low operating margin properties during the first quarter. Impairments totaled $29.4 million for the three months and nine months ended September 30, 2014, including $19.9 million in Florida, $6.5 million in Michigan and $3.0 million in Wyoming. The carrying values of the properties were reduced to their estimated fair values using level 3 inputs. Additional impairments may be recognized in the fourth quarter of 2015 should commodity prices decline further.

As of March 31, 2015, we had $95.9 million of goodwill related to the QRE Merger (see Note 2 to the consolidated financial statements within this report for a discussion of goodwill related to the QRE Merger). Due to a decrease in the price of our Common Units during the second quarter of 2015, we performed a qualitative goodwill impairment assessment. In the first step of the goodwill impairment test, we determined that the fair value of our goodwill was less than the carrying amount, primarily due to the decrease in the price of our Common Units. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there was no remaining implied fair value attributable to goodwill. We therefore recorded a non-cash goodwill impairment charge of $95.9 million during the three months ended June 30, 2015, to reduce the carrying value of goodwill to zero.

General and administrative expenses

Our G&A expenses totaled $23.3 million and $18.7 million for the three months ended September 30, 2015 and 2014, respectively. This included $6.4 million and $5.8 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans for the three months ended September 30, 2015 and 2014. G&A expenses, excluding non-cash unit-based compensation, were $16.9 million and $12.9 million for the three months ended September 30, 2015 and 2014, respectively. The increase was primarily due to $2.9 million in higher expenses from adding personnel from the QRE Merger

and $1.1 million higher integration and acquisition costs and higher office building rent. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $3.38 and $3.85 for the three months ended September 30, 2015 and 2014, respectively.

Our G&A expenses totaled $78.4 million and $53.9 million for the nine months ended September 30, 2015 and 2014, respectively. This included $19.4 million and $18.5 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans. G&A expenses, excluding non-cash unit-based compensation, were $59.0 million and $35.4 million for the nine months ended September 30, 2015 and 2014, respectively. The increase was primarily due to higher acquisition and integration costs of $7.9 million and higher payroll expenses from adding personnel from the QRE Merger, higher office building rent and legal costs. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $3.92 and $3.56 for the nine months ended September 30, 2015 and 2014, respectively. The increase in G&A expenses per Boe was primarily due to higher integration costs. The increase in unit-based compensation expense was primarily due to additional personnel attributable to the QRE Merger.

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 which included severance cash payments, accelerated vesting of LTIP grants for certain individuals and other employee-related termination costs. Of the $5.6 million in restructuring costs, $4.9 million were recognized in the first quarter of 2015 and $0.7 million were recognized in the second quarter of 2015. In April 2015, we communicated further reductions to an additional 8 employees and incurred a total cost of approximately $1.1 million, which was 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.

Interest expense, net of amounts capitalized

Our interest expense totaled $50.9 million and $29.5 million for the three months ended September 30, 2015 and 2014, respectively. The increase in interest expense was primarily due to $15.0 million of interest on our Senior Secured Notes and $4.3 million higher credit facility interest expense as a result of higher borrowings related to the QRE Merger. Interest expense, excluding debt amortization, totaled $47.1 million and $27.7 million for the three months ended September 30, 2015 and 2014, respectively.

Our interest expense totaled $152.0 million and $90.4 million for the nine months ended September 30, 2015 and 2014, respectively. The increase in interest expense was primarily due to $28.9 million of interest on our Senior Secured Notes, $17.5 million higher credit facility interest expense as a result of higher borrowings related to the QRE Merger and $10.6 million write-off of debt issuance costs associated with the reduction of our credit facility borrowing base in April 2015. Interest expense, excluding debt amortization, totaled $131.1 million and $84.6 million for the nine months ended September 30, 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 September 30, 2015, we had interest rate swaps, indexed to 1-month LIBOR, to fix a portion of floating LIBOR-based debt under our credit facility for 2015 and 2016, for notional amounts of $374.0 million and $410.0 million, respectively, with average fixed rates of 1.64% and 1.72%, respectively, that were assumed as part of the QRE Merger. As of September 30, 2014, we had no interest rate swaps in place. Loss on interest swaps for the three months ended September 30, 2015 and 2014 were $1.0 million and zero, respectively. The loss on interest rate swaps for the three months ended September 30, 2015 included settlement payments of $1.5 million and a mark-to-market gain of $0.5 million. Loss on interest swaps for the nine months ended September 30, 2015 and 2014 were $3.4 million and zero, respectively. The loss on interest rate swaps for the nine months ended September 30, 2015 included settlement payments of $4.4 million and a mark-to-market gain of $1.0 million.

Liquidity and Capital Resources

Overview

As of September 30, 2015, we had approximately $526 million of available borrowing capacity under our credit facility (including the impact of outstanding letters of credit), which has a borrowing base of $1.8 billion, and we had approximately $1.25 billion of indebtedness outstanding under our credit facility. We have historically funded our operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under our credit facility and equity and debt offerings. Future cash flow is subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2015. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position.

During the second quarter of 2015, we took actions to improve our liquidity position. On April 8, 2015, we completed private offerings of $650 million of Senior Secured Notes and $350 million of Series B Preferred Units with combined net proceeds of approximately $944 million, which we used primarily to repay borrowings under our credit facility.

Concurrently with those transactions, we also amended our credit facility to establish a borrowing base of $1.8 billion until April 1, 2016, subject, starting with the October 1, 2015 borrowing base redetermination date, to our having liquidity (inclusive of borrowing base availability) of 10% of the borrowing base. Based on current commodity prices and other factors at the time of the April 2016 redetermination, we expect our borrowing base to be decreased. Without a waiver from our lenders, our credit facility currently provides that if the borrowing base is reduced below our current outstanding borrowings, we are required to repay the deficiency in five equal monthly installments. Although our lenders have discretion to redetermine the borrowing base below our outstanding borrowings, we do not expect this to occur.

Although we currently expect our sources of capital to be sufficient to meet our near-term liquidity needs, there can be no assurance that the lenders under our credit facility will not reduce the borrowing base to an amount below our outstanding borrowings or that our liquidity requirements will continue to be satisfied, given current oil prices and the discretion of our lenders to decrease our borrowing base. Due to the steep decline in commodity prices, we may not be able to obtain funding in the equity or capital markets on terms we find acceptable. The cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, and reduced and, in some cases, ceased to provide any new funding. If the borrowing base determination in April 2016 results in a borrowing base deficiency and we cannot access the capital markets and repay debt under our credit facility, we may be unable to continue to pay distributions to our unitholders and may take other actions to reduce costs and to raise funds to repay debt, such as selling assets or monetizing derivative contracts.

Our ability to access the public or private debt or equity capital markets on economic terms in the future will be affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control.

Cash Flows

Operating activities. Our cash flows from operating activities for the nine months ended September 30, 2015 were $351.2 million compared to $294.9 million for the nine months ended September 30, 2014. The increase in cash flows from operating activities was primarily due to non-cash adjustments of $1.5 billion for impairment of oil and natural gas properties, higher sales revenues in 2015 from a 52% increase in sales volume primarily due to the QRE properties, which increased sales revenue by approximately $340 million and $390 million in higher commodity derivative settlement receipts primarily due to lower commodity prices, which was partially offset by lower physical sales revenue driven by lower commodity prices, which decreased sales revenue by approximately $493 million, $101 million of additional operating costs primarily for the QRE properties and $51 million higher cash interest paid due to higher debt levels. Cash flow from working capital changes during the nine months ended September 30, 2015 was $8 million lower than the nine months ended September 30, 2014, primarily due to lower commodity prices, which impacted our payable balances for lease operating expenses, royalties, and production taxes.

Investing activities. Net cash flows used in investing activities during the nine months ended September 30, 2015 and 2014 were $235.5 million and $308.6 million, respectively. During the nine months ended September 30, 2015, we paid

$226.7 million for cash capital expenditures, consisting of approximately $218.9 million primarily for drilling and completion activities, and approximately $7.8 million for IT capital expenditures, $17.2 million on property acquisitions, primarily for CO₂ producing properties, $3.8 million on purchases of available-for-sale securities and $0.9 million on CO₂ advances, partially offset by $9.4 million in proceeds from sale of assets and $3.6 million in proceeds from the sale of available-for-sale securities. During the nine months ended September 30, 2014, we spent $293.3 million on cash capital expenditures, primarily for drilling and completion activities, $9.2 million on CO₂ advances and $6.4 million on property acquisitions, partially offset by $0.4 million in proceeds from sale of assets.

Financing activities. Net cash flows used in financing activities for the nine months ended September 30, 2015 were $116.3 million, and net cash flows provided by financing activities for the nine months ended September 30, 2014 were $14.4 million. During the nine months ended September 30, 2015, we decreased our outstanding borrowings under our credit facility by approximately $941.5 million. We had total outstanding borrowings, net of unamortized discount on our Senior Notes, of approximately $3.04 billion at September 30, 2015 and $3.35 billion at December 31, 2014. During the nine months ended September 30, 2015, we received net proceeds of $337.9 million and $4.8 million from the issuance of Series B Preferred Units and Common Units, respectively, we made cash distributions of $108.3 million and $12.4 million on Common Units and Series A Preferred Units, respectively, borrowed $1.20 billion, repaid $1.51 billion on our credit facility and other long-term debt and paid $29.1 million of debt issuance costs. During the nine months ended September 30, 2014, we received net proceeds of $193.2 million and $25.9 million from the issuance of Series A Preferred Units and Common Units, respectively, made cash distributions of $181.4 million on Common Units, borrowed $693.0 million and repaid $707.0 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 8.0% 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 distribution on our Series B Preferred Units, which we elected to pay in kind by issuing additional Series B Preferred Units (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) in lieu of cash of 0.008222 Series B Preferred Unit per unit, which was paid on May 15, 2015. On May 28, 2015, July 1, 2015, July 31, 2015, August 25, 2015, October 1, 2015 and October 30, 2015, we declared distributions on our Series B Preferred Units, which we elected to pay in kind by issuing additional Series B Preferred Units (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) of 0.006666 Series B Preferred Unit per unit, paid on June 15, 2015, July 15, 2015, August 17, 2015, September 15, 2015, October 15, 2015 and payable November 16, 2015, respectively.

Common Units

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

During the three months ended September 30, 2015, we paid three monthly cash distributions at the rate of $0.0417 per Common Unit per month, totaling approximately $26.5 million, or $0.1250 per Common Unit. During the nine months ended September 30, 2015, we paid nine monthly cash distributions, totaling approximately $105.6 million, or $0.4999 per Common Unit.

On October 1, 2015, we announced a cash distribution of $0.04166 per Common Unit for the first monthly payment attributable to the third quarter of 2015, which was paid on October 16, 2015, to record holders of Common Units at the close of business on October 12, 2015. On October 30, 2015, we announced a cash distribution to unitholders of the second monthly payment attributable to the third quarter of 2015 at the rate of $0.04166 per Common Unit, payable on November 13, 2015 to the unitholders of record at the close of business on November 9, 2015. These monthly distributions are equal to a distribution of $0.50 per Common Unit on an annualized basis.

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 7 to the consolidated financial statements within this report for a discussion of our

Senior Secured Notes.

As of September 30, 2015, we had $305 million in 2020 Senior Notes and $850 million in 2022 Senior Notes in addition to the Senior Secured Notes. See Note 7 to the consolidated financial statements within this report for a discussion of our Senior Unsecured Notes.

Credit Agreement

At each of September 30, 2015 and December 31, 2014, we had a $5.0 billion credit facility with a maturity date of November 19, 2019. At September 30, 2015 and December 31, 2014, our borrowing base was $1.8 billion and $2.5 billion respectively.

In connection with the Series B Preferred Units and Senior Secured Notes offerings, on April 8, 2015, we entered into the First Amendment. Among other changes, the First Amendment: (i) established 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) permitted $650 million of second lien indebtedness; (iii) increased the base rate and LIBOR margins by 0.25%; (iv) added 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) added 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 November 4, 2015 and September 30, 2015, were $1.28 billion and $1.25 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 September 30, 2015, the lending group under the Third Amended and Restated Credit Agreement included 35 banks. Of the $1.8 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; permit the interest coverage ratio (defined as the ratio of EBITDAX to Consolidated Interest Expense) to be less than 2.50 to 1.00; 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 September 30, 2015 and November 4, 2015, we were in compliance with our debt covenants. We expect to remain in compliance with these debt covenants through 2016.

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 September 30, 2015, our derivative counterparties were Bank of Montreal, Barclays Bank PLC, BNP Paribas, Canadian Imperial Bank of Commerce, Citibank, N.A, Citizens Bank, National Association, Comerica Bank, Credit Agricole Corporate and Investment Bank, Credit Suisse Energy LLC, Credit Suisse International, ING Capital Markets LLC, JP Morgan Chase Bank N.A., Merrill Lynch Commodities, Inc., Morgan Stanley Capital Group Inc., Royal Bank of Canada, The Bank of Nova Scotia, The Toronto-Dominion Bank, Union Bank N.A. and Wells Fargo Bank, N.A. 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 September 30, 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 September 30, 2015, our largest derivative asset balances were with Wells Fargo Bank, N.A., Credit Suisse Energy LLC, JP Morgan Chase Bank N.A. and Barclays Bank PLC, which accounted for approximately 19%, 11%, 11% and 11% of our net derivative asset balances, respectively.

Except as discussed above, we had no material changes to our financial contractual obligations during the nine months ended September 30, 2015.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of September 30, 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 September 30, 2015.

Changes in Fair Value

The fair value of our outstanding oil and natural gas commodity derivative instruments was a net asset of approximately $668.0 million and $727.2 million at September 30, 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 September 30, 2015 would have decreased by approximately $175 million. With a $10.00 per barrel decrease in the price of oil, and a corresponding $1.00 per Mcf decrease in natural gas, our net commodity derivative instrument asset at September 30, 2015 would have increased by approximately $187 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 $6.2 million and $7.2 million at September 30, 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 September 30, 2015 would have decreased by approximately $5 million. With a 100 basis points decrease in the LIBOR rate to a minimum rate of zero, our net liability at September 30, 2015 would have increased by approximately $5 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 Securities and Exchange Commission. Based upon the evaluation, our General Partner’s principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 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 September 30, 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

None.

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 (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q (File No. 001-33055) filed on May 5, 2015.
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).
31.1*		Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.



32.2**		Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
101*		Interactive Data Files.
*		Filed herewith.
**		Furnished herewith.
†		Management contract or compensatory plan or arrangement.

SIGNATURES

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



		BREITBURN ENERGY PARTNERS LP

		By:	BREITBURN GP LLC,
			its General Partner

Dated:	November 5, 2015	By:	/s/ Halbert S. Washburn
			Halbert S. Washburn
			Chief Executive Officer

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

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