Breitburn Energy Partners LP - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - Breitburn Energy Partners LP	q1201610-qex322.htm
EX-32.1 - EXHIBIT 32.1 - Breitburn Energy Partners LP	q1201610-qex321.htm
EX-31.1 - EXHIBIT 31.1 - Breitburn Energy Partners LP	q1201610-qex311.htm
EX-31.2 - EXHIBIT 31.2 - Breitburn Energy Partners LP	q1201610-qex312.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



x	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarterly period ended March 31, 2016



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)

707 Wilshire Boulevard, Suite 4600
Los Angeles, California	90017
(Address of principal executive offices)	(Zip Code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes x No o

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



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

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

Yes o No x

As of May 6, 2016, the registrant had 213,789,296 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 March 31, 2016 and December 31, 2015	2
	– Consolidated Statements of Operations (Unaudited) for the Three Months Ended March 31, 2016 and 2015	3
	– Consolidated Statements of Comprehensive Loss (Unaudited) for the Three Months Ended March 31, 2016 and 2015	4
	– Consolidated Statements of Cash Flows (Unaudited) for the Three Months Ended March 31, 2016 and 2015	5
	– Condensed Notes to the Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	35

	PART II
	OTHER INFORMATION

Item 1.	Legal Proceedings	36
Item 1A.	Risk Factors	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3.	Defaults Upon Senior Securities	37
Item 4.	Mine Safety Disclosures	37
Item 5.	Other Information	37
Item 6.	Exhibits	38

Signatures		40

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 facility and any deficiencies that would have to be repaid in five equal monthly installments; ability to continue to borrow under the credit agreement; ability to generate sufficient cash flows from operations to meet the internally funded portion of any capital expenditures budget; changes in our business strategy; ability to obtain external capital to finance exploitation and development operations and acquisitions; the potential need to sell certain assets, restructure our debt, raise additional capital or seek bankruptcy protection; our future levels of indebtedness, liquidity, compliance with financial covenants and our ability to continue as a going concern; 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, 2015 (our “2015 Annual Report”), and under Part II—Item 1A of this report. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

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

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Breitburn Energy Partners LP and Subsidiaries

Consolidated Balance Sheets

(Unaudited)



Thousands of dollars	March 31, 2016			December 31, 2015
ASSETS
Current assets
Cash	$	81,691		$	10,464
Accounts and other receivables, net	113,215			128,589
Derivative instruments (note 3)	388,829			439,627
Related party receivables (note 4)	1,518			2,274
Inventory	1,345			926
Prepaid expenses	3,470			6,447
Total current assets	590,068			588,327
Equity investments	6,657			6,567
Property, plant and equipment
Oil and natural gas properties (note 2)	7,855,082			7,898,117
Other property, plant and equipment (note 2)	194,876			188,795
	8,049,958			8,086,912
Accumulated depletion, depreciation, and impairment (note 5)	(4,185,936		)	(4,154,030		)
Net property, plant and equipment	3,864,022			3,932,882
Other long-term assets
Derivative instruments (note 3)	179,658			226,764
Other long-term assets (note 6)	74,981			80,847
Total assets	$	4,715,386		$	4,835,387
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	42,169		$	50,412
Current portion of long-term debt (note 7)	172,000			154,000
Derivative instruments (note 3)	4,309			4,462
Distributions payable	733			733
Current portion of asset retirement obligation	1,679			2,341
Revenue and royalties payable	33,476			35,462
Wages and salaries payable	12,928			21,654
Accrued interest payable	61,415			19,517
Production and property taxes payable	20,178			24,292
Other current liabilities	7,834			5,133
Total current liabilities	356,721			318,006
Credit facility	1,025,000			1,075,000
Senior notes, net	1,754,840			1,752,194
Other long-term debt	3,779			3,148
Total long-term debt (note 7)	2,783,619			2,830,342
Deferred income taxes	3,704			3,844
Asset retirement obligation (note 9)	247,956			252,037
Derivative instruments (note 3)	752			255
Other long-term liabilities	19,751			25,008
Total liabilities	3,412,503			3,429,492
Commitments and contingencies (note 10)
Equity
Series A preferred units, 8.0 million units issued and outstanding at each of March 31, 2016 and December 31, 2015 (note 11)	193,215			193,215
Series B preferred units, 49.6 million and 48.8 million units issued and outstanding at March 31, 2016 and December 31, 2015, respectively (note 11)	359,611			353,471
Common units, 213.7 million and 213.5 million units issued and outstanding at March 31, 2016 and December 31, 2015, respectively (note 11)	742,713			852,114
Accumulated other comprehensive income (loss) (note 12)	49			(229		)
Total partners' equity	1,295,588			1,398,571
Noncontrolling interest	7,295			7,324
Total equity	1,302,883			1,405,895
Total liabilities and equity	$	4,715,386		$	4,835,387

See accompanying notes to consolidated financial statements.

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Operations

(Unaudited)



	Three Months Ended
	March 31,
Thousands of dollars, except per unit amounts	2016			2015
Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	105,450		$	162,623
Gain on commodity derivative instruments, net (note 3)	37,923			137,192
Other revenue, net	4,593			6,469
Total revenues and other income items	147,966			306,284
Operating costs and expenses
Operating costs	94,974			117,978
Depletion, depreciation and amortization	83,723			109,824
Impairment of oil and natural gas properties (note 5)	2,793			59,113
General and administrative expenses	21,414			32,262
Restructuring costs (note 14)	2,809			4,918
(Gain) loss on sale of assets	(12,260		)	15
Total operating costs and expenses	193,453			324,110

Operating loss	(45,487		)	(17,826		)

Interest expense, net of capitalized interest	55,989			39,665
Loss on interest rate swaps (note 3)	2,343			1,812
Other expense (income), net	282			(477		)

Loss before taxes	(104,101		)	(58,826		)

Income tax (benefit) expense	(95		)	92

Net loss	(104,006		)	(58,918		)

Less: Net loss attributable to noncontrolling interest	(220		)	(93		)

Net loss attributable to the partnership	(103,786		)	(58,825		)

Less: Distributions to Series A preferred unitholders	4,125			4,125
Less: Non-cash distributions to Series B preferred unitholders	7,386			—
Less: Net loss attributable to participating units	—			(1,432		)

Net loss used to calculate basic and diluted net loss per unit	$	(115,297	)	$	(61,518	)

Basic net loss per common unit (note 11)	$	(0.54	)	$	(0.29	)
Diluted net loss per common unit (note 11)	$	(0.54	)	$	(0.29	)

Weighted average number of units used to calculate basic and diluted net loss per unit (in thousands):
Basic	213,661			210,931
Diluted	213,661			210,931

See accompanying notes to consolidated financial statements.

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Comprehensive Loss

(Unaudited)



	Three Months Ended
	March 31,
Thousands of dollars, except per unit amounts	2016			2015
Net loss	$	(104,006	)	$	(58,918	)

Other comprehensive income, net of tax:
Change in fair value of available-for-sale securities (a)	470			173
Total other comprehensive income	470			173

Total comprehensive loss	(103,536		)	(58,745		)

Less: Comprehensive loss attributable to noncontrolling interest	(28		)	(23		)

Comprehensive loss attributable to the partnership	$	(103,508	)	$	(58,722	)

(a) Net of income taxes of $0.2 million and $0.1 million for the three months ended March 31, 2016 and 2015, respectively.

See accompanying notes to consolidated financial statements.

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)



	Three Months Ended
	March 31,
Thousands of dollars	2016			2015
Cash flows from operating activities
Net loss	$	(104,006	)	$	(58,918	)
Adjustments to reconcile to cash flows from operating activities:
Depletion, depreciation and amortization	83,723			109,824
Impairment of oil and natural gas properties	2,793			59,113
Unit-based compensation expense	5,311			7,741
Gain on derivative instruments	(35,580		)	(135,380		)
Derivative instrument settlement receipts	133,828			124,904
Income from equity affiliates, net	(90		)	325
Deferred income taxes	(140		)	168
(Gain) loss on sale of assets	(12,260		)	15
Other	8,182			(41		)
Changes in net assets and liabilities
Accounts receivable and other assets	12,109			30,043
Inventory	(419		)	(185		)
Net change in related party receivables and payables	756			2,462
Accounts payable and other liabilities	32,602			1,078
Net cash provided by operating activities	126,809			141,149
Cash flows from investing activities
Property acquisitions	(3,942		)	(13,993		)
Capital expenditures	(26,965		)	(97,230		)
Proceeds from sale of assets	11,796			—
Proceeds from sale of available-for-sale securities	5,118			—
Purchases of available-for-sale securities	(5,416		)	—
Other	—			(853		)
Net cash used in investing activities	(19,409		)	(112,076		)
Cash flows from financing activities
Proceeds from issuance of common units, net	—			(63		)
Distributions to preferred unitholders	(4,126		)	(4,125		)
Distributions to common unitholders	—			(54,122		)
Proceeds from issuance of long-term debt, net	37,000			193,600
Repayments of long-term debt	(69,000		)	(168,500		)
Principal payments on capital lease obligations	(19		)	—
Change in bank overdraft	(25		)	199
Debt issuance costs	(3		)	—
Net cash used in financing activities	(36,173		)	(33,011		)
Increase (decrease) in cash	71,227			(3,938		)
Cash beginning of period	10,464			12,628
Cash end of period	$	81,691		$	8,690

See accompanying notes to consolidated financial statements.

Condensed Notes to Consolidated Financial Statements

1. Organization and Basis of Presentation

The accompanying unaudited condensed consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015 (“2015 Annual Report”). The financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. In the opinion of management, all adjustments considered necessary for a fair statement of our financial position at March 31, 2016, our operating results for the three months ended March 31, 2016 and 2015 and our cash flows for the three months ended March 31, 2016 and 2015 have been included. Operating results for the three months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ended December 31, 2016. The consolidated balance sheet at December 31, 2015 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 2015 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.

Liquidity

As of March 31, 2016, we were in compliance with our financial covenants in our Third Amended and Restated Credit Agreement (as amended, “Credit Agreement”); however, based on market volatility and prolonged depressed commodity prices, if we are unable to execute on one of the strategic alternatives discussed herein and adequately address liquidity concerns, we may not be able to remain in compliance with the financial covenants in our Credit Agreement or to make certain representations that are a condition to borrowing additional funds and issuing letters of credit. We are evaluating various alternatives with respect to our credit facility, but there is no certainty that we will be able to implement any such alternatives. If we are unable to remain in compliance with the covenants in the Credit Agreement, absent relief from our lenders, we may be forced to repay or refinance amounts then outstanding under the credit facility. If the lenders under the credit facility were to accelerate the indebtedness under the credit facility as a result of such defaults, such acceleration would cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness.

On April 14, 2016, we elected to suspend the declaration of any further distributions on our 8.25% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”) and 8.0% Series B Perpetual Convertible Preferred Units (“Series B Preferred Units”). In addition, we elected to defer a $33.5 million interest payment due with respect to our 7.875% Senior Notes due 2022 (“2022 Senior Notes”) and a $13.2 million interest payment due with respect to our 8.625% Senior Notes due 2020 (“2020 Senior Notes” and together with the 2022 Senior Notes, the “Senior Unsecured Notes”), with each such interest payment due on April 15, 2016 and subject to a 30-day grace period. During the 30-day grace period, we have been working with our debt holders regarding our ongoing effort to develop a comprehensive plan to restructure our balance sheet. As a result of the failure to pay interest on the Senior Unsecured Notes on April 15, 2016, we cannot satisfy the conditions for borrowing or the issuance of letters of credit under the Credit Agreement. Failure to make these interest payments prior to the expiration of the applicable grace period constitutes an event of default under each series of Senior Unsecured Notes and a cross-default under both the Credit Agreement and the indenture governing our 9.25% Senior Secured Second Lien Notes due 2020 (“Senior Secured Notes”). With respect to each series of Senior Unsecured Notes, if such an event of default continues, the trustee under the related indenture or the holders of at least 25% in aggregate principal amount of the then outstanding notes with respect to such series of notes may declare all the notes to be due and payable immediately. Such an event of default would have a material adverse effect on our liquidity, financial condition and results of operations.

such amounts due. As a result, there would be substantial doubt regarding our ability to continue as a going concern, and we could potentially be forced to seek bankruptcy protection. We also will not be able to continue as a going concern if our borrowing base is redetermined below our current outstanding borrowings and we are unable to repay the deficiency in five equal monthly installments. We expect the borrowing base to be redetermined in late May 2016.

Although we have a strong hedge position for the remainder of 2016, and also a significant hedge position in 2017, the forecasted long-term downturn in commodity prices has had a detrimental impact on our economic condition. We have engaged Lazard Frères & Co. LLC as a financial advisor and Weil, Gotshal & Manges LLP as a legal advisor to advise management and the Board of Directors (the “Board”) of our general partner (Breitburn GP LLC) regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness or capital structure or seeking to raise additional capital through debt or equity financing to address our liquidity issues and high debt levels. We cannot assure you that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. We are also focused on long-term recurring cost reductions and the identification of non-core assets for potential sale. We cannot assure that any of these efforts will be successful or will result in cost reductions or additional cash flows or the timing of any such cost reductions or additional cash flows. Absent a material improvement in oil and gas prices or a refinancing or some restructuring of our debt obligations or other improvement in liquidity, we may seek bankruptcy protection to continue our efforts to restructure our business and capital structure.

Presentation

Certain reclassifications were made to the prior year’s consolidated financial statements to conform to the 2016 presentation. Other long-term debt on the consolidated balance sheet at December 31, 2015 was reported in our 2015 Annual Report as $2.9 million compared to $3.1 million in this report due to $0.2 million in capital lease obligations reclassified from other long-term liabilities to other long-term debt.

Change in Accounting Principle

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. 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. Effective January 1, 2016, we adopted these standards which required retroactive application and represented a change in accounting principle. The unamortized debt issuance costs of approximately $37.0 million associated with our outstanding senior notes, which were formerly presented as a component of other long-term assets on the consolidated balance sheets, are reflected as a reduction to the carrying liability of our senior notes. Debt issuance costs associated with our credit facility remain classified in other long-term assets and continue to be charged to interest expense over the term of the facility. As a result of this change in accounting principle, the consolidated balance sheet at December 31, 2015 was adjusted as follows:



	December 31, 2015
	Previously		Effect of Adoption of
Thousands of dollars	Reported		Accounting Principle			As Adjusted
Assets:
Other long-term assets	$	117,872	$	(37,025	)	$	80,847
Total assets	4,872,412		(37,025		)	4,835,387

Liabilities:
Senior notes, net	$	1,789,219	$	(37,025	)	$	1,752,194
Total long-term debt	2,867,367		(37,025		)	2,830,342
Total liabilities	3,466,517		(37,025		)	3,429,492
Total liabilities and equity	4,872,412		(37,025		)	4,835,387

Accounting Standards

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. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). The amendments provide clarifications in the assessment of principal versus agent considerations in the new revenue standard. The amendments are effective for annual and interim periods beginning after December 15, 2017. We are assessing the impact that the adoption of these standards will have on our consolidated financial statements.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements — Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The amendments require management to perform interim and annual assessments of whether there are conditions or events that raise substantial doubt of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. Certain disclosures are required if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, and with early adoption permitted. The amendments will not impact our financial position or results of operations but will require management to perform a formal going concern assessment. We are reviewing our policies and procedures to ensure compliance with this new guidance.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The amendments provide guidance on financial instruments specifically related to (i) the classification and measurement of investments in equity securities, (ii) the presentation of certain fair value changes for financial liabilities measured at fair value and (iii) certain disclosure requirements associated with the fair value of financial instruments. ASU 2016-01 is effective for annual and interim periods beginning after December 15, 2017, with early adoption permitted. A cumulative-effect adjustment to beginning retained earnings is required as of the beginning of the fiscal year in which this ASU is adopted. The adoption of this ASU will not have a significant impact on our consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires recognizing a right-of-use lease asset and a lease liability on the balance sheet. Lessees are permitted to make an accounting policy to elect not to recognize lease assets and lease liabilities for leases with a term of 12 months or less, and to recognize lease expense on a straight-line basis over the lease term. These new requirements become effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. We are assessing the impact that ASU 2016-02 will have on our consolidated financial statements.

In March 2016, the FASB issued ASU 2016-09, Compensation — Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments simplify certain areas of accounting for share-based payment transactions, including classification of awards as either equity or liability, classification on the statement of cash flows, and election of accounting policy to estimate forfeitures or recognize forfeitures when they occur. The amendments are effective for annual and interim periods beginning after December 15, 2016. Early adoption is permitted, however, adoption of all of the amendments are required in the same period of adoption. We are assessing the impact that ASU 2016-09 will have on our consolidated financial statements.

2. Acquisitions, Dispositions and Other Transactions

2016 Acquisitions, Dispositions and Other Transactions

In March 2016, we completed the sale of certain of our Mid-Continent assets (the “Mid-Continent Sale”) for net proceeds of $11.8 million. The sale included all Mid-Continent properties acquired in the merger with QR Energy, LP (“QRE”) in 2014, excluding five wells for which we have asset retirement obligations and over-riding royalty interests and royalty interests in an additional 42 wells. This transaction was effective January 1, 2016. We recognized a gain of $12.3 million from the Mid-Continent Sale.

In January 2016, we entered into an agreement to purchase CO₂ assets in Harding County, New Mexico for a total preliminary purchase price of $3.9 million. We acquired compression, dehydration, and electrical sub-station facilities, all associated surface leases and contracts related to the facilities, and six existing producing wells associated with the leases and gathering lines.

2015 Acquisitions & Other Transactions

In March 2015, we completed the acquisition of certain CO₂ producing properties located in Harding County, New Mexico (“CO₂ Assets”), primarily reflected in property, plant and equipment on the consolidated balance sheets, for a total preliminary purchase price of $70.5 million (the “CO₂ Acquisition”), of which $13.7 million was paid in cash during the three months ended March 31, 2015.

3. Financial Instruments and Fair Value Measurements

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

Commodity Activities

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

We had the following commodity derivative contracts in place at March 31, 2016:



	Year
	2016		2017		2018		2019
Oil Positions:
Fixed Price Swaps - NYMEX WTI
Volume (Bbl/d)	17,404		14,519		1,493		1,000
Average Price ($/Bbl)	$	82.92	$	82.81	$	64.02	$	56.35
Fixed Price Swaps - ICE Brent
Volume (Bbl/d)	4,300		298		—		—
Average Price ($/Bbl)	$	95.17	$	97.50	$	—	$	—
Collars - NYMEX WTI
Volume (Bbl/d)	1,500		—		—		—
Average Floor Price ($/Bbl)	$	80.00	$	—	$	—	$	—
Average Ceiling Price ($/Bbl)	$	102.00	$	—	$	—	$	—
Collars - ICE Brent
Volume (Bbl/d)	500		—		—		—
Average Floor Price ($/Bbl)	$	90.00	$	—	$	—	$	—
Average Ceiling Price ($/Bbl)	$	101.25	$	—	$	—	$	—
Puts - NYMEX WTI
Volume (Bbl/d)	1,000		—		—		—
Average Price ($/Bbl)	$	90.00	$	—	$	—	$	—
Total:
Volume (Bbl/d)	24,704		14,817		1,493		1,000
Average Price ($/Bbl)	$	85.31	$	83.11	$	64.02	$	56.35

Natural Gas Positions:
Fixed Price Swaps - MichCon City-Gate
Volume (MMBtu/d)	29,000		24,000		17,500		10,000
Average Price ($/MMBtu)	$	3.91	$	3.71	$	3.10	$	3.15
Fixed Price Swaps - Henry Hub
Volume (MMBtu/d)	42,050		21,016		2,870		—
Average Price ($/MMBtu)	$	4.02	$	4.29	$	3.74	$	—
Collars - Henry Hub
Volume (MMBtu/d)	630		595		—		—
Average Floor Price ($/MMBtu)	$	4.00	$	4.00	$	—	—
Average Ceiling Price ($/MMBtu)	$	5.55	$	6.15	$	—	$	—
Puts - Henry Hub
Volume (MMBtu/d)	11,350		10,445		—		—
Average Price ($/MMBtu)	$	4.00	$	4.00	$	—	$	—
Deferred Premium ($/MMBtu)	$	0.66	$	0.69	$	—	$	—
Total:
Volume (MMBtu/d)	83,030		56,056		20,370		10,000
Average Price ($/MMBtu)	$	3.98	$	3.98	$	3.19	$	3.15

During the three months ended March 31, 2016 and 2015, we did not enter into any derivative instruments that required pre-paid premiums.

As of March 31, 2016, premiums paid in 2012 related to oil and natural gas derivatives to be settled beyond March 31, 2016 were as follows:



	Year
Thousands of dollars	2016		2017
Oil	$	5,589	$	734
Natural gas	$	715	$	—

Interest Rate Activities

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. To fix a portion of our floating LIBOR-base debt under our credit facility, we had the following interest rate swaps in place at March 31, 2016:



	Year
	2016			2017
Fixed Rate Swaps - LIBOR
Notional Amount (thousands of dollars)	$	710,000		$	200,000
Average Fixed Rate	1.28		%	1.23		%

We do not currently designate any of our interest rate derivatives as cash flow 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 March 31, 2016
Assets
Current assets - derivative instruments	$	346,071		$	45,448		$	—		$	(2,690	)	$	388,829
Other long-term assets - derivative instruments	160,194			21,530			—			(2,066		)	179,658
Total assets	506,265			66,978			—			(4,756		)	568,487
Liabilities
Current liabilities - derivative instruments	(3		)	(2,699		)	(4,297		)	2,690			(4,309		)
Long-term liabilities - derivative instruments	—			(2,179		)	(639		)	2,066			(752		)
Total liabilities	(3		)	(4,878		)	(4,936		)	4,756			(5,061		)
Net assets (liabilities)	$	506,262		$	62,100		$	(4,936	)	$	—		$	563,426

As of December 31, 2015
Assets
Current assets - derivative instruments	$	397,748		$	44,426		$	222		$	(2,769	)	$	439,627
Other long-term assets - derivative instruments	202,140			27,105			216			(2,697		)	226,764
Total assets	599,888			71,531			438			(5,466		)	666,391
Liabilities
Current liabilities - derivative instruments	(15		)	(2,740		)	(4,476		)	2,769			(4,462		)
Long-term liabilities - derivative instruments	—			(2,865		)	(87		)	2,697			(255		)
Total liabilities	(15		)	(5,605		)	(4,563		)	5,466			(4,717		)
Net assets (liabilities)	$	599,873		$	65,926		$	(4,125	)	$	—		$	661,674

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

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



Thousands of dollars	Oil Commodity Derivatives (a)		Natural Gas Commodity Derivatives (a)		Interest Rate Derivatives (b)			Total Financial Instruments
Three Months Ended March 31, 2016
Net gain (loss)	$	28,375	$	9,548	$	(2,343	)	$	35,580
Three Months Ended March 31, 2015
Net gain (loss)	$	118,514	$	18,678	$	(1,812	)	$	135,380

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

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

Fair Value Measurements

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

Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2 – Inputs that are observable other than quoted prices that are included within Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. We consider the over-the-counter (“OTC”) commodity and interest rate swaps in our portfolio to be Level 2. Level 3 – Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Certain OTC derivative instruments that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. As of March 31, 2016, and December 31, 2015, 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 ended March 31, 2016 and 2015. 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

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

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

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

The fair value of the commodity and interest rate derivative instruments that were novated to us in connection with the QRE Merger are estimated using a combined income and market valuation methodology based upon 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 March 31, 2016
Assets (liabilities)
Crude Oil
Crude oil swaps	$	—	$	470,930		$	—	$	470,930
Crude oil collars	—		—			22,205		22,205
Crude oil puts	—		—			13,127		13,127
Natural Gas
Natural gas swaps	—		51,082			—		51,082
Natural gas collars	—		—			583		583
Natural gas puts	—		—			10,435		10,435
Interest rate swaps
Interest rate swaps	—		(4,936		)	—		(4,936		)
Available-for-sale securities
Equities	1,378		—			—		1,378
Mutual funds	12,073		—			—		12,073
Exchange traded funds	5,839		—			—		5,839
Net assets	$	19,290	$	517,076		$	46,350	$	582,716



Thousands of dollars	Level 1		Level 2			Level 3		Total

As of December 31, 2015
Assets (liabilities)
Crude Oil
Crude oil swaps	$	—	$	552,552		$	—	$	552,552
Crude oil collars	—		—			29,737		29,737
Crude oil puts	—		—			17,584		17,584
Natural gas commodity derivatives
Natural gas swaps	—		54,182			—		54,182
Natural gas collars	—		—			618		618
Natural gas puts	—		—			11,126		11,126
Interest rate swaps
Interest rate swaps	—		(4,125		)	—		(4,125		)
Available-for-sale securities
Equities	2,524		—			—		2,524
Mutual funds	11,190		—			—		11,190
Exchange traded funds	4,977		—			—		4,977
Net assets	$	18,691	$	602,609		$	59,065	$	680,365

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



	Three Months Ended March 31,
	2016						2015
Thousands of dollars	Oil			Natural Gas			Oil			Natural Gas
Assets (a):
Beginning balance	$	47,321		$	11,744		$	61,410		$	19,892
Derivative instrument settlements (b)	13,981			2,114			10,987			3,567
Loss (b)(c)	(25,970		)	(2,840		)	(13,296		)	(3,788		)
Ending balance	$	35,332		$	11,018		$	59,101		$	19,671

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

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

For Level 3 derivative instruments measured at fair value on a recurring basis as of March 31, 2016, the significant unobservable inputs used in the fair value measurements were as follows:



	Fair Value at		Valuation
Thousands of dollars	March 31, 2016		Technique	Unobservable Input	Range
Oil Options	$	35,332	Option Pricing Model	Oil forward commodity prices	$38.34/Bbl - $45.84/Bbl
				Oil volatility	26.58% - 60.07%
				Own credit risk	5%
Natural Gas Options	11,018		Option Pricing Model	Gas forward commodity prices	$1.96/MMBtu - $2.97/MMBtu
				Gas volatility	26.24% - 47.25%
				Own credit risk	5%
Total	$	46,350

For Level 3 derivative instruments measured at fair value on a recurring basis as of December 31, 2015, the significant unobservable inputs used in the fair value measurements were as follows:



	Fair Value at		Valuation
Thousands of dollars	December 31, 2015		Technique	Unobservable Input	Range
Oil Options	$	47,321	Option Pricing Model	Oil forward commodity prices	$37.04/Bbl - $47.79/Bbl
				Oil volatility	32.24% - 44.95%
				Own credit risk	5%
Natural Gas Options	11,744		Option Pricing Model	Gas forward commodity prices	$2.34/MMBtu - $2.99/MMBtu
				Gas volatility	23.44% - 73.05%
				Own credit risk	5%
Total	$	59,065

Credit and Counterparty Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of March 31, 2016, 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, or affiliates of lenders, that participate in our credit facility. Our credit facility is secured by our oil, NGL and natural gas reserves, so we are not required to post any collateral, and we conversely do not receive collateral from our counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to fail to perform in accordance with the terms of the contract. This risk is managed by diversifying our derivatives portfolio. As of March 31, 2016, each of these financial institutions had an investment grade credit rating. As of March 31, 2016, our largest derivative asset balances were with Barclays Bank PLC, Credit Suisse Energy LLC, Wells Fargo Bank, N.A. and Morgan Stanley which accounted for approximately 15%, 12%, 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 ended March 31, 2016 and 2015, the monthly fee paid by PCEC for indirect expenses was $700,000. On February 5, 2016, PCEC provided written notice to Breitburn Management of its intention to terminate the administrative services agreement effective as of June 30, 2016.

On April 8, 2015, Kurt A. Talbot, then Vice Chairman and Co-Head of the Investment Committee of EIG Global Energy Partners (EIG), was appointed to our Board in connection with the closing of our offerings of the Senior Secured Notes and Series B Preferred Units. On March 23, 2016, Mr. Talbot notified us that he would resign from the Board effective immediately.

At March 31, 2016 and December 31, 2015, we had a current receivable of $0.6 million and $1.7 million, respectively, due from PCEC related to the administrative services agreement and employee-related costs. For the three months ended March 31, 2016 and 2015, 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 $2.0 million and $2.8 million, respectively. At March 31, 2016 and December 31, 2015, we had receivables of $0.9 million and $0.7 million, respectively, due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf.

5. Impairments

Long-Lived Assets

We review our oil and gas properties for impairment periodically or when events or circumstances indicate that their carrying value may not be recoverable. 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 forward 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 net cash flows. In the first quarter of 2016, the estimated discounted future cash flows were determined by using applicable basis adjusted (i) nine-year NYMEX forward strip prices for oil, and (ii) ten-year NYMEX forward strip prices for natural gas, in each case, at the end of the reporting period, and escalated along with expenses and capital starting in (i) year ten for oil and (ii) year eleven for natural gas, 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, which approximates 11% at March 31, 2016. 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 impairment charges totaled $2.8 million for the three months ended March 31, 2016, including $2.1 million in the Southeast, $0.5 million in the Permian Basin and $0.2 million in the Rockies, primarily related to the impact of the drop in commodity strip prices on projected future revenues of our lower margin properties. Impairments totaled $59.1 million for the three months ended March 31, 2015, including $33.1 million in the Permian Basin, $16.7 million in the Rockies and $9.3 million in Mid-Continent.

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

6. Other Long-Term Assets

As of March 31, 2016, and December 31, 2015, our other long-term assets were as follows:



	As of
Thousands of dollars	March 31, 2016		December 31, 2015
Debt issuance costs	$	16,113	$	22,142
Available-for-sale securities	19,290		18,691
Deposit for Jay Field net profit interest obligation	18,263		18,263
Property reclamation deposit	10,736		10,736
Other	10,579		11,015
Total	$	74,981	$	80,847

Effective January 1, 2016, the unamortized debt issuance costs of $37.0 million associated with our outstanding senior notes, which were formerly presented as a component of other long-term assets, are now reflected as a reduction to the carrying liability of senior notes, net on the consolidated balance sheets in connection with the adoption of ASU 2015-03. See Note 1 for a detailed discussion of the adoption of the change in accounting principle.

7. Long-Term Debt

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



	As of
Thousands of dollars	March 31, 2016			December 31, 2015
Credit facility	$	1,197,000		$	1,229,000
Promissory note	2,938			2,938
9.25% Senior Secured Notes due 2020	650,000			650,000
8.625% Senior Unsecured Notes due 2020	305,000			305,000
7.875% Senior Unsecured Notes due 2022	850,000			850,000
Unamortized debt issuance costs and net (discount) premium on Senior Notes (a)	(50,160		)	(52,806		)
Capital lease obligations	841			210
Total debt	2,955,619			2,984,342
Less: Current portion of long-term debt	(172,000		)	(154,000		)
Total long-term debt	$	2,783,619		$	2,830,342

(a) In connection with the adoption of ASU 2015-03, unamortized senior note debt issuance costs at December 31, 2015 of $37.0 million were reclassified from other long-term assets to long-term debt. See Note 1 for a detailed discussion of the adoption of the change in accounting principle.

Credit Facility

As of March 31, 2016, Breitburn Operating LP, 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 March 31, 2016, our borrowing base was $1.8 billion. On March 28, 2016, we entered into a Consent (the “Consent”) to the Credit Agreement, which delayed the scheduled borrowing base redetermination from April 1, 2016 to May 1, 2016 and reduced the elected commitment amount under the Credit Agreement from $1.8 billion to $1.4 billion. During the three months ended March 31, 2016, we recognized $4.6 million of interest expense for the write-off of debt issuance costs related to the reduction of the elected commitment amount under our Credit Agreement. As of May 9, 2016, the borrowing base has not been redetermined. We expect the borrowing base to be redetermined in late May 2016.

As of March 31, 2016 and December 31, 2015, we had $1.2 billion at each date in indebtedness outstanding under our credit facility. At March 31, 2016, the 1-month LIBOR interest rate plus an applicable spread was 2.6863% on the 1-month LIBOR portion of $1.2 billion. As of March 31, 2016, we were in compliance with the covenants in the Credit Agreement.

Although we currently expect our sources of capital to be sufficient to meet our near-term liquidity needs, the lenders under our credit facility could reduce the borrowing base to an amount below our current outstanding borrowings when our borrowing base is redetermined, and we may not be able to satisfy our liquidity requirements, given current oil prices and the discretion of our lenders to decrease our borrowing base. Based upon current commodity prices and other factors at the time of future redeterminations, we expect our borrowing base to be significantly decreased. Without a waiver from our lenders, our Credit Agreement 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.

Senior Secured Notes

As of March 31, 2016, we had $650 million of Senior Secured Notes, which had a carrying value of $614.1 million, net of unamortized discount of $16.5 million and unamortized debt issuance costs of $19.4 million. Interest on our Senior Secured Notes is payable quarterly in March, June, September and December.

As of March 31, 2016, the fair value of our Senior Secured Notes was estimated to be approximately $463.2 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. As of March 31, 2016, we were in compliance with the covenants in the indentures governing our Senior Secured Notes.

Senior Unsecured Notes

As of March 31, 2016, we had $305 million in aggregate principal amount of 2020 Senior Notes, which had a carrying value of $298.2 million, net of unamortized discount of $2.8 million and unamortized debt issuance costs of $4.0 million. In addition, as of March 31, 2016, we had $850 million in aggregate principal amount of 2022 Senior Notes, which had a carrying value of $842.6 million, net of unamortized premium of $4.3 million and unamortized debt issuance costs of $11.7 million. Interest on the 2020 Senior Notes and the 2022 Senior Notes is payable twice a year in April and October.

As of March 31, 2016, the fair value of our 2020 Senior Notes and 2022 Senior Notes were estimated to be approximately $31 million and $82 million, respectively, based on prices quoted from third-party financial institutions. We consider the inputs to the valuation of our Senior Unsecured Notes to be Level 2, as fair value was estimated based on prices quoted from third-party financial institutions. As of March 31, 2016, we were in compliance with the covenants in the indentures governing our Senior Unsecured Notes.

Interest Expense

Our interest expense is detailed as follows:



	Three Months Ended
	March 31,
Thousands of dollars	2016			2015
Credit Facility (including commitment fees) and other long-term debt	$	8,999		$	13,965
Senior Secured Notes	15,031			—
Senior Unsecured Notes	23,311			23,311
Amortization of net discount/premium and debt issuance costs (a)	8,675			2,389
Capitalized interest	(27		)	—
Total	$	55,989		$	39,665

(a) The three months ended March 31, 2016 included a write-off of $4.6 million of debt issuance costs related to the reduction of the elected commitment amount under our Credit Agreement.

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:


(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,


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


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


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

9. Asset Retirement Obligations

ARO is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities together with our estimate of the future timing of the costs to be incurred. Payments to settle ARO occur over the operating lives of the assets, estimated to range from less than one year to 50 years. Estimated cash flows have been discounted at our credit-adjusted risk-free rate of approximately 14% for the three months ended March 31, 2016 and 14% for the year ended December 31, 2015, and adjusted for inflation using a rate of 2%. Our credit-adjusted risk-free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk.

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

Changes in ARO for the period ended March 31, 2016, and the year ended December 31, 2015 are presented in the following table:



	Three Months Ended			Year Ended
Thousands of dollars	March 31, 2016			December 31, 2015
Carrying amount, beginning of period	$	254,378		$	238,411
Liabilities added from acquisitions	78			796
Liabilities related to divested properties	(8,380		)	(261		)
Liabilities incurred from drilling	17			2,268
Liabilities settled	(907		)	(7,744		)
Revision of estimates	118			3,954
Accretion expense	4,331			16,954
Carrying amount, end of period	249,635			254,378
Less: Current portion of ARO	(1,679		)	(2,341		)
Non-current portion of ARO	$	247,956		$	252,037

10. Commitments and Contingencies

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily relate to abandonments, environmental and other responsibilities where governmental and other organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At March 31, 2016 and December 31, 2015, we had approximately $31 million and $27 million, respectively, of surety bonds. At March 31, 2016 and December 31, 2015, we had approximately $32.4 million and $25.8 million, respectively, 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.

11. Partners’ Equity

Preferred Units

On April 8, 2015, we issued in private offerings $350 million of Series B Preferred Units at an issue price of $7.50 per unit. We received approximately $337.2 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 (as defined below) and on parity with the Series A Preferred Units (as defined below) with respect to the payment of current distributions.

For the three months ended March 31, 2016, 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 ended March 31, 2016, we declared distributions on our Series B Preferred Units at a monthly rate of 0.006666 Series B Preferred Units per unit, in the form of a total of 818,626 Series B Preferred Units and 163,314 Common Units. During the three months ended March 31, 2016, we recognized $7.4 million of accrued distributions on the Series B Preferred Units, which were included in non-cash distributions to Series B preferred unitholders on the consolidated statements of operations.

On May 21, 2014, we sold 8.0 million 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 each of the three months ended March 31, 2016 and March 31, 2015, we recognized $4.1 million of accrued distributions on the Series A Preferred Units, which were included in distributions to Series A preferred unitholders on the consolidated statements of operations.

Common Units

At each of March 31, 2016 and December 31, 2015, we had approximately 213.7 million and 213.5 million, respectively, of common units representing limited partner interests in us (“Common Units”) outstanding.

During the three months ended March 31, 2016 and 2015, we issued 163,314 and zero 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 ended March 31, 2016 and 2015, we issued less than 0.1 million Common Units, to non-employee directors for restricted phantom units (“RPUs”) that vested in January 2016 and January 2015.

At March 31, 2016 and December 31, 2015, there were approximately 21.0 million and 3.6 million, respectively, of units outstanding under our long-term incentive plan (“LTIP”) that were eligible to be paid in Common Units upon vesting.

In 2016, we declared no cash distributions to holders of our Common Units and our RPUs. In response to current commodity and financial market conditions, the Board suspended distributions on Common Units effective with the third monthly payment attributable to the third quarter of 2015. During the three months ended March 31, 2015, we paid cash distributions of approximately $52.7 million, or $0.2499 per Common Unit.

During the three months ended March 31, 2016 and 2015, we paid zero and $1.4 million, respectively, in cash at a rate equal to the distributions paid to our holders of Common Units to holders of outstanding unvested RPUs issued under our LTIP.

Earnings per Common Unit

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

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



	Three Months Ended
	March 31,
Thousands, except per unit amounts	2016			2015
Net loss attributable to the partnership	$	(103,786	)	$	(58,825	)
Less:
Net loss attributable to participating units	—			(1,432		)
Distributions to Series A preferred unitholders	4,125			4,125
Non-cash distributions to Series B preferred unitholders	7,386			—
Net loss used to calculate basic and diluted net loss per unit	$	(115,297	)	$	(61,518	)

Weighted average number of units used to calculate basic and diluted net loss per unit (in thousands):
Common Units (a)	213,661			210,931
Dilutive units (b)	—			—
Denominator for diluted net loss per unit	213,661			210,931

Net loss per common unit
Basic	$	(0.54	)	$	(0.29	)
Diluted	$	(0.54	)	$	(0.29	)

(a) The three months ended March 31, 2016 excludes 18,033 of weighted average anti-dilutive units from the calculation of the denominator for basic earnings per common unit, as we were in a loss position.

(b) The three months ended March 31, 2016 and 2015 exclude 413 and 706, 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.

12. Accumulated Other Comprehensive Loss

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



	Three Months Ended March 31,
	2016								2015
	Gain (loss) on								Gain (loss) on
Thousands of dollars	Available-For-Sale Securities			Post retirement Benefits		Total			Available-For-Sale Securities			Post retirement Benefits			Total
Carrying amount, beginning of period	$	(350	)	$	121	$	(229	)	$	(112	)	$	(280	)	$	(392	)

Other comprehensive income before reclassification	882			—		882			195			—			195
Amounts reclassified from accumulated other comprehensive loss (a)	(412		)	—		(412		)	(22		)	—			(22		)
Net current period other comprehensive income	470			—		470			173			—			173
Less: Noncontrolling interest	192			—		192			70			—			70
Carrying amount, end of period	$	(72	)	$	121	$	49		$	(9	)	$	(280	)	$	(289	)

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

13. Unit and Other Valuation-Based Compensation Plans

For detailed information on our various compensation plans, see Note 18 to the consolidated financial statements included in our 2015 Annual Report.

Non-Cash Unit-Based Compensation

During the three months ended March 31, 2016, the Board approved the grant of 7.0 million RPUs to employees of Breitburn Management and 0.6 million to outside directors under our LTIP, which vest one-half after 30 months and one-half after 36 months. The weighted average grant date fair value of the RPUs granted during the three months ended March 31, 2016 was $0.68 per unit. During the three months ended March 31, 2016, we recorded non-cash unit-based compensation expense of $5.3 million, of which $0.9 million was included in operating costs, $3.8 million was included in general and administrative expenses, and $0.6 million was included in restructuring costs on the consolidated statement of operations. During the three months ended March 31, 2015, we recorded non-cash unit-based compensation expense of $7.7 million, of which $6.9 million was included in general and administrative expenses and $0.8 million was included in restructuring costs on the consolidated statement of operations. See Note 14 for a discussion of restructuring costs. As of March 31, 2016, there was $26.8 million of unrecognized compensation cost related to our non-cash unit based compensation plans, which is expected to be recognized over the period from April 1, 2016 to December 31, 2018. During each of the three months ended March 31, 2016 and 2015, we paid zero and $0.7 million for taxes withheld on RPUs.

Phantom Units

During the three months ended March 31, 2016, the Board approved the grant of 10.4 million phantom units (“Phantom Units”) to employees of Breitburn Management and 0.6 million Phantom Units to outside directors under our LTIP. Phantom Units vest one-half after 18 months and one-half after 24 months and are settled in cash (or Common Units if elected by us), for each outstanding and vested unit equal to the fair market value of one Common Unit upon vesting, with a minimum cash value of $0.50 per Phantom Unit with respect to employees. The Phantom Units are accounted for as a liability and remeasured at fair value at the end of each reporting period, with the changes to fair value recognized over the vesting period.

The weighted average grant date fair value of the Phantom Units was $0.68 per unit during the three months ended March 31, 2016. During the three months ended March 31, 2016, we recorded compensation expense for the Phantom Units of $0.8 million, of which $0.6 million was included in operating costs and $0.2 million was included in general and administrative expenses on the consolidated statement of operations. As of March 31, 2016, there was $5.3 million of unrecognized compensation cost related to unvested Phantom Units, which is expected to be recognized over the period from April 1, 2016 to January 1, 2018.

14. Restructuring Costs

During the three months ended March 31, 2016 and 2015, we executed workforce reduction plans as part of company-wide reorganization efforts intended to reduce costs, due in part to lower commodity prices. In connection with the reductions in workforce, we incurred total costs of approximately $2.8 million and $4.9 million for the three months ended March 31, 2016 and 2015, respectively, which included severance cash payments, accelerated vesting of LTIP grants for certain individuals and other employee-related termination costs. The 2016 reduction was communicated to affected employees on various dates during March 2016, and all such notifications were completed by March 31, 2016. The 2015 reduction was communicated to affected employees on various dates during March 2015, and all such notifications were completed by March 31, 2015. The plans resulted in a reduction of 57 employees and 37 employees for the three months ended March 31, 2016 and 2015, respectively. In connection with the 2016 reduction, we expect our total cost to be approximately $5.2 million, of which $2.8 million was incurred in the first quarter of 2016, which included severance cash payments, accelerated vesting of LTIP grants for certain individuals and other employee-related termination costs.



	Three Months Ended March 31,
Thousands of dollars	2016		2015
Severance payments	$	1,943	$	3,815
Unit-based compensation expense	638		814
Other termination costs	228		289
Total	$	2,809	$	4,918

15. Subsequent Events

On April 13, 2016, the Board adopted the Key Executive Incentive Plan (“KEIP”) and the Key Employee Program (“KEP”). Participants in the KEIP will be eligible to receive cash payments in two equal installments, the first of which is contingent upon (i) entry into a definitive agreement for a transaction that de-levers our balance sheet and on satisfactory performance against 2016 objectives; the second of which is contingent upon (ii) the consummation of the deleveraging transaction (after determination by the Board of performance achievement); and both of which are contingent upon (iii) meeting performance thresholds tied to production and lease operating expense; and (iv) satisfactory individual performance of each participant. The maximum aggregate amount payable to all participants under the KEIP is approximately $10.7 million. Participants must be employed on the scheduled payment dates in order to receive a payment under the KEIP. If a participant in the KEIP voluntarily terminates his employment or is terminated for cause prior to the consummation of the deleveraging transaction, the participant must repay all amounts received under the KEIP as of such date. Participants in the KEP will be eligible to receive quarterly cash payments at the Board’s discretion, which are contingent on meeting performance thresholds tied to production and lease operating expense and satisfactory individual performance. If a participant in the KEP voluntarily terminates his or her employment or is terminated for cause prior to the one year anniversary of the KEP, the participant must repay all amounts received under the KEP as of such date.

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 2015 Annual Report and the consolidated financial statements and related notes therein. Our 2015 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 2015 Annual Report and Part I—Item 1A “—Risk Factors” of our 2015 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:


•	Midwest (Michigan, Indiana and Kentucky);


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


•	Permian Basin in Texas and New Mexico;


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


•	Rockies (Wyoming and Colorado);


•	Southeast (Florida and Alabama); and


•	California.

2016 Highlights

Acquisitions and Other Transactions

In March 2016, we completed the sale of certain of our Mid-Continent assets for net proceeds of $11.8 million. The sale includes all Mid-Continent properties acquired in the merger with QRE in 2014, excluding five wells for which we have asset retirement obligations and over-riding royalty interests and royalty interests in an additional 42 wells. This transaction was effective January 1, 2016. We recognized a gain of $12.3 million from the Mid-Continent Sale.

Credit Facility Borrowing Base

On March 28, 2016, we entered into a Consent to our Third Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), which delayed our scheduled borrowing base redetermination from April 1, 2016 to May 1, 2016 and reduced the elected commitment amount under the Credit Agreement from $1.8 billion to $1.4 billion. As of May 9, 2016, the borrowing base has not been redetermined. We expect the borrowing base to be redetermined in late May 2016. As of March 31, 2016 and May 9, 2016, we had $1.2 billion at each date in indebtedness outstanding under our credit facility.

Other Highlights

During the three months ended March 31, 2016, we recognized $4.1 million of accrued distributions on the Series A Preferred Units.

For the three months ended March 31, 2016, 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 ended March 31, 2016, we declared distributions on our Series B Preferred Units of 0.006666 Series B Preferred Unit per unit in the form of 818,626 Series B Preferred Units and 163,314 Common Units. During the three months ended March 31, 2016, we recognized $7.4 million 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 14, 2016, we elected to suspend the declaration of any further distributions on our Series A Preferred Units and Series B Preferred Units. In addition, we elected to defer a $33.5 million interest payment due with respect to our 2022 Senior Notes and a $13.2 million interest payment due with respect to our 2020 Senior Notes, with each such interest payment due on April 15, 2016 and subject to a 30-day grace period. For additional detail, see “—Liquidity and Capital Resources—Overview.”

Operational Focus and Capital Expenditures

In the first three months of 2016, our capital expenditures for oil and gas activities, including capitalized engineering costs, totaled $16 million, compared to approximately $73 million in the first three months of 2015. We spent approximately $7 million in Ark-La-Tex, $5 million in Mid-Continent, $3 million in California, and $1 million in the Permian Basin. In the first three months of 2016, we drilled and completed two productive wells in Ark-La-Tex. We also performed one recompletion in California.

Our 2016 capital spending program for oil and gas activities, including capitalized engineering costs and excluding acquisitions, is expected to be approximately $80 million. This compares with approximately $209 million in 2015. We anticipate that 64% 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. In 2016, we plan to drill 17 wells in Ark-La-Tex and the Permian Basin.

In the first quarter of 2016, 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 2016, and all such notifications were completed by March 31, 2016. The plan resulted in a reduction of approximately 57 employees.

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 first quarter of 2016, the NYMEX WTI spot price averaged $33 per barrel, compared with approximately $48 per barrel in the first quarter of 2015. In the first three months of 2016, the NYMEX WTI spot price ranged from a low of $26 per barrel to a high of $41 per barrel. In the first three months of 2015, the NYMEX WTI spot price ranged from a low of $43 per barrel to a high of $54 per barrel.

In the first quarter of 2016, the Henry Hub natural gas spot price averaged $1.99 per MMBtu compared with approximately $2.90 per MMBtu in the first quarter of 2015. In the first three months of 2016, the Henry Hub natural gas spot price ranged from a low of $1.49 per MMBtu to a high of $2.54 per MMBtu. In the first three months of 2015, the Henry Hub spot price ranged from a low of $2.62 per MMBtu to a high of $3.32 per MMBtu. In the first quarter of 2016, the MichCon natural gas spot price averaged $2.18 per MMBtu compared with approximately $3.29 per MMBtu in the first quarter of 2015.

These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices will have a material 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 continued volatility and significant decline in oil and natural gas prices increase 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 will 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 2015 beginning of the prior 12 months average prices used for our December 31, 2015 reserve report had been replaced with NYMEX WTI, ICE Brent and NYMEX Henry Hub Futures strip prices for the applicable commodity as of March 31, 2016 (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 standardized measure of discounted future net cash flows relating to our estimated proved reserves as of December 31, 2015 would have decreased by approximately 4%. The prices assumed in this example were derived using NYMEX WTI, ICE Brent and NYMEX Henry Hub Futures strip prices at March 31, 2016 through December 31, 2022, which averaged $47.66 per Bbl, $50.02 per Bbl, and $2.89 per Mcf, respectively, and then held flat thereafter. The average realized blended price is $32.88 per Boe. We believe that the use of NYMEX WTI, ICE Brent and NYMEX Henry Hub Futures strip prices 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 downward revisions of proved reserves occur in the future, we could have further increases in our DD&A rates. We are not able 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 ended March 31, 2016, the monthly fee paid by PCEC for indirect expenses was $700,000. On February 5, 2016, PCEC provided written notice to Breitburn Management of its intention to terminate the Administrative Services Agreement effective as of June 30, 2016.

For information on potential conflicts between us and PCEC, see Part I—Item 1A “—Risk Factors” of our 2015 Annual Report, — “Risks Related to Our Structure — Certain of the directors and officers of our General Partner, including the Vice Chairman of our Board, our Chief Executive Officer, our President and other members of our senior management, own interests in PCEC, which is managed by our subsidiary, Breitburn Management. Conflicts of interest may arise between PCEC, on the one hand, and us and our unitholders, on the other hand. Our partnership agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.”

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 March 31,					Increase/
except as indicated	2016			2015		(Decrease)			%
Total production (MBoe) (a)	4,848			5,051		(203		)	(4	)%
Oil (MBbl)	2,589			2,890		(301		)	(10	)%
NGLs (MBbl)	498			459		39			8	%
Natural gas (MMcf)	10,567			10,211		356			3	%
Average daily production (Boe/d)	53,275			56,122		(2,847		)	(5	)%
Sales volumes (MBoe) (b)	4,927			4,999		(72		)	(1	)%
Average realized sales price (per Boe) (c)	$	21.40		$	32.52	$	(11.12	)	(34	)%
Oil (per Bbl)	29.37			43.62		(14.25		)	(33	)%
NGLs (per Bbl)	10.81			16.54		(5.73		)	(35	)%
Natural gas (per Mcf)	2.05			3.05		(1.00		)	(33	)%
Oil sales	78,358			123,843		(45,485		)	(37	)%
NGL sales	5,382			7,591		(2,209		)	(29	)%
Natural gas sales	21,710			31,189		(9,479		)	(30	)%
Gain on commodity derivative instruments	37,923			137,192		(99,269		)	(72	)%
Other revenues, net (d)	4,593			6,469		(1,876		)	(29	)%
Total revenues	147,966			306,284		(158,318		)	(52	)%
Lease operating expenses before taxes (e)	79,842			100,079		(20,237		)	(20	)%
Production and property taxes (f)	9,909			13,544		(3,635		)	(27	)%
Total lease operating expenses	89,751			113,623		(23,872		)	(21	)%
Purchases and other operating costs	2,618			158		2,460			n/a
Salt water disposal costs	2,980			4,021		(1,041		)	(26	)%
Change in inventory	(375		)	176		(551		)	n/a
Total operating costs	94,974			117,978		(23,004		)	(19	)%
Lease operating expenses before taxes per Boe (g)	16.29			19.81		(3.52		)	(18	)%
Production and property taxes per Boe	2.04			2.68		(0.64		)	(24	)%
Total lease operating expenses per Boe	18.33			22.49		(4.16		)	(18	)%
Depletion, depreciation and amortization (“DD&A”)	83,723			109,824		(26,101		)	(24	)%
DD&A per Boe	17.27			21.74		(4.47		)	(21	)%
Impairment of oil and natural gas properties	2,793			59,113		(56,320		)	(95	)%
G&A excluding unit-based compensation	17,616			25,335		(7,719		)	(30	)%
G&A excluding unit-based compensation per Boe	$	3.63		$	5.02	$	(5.01637	)	(100	)%

(a) Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a Bbl of oil equivalent for natural gas is significantly less than the price for a Bbl of oil.
(b) Includes 90 MBoe of condensate purchased from third parties during the three months ended March 31, 2016.
(c) Excludes the effect of commodity derivative settlements.
(d) Includes salt water disposal revenues, gas processing fees, earnings from equity investments and other operating revenues.
(e) Includes district expenses, transportation expenses and processing fees.
(f) Includes ad valorem and severance taxes.
(g) Excludes non-cash unit-based compensation expense of $0.9 million for the three months ended March, 31 2016.

Comparison of Results for the Three Months Ended March 31, 2016 and 2015

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

Production

For the three months ended March 31, 2016, total production was 4,848 MBoe compared to 5,051 MBoe for the three months ended March 31, 2015, a decrease of 4%, primarily due to lower oil production from our Permian Basin and California properties due to natural field declines.

Oil, NGL and natural gas sales

Total oil, NGL and natural gas sales revenues decreased $57.2 million for the three months ended March 31, 2016, compared to the three months ended March 31, 2015. Crude oil revenues decreased $45.5 million due to lower average crude oil prices, and lower sales volume in Permian Basin, California, and Ark-La-Tex properties. NGL revenues decreased $2.2 million primarily due to lower average NGL prices. Natural gas revenues decreased $9.5 million primarily due to lower average natural gas prices.

Realized prices for crude oil, excluding the effect of derivative instruments, decreased $14.25 per Boe, or 33%, for the three months ended March 31, 2016 compared to the three months ended March 31, 2015. Realized prices for NGLs, excluding the effect of derivative instruments, decreased $5.73 per Boe, or 35% for the three months ended March 31, 2016 compared to the three months ended March 31, 2015. Realized prices for natural gas, excluding the effect of derivative instruments, decreased $1.00 per Mcf, or 33%, for the three months ended March 31, 2016 compared to the three months ended March 31, 2015.

Gain on commodity derivative instruments

Gain on commodity derivative instruments for the three months ended March 31, 2016 was $37.9 million compared to a gain of $137.2 million during the three months ended March 31, 2015. Oil and natural gas derivative instrument settlement receipts net of payments totaled $135.4 million and $126.4 million for the three months ended March 31, 2016 and 2015, respectively, due to lower commodity prices during, partially offset by lower hedge volume.

Mark-to-market loss on commodity derivative instruments for the three months ended March 31, 2016 was $97.4 million, primarily due to derivative instrument settlements during the three months ended March 31, 2016, compared to a mark-to-market gain of $10.8 million for the three months ended March 31, 2015, primarily due to a decrease in commodity future prices during the three months ended March 31, 2015.

Other revenues, net

Other revenues decreased $1.9 million for the three months ended March 31, 2016, compared to the three months ended March 31, 2015, primarily due to $0.9 million lower salt water disposal revenue and $0.9 million lower pipeline revenue.

Lease operating expenses

Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the three months ended March 31, 2016 decreased $20.2 million compared to the three months ended March 31, 2015. The decrease in pre-tax lease operating expenses primarily reflects cost-cutting efforts, lower commodity prices and slightly lower oil production volumes leading to lower overall costs. On a per Boe basis, pre-tax lease operating expenses excluding $0.9 million of non-cash unit based compensation expense were 18% lower than the three months ended March 31, 2015 at $16.29 per Boe, primarily due to lower commodity prices, cost-cutting efforts, and lower well service expenses.

Production and property taxes for the three months ended March 31, 2016 totaled $9.9 million, which was $3.6 million lower than the three months ended March 31, 2015, primarily due to lower crude oil and natural gas prices and lower oil production. On a per Boe basis, production and property taxes for the three months ended March 31, 2016 were $2.04 per Boe, which was 24% lower than the three months ended March 31, 2015, primarily 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 eight weeks. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are credited to operating costs through the change in inventory account. Production expenses are charged to operating costs through the change in inventory account when they are sold.

For the three months ended March 31, 2016, the change in inventory account amounted to a credit of $0.4 million compared to a charge of $0.2 million during the same period in 2015. The credit to inventory during the three months ended March 31, 2016 primarily reflects a lower volume of crude oil sold than produced during the quarter. The charge during the three months ended March 31, 2015 reflects the lower cost of oil produced during the quarter compared to the oil sold during the quarter, primarily due to the effect of decreasing commodity prices on operating costs and lower well services. In the three months ended March 31, 2016, we sold 110 gross MBbls and produced 125 gross MBbls of crude oil from our Florida operations.

Depletion, depreciation and amortization

DD&A totaled $83.7 million, or $17.27 per Boe, during the three months ended March 31, 2016, a decrease of approximately 21% per Boe from the same period a year ago. The decrease in DD&A per Boe compared to the three months ended March 31, 2015 was primarily due to impairments of proved properties during the year ended December 31, 2015 due to decreases in commodity prices and the effect the impairments had on our reserve volumes and DD&A rates.

Impairments

Impairments of proved properties totaled $2.8 million for the three months ended March 31, 2016, including $2.1 million in the Southeast, $0.5 million in the Permian Basin, and $0.2 million in the Rockies, primarily related to the impact of the drop in commodity strip prices on projected future revenues of our lower margin properties. During the three months ended March 31, 2015, impairments of proved properties totaled $59.1 million including $33.1 million in the Permian Basin, $16.7 million in the Rockies and $9.3 million in Mid-Continent, primarily due to the impact that the decrease in oil and natural gas prices had on certain of our lower margin properties.

General and administrative expenses

Our general and administrative (“G&A”) expenses totaled $21.4 million and $32.3 million for the three months ended March 31, 2016 and 2015, respectively. This included $3.8 million and $6.9 million in non-cash unit-based compensation expense related to employee incentive plans for the three months ended March 31, 2016 and 2015, respectively. G&A expenses, excluding non-cash unit-based compensation, were $17.6 million and $25.3 million for the three months ended March 31, 2016 and 2015, respectively. Unit-based compensation for Phantom Units expected to be settled in cash included in G&A totaled $0.2 million and zero for the three months ended March 31, 2016 and 2015, respectively. The decrease in G&A excluding non-cash unit-based compensation was primarily due to $4.6 million of integration costs incurred during the three months ended March 31, 2015, lower employee related expenses due to a decrease in the number of employees, and lower legal costs. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $3.63 and $5.02 for the three months ended March 31, 2016 and 2015, respectively. Excluding integration costs incurred during the three months ended March 31, 2015, G&A per Boe would have been $4.10 for three months ended March 31, 2015

Restructuring costs

During the three months ended March 31, 2016 and 2015, we completed workforce reduction plans as part of company-wide reorganization efforts intended to reduce costs, due in part to lower commodity prices.

The workforce reductions during the three months ended March 31, 2016 were communicated to affected employees on various dates during March 2016, and all such notifications were completed by March 31, 2016. The plan resulted in a reduction of approximately 57 employees. In connection with the 2016 reduction, we incurred a total cost of approximately $2.8 million, which included severance cash payments, accelerated vesting of LTIP grants for certain individuals and other employee-related termination costs.

The workforce reductions during the three months ended March 31, 2015 were communicated to affected employees on various dates during March 2015, 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 2015 reduction, we incurred a total cost of approximately $5.6 million, of which $4.9 million was incurred in the first quarter of 2015, which includes severance cash payments, accelerated vesting of LTIP grants for certain individuals and other employee-related termination costs.

Interest expense, net of amounts capitalized

Our interest expense totaled $56.0 million and $39.7 million for the three months ended March 31, 2016 and 2015, respectively. The increase in interest expense was primarily due to $15.0 million of interest on our Senior Secured Notes and a $4.6 million write-off of debt issuance costs related to the reduction of the elected commitment amount under our Credit Agreement, partially offset by $5.0 million lower credit facility interest expense due to lower credit facility borrowings. Interest expense, excluding debt amortization, totaled $47.3 million and $37.3 million for the three months ended March 31, 2016 and 2015, respectively.

Loss on interest rate swaps

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. In order to mitigate our interest rate exposure, as of March 31, 2016, we had interest rate swaps, indexed to 1-month LIBOR, to fix a portion of floating LIBOR-based debt under our credit facility for 2016 and 2017, for notional amounts of $710 million and $200 million, respectively, with average fixed rates of 1.28% and 1.23%, respectively. Loss on interest swaps for the three months ended March 31, 2016 and 2015 were $2.3 million and $1.8 million, respectively. The loss on interest rate swaps for the three months ended March 31, 2016 included settlement payments of $1.5 million and a mark-to-market loss of $0.8 million. The loss on interest rate swaps for the three months ended March 31, 2015 included settlement payments of $1.5 million and a mark-to-market loss of $0.3 million.

Liquidity and Capital Resources

Overview

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 2016. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices will have a material and adverse effect on our liquidity position.

As of March 31, 2016 and May 9, 2016, we had $1.2 billion at each date in indebtedness outstanding under our credit facility. On March 28, 2016, we entered into a Consent to our Credit Agreement, which delayed our scheduled borrowing base redetermination from April 1, 2016 to May 1, 2016 and reduced the elected commitment amount under the Credit Agreement from $1.8 billion to $1.4 billion. As of May 9, 2016, the borrowing base has not been redetermined. We expect the borrowing base to be redetermined in late May 2016. Although we currently expect our sources of capital to be sufficient to meet our near-term liquidity needs, the lenders under our credit facility could reduce the borrowing base to an amount below our current outstanding borrowings when our borrowing base is redetermined, and we may not be able to satisfy our liquidity requirements, given current oil prices and the discretion of our lenders to decrease our borrowing base. Based upon current commodity prices and other factors at the time of future redeterminations, we expect our borrowing base to be significantly decreased. Without a waiver from our lenders, our Credit Agreement 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.

As of March 31, 2016, we were in compliance with our financial covenants in the Credit Agreement; however, based on market volatility and prolonged depressed commodity prices, if we are unable to execute on one of the strategic alternatives discussed herein and adequately address liquidity concerns, we may not be able to remain in compliance with the financial covenants in our Credit Agreement or to make certain representations that are a condition to borrowing additional funds and issuing letters of credit. We are evaluating various alternatives with respect to our credit facility, but there is no certainty that we will be able to implement any such alternatives. If we are unable to remain in compliance with the covenants in the Credit Agreement, absent relief from our lenders, we may be forced to repay or refinance amounts then outstanding under the credit facility. If the lenders under the credit facility were to accelerate the indebtedness under the credit facility as a result of

such defaults, such acceleration would cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness.

On April 14, 2016, we elected to suspend the declaration of any further distributions on the Series A Preferred Units and Series B Preferred Units. Management and the Board of Directors of our general partner believe that the suspension is in the best long-term interest of all stakeholders in the partnership. In addition, we elected to defer a $33.5 million interest payment due with respect to our 2022 Senior Notes and a $13.2 million interest payment due with respect to our 2020 Senior Notes, with each such interest payment due on April 15, 2016 and subject to a 30-day grace period. During the 30-day grace period, we have been working with our debt holders regarding our ongoing effort to develop a comprehensive plan to restructure our balance sheet. As a result of the failure to pay interest on the Senior Unsecured Notes on April 15, 2016, we cannot satisfy the conditions for borrowing or the issuance of letters of credit under the Credit Agreement. Failure to make these interest payments prior to the expiration of the applicable grace period constitutes an event of default under each series of Senior Unsecured Notes and a cross-default under both the Credit Agreement and the indenture governing our Senior Secured Notes. With respect to each series of Senior Unsecured Notes, if such an event of default continues, the trustee under the related indenture or the holders of at least 25% in aggregate principal amount of the then outstanding notes with respect to such series of notes may declare all the notes to be due and payable immediately. Such an event of default would have a material adverse effect on our liquidity, financial condition and results of operations.

In addition, if interest on the Senior Unsecured Notes is not paid by the expiration of the grace periods, approximately $3.0 billion in principal amount of indebtedness may be accelerated with respect to amounts due under our Senior Unsecured Notes, Senior Secured Notes and Credit Agreement as of May 9, 2016. We do not expect to have sufficient liquidity to pay such amounts due. As a result, there would be substantial doubt regarding our ability to continue as a going concern, and we would potentially be forced to seek bankruptcy protection. We also will not be able to continue as a going concern if our borrowing base is redetermined below our current outstanding borrowings and we are unable to repay the deficiency in five equal monthly installments. We expect the borrowing base to be redetermined in late May 2016.

Although we have a strong hedge position for the remainder of 2016, and also a significant hedge position in 2017, the forecasted long-term downturn in commodity prices has had a detrimental impact on our economic condition. We have engaged Lazard Frères & Co. LLC as a financial advisor and Weil, Gotshal & Manges LLP as a legal advisor to advise management and the Board regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness or capital structure or seeking to raise additional capital through debt or equity financing to address our liquidity issues and high debt levels. We cannot assure you that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. We are also focused on long-term recurring cost reductions and the identification of non-core assets for potential sale. We cannot assure that any of these efforts will be successful or will result in cost reductions or additional cash flows or the timing of any such cost reductions or additional cash flows. Absent a material improvement in oil and gas prices or a refinancing or some restructuring of our debt obligations or other improvement in liquidity, we may seek bankruptcy protection to continue our efforts to restructure our business and capital structure.

Cash Flows

Operating activities. Our cash flows from operating activities for the three months ended March 31, 2016 were $126.8 million compared to $141.1 million for the three months ended March 31, 2015. The decrease in cash flows from operating activities was primarily due to lower sales revenues in 2016 driven by lower commodity prices, which reduced sales revenue by $51.5 million, a 1% decrease in sales volume primarily due to lower Permian Basin, California, and Ark-La-Tex oil production, which reduced sales revenue by approximately $5.7 million, and a $10.1 million higher interest expense, excluding amortization of debt issuance costs, discounts and premiums, primarily due to interest on our Senior Secured Notes, partially offset by $23.0 million lower operating costs primarily at our Ark-La-Tex, Permian Basin, and Southeast properties, and $9.0 million higher commodity derivative settlement receipts primarily due to lower commodity prices. Cash flow from working capital changes during the three months ended March 31, 2016 was $11.7 million higher than the three months ended March 31, 2015, primarily due to higher interest payable due to timing of payments, partially offset by 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 three months ended March 31, 2016 and 2015 were $19.4 million and $112.1 million, respectively. During the three months ended March 31, 2016, we spent $27.0 million on capital expenditures, consisting of approximately $24.6 million primarily for drilling and completion activities, and approximately $2.4 million for IT and other capital expenditures, $5.4 million on purchases of available-for-sale securities, and $3.9 million on property acquisitions, primarily for CO₂ producing properties, partially offset by $11.8 million in net proceeds from sale of assets and $5.1 million in proceeds from the sale of available-for-sale securities. During the three months ended March 31, 2015, we spent $97.2 million on capital expenditures, primarily for drilling and completion activities, $14.0 million on property acquisitions, primarily CO₂properties from the CO₂Acquisition and $0.9 million on CO₂ advances.

Financing activities. Net cash flows used in financing activities for the three months ended March 31, 2016 and 2015 were $36.2 million and $33.0 million, respectively. During the three months ended March 31, 2016, we decreased our outstanding borrowings under our credit facility by approximately $32.0 million. We had total outstanding borrowings, net of unamortized discount/premium and unamortized debt issuance cost on our Senior Notes, of approximately $2.96 billion at March 31, 2016 and $2.98 billion at December 31, 2015. During the three months ended March 31, 2016, we made cash distributions of $4.1 million on Series A Preferred Units, borrowed $37.0 million and repaid $69.0 million under our credit facility. During the three months ended March 31, 2015, we made cash distributions of $4.1 million on Series A Preferred Units, cash distributions of $54.1 million on Common Units, and borrowed $193.6 million and repaid $168.5 million under our credit facility.

Preferred Units

In April 2015, we issued in private offerings $350 million of Series B Preferred Units at an issue price of $7.50 per unit. We received approximately $337.2 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 our Common Units and on parity with the Series A Preferred Units with respect to the payment of current distributions.

For the three months ended March 31, 2016, 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 ended March 31, 2016, we declared distributions on our Series B Preferred Units at a monthly rate of 0.006666 Series B Preferred Units per unit, in the form of a total of 818,626 Series B Preferred Units and 163,314 Common Units. During the three months ended March 31, 2016, we recognized $7.4 million 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.

In May 2014, we issued 8.0 million 8.25% Series A Preferred Units. Our Series A Preferred Units rank senior to our 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 each of the three months ended March 31, 2016 and March 31, 2015, we recognized $4.1 million 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.

On April 14, 2016, we elected to suspend the declaration of any further distributions on its Series A Preferred Units and Series B Preferred Units.

Common Units

In response to current commodity and financial market conditions, the Board suspended distributions on Common Units and RPUs effective with the third monthly payment attributable to the third quarter of 2015.

Senior Notes

As of March 31, 2016, we had $305 million in 2020 Senior Notes, $650 million in Senior Secured Notes, and $850 million in 2022 Senior Notes. See Note 7 to the consolidated financial statements within this report for a discussion of our Senior Unsecured Notes and Senior Secured Notes. For additional detail, see “—Liquidity and Capital Resources—Overview.”

Credit Agreement

At each of March 31, 2016 and December 31, 2015, we had a $5.0 billion credit facility with a maturity date of November 19, 2019. At each of March 31, 2016 and December 31, 2015, our borrowing base was $1.8 billion.

On March 28, 2016, we entered into the Consent to the Credit Agreement, which delayed the scheduled borrowing base redetermination from April 1, 2016 to May 1, 2016 and reduced the elected commitment amount under the Credit Agreement from $1.8 billion to $1.4 billion. As of May 9, 2016, the borrowing base has not been redetermined. We expect the borrowing base to be redetermined in late May 2016.

As of March 31, 2016, the lending group under the Credit Agreement included 35 banks. Of the $1.4 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 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 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 the Credit Agreement. As of March 31, 2016 and May 9, 2016, we were in compliance with the covenants in the Credit Agreement. See “—Liquidity and Capital Resources—Overview.”

The events that constitute an event of default under the 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 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 Credit Agreement) and excluding income from our unrestricted entities. If any acquisition or disposition was consummated during an applicable quarter, all calculations of EBITDAX shall be determined on a pro forma basis.

Contractual Obligations and Commitments

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of derivative instruments and accounts receivable. Our derivative instruments expose us to credit risk from counterparties. As of March 31, 2016, 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, or affiliates of lenders, that participate in our credit facility. Future volatility could adversely affect the financial condition of our derivative counterparties. On all transactions where we are exposed to counterparty risks, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. As of March 31, 2016, each of these financial institutions had an investment grade credit rating. Although we currently do not believe we have a specific

counterparty risk with any party, our loss could be substantial if any of these parties were to default. As of March 31, 2016, our largest derivative asset balances were with Barclays Bank PLC, Credit Suisse Energy LLC, Wells Fargo Bank, N.A. and Morgan Stanley, which accounted for approximately 15%, 12%, 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 three months ended March 31, 2016.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of March 31, 2016 and December 31, 2015.

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 2015 Annual Report. Also, see Note 3 to the consolidated financial statements within this report for additional discussion related to our financial instruments, including a summary of our derivative instruments as of March 31, 2016.

Changes in Fair Value

The fair value of our outstanding oil and natural gas commodity derivative instruments was a net asset of approximately $568.4 million and $665.8 million at March 31, 2016 and December 31, 2015, respectively. With a $10.00 per barrel increase in the price of oil, and a corresponding $1.00 per Mcf increase in natural gas, our net commodity derivative instrument asset at March 31, 2016 would have decreased by approximately $176 million. With a $10.00 per barrel decrease in the price of oil, and a corresponding $1.00 per Mcf decrease in natural gas, our net commodity derivative instrument asset at March 31, 2016 would have increased by approximately $189 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 $4.9 million and $4.1 million at March 31, 2016 and December 31, 2015, respectively. With a 100 basis point increase in the LIBOR rate, our outstanding interest rate derivative instruments net liability at March 31, 2016 would have decreased by approximately $7.4 million. With a 100 basis points decrease in the LIBOR rate to a minimum rate of zero, our net liability at March 31, 2016 would have increased by approximately $7.4 million.

Item 4. Controls and Procedures

Controls and Procedures

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

specified in the rules and forms of the 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 March 31, 2016 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2016 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 2015 Annual Report except as follows.

Our debt rating has been downgraded and liquidity concerns could result in a further downgrade in our debt ratings, which could further restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

Our ability to obtain financings and trade credit and the terms of any financings or trade credit are, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, liquidity, asset quality, cost structure, product mix and commodity pricing levels. Further ratings downgrades could adversely impact our ability to access financings or trade credit, increase our borrowing costs and potentially require us to post letters of credit or other credit support for certain obligations.

We may seek protection under the U.S. Bankruptcy Code, which may harm our business and place equity holders at significant risk of losing all of their interests in the partnership.

We are in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives through a private restructuring. However, a filing under Chapter 11 of the U.S. Bankruptcy Code may be unavoidable. Seeking protection under the Bankruptcy Code could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as Chapter 11 proceedings remain pending, our senior management would be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. Seeking protection under the Bankruptcy Code also might make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer Chapter 11 proceedings continue, the more likely it is that our customers and suppliers would lose confidence in our ability to reorganize our businesses successfully and would seek to establish alternative commercial relationships. Additionally, we have a significant amount of secured indebtedness that is senior to our unsecured indebtedness and a significant amount of total indebtedness that is senior to our existing preferred units and common units in our capital structure. As a result, we believe that seeking protection under the Bankruptcy Code could result in a limited recovery for unsecured noteholders, if any, and place equity holders at significant risk of losing all of their interests in the partnership. In addition, a Bankruptcy Court debt restructuring could result in cancellation of debt income allocable to the equity holders, and income tax liabilities arising therefrom may exceed the value of their investment in the partnership. Please read Part I—Item 1A “—Risk Factors—Tax Risks to Unitholders—We anticipate engaging in transactions to reduce the Partnership’s indebtedness and manage our liquidity that generate taxable income (including cancellation of indebtedness income) allocable to unitholders, and income tax liabilities arising therefrom may exceed the value of your investment in the Partnership.” from our 2015 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).
10.1		Consent to Third Amended and Restated Credit Agreement, dated effective as of March 28, 2016, by and among Breitburn Operating LP, Breitburn Energy Partners LP, Breitburn GP LLC, Breitburn Operating GP LLC, the guarantors named therein, the lenders signatory thereto and Wells Fargo Bank, National Association, as administrative agent for the Lenders (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 1, 2016).
31.1*		Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.



31.2*		Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
101*		Interactive Data Files.
*		Filed herewith.
**		Furnished herewith.
†		Management contract or compensatory plan or arrangement.

SIGNATURES

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



		BREITBURN ENERGY PARTNERS LP

		By:	BREITBURN GP LLC,
			its General Partner

Dated:	May 9, 2016	By:	/s/ Halbert S. Washburn
			Halbert S. Washburn
			Chief Executive Officer

Dated:	May 9, 2016	By:	/s/ James G. Jackson
			James G. Jackson
			Chief Financial Officer

Attached files

Stock widget

Investing forum

Breitburn Energy Partners LP Reports

Also read