Delaware	74-3169953
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)
707 Wilshire Boulevard, Suite 4600
Los Angeles, California	90017
(Address of Principal Executive Offices)	(Zip Code)

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PART I

Cautionary Statement Regarding Forward-Looking Information

 

Certain statements and information in this report may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “future,” “projected,” “goal,” “should,” “could,” “would” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those described in (1) Part I—Item 1A“—Risk Factors” and elsewhere in this report, and (2) our Quarterly Reports on Form 10-Q and Current Reports on Form 8-K filed with the Securities and Exchange Commission (the “SEC”).

 

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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Item 1. Business.

Overview

We are an independent oil and gas partnership focused on the exploitation and development of oil, NGL and natural gas properties in the United States. Our assets consist primarily of producing and non-producing oil, NGL and natural gas reserves located in seven producing areas:

•	Permian Basin in Texas and New Mexico;

•	Midwest (Michigan, Indiana and Kentucky);

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

•	Mid-Continent (Oklahoma);

•	Rockies (Wyoming and Colorado);

•	California; and

•	Southeast (Florida and Alabama).

Our assets are characterized by stable, long-lived production and proved reserve life indexes averaging greater than 12 years. As of December 31, 2016 , our total estimated proved reserves were 205.3 MMBoe, of which approximately 55% was oil, 9% was NGLs and 36% was natural gas. Our production in 2016 was 18,279 MBoe, of which approximately 52% was oil, 11% was NGLs and 37% was natural gas.

We are a Delaware limited partnership formed in 2006. Our general partner is Breitburn GP, a Delaware limited liability company and our wholly-owned subsidiary, and the board of directors of our General Partner (the “Board”) has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly-owned subsidiary, BOLP, BOLP’s general partner, BOGP, and through BOLP’s operating subsidiaries.

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. See Note 6 to the consolidated financial statements in this report for more information regarding our relationship with Breitburn Management.

Structure

The following diagram depicts our organizational structure as of December 31, 2016 :

As of December 31, 2016 and March 7, 2017 , we had approximately 213.8 million common units outstanding representing limited partner interests in us (“Common Units”). As of December 31, 2016 and March 7, 2017 , we had 8.0 million 8.25% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”) outstanding. As of December 31, 2016 and March 7, 2017 , we had 49.6 million 8.0% Series B Perpetual Convertible Preferred Units (“Series B Preferred Units”) outstanding.

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Chapter 11 Cases

On May 15, 2016 (the “Chapter 11 Filing Date”), the Partnership and certain of its affiliates (the “Debtors”) filed voluntary petitions for relief (collectively, the “Chapter 11 Petitions” and the cases commenced thereby, the “Chapter 11 Cases”) under chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The Chapter 11 Cases are being administered jointly under the caption “In re Breitburn Energy Partners LP, et al.”, Case No. 16-11390. The Debtors include the Partnership, Breitburn Management, BOGP, BOLP, Breitburn Finance, Breitburn GP, Breitburn Sawtelle LLC, Breitburn Oklahoma LLC, Phoenix Production Company, QR Energy, LP, QRE GP, LLC, QRE Operating, LLC, Breitburn Transpetco LP LLC, Breitburn Transpetco GP LLC, Transpetco Pipeline Company, L.P., Terra Energy Company LLC, Terra Pipeline Company LLC, Breitburn Florida LLC, Mercury Michigan Company, LLC, Beaver Creek Pipeline, L.L.C., GTG Pipeline LLC and Alamitos Company. See Note 2 to the consolidated financial statements in this report for more information regarding the Chapter 11 Cases. No trustee has been appointed and we continue to manage the Partnership and our affiliates and operate our businesses as “debtors in possession” subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. To assure ordinary course operations, we received approval from the Bankruptcy Court on a variety of “first day” motions, including motions that authorize us to maintain our existing cash management system, to secure debtor-in-possession financing and other customary relief. In August 2016, the Bankruptcy Court entered a final order approving the Debtor-in-Possession Credit Agreement, dated as of May 19, 2016, by and among BOLP, as borrower, the Partnership, as parent guarantor, the financial institutions from time to time party thereto (the “DIP Lenders”) and Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender (the “DIP Credit Agreement”). In December 2016, the Bankruptcy Court entered an order approving an extension of the DIP Credit Agreement to June 30, 2017.

The commencement of the Chapter 11 Cases resulted in the acceleration of the Debtors’ obligations under the Third Amended and Restated Credit Agreement, dated as of November 19, 2014, by and among BOLP, as borrower, the Partnership, as parent guarantor, the financial institutions from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender (as amended, the “RBL Credit Agreement”) and the indentures governing the Senior Secured Notes and Senior Unsecured Notes (each, as defined below). Any efforts to enforce such obligations are automatically stayed as a result of the filing of the Chapter 11 Petitions and the holders’ rights of enforcement in respect of these obligations are subject to the applicable provisions of the Bankruptcy Code. We are making adequate protection payments with respect to the lenders under the RBL Credit Agreement consisting of the payment of interest (at the default rate) and the payment of all reasonable fees and expenses of professionals retained by our lenders, as provided for in the RBL Credit Agreement. We are also making adequate protection payments with respect to the Senior Secured Notes in the form of the payment of all reasonable fees and expenses of professionals retained by the holders of the Senior Secured Notes.

The commencement of the Chapter 11 Cases constituted an event of default under our commodity and interest rate derivative instruments, resulting in a termination right by our counterparties. All of our counterparties exercised this termination right during the year ended December 31, 2016. The termination of these transactions has since exposed our cash flows to fluctuations in commodity prices. See Note 5 to the consolidated financial statements in this report for a discussion of the terminated derivative instruments.

We have incurred and will continue to incur significant costs associated with the reorganization in connection with the Chapter 11 Cases. These costs are being expensed as incurred, and are expected to significantly affect our results. See Note 2 to the consolidated financial statements in this report for additional details.

Effect of Filing on Creditors and Unitholders

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 7.875% Senior Notes due 2022 (the “2022 Senior Notes”) and a $13.2 million interest payment due with respect to our 8.625% Senior Notes due 2020 (the “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. As a consequence of the commencement of the Chapter 11 Cases, such interest payments have not been made.

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities and post-petition liabilities must be satisfied in full before the holders of our Series A Preferred Units, Series B Preferred Units and Common Units are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or unitholders, if any, will not be determined until confirmation and implementation of a

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plan of reorganization. No assurance can be given as to what distributions, if any, will be made to each of these constituencies or the nature thereof. If certain requirements of the Bankruptcy Code are met, a plan of reorganization can be confirmed notwithstanding its rejection or deemed rejection by the holders of our Series A Preferred Units, Series B Preferred Units and Common Units and notwithstanding the fact that such holders do not receive or retain any property on account of their equity interests under the plan. Because of such possibilities, the value of our securities, including our Series A Preferred Units, Series B Preferred Units and Common Units, is highly speculative. There can be no assurance that the holders of our Series A Preferred Units, Series B Preferred Units and Common Units will retain any value under a plan of reorganization. We believe it is highly likely that our Series A Preferred Units, Series B Preferred Units and Common Units will be canceled in our Chapter 11 Cases and that the holders thereof will not receive any distribution on account of their holdings.

Executory Contracts . Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired

lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory

contract or unexpired lease, but may give rise to a pre-petition general unsecured claim for damages caused by such deemed

breach. The assumption of an executory contract or unexpired lease generally requires the Debtors to cure existing monetary

defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. By order of the Bankruptcy Court dated December 12, 2016, the Debtors assumed all of their executory contracts and unexpired leases related to their oil and gas operations to the extent such contracts and leases constituted commercial property leases under the purview of the Bankruptcy Code.

Process for Plan of Reorganization . In order to successfully emerge from Chapter 11, the Debtors will need to obtain confirmation by the Bankruptcy Court of a plan of reorganization that satisfies the requirements of the Bankruptcy Code. A plan of reorganization generally provides for how pre-petition obligations and equity interests will be treated in satisfaction and discharge thereof, and provides for the means by which the plan of reorganization will be implemented.

Fresh Start Accounting . We may be required to adopt fresh start accounting upon emergence from Chapter 11. Adopting fresh start accounting would result in the allocation of the reorganization value to individual assets based on their estimated fair values. The enterprise value of the equity of the emerging company is based on several assumptions and inputs contemplated in the future projections of the plan of reorganization and are subject to significant uncertainties. We currently cannot estimate the potential financial effect of fresh start accounting on our consolidated financial statements upon the emergence from Chapter 11, although we would expect to recognize material adjustments upon implementation of fresh start accounting guidance upon emergence pursuant to a plan of reorganization. The assumptions for which there is a reasonable possibility of material impact affecting the reorganization value include management’s assumptions and capital expenditure plans related to the estimation of our oil and gas reserves.

Available Information

Our internet website address is www.breitburn.com. We make available, free of charge at the “Investor Relations” portion of our website, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC. The information contained on our website does not constitute part of this report.

The SEC maintains an internet website that contains these reports at www.sec.gov. Any materials that the Partnership files with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room may be obtained by calling the SEC at (800) 732-0330.

Long-Term Business Strategy

Our long-term goals have been to manage our current and future oil, NGL and natural gas producing properties for the purpose of generating cash flow. Prior to the decline in commodity prices and the filing of the Chapter 11 Petitions, our core investment strategy included the following principles:

•	acquire long-lived assets with low-risk exploitation and development opportunities;

•	use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;

•	reduce cash flow volatility through commodity price and interest rate derivatives; and

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•	maximize asset value and cash flow stability through our operating and technical expertise.

In response to the steep and continued decline in commodity prices during 2014, 2015 and the first part of 2016, we adjusted our business strategies by suspending distributions to common and preferred unitholders, significantly reducing our capital budget, cutting operating and overhead costs, scaling back derivative activity and reducing our acquisition expectations. Sustained low commodity prices led to the filing of the Chapter 11 Petitions, as described above.

Acquisitions and Dispositions

2016 Disposition

In March 2016, we completed the sale of certain of our Mid-Continent assets (the “Mid-Continent Sale”) for net proceeds of $11.9 million . The sale included substantially all Mid-Continent properties acquired in our 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 as of January 1, 2016. We recognized a gain of $11.3 million from the Mid-Continent Sale.

2015 Acquisitions

CO ₂ Acquisition . On March 31, 2015, we completed the acquisition of certain CO ₂ producing properties located in Harding County, New Mexico, for a total purchase price of $70.5 million (the “CO ₂ Acquisition”), which is primarily reflected in other property, plant and equipment on the consolidated balance sheet. See Note 4 to the consolidated financial statements in this report for a discussion of the CO ₂ Acquisition.

2014 Acquisitions

Antares Acquisition. On October 24, 2014, we completed the acquisition of certain oil and gas properties located in the Midland Basin, Texas from Antares Energy Company, in exchange for 4.3 million Common Units and $50.0 million in cash, for a total purchase price of $122.3 million (the “Antares Acquisition”).

QRE Merger.      On November 19, 2014, we acquired QRE in exchange for approximately 71.5 million Common Units and $350 million in cash (the “QRE Merger”). The QRE Merger had a transaction value of approximately $2.5 billion , including approximately $1.1 billion of QRE debt assumed and net of approximately $5.1 million of cash acquired. Our consolidated financial statements and financial and operational results reflect the combined entities since the acquisition date. The properties acquired in the QRE Merger were located in Alabama, Arkansas, Florida, Kansas, Louisiana, Michigan, New Mexico, Oklahoma and Texas.

Properties

Our properties include oil, NGL and natural gas assets as well as midstream assets located in the following producing areas: (i) Permian Basin in Texas and New Mexico, (ii) Midwest (Michigan, Indiana, and Kentucky), (iii) Ark-La-Tex (Arkansas, Louisiana and East Texas), (iv) Mid-Continent (Oklahoma), (v) the Rockies (Wyoming and Colorado), (vi) California and (vii) Southeast (Florida and Alabama). Our midstream assets include transmission and gathering pipelines, gas processing plants, NGL recovery plants, a controlling interest in a salt water disposal company and the 120-mile Transpetco Pipeline.

Breitburn Management manages all of our properties and employs production and reservoir engineers, geologists and other specialists, as well as field personnel. On a net production basis, we operated approximately 89% of our total production in 2016 . As the operator, we design and manage the development of wells and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate. We engage independent contractors to provide all the equipment and personnel associated with these activities.

2017 Outlook

In 2016, oil and natural gas prices continued to remain low and volatile. In 2016, the monthly average WTI posted price ranged from a low of $30 per Bbl in February to a high of $52 per Bbl in December , and the monthly average Henry Hub posted price ranged from a low of $1.73 per MMBtu in March to a high of $3.59 MMBtu in December . Declines in commodity prices that began at the end of 2014 led us to file for relief under the Bankruptcy Code, as described above. We

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have been managing, and plan to continue to evaluate, our operating activities and liquidity carefully in light of the uncertainty regarding future oil and natural gas prices and the Chapter 11 Cases. We do not expect increased production as a result of our 2017 capital program to entirely offset production declines; we expect overall decreases to our production in 2017, without taking into account acquisitions, divestitures or further modifications to our capital and operating plan based on price changes through 2017.

We expect our full year 2017 oil and gas capital spending program to be approximately $100 million , including capitalized engineering costs, compared with approximately $65 million in 2016 , approximately $209 million in 2015 and approximately $389 in 2014. The increase in capital expenditures primarily reflects higher CO2 purchases for our Postle field in Mid-Continent to counteract production declines and our continued development in Ark-La-Tex and the Permian Basin. We anticipate that 60% of our total capital spending will be focused on drilling and rate-generating projects and CO ₂ purchases in our core operating areas of Ark-La-Tex, the Permian Basin and Mid-Continent that are designed to increase or add to production or reserves. We plan to drill 20 operated and non-operated wells primarily in Ark-La-Tex and the Permian Basin.

Reserves and Production

As of December 31, 2016 , our total estimated proved reserves were 205.3 MMBoe, of which approximately 55% was oil, 9% was NGLs and 36% was natural gas. As of December 31, 2015 , our total estimated proved reserves were 239.3 MMBoe, of which approximately 54% was oil, 8% was NGLs and 38% was natural gas. The change to our total estimated proved reserves from December 31, 2015 to December 31, 2016 was a net decrease of 34.0 MMBoe, and included negative reserve revisions of 34.4 MMBoe, 18.3 MMBoe of production and a 2.0 MMBoe sale of reserves-in-place, partially offset by 20.6 MMBoe in extensions and discoveries. The reserve revisions in 2016 were primarily the result of a 22.0 MMBbl decrease in oil reserves and a 1.4 MMBbl decrease in NGL reserves, driven primarily by a decrease in oil and NGL prices, and a 66.3 Bcf decrease in natural gas reserves, driven primarily by a decrease in natural gas prices. The unweighted average first-day-of-the-month oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2016 were $42.75 per Bbl of oil for the WTI spot price and $2.48 per MMBtu of natural gas for the Henry Hub spot price, compared to $50.28 per Bbl of oil for the WTI spot price and $2.59 per MMBtu of natural gas for the Henry Hub spot price in 2015 .

The following table summarizes our estimated proved reserves and production by producing area as of December 31, 2016 :

		As of December 31, 2016																		Year Ended
		Proved Reserves																		December 31, 2016
		Total			Oil			NGLs			Natural Gas			% Proved						Production			Average Daily Production
		(MMBoe) (a)			(MMBbl)			(MMBbl)			(Bcf)			Developed			% Total			(MBoe)			(Boe/d)
Permian Basin		46.2			30.1			8.1			47.8			44	%		22	%		3,908			10,644
Midwest		41.1			3.5			0.6			221.8			100	%		20	%		2,897			7,948
Ark-La-Tex		34.4			15.8			4.2			86.3			94	%		17	%		3,908			10,678
Mid-Continent		30.4			24.9			4.9			3.8			30	%		15	%		2,152			5,881
Rockies		24.2			11.0			—			79.2			99	%		12	%		2,150			5,874
California		15.5			15.1			—			2.7			96	%		7	%		1,519			4,149
Southeast		13.5			12.3			1.1			0.6			78	%		7	%		1,745			4,769
Total		205.3			112.7			18.9			442.2			74	%		100	%		18,279			49,943
Antrim Shale (b)		33.7			—			—			201.9			100	%		16	%		2,133			5,828
Spraberry Trend (b)		31.0			21.3			5.5			25.3			33	%		15	%		2,128			5,814
(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) As of December 31, 2016, the Antrim Shale, included in “Midwest” above, and Spraberry Trend, included in “Permian Basin” above, were the only fields which contained 15% or more of our total proved reserves.

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The following table summarizes our production volumes, sales prices and production costs for the Antrim Shale in the Midwest and the Spraberry Trend in the Permian Basin, which accounted for 16% and 15% , respectively, of our total proved reserves as of December 31, 2016 :

		Antrim Shale												Spraberry Trend
		2016				2015				2014				2016				2015				2014
Net Production
	Crude Oil (MBbl)	—				—				—				1,059				1,302				1,458
	NGL (MBbl)	—				—				—				589				616				643
	Natural Gas (MMcf)	12,793				13,390				13,902				2,884				3,069				3,136
	Total (MBoe)	2,133				2,233				2,317				2,128				2,429				2,623
Average Realized Sales Price
	Crude Oil price per Bbl	$	—			$	—			$	—			$	39.62			$	45.05			$	85.49
	NGL price per Bbl	—				—				—				11.93				11.77				26.74
	Natural Gas price per Mcf	2.52				2.94				5.29				1.89				2.10				3.66
	Total price per Boe	$	15.13			$	17.66			$	31.79			$	25.58			$	29.79			$	58.45
Average Production Cost per Boe
	Pre-tax lease operating expense	$	8.27			$	8.54			$	10.35			$	12.82			$	15.39			$	10.77

See “Results of Operations” in Part II—Item 7 of this report for average realized sales price and average production cost per Boe for the Partnership in total.

As of December 31, 2016 , proved undeveloped reserves were 53.3 MMBoe compared to 47.3 MMBoe as of December 31, 2015 . During 2016 , we incurred $16.8 million in capital expenditures and drilled seven net wells related to the conversion of estimated proved undeveloped reserves to estimated proved developed reserves. During 2016 , we converted 580.0 MBbl of oil, 654.0 MBbl of NGLs and 13.8 Bcf of natural gas from estimated proved undeveloped reserves to estimated proved developed reserves. As of December 31, 2016 , we had no estimated proved undeveloped reserves that have remained undeveloped for more than five years, and we expect to develop substantially all estimated proved undeveloped reserves within five years of the recognition of those reserves.

As of December 31, 2016 , the total standardized measure of discounted future net cash flows was $803.7 million . During 2016 , we filed estimates of oil and gas reserves as of December 31, 2015 with the U.S. Department of Energy, which were consistent with the reserve data as of December 31, 2015 as reported in Note A in the supplemental information to the consolidated financial statements in this report.

Uncertainties are inherent in estimating quantities of proved reserves, including many factors that are beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices or development costs and production expenses, may require revision of such estimates. Accordingly, oil and gas quantities ultimately recovered will vary from reserve estimates. See Part I—Item 1A “—Risk Factors” in this report for a description of some of the risks and uncertainties associated with our business and reserves.

The information in this report relating to our estimated proved oil and gas reserves is based upon reserve reports prepared as of December 31, 2016 . Estimates of our proved reserves were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”) and Cawley, Gillespie & Associates, Inc. (“CGA”), independent petroleum engineering firms. NSAI prepared reserve data for all our properties except for our Postle and North East Hardesty fields in Oklahoma, which was prepared by CGA. The reserve estimates are reviewed and approved by members of our senior engineering staff and management. The process performed by NSAI and CGA to prepare reserve amounts included their estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue. NSAI and CGA also prepared estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Rule 4-10(a)(22) of Regulation S-X and subsequent SEC staff interpretations and guidance. In the conduct of their preparation of the reserve estimates, NSAI and CGA did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their work, something came to their attention that brought into question the validity

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or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their questions relating thereto.

The technical person primarily responsible for overseeing preparation of the reserves estimates and the third party reserve reports is Mark L. Pease, the President and Chief Operating Officer of our General Partner. Mr. Pease received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines in 1979. Prior to joining our General Partner, Mr. Pease was Senior Vice President, E&P Technology & Services for Anadarko Petroleum Corporation.  Mr. Pease has over 30 years of experience working in various capacities in the energy industry, including acquisition analysis, reserve estimation, reservoir engineering and operations engineering. Mr. Pease consults with NSAI and CGA during the reserve estimation process to review properties, assumptions and relevant data.

See Exhibit 99.1 to this report for the estimates of proved reserves provided by NSAI and Exhibit 99.2 to this report for the estimates of proved reserves provided by CGA. We only employ large, widely known, highly regarded and reputable engineering consulting firms. Not only the firms, but the technical persons that sign and seal the reports are licensed and certify that they meet all professional requirements. Licensing requirements formally require mandatory continuing education and professional qualifications. See Supplemental Note A to the consolidated financial statements in this report for further details about the qualifications of the technical persons at NSAI and CGA primarily responsible for preparing the reserves estimates.

Properties

    

Permian Basin

Our Permian Basin properties are primarily located in the southern Midland Basin and Eastern Shelf in Texas and New Mexico. As of December 31, 2016 , estimated proved reserves attributable to our Permian Basin properties were 46.2 MMBoe, or approximately 22% of our total estimated proved reserves. As of December 31, 2016 , approximately 65% of our Permian Basin total estimated proved reserves were oil, 18% were NGLs, and 17% were natural gas. For the year ended December 31, 2016 , our average production from the Permian Basin was approximately 10.6 MBoe/d. In 2016 , we drilled 15 gross new productive development wells, one recompletion, and completed six workovers in the Permian Basin. Our capital spending in the Permian Basin for the year ended December 31, 2016 was approximately $14 million . In total, as of December 31, 2016, we had interests in 3,186 productive wells in the Permian Basin, and we operated approximately 44% of those wells.

Midwest (Michigan, Indiana, Kentucky)

As of December 31, 2016 , our estimated proved reserves attributable to our Midwest properties were 41.1 MMBoe, or approximately 20% of our total estimated proved reserves. As of December 31, 2016 , approximately 90% of our Midwest total estimated proved reserves were natural gas, 8% were oil and 2% were NGLs . For the year ended December 31, 2016 , our average production from our Midwest properties was approximately 7.9 MBoe/d or 47.7 MMcfe/d. Our integrated midstream assets enhance the value of our Midwest properties as gas is sold at MichCon City-Gate prices, and we have no significant reliance on third party transportation. In 2016 , we drilled one gross new productive development well and completed one workover in the Midwest. Our capital spending in the Midwest for the year ended December 31, 2016 was approximately $3 million . As of December 31, 2016, we had interests in 3,729 productive wells in the Midwest, and we operated approximately 50% of those wells.

The Antrim Shale underlies a large percentage of our Midwest acreage; wells tend to produce relatively predictable amounts of natural gas in this reservoir. On average, our Antrim Shale wells have an estimated proved reserve life of greater than 16 years. Since reserve quantities and production levels over a large number of wells are fairly predictable, maximizing per well recoveries and minimizing per unit production costs are the keys to profitable Antrim Shale development. Growth opportunities include infill drilling and recompletions, horizontal drilling and bolt-on acquisitions.

Our non-Antrim interests in Michigan are located in several reservoirs including the Prairie du Chien, Richfield, Detroit River Zone III and Niagaran pinnacle reefs. Our operations in the New Albany Shale of southern Indiana and northern Kentucky include 21 miles of high pressure gas pipeline that interconnects with the Texas Gas Transmission interstate pipeline.

    

    

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Ark-La-Tex

The Ark-La-Tex area includes properties located in southern Arkansas, northern Louisiana and eastern Texas. These properties produce from formations including the Cotton Valley Sand, Haynesville Sand, Woodbine Sand and Smackover Carbonate.

As of December 31, 2016 , estimated proved reserves attributable to our Ark-La-Tex properties were 34.4 MMBbls, or approximately 17% of our total estimated proved reserves. As of December 31, 2016, approximately 46% of our Ark-La-Tex total estimated proved reserves were oil, 12% were NGLs, and 42% were natural gas. For the year ended December 31, 2016 , our average production was approximately 10.7 MBoe/d. Our capital spending in Ark-La-Tex for the year ended December 31, 2016 was approximately $19 million . As of December 31, 2016 , we had interests in 3,043 productive wells in Ark-La-Tex, and we operated 97% of those wells. During 2016 , we drilled nine gross wells, three recompletions and completed 29 workovers.

    

Mid-Continent

Our Mid-Continent area includes properties located in western Oklahoma and CO2 operations in northeastern New Mexico. These properties produce from regionally significant geologic formations such as the Council Grove, Morrow, Cherokee and Tubb. As of December 31, 2016 , estimated proved reserves attributable to our Mid-Continent properties were 30.4 MMBoe, or approximately 15% of our total estimated proved reserves. Approximately 82% of our Mid-Continent total estimated proved reserves were oil, 16% were NGLs and 2% were natural gas. For the year ended December 31, 2016 , the average production from our Mid-Continent properties were approximately 5.9 MBoe/d. In 2016 , we completed three workovers in the Mid-Continent. Our capital spending in the Mid-Continent for the year ended December 31, 2016 was approximately $15 million , primarily attributable to CO ₂ purchases. In total, as of December 31, 2016, we had interests in 357 productive wells, and we operated approximately 100% of those wells.

The most significant of our Mid-Continent properties are the Postle Field and the Northeast Hardesty Unit, both of which are located in Texas County, Oklahoma. CO ₂ miscible flooding has been on-going in the Postle Field since 1995. CO ₂ for the projects is sourced from the Bravo Dome Field in eastern New Mexico. We are also the sole owner of the Dry Trails gas plant located at the Postle Field complex. This plant is comprised of two trains with a combined processing capacity of approximately 100 MMcf/d. Gas is processed to recover marketable hydrocarbon components from the wellhead stream and capture CO ₂ gas for recompression and reuse in the flooding process. In addition, we are the sole owner of a collection of facilities and CO ₂ transportation pipelines delivering product from New Mexico to the Postle and Northeast Hardesty fields.

    

Rockies

Our Rockies assets consist primarily of oil properties in the Powder River Basin in eastern Wyoming and Wind River and Big Horn Basins in central Wyoming and natural gas properties in the Evanston and Green River Basins in southwestern Wyoming. We also own non-operated producing assets in Weld County, Colorado.

    

As of December 31, 2016 , estimated proved reserves attributable to our properties in the Rockies were 24.2 MMBoe, or approximately 12% of our total estimated proved reserves. As of December 31, 2016 , approximately 46% of our Wyoming total estimated proved reserves were oil and 54% were natural gas. For the year ended December 31, 2016 , our average production from our fields in Wyoming and Colorado were approximately 5.9 MBoe/d. In 2016 , we completed six workovers in Wyoming. Our capital spending in Wyoming for the year ended December 31, 2016 was approximately $1 million . In total, as of December 31, 2016, we had interests in 976 productive wells in Wyoming, and we operated approximately 66% of those wells. Our non-operated assets in Colorado consist of 18 productive wells.

California

As of December 31, 2016 , estimated proved reserves attributable to our California properties were 15.5 MMBoe, or approximately 7% of our total estimated proved reserves. As of December 31, 2016 , approximately 97% of our California total estimated proved reserves were oil and 3% were natural gas. For the year ended December 31, 2016 , our average California production was approximately 4.1 MBoe/d. In 2016 , we drilled 13 recompletions in California. Our capital spending in California for the year ended December 31, 2016 was approximately $8 million . In total, as of December 31, 2016, we had interests in 567 productive wells in California, and we operated 100% of those wells.

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Our operations in California are concentrated in several large, complex oil fields within the Los Angeles Basin. We also operate oil properties in the San Joaquin Basin in Kern County, California.

Southeast

Our Southeast producing area is comprised of significant holdings in two major geologic trends, the Sunniland trend in southwest Florida and the Jay trend in the northwest Florida Panhandle. These properties produce from the Cretaceous formations of the South Florida Basin and the Smackover Carbonate formation, respectively.

Our assets in the Southeast are characterized by large hydrocarbon resources in place. The Jay/Little Escambia Creek Unit (“Jay Unit”), which straddles the Alabama/Florida state lines, has been under nitrogen miscible gas injection since 1980. We operate a 70 acre processing and handling facility within the Jay Unit that separates oil, marketable hydrocarbon components and sulfur from the produced fluid stream. The remaining nitrogen rich gas is recompressed and reused in the flood process. Additional volumes of injected nitrogen are sourced from two operated air separation units located in Flomaton, Alabama in the north area of the field.

As of December 31, 2016 , estimated proved reserves attributable to our assets in the Southeast were 13.5 MMBoe, or approximately 7% of our total estimated proved reserves. As of December 31, 2016, approximately 91% of our Southeast total estimated proved reserves were oil, 8% were NGLs, and 1% were natural gas. For the year ended December 31, 2016 , our average Southeast production was approximately 4.8 MBoe/d. In 2016 , we completed eight workovers in the Southeast. Our capital spending for the year ended December 31, 2016 was approximately $5 million . As of December 31, 2016 , we had interests in 92 productive wells in the Southeast, and we operated 96% of those wells.

Productive Wells

The following table sets forth information for our properties as of December 31, 2016 , relating to the productive wells in which we owned a working interest. Productive wells consist of producing wells and wells capable of production. Gross wells are the total number of productive wells in which we have an interest, and net wells are the sum of our fractional working interests owned in the gross wells. We had approximately 44 wells with multiple completions as of December 31, 2016 .

		Oil Wells						Gas Wells
		Gross			Net			Gross			Net
Operated		5,088			4,913			2,807			2,298
Non-operated		1,726			83			2,347			776
Total		6,814			4,996			5,154			3,074

 

Developed and Undeveloped Acreage

The following table sets forth information for our properties as of December 31, 2016 relating to our leasehold acreage. Developed acres are acres spaced or assigned to productive wells. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas or oil, regardless of whether such acreage contains proved reserves. Gross acres are the total number of acres in which a working interest is owned. Net acres are the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

		Developed Acreage						Undeveloped Acreage						Total Acreage
		Gross			Net			Gross			Net			Gross			Net
Permian Basin		110,156			75,028			14,832			10,358			124,988			85,386
Midwest		493,967			251,085			13,204			12,687			507,171			263,772
Ark-La-Tex		116,990			75,599			5,182			3,451			122,172			79,050
Mid-Continent		32,094			30,773			—			—			32,094			30,773
Rockies		177,352			101,452			26,304			8,967			203,656			110,419
California		3,956			3,216			41			41			3,997			3,257
Southeast		52,031			47,193			5,539			3,694			57,570			50,887
Total		986,546			584,346			65,102			39,198			1,051,648			623,544

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The following table lists the net undeveloped acres as of December 31, 2016 , the net acres expiring in the years ending December 31, 2016, 2017 and 2018, and, where applicable, the net acres expiring that are subject to extension options.

					2017 Expirations						2018 Expirations						2019 Expirations
		Net Undeveloped Acreage			Net Acreage without Extension Option			Net Acreage with Extension Option			Net Acreage without Extension Option			Net Acreage with Extension Option			Net Acreage without Extension Option			Net Acreage with Extension Option
Permian Basin		10,358			63			320			233			3			351			—
Midwest		12,687			544			1,157			40			—			30			—
Ark-La-Tex		3,451			—			13			29			7			—			—
Rockies		8,967			960			—			36			—			—			—
California		41			—			—			34			—			—			—
Southeast		3,694			400			—			3,294			—			1,297			—
Total		39,198			1,967			1,490			3,666			10			1,678			—

 

As of December 31, 2016 , we held more than 110,000 net acres in the developing Utica-Collingwood shale play in Michigan, all of which was held by production and is included in the developed acreage in the above table.

Drilling Activity

Drilling activity and production optimization projects are on lower risk, development properties. The following table sets forth information for our properties with respect to wells completed during the years ended December 31, 2016 , 2015 and 2014 . Productive wells are those that produce commercial quantities of oil and gas, regardless of whether they produce a reasonable rate of return. No exploratory wells were drilled during the periods presented.

		Year Ended December 31,
		2016			2015			2014
Gross development wells:
Productive		25			62			170
Dry		—			—			1
Total		25			62			171
Net development wells:
Productive		9			45			160
Dry		—			—			1
Total		9			45			161

 

As of December 31, 2016 , we had the following wells in progress: one gross well and less than one net well in the Midwest and two gross wells and one net well in Ark-La-Tex. As of December 31, 2016 , we had a CO2 injection pressure maintenance project in process in Michigan, and a waterflood expansion project in process in Wyoming.

Delivery Commitments

As of December 31, 2016 , we had a contractual commitment to deliver 14.7 MMBoe of oil to a pipeline in West Texas through September 30, 2024. We expect to fulfill this commitment with existing Permian Basin estimated proved reserves.

Sales Contracts

We have a portfolio of oil, NGL and natural gas sales contracts with large, established refiners and utilities. Our sales contracts are sold at market-sensitive or spot prices. Because commodity products are sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. During 2016 , our largest purchasers were Shell Trading (US) Company (“Shell Trading”), which accounted for approximately 17% of our net sales revenues, and Plains Marketing (“Plains Marketing”), which accounted for approximately 11% of our net sales revenues. See Note 17 to the consolidated financial statements in this report for a discussion of significant customers for the years ended December 31, 2016 , 2015 and 2014 .

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Commodity Prices

We analyze the prices we realize from the sales of all our produced products, including crude oil, NGLs and natural gas, and the impact on those prices of differences in market-based index prices. We market our oil and natural gas production to a variety of purchasers based upon the NYMEX posted prices for WTI and Natural Gas, as well as on the geographic regional U.S. posted prices for all products. The NYMEX WTI posted price of oil is the widely used benchmark in the pricing of domestic oil in the United States. The relative value of crude oil is mainly determined by its quality and geographic location. In the case of NYMEX WTI posted pricing, this oil is light and sweet, deemed 40 degrees API, and is priced for delivery at Cushing, Oklahoma. In general, produced products with fewer transportation requirements result in higher realized pricing for producers. Historically there has been a strong relationship between changes in NGL and crude oil prices. NGL prices are correlated to North American supply and petrochemical demands.

Our Permian Basin oil trades at a discount to WTI posted prices due to the deduction of transportation costs, and our Permian Basin NGLs trade at a discount due to processing fees, profit sharing and transportation. Our Mid-Continent oil trades at a discount to WTI posted prices primarily due to transportation and quality, and our Mid-Continent NGLs trade at a discount due to regional market demand and transportation. Our Rockies oil trades at a significant discount to WTI posted prices because of its distance from a major refining market and the fact that our central Wyoming production is priced relative to the Western Canadian Select benchmark. Our Southwestern Wyoming production is priced relative to Flint Hills Resources Wyoming Sweet posted prices. Our Ark-La-Tex oil trades at a premium to WTI posted prices due to local refinery market supply. Our oil from the Sunniland Trend in Florida trades at a discount to WTI posted prices primarily because it is heavy crude and is transported via barge to market. Our oil from the Jay Field in Florida also trades at a discount to WTI posted price due to transportation costs and quality. Our California oil is generally in proximity to the extensive Los Angeles refining market and trades in accordance with that local market, which competes with waterborne crude imports.

In 2016 , the WTI posted price averaged approximately $43 per Bbl, compared with $48 a year earlier. The monthly average WTI posted prices during 2016 ranged from a high of $52 per Bbl in December to a low of $30 per Bbl in February . As of February 28, 2017 , the WTI spot price during 2017 has averaged $53 per Bbl.

Our Midwest properties have favorable natural gas supply and demand characteristics due to their proximity to the Northeast, allowing us to sell our natural gas production at a slight premium to posted prices. Our Rockies area natural gas generally trades at a discount to NYMEX due to its location and the regional supply and demand market balances. Prices for natural gas have historically fluctuated widely, and many regional markets are aligned with the local supply and demand conditions in those regional markets rather than with the overall U.S. market. Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the inventory in underground storage relative to customer demand. U.S. natural gas prices are also typically higher during the winter period when demand for heating is greatest. During 2016 , the monthly average Henry Hub posted price ranged from a high of $3.59 per MMBtu in December to a low of $1.73 per MMBtu in March . During 2016 , the Henry Hub posted price averaged approximately $2.51 per MMBtu. As of February 28, 2017 , the Henry Hub posted price during 2017 has averaged $3.10 per MMBtu.

Our operating expenses are responsive to changes in commodity prices. We experience pressure on operating expenses that is highly correlated to oil prices for specific expenditures such as lease fuel, electricity, drilling services and severance and minerals-based property taxes. Sustained depressed prices of oil and natural gas will adversely affect our assets, development plans, results of operations and financial position, perhaps materially. See Part I—Item 1A “—Risk Factors” — “Risks Related to Our Business — Oil, NGL and natural gas prices and differentials are highly volatile. Declines in commodity prices, especially steep declines in the price of oil, have adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flow, access to the capital markets and ability to grow. ”

Derivative Activity

Our revenues and net income are highly sensitive to oil and natural gas prices. In the past, we entered into various derivative contracts intended to achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas. As discussed above, the commencement of the Chapter 11 Cases constituted an event of default under our commodity and interest rate derivative instruments, resulting in a termination right by our counterparties. All of our counterparties exercised this right during the year ended December 31, 2016, and, as a result, we had no active commodity derivative instruments outstanding as of December 31, 2016. For a more detailed discussion of our derivative activities, see Note 5 to the consolidated financial statements included in this report.

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Competition

The oil and gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in all aspects of our business, including acquiring properties and oil and gas leases, marketing oil and gas, contracting for drilling rigs and other equipment necessary for drilling and completing wells and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit.

In regards to the competition we face for drilling rigs and the availability of related equipment, the oil and gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel in the past, which have delayed development drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program. Competition is also strong for attractive oil and gas producing properties, undeveloped leases and drilling rights, which may affect our ability to compete satisfactorily when attempting to make further acquisitions. See Item 1A “—Risk Factors” — “Risks Related to Our Business — We may be unable to compete effectively with other companies in the oil and gas industry, which may adversely affect our ability to generate revenue” in this report.

Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing oil leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. We have granted the lenders under the RBL Credit Agreement a first lien on substantially all of our oil and gas properties. We have granted the holders of our 9.25% Senior Secured Second Lien Notes due 2020 (the “Senior Secured Notes” and together with the Senior Unsecured Notes, the “Senior Notes”) a second lien on substantially all of our oil and gas properties. We have also granted the lenders under the DIP Credit Agreement a superpriority lien on substantially all of our oil and gas properties. Our properties are also subject to customary royalty and other interests, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Some of our oil and gas leases, easements, rights-of-way, permits, licenses and franchise ordinances require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained sufficient third party consents, permits and authorizations for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that the failure to obtain these consents, permits or authorizations have no material adverse effect on the operation of our business.

Seasonal Nature of Business

Seasonal weather conditions, especially freezing conditions in Michigan and Wyoming and tropical storms and hurricanes in the Gulf Coast, and lease stipulations can limit our drilling activities and other operations in certain of the areas in which we operate, and, as a result, we seek to perform the majority of our drilling during the non-winter months. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

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Environmental Matters and Regulation

General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the emission and discharge of materials into the environment. These laws and regulations may, among other things:

•	require the acquisition of various permits before exploration, drilling or production activities commence;

•	prohibit some or all of the operations of facilities deemed in non-compliance with regulatory requirements;

•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;

•	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

•	require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits, plug abandoned wells and restore drilling sites.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the United States Congress (“Congress”), state legislatures and federal and state agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Waste Handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. The U.S. Environmental Protection Agency (“EPA”) has delegated authority to the individual states to administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exemption certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.

Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses oil and natural gas, we may nonetheless handle hazardous substances subject to CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be held jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

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We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. From time to time, we have discovered evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by us. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges. The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers. In September 2015, new EPA and U.S. Army Corps of Engineers rules defining the scope of the EPA’s and the Corps’ jurisdiction became effective. To the extent the rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of Clean Water Act programs, and implementation of the rule has been stayed pending resolution of the court challenge. Litigation surrounding the rule is ongoing. The Clean Water Act also imposes spill prevention, control, and countermeasure requirements, including requirements for appropriate containment berms and similar structures, to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The primary federal law for oil spill liability is the Oil Pollution Act (“OPA”), which establishes a variety of requirements pertaining to oil spill prevention, containment, and cleanup. OPA applies to vessels, offshore facilities and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, are required to develop and implement plans for preventing and responding to oil spills and, if a spill occurs, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from the spill. Effective as of September 2015, comparable California regulations require spill contingency plans for inland oil and gas facilities.

Underground Injection Control (“UIC”). The Safe Drinking Water Act (“SDWA”) and comparable state laws regulate the construction, operation, permitting and closure of injection wells that place fluids underground for storage or disposal. Under the SDWA’s UIC Program, producers must obtain federal or state Class II injection well permits and routinely monitor and report fluid volumes, pressures and chemistry, and conduct mechanical integrity tests on injection wells. While the EPA itself implements the UIC Program for Class II wells (which are used to inject brines and other fluids associated with oil and gas production) in some of the states in which we operate, other states in which we operate, such as California, Oklahoma and Texas, have primary enforcement authority with respect to the regulation of Class II wells. In response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewater, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of certain injection wells. As a result of these concerns, regulators in some states are considering additional requirements related to seismic safety. For example, the Texas Railroad Commission (“RRC”) in October 2014 adopted new oil and gas permit rules for wells used to dispose of saltwater and other fluids resulting from the production of oil and natural gas in order to address seismic activity concerns. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. Similarly, in July 2015, January 2016 and September 2016, the Oklahoma Corporation Commission (“OCC”) issued various orders and regulations applicable to disposal operations in specific counties in Oklahoma. These rules require that disposal well operators, among other things, conduct additional mechanical integrity testing, ensure that their wells are not injecting wastes in targeted formations and/or reduce the volumes of wastes disposed in such wells. The OCC’s actions have resulted in reductions in volume of 50% for injection wells in some areas where increased seismic activity has occurred.

  

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In addition, in July 2014, the EPA sent a letter to the California Environmental Protection Agency and California Natural Resources Agency describing “serious deficiencies” in the state’s UIC Program and setting forth comprehensive requirements and deadlines for bringing the program into compliance with federal regulations by February 2017. In its letter, the EPA mandated an in-depth review of all existing Class II wells in California that may be injecting into non-exempt aquifers as well as a review of the state’s aquifer exemption process. In addition, the EPA directed the state to prohibit new and existing injections into aquifers that have not been approved as exempt by the EPA by February 15, 2017. The state responded by promulgating Aquifer Exemption Compliance Schedule regulations that became effective on April 20, 2016. The regulations set a final deadline of February 15, 2017 for Class II injection wells to stop injecting into non-exempt waters and are projected to affect more than 460 injection wells. Although none of the Partnership’s wells are affected by these regulations, if new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to continue production may be delayed or limited, which could have an adverse effect on our results of operation and financial position.

Air Emissions. The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers, pneumatic pumps, and storage vessels. The Clean Air Act also imposes leak detection requirements for new or modified well sites, compressor stations, and natural gas processing plants. Compliance with these rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. More recently, in June 2016, the EPA finalized rules under the Clean Air Act regarding criteria for aggregating multiple sites into a single source for air quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities (such as compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. States can also impose air emissions limitations that are more stringent than the federal standards imposed by the EPA, and California air quality laws and regulations are in many instances more stringent than comparable federal laws and regulations. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Regulatory requirements relating to air emissions are particularly stringent in Southern California. Rules restricting air emissions may require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our operating results. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

Hydraulic Fracturing. Hydraulic fracturing involves the injection of water, sand, and chemicals under pressure into dense subsurface rock formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel, and in February 2014 issued guidance for such activities. The EPA has also issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and finalized effluent limitation guidelines in June 2015 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.

At the state level, several states, including California, Florida, Indiana, Michigan, Oklahoma, Texas and Wyoming, have adopted and/or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, the California Department of Conservation rules, effective July 2015, require the approval of Well Stimulation Treatment Notices before starting stimulation treatment, disclosure of the fluids used and adoption of groundwater monitoring and water management plans. They also govern

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resident notifications, storage and handling of fluids and well integrity. We do not expect any material adverse impact to result from these rules. In addition, several local jurisdictions in California and Florida have proposed or adopted various forms of moratoria or bans on hydraulic fracturing. In some cases, these measures include broad terms which, if enacted or upheld, could affect current operations. We do not believe that any current local proposal or measures will have a material adverse effect on the Partnership as a whole.

In December 2016, at the federal level, the EPA released its final report on the potential impacts of hydraulic fracturing on water resources. The EPA report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water sources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.

Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These or future studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Climate Change. In response to findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. These regulations include limits on tailpipe emissions from motor vehicles and pre-construction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. In December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rules. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. More recently, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. In November 2016, the EPA issued a final Information Collection Request seeking information needed to help the agency regulate methane and other emissions from existing sources. The BLM finalized similar rules in November 2016 that limit methane emissions from new and existing oil and gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements, but it is unclear when and whether these rules will be implemented. Compliance with rules to control methane emissions will likely require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks, and the increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance with these new and proposed rules, which could increase the cost of our operations. In California, the state Air Resources Board has proposed the adoption of new regulations governing methane emissions from oil and gas production operations. These new rules are expected to brought to public hearing in 2017. These new and proposed rules could result in increased compliance costs for the Partnership.

In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and many of the states have already established greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

California has been one of the leading states in adopting greenhouse gas emission reduction requirements, and has implemented a cap and trade program as well as mandates for renewable fuels sources. California’s cap and trade program requires us to report our greenhouse gas emissions and essentially sets maximum limits or caps on total emissions of greenhouse gases from all industrial sectors that are or become subject to the program. This includes the oil and natural gas extraction sector of which we are a part. Our main sources of greenhouse gas emissions for our Southern California oil and

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gas operations are primarily attributable to emissions from internal combustion engines powering generators to produce electricity, flares for the disposal of excess field gas and drilling rigs. Under the California program, the cap declines annually from 2013 through 2020. In January 2017, California proposed to extend the cap and trade program beyond 2020 based on California’s greenhouse gas emission reduction requirements being extended through 2030. Under the cap and trade program, we are required to obtain authorizations for each metric ton of greenhouse gases that we emit, either in the form of allowances (each the equivalent of one ton of carbon dioxide) or qualifying offset credits. A portion of the allowance will be granted by the state, but any shortfall between the state-granted allowance and the facility’s emissions will have to be addressed through the purchase of additional allowances either from the state or a third party. The availability of allowances will decline over time in accordance with the declining cap, and the cost to acquire such allowances may increase over time. However, we do not expect the cost to be material to our operations.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements or they could promote the use of alternative fuels and thereby decrease demand for the oil and gas that we produce. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. Such climatic events could have an adverse effect on our financial condition and results of operations.

Pipeline Safety . Some of our pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”) and analogous state agencies in some cases under the Pipeline Safety Improvement Act of 2002, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined to include areas with specified population densities, buildings containing populations with limited mobility, areas where people may gather along the route of a pipeline (such as athletic fields or campgrounds), environmentally sensitive areas and commercially navigable waterways. Under the DOT’s regulations, integrity management programs are required to include baseline assessments to identify potential threats to each pipeline segment, implementation of mitigation measures to reduce the risk of pipeline failure, periodic reassessments, reporting and record keeping. In two steps taken in 2008 and 2010, PHMSA extended its integrity management program requirements to hazardous liquid gathering lines located in “unusually sensitive areas,” such as locations containing sole-source drinking water aquifers, endangered species or other protected ecological resources.

Also, in March of 2015, PHMSA finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements for calculating pressure reductions for immediate repairs on liquid pipelines. In October 2015, PHMSA proposed new regulations for hazardous liquid pipelines that would significantly extend and expand the reach of certain PHMSA integrity management requirements, regardless of the pipeline’s proximity to a high consequence area. The proposal also requires new reporting requirements for certain unregulated pipelines, including all gathering lines. To date, PHMSA has not published the final rule in the Federal Register. More recently, in May 2016, PHMSA proposed rules that would, if adopted, impose more stringent requirements for certain gas lines. Among other things, the proposed rulemaking would extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond “high consequence areas” to cover gas pipelines found in newly defined “moderate consequence areas” that contain as few as five dwellings within the potential impact area and would also require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”). Other new requirements proposed by PHMSA under the rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and use more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. The proposed rulemaking also seeks to impose a number of requirements on gathering lines. Additional future regulatory action expanding PHMSA jurisdiction and imposing stricter integrity management requirements is likely. In June 2016, the President signed into law legislation that, among other things, requires PHMSA to conduct an assessment of its inspections process and integrity management programs for natural gas and hazardous liquid pipelines. The legislation also requires PHMSA to prioritize various rulemakings required by the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 and propose and finalize the rules mandated by the Act. At this time, we cannot predict the cost of additional potential pipeline

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safety rulemakings, but they could be significant. Moreover, fines and penalties may be imposed on pipeline operators that fail to comply with PHMSA requirements, and such operators may also become subject to orders or injunctions restricting pipeline operations. Violations of the pipeline safety laws and regulations that occur after January 2012 can result in fines of up to $200,000 per violation per day, with a maximum of $2 million for a series of violations.

Endangered Species. The Endangered Species Act and similar state statutes prohibit certain actions that harm endangered or threatened species and their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas development. This could result in increased costs to us, and could delay or restrict drilling program activities, any of which could adversely impact our business. The presence of any protected species or the final designation of previously unprotected species as threatened or endangered in areas where we operate could result in increased costs from species protection measures or could result in limitations, delays, or prohibitions on our exploration and production activities that could have an adverse effect on our ability to develop and produce our reserves.

Activities on Federal Lands . Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. The Partnership’s exploration and production operations include activities on federal lands. For those current activities as well as for future or proposed exploration and development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA are required. This process has the potential to delay, limit or increase the cost of developing oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

OSHA and Other Laws and Regulation. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, OSHA Process Safety Management, the EPA community right-to know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations.

We believe that compliance with existing requirements will not have a material adverse effect on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2016 . Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2017 . However, accidental spills or releases may occur in the course of our operations, and we cannot assure you that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. In addition, we expect to be required to incur remediation costs for property, wells and facilities at the end of their useful lives. Moreover, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our business, financial condition and results of operations or ability to make distributions to our unitholders.

Other Regulation of the Oil and Gas Industry

The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

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Production Regulation. Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate, also regulate one or more of the following:

•	the location of wells;

•	the method of drilling and casing wells;

•	the surface use and restoration of properties upon which wells are drilled;

•	the plugging and abandoning of wells; and

•	notice to surface owners and other third parties.

The various states regulate the drilling for, and the production of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Production taxes vary by state. All states in which we operate impose ad valorem taxes on our oil and gas properties. Various states regulate the drilling for, and the production, gathering and sale of, oil, NGLs and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Currently, Alabama, Arkansas, Florida, Indiana, Kansas, Kentucky, Louisiana, Michigan, New Mexico, Oklahoma, Texas, and Wyoming impose severance taxes on producers at rates ranging from 1% to 13% of the value of the gross product extracted. Wyoming and Oklahoma wells that reside on Native American or federal land are subject to an additional tax of 8.5% and 8.0% , respectively. Florida sulfur sales are subject to a tax of $6.13 per long ton. In Wyoming, Florida and Michigan, reduced rates may apply to certain types of wells and production methods, such as new wells, renewed wells, stripper production and tertiary production. California does not currently impose a severance tax but taxes minerals in place. Attempts by California to impose a similar tax have been introduced in the past.

States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowances from oil and gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. Our Los Angeles Basin properties are located in urbanized areas, and certain drilling and development activities within these fields require local zoning and land use permits obtained from individual cities or counties. These permits are discretionary and, when issued, usually include mitigation measures which may impose significant additional costs or otherwise limit development opportunities.

Natural Gas Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act (“NGA”) exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”) as a natural gas company under the NGA. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, and, therefore, the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. If our natural gas gathering pipelines were subject to FERC’s jurisdiction, we would be required to file a tariff with FERC, provide a cost justification for the transportation charge and obtain certificate(s) of public convenience and necessity for the FERC-regulated pipelines. Our natural gas gathering operations could be adversely affected should they be subject to the more stringent application of state or federal regulation of rates and services.

Our natural gas gathering operations are subject to regulation in the various states in which we operate. The level of such regulation varies by state. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties. Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Natural Gas Transportation Pipeline Regulation . Our sole interstate natural gas pipeline is an 8.3 mile pipeline in Kentucky that connects with the Texas Gas Transmission interstate pipeline. Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and

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records, the acquisition and disposition of facilities, the initiation and discontinuation of services and various other matters. Natural gas companies may not charge rates that have been determined not to be just and reasonable by FERC. In addition, FERC prohibits FERC regulated natural gas facilities from unduly preferring, or unduly discriminating against, any person with respect to pipeline rates or terms and conditions of service or other matters. Our 8.3 mile pipeline is subject to a limited jurisdiction FERC certificate, and we are not currently required to maintain a tariff at FERC. We cannot be assured that our 8.3 mile pipeline will always maintain its limited jurisdiction status, and we may be required to establish rates and file a FERC tariff in the future, which may have an adverse impact on our revenues. Pursuant to FERC’s jurisdiction, existing rates and/or other tariff provisions may be challenged by complaint and rate increases proposed by the pipeline or other tariff charges may be challenged by protest. A successful complaint or protest related to our facilities could have an adverse impact on our revenue.

Our intrastate natural gas transportation pipelines are subject to regulation by applicable state regulatory commissions that can affect the rates we charge and terms of service. The level of such regulation varies by state. Although state regulations are typically less onerous than FERC, state regulations typically require pipelines to charge just and reasonable rates and to provide service on a non-discriminatory basis. Additionally, FERC has adopted certain regulations and reporting requirements applicable to intrastate and Hinshaw natural gas pipelines that provide certain interstate services subject to FERC’s jurisdiction. We could become subject to such regulations and reporting requirements in the future to the extent that any of our intrastate pipelines were to begin providing, or were found to provide, such interstate services. Failure to comply with federal or state regulations can result in the imposition of administrative, civil and criminal penalties.

Additional proposals and proceedings that might affect the natural gas pipeline industry are pending before Congress, FERC and in the courts. We cannot predict the ultimate impact of these on our natural gas operations. We do not believe that we would be affected by any such actions materially differently than other midstream natural gas companies with whom we compete.

Liquids Pipeline Regulation. We own a 51 mile oil pipeline in Oklahoma and Texas that is a common carrier pipeline and subject to regulation by FERC under the October 1, 1977, version of the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (“EPAct 1992”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on the interstate common carrier liquids pipelines and generally require the rates and practices of interstate liquids pipelines to be just and reasonable and nondiscriminatory. The ICA also requires these pipelines to keep tariffs on file with FERC that set forth the rates the pipeline charges for providing transportation services and the rules and regulations governing these services. EPAct 1992 and its implementing regulations allow interstate common carrier oil pipelines to annually index their rates up to a prescribed ceiling level. FERC retains cost-of-service ratemaking, market‑based rates and settlement rates as alternatives to the indexing approach. The ICA also requires these pipelines to keep tariffs on file with FERC that set forth the rates the pipelines charge for providing transportation services and the rules and regulations governing these services. On January 27, 2016, in Docket No. OR16-10-000, we received a temporary waiver of the filing and reporting requirements of sections 6 and 20 of the ICA. On February 2, 2016, we filed a cancellation of our tariffs. We cannot be assured that our 51 mile oil pipeline will always maintain its temporary waiver, and we may be required to establish rates and file a FERC tariff in the future, which may have an adverse impact on our revenues.

Natural Gas Processing Regulation . Our natural gas processing operations are not presently subject to FERC regulation. There can be no assurance that our processing operations will continue to be exempt from other FERC regulation in the future.

Our processing facilities are affected by the availability, terms and cost of pipeline transportation. The price and terms of access to pipeline transportation can be subject to extensive federal and in state regulation. FERC is continually proposing and implementing new rules and regulations affecting the interstate transportation of natural gas, and to a lesser extent, the interstate transportation of NGLs. These initiatives also may indirectly affect the intrastate transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of these regulatory changes to our processing operations.

Regulation of Sales of Oil, Natural Gas and NGLs . The price at which we buy and sell oil, natural gas and NGLs is currently not subject to federal regulation and, for the most part, is not subject to state regulation. The availability, terms and cost of transportation significantly affect the sales of oil, natural gas and NGLs. Although the prices are not currently regulated, Congress has historically been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate prices for energy commodities might be proposed, and what effect, if any, such proposals might have on the operations of our business.

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With regard to our physical purchases and sales of these energy commodities and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC, the Commodity Futures Trading Commission (“CFTC”) and the Federal Trade Commission (“FTC”), as further described below. Should we violate the anti-market manipulation laws and regulations, we could be subject to fines and penalties as well as related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.

In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1 million per violation per day. In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the CFTC to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to liquids swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to liquids purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation. For a description of FERC’s anti market manipulation rules, see “Energy Policy Act of 2005” below.

Our sales of oil, natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation can be subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting the interstate transportation of natural gas, and to a lesser extent, the interstate transportation of oil and NGLs. These initiatives also may indirectly affect the intrastate transportation of oil, natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of these regulatory changes to our oil, natural gas and NGL marketing operations, and we do not believe that we would be affected by any such FERC action materially differently than other oil, natural gas and NGL marketers with whom we compete.

Energy Policy Act of 2005 . On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005 (“EPAct 2005”). EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to the statutory policy that affects all segments of the energy industry. With respect to regulation of natural gas transportation, EPAct 2005 amended the NGA and the Natural Gas Policy Act (“NGPA”) by increasing the criminal penalties available for violations of each Act. EPAct 2005 also added a new section to the NGA, which provides FERC with the power to assess civil penalties of up to $1,000,000 per day for each violation of the NGA and increased FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in FERC-jurisdictional transportation and the sale for resale of natural gas in interstate commerce. EPAct 2005 also amended the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of EPAct 2005, and subsequently denied rehearing. The rules make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC or the purchase or sale of transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which they were made, not misleading; or (3) engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any entity. The new anti-market manipulation rule does not apply to activities that relate only to non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, including the annual reporting requirements under Order No. 704 (described below). The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s enforcement authority. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts.

FERC Market Transparency Rules . Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers, and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

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Employees

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. As of December 31, 2016 , Breitburn Management had 671 full time employees. None of Breitburn Management’s employees are represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are satisfactory.

Offices

Breitburn Management’s principal executive offices are located at 707 Wilshire Boulevard, Suite 4600, Los Angeles, California 90017. Breitburn Management leases office space at 1111 Bagby Street, Houston, Texas 77002.

Financial Information

We operate our business as a single segment. Additionally, all of our properties are located in the United States and all of the related revenues are derived from purchasers located in the United States. Our financial information is included in the consolidated financial statements and the related notes beginning on page F-1.

Item 1A. Risk Factors.

An investment in our securities is subject to certain risks described below. If any of these risks were actually to occur, our business, financial condition and results of operations could be materially adversely affected. In that case, the trading price of our securities could decline, and you could lose part or all of your investment.

Risks Related to the Chapter 11 Cases

We are subject to the risks and uncertainties associated with the Chapter 11 Cases.

During the pendency of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan, and our continuation as a going concern, are subject to the risks and uncertainties associated with cases pending under chapter 11 of the Bankruptcy Code. These risks include the following:

•	our ability to develop, confirm and consummate a plan of reorganization;

•	the high costs of bankruptcy proceedings and related fees;

•	our ability to obtain court approval with respect to motions filed in the Chapter 11 Cases from time to time;

•	our ability to obtain sufficient financing to allow us to emerge from Chapter 11 and execute our business plan post-emergence;

•	our ability to maintain our relationships with our suppliers, customers, other third parties and our employees;

•	our ability to maintain contracts that are critical to our operations;

•	our ability to execute our business plan in the current depressed commodity price environment;

•	our ability to attract, motivate and retain key employees;

•	the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;

•	the ability of third parties to seek and obtain court approval to convert the Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code; and

•	the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with our plans.

Delays in the Chapter 11 Cases increase the risks of our being unable to reorganize our business and emerge from Chapter 11 and increase our costs associated with the Chapter 11 process.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our Chapter 11 Cases could adversely affect our relationships with our suppliers, customers, other third parties and our employees, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our Chapter 11 Cases, we cannot accurately predict or quantify the ultimate impact of events that occur during our Chapter 11 Cases that may be inconsistent with our plans.

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We believe it is highly likely that our Series A Preferred Units, Series B Preferred Units and Common Units will be canceled in our Chapter 11 Cases.

We have a significant amount of indebtedness that is senior to our existing Series A Preferred Units, Series B Preferred Units and Common Units in our capital structure. As a result, we believe that it is highly likely that the existing Series A Preferred Units, Series B Preferred Units and Common Units will be canceled in our Chapter 11 Cases with no recovery or distribution. Accordingly, any trading in our Series A Preferred Units, Series B Preferred Units and Common Units during the pendency of our Chapter 11 Cases is highly speculative and poses substantial risks to purchasers of our Series A Preferred Units, Series B Preferred Units and Common Units.

Operating under Bankruptcy Court protection for a long period of time may harm our business.

Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. A long period of operations in Chapter 11 could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as the Chapter 11 Cases continue, our senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. A prolonged period of operating in Chapter 11 also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships.

In addition, so long as the Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 Cases.

Furthermore, we cannot predict how claims and equity interests will be treated under a plan of reorganization. Even once a plan of reorganization is confirmed and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from Chapter 11.

We have substantial liquidity needs and may be required to seek additional financing. If we are unable to obtain financing on satisfactory terms or maintain adequate liquidity, our ability to replace our proved reserves or to maintain current production levels and generate revenue will be limited.

As of March 2, 2017, we had approximately $1.2 billion in borrowings outstanding under the RBL Credit Agreement and approximately $1.8 billion in aggregate principal amount of senior notes outstanding, which we expect to restructure in connection with the Chapter 11 Cases. In addition, as of March 2, 2017, we had no amounts borrowed and $51.2 million in letters of credit outstanding under the DIP Credit Agreement. Our principal sources of liquidity historically have been cash generated from operating activities, amounts available under our credit facility and cash from the issuance of secured and unsecured long-term debt and partnership units. In 2017, our oil and gas capital spending program is expected to be approximately $100 million. If our cash flow from operations remains depressed or decreases as a result of lower commodity prices or otherwise, our ability to expend the capital necessary to replace our proved reserves, maintain our leasehold acreage or maintain current production may be limited, resulting in decreased production and proved reserves over time. In addition, drilling activity may be directed by our partners in certain areas, and we may have to forfeit acreage if we do not have sufficient capital resources to fund our portion of expenses.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with preparation for and administration of the Chapter 11 Cases. We cannot assure you that cash on hand, cash flow from operations and borrowings available under the DIP Credit Agreement will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to the Chapter 11 Cases until we are able to emerge from Chapter 11. We face additional uncertainty regarding the ability to emerge successfully from Chapter 11 and to obtain adequate liquidity to finance our capital program subsequent to emergence from Chapter 11.

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of the DIP Credit Agreement and the order entered by the Bankruptcy Court approving the same and authorizing the use of cash collateral, (ii) our ability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate a Chapter 11 plan or other alternative restructuring transaction and (v) the cost, duration and outcome of the Chapter 11 Cases. Our ability to

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maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. In the event that cash on hand, cash flow from operations and availability under the DIP Credit Agreement are not sufficient to meet our liquidity needs, we may be required to seek additional financing. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited if it is available at all. Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

We may not be able to obtain confirmation of a Chapter 11 plan.

In order to emerge successfully from Chapter 11 as a viable entity, we must file a plan of reorganization, solicit and obtain the requisite acceptances of such a reorganization plan and fulfill other statutory conditions for confirmation of such a reorganization plan, which have not occurred to date. There is no assurance that a plan of reorganization will be confirmed and become effective, or if such a plan is confirmed and becomes effective, the distributions that will be made pursuant thereto.

Even if a Chapter 11 plan of reorganization were consummated, we may not be able to achieve our stated goals and continue as a going concern.

Even if a Chapter 11 plan of reorganization were consummated, we may continue to face a number of risks, such as further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our oil and gas and increasing expenses. Some of these risks become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, we cannot guarantee that any Chapter 11 plan of reorganization will achieve our stated goals.

In addition, the Bankruptcy Code gives the Debtors the exclusive right to file a plan of reorganization for up to a maximum of 18 months from the Chapter 11 Filing Date, and prohibits creditors, equity security holders and others from proposing a plan during this period. We have currently retained the exclusive right to file a plan of reorganization until April 13, 2017. If that right is terminated, however, or the exclusivity period expires, there could be a material adverse effect on our ability to achieve confirmation of a plan of reorganization in order to achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through a plan of reorganization, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the Chapter 11 Cases. Our access to additional financing may be limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.

Our ability to continue as a going concern is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if a plan of reorganization is confirmed.

Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may be unsuccessful in its execution.

Any plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to change substantially our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

In addition, any plan of reorganization will be premised upon financial projections, including with respect to revenues, Adjusted EBITDA, capital expenditures, debt service and cash flow. Financial projections are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial projections will not be accurate. In our case, the projections will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the

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results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

We may be subject to claims that will not be discharged in the Chapter 11 Cases, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. Any claims not ultimately discharged through a Chapter 11 plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

Our financial results may be volatile and may not reflect historical trends.

During our Chapter 11 Cases, we expect our financial results to continue to be volatile as potential asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments may significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of our Chapter 11 filing.

In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at their fair values as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

We have significant exposure to fluctuations in commodity prices since none of our estimated future production is covered by commodity derivatives, and we may not be able to enter into commodity derivatives covering our estimated future production on favorable terms or at all.

We have significant exposure to fluctuations in commodity prices since none of our estimated future production is covered by commodity derivatives. We may not be able to enter into commodity derivatives covering our production in future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivatives in the future, we could be more affected by changes in commodity prices than our competitors who engage in hedging arrangements. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.

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.

In connection with the Chapter 11 Cases, we anticipate engaging in transactions to de-lever the Partnership and manage our liquidity that would result in income and gain to our unitholders without a corresponding cash distribution. For example, we may sell assets and use the proceeds to repay existing debt or fund capital expenditures, in which case, you would be allocated taxable income and gain resulting from the sale without receiving a cash distribution or may exceed the amount of any distribution we might pay in any given year. Further, during the course of the Chapter 11 Cases, we will be seeking to restructure and, thereby, reduce our existing debt which, depending on the form of the restructuring, could result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as ordinary taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed the current value of your investment in the Partnership.

Entities taxed as corporations may have net operating losses to offset COD income or may otherwise qualify for an exception to the recognition of COD income, such as the bankruptcy or insolvency exceptions. In the case of partnerships like ours, however, these exceptions are not available to the Partnership and are only available to a unitholder if the unitholder itself is insolvent or in bankruptcy. As a result, these exceptions generally would not apply to prevent the taxation of COD income allocated to our unitholders. The ultimate tax effect of any such income allocations will depend on the

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unitholder’s individual tax position, including, for example, the availability of any suspended passive losses that may offset some portion of the allocable COD income. The suspended passive losses available to offset COD income will increase the longer a unitholder has owned our units. Unitholders may, however, be allocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated income against any capital losses attributable to the unitholder’s ultimate disposition of its units.

It may be possible for unitholders to estimate their approximate allocation of COD income once the amount of COD income that the Partnership will likely recognize, if any, is known. For example, if, in a “worst-case scenario,” all of the Partnership’s debt is canceled for no consideration causing the recognition of approximately $3 billion in COD income, then based on 213,789,296 Common Units outstanding as of December 31, 2016, and assuming that no amount of COD income is allocated to the Series A Units, each outstanding Common Unit would be allocated approximately $14.03 of COD income.

Unitholders are encouraged to consult their tax advisors with respect to the consequences to them of COD income.

In certain instances, a Chapter 11 case may be converted to a case under chapter 7 of the Bankruptcy Code.

If the Bankruptcy Court finds that it would be in the best interest of creditors and/or the Partnership, the Bankruptcy Court may convert our Chapter 11 reorganization case to a case under chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under chapter 7 would result in significantly smaller distributions being made to creditors than those that would be provided for in a Chapter 11 plan because (i) in a Chapter 7 case our assets would be sold or otherwise disposed of in a relatively short period of time rather than our business reorganizing or our business being sold as a going concern, (ii) of the additional administrative expenses involved in the administration of a Chapter 7 case and (iii) of the additional expenses and claims that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations in a Chapter 7 case.

Risks Related to Our Business

  Oil, NGL and natural gas prices and differentials are highly volatile. Declines in commodity prices, especially steep declines in the price of oil, have adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flow, access to the capital markets and ability to grow.

 

The oil, NGL and natural gas markets are highly volatile, and we cannot predict future oil, NGL and natural gas prices. Prices for oil, NGL and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, NGLs and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

•	domestic and foreign supply of and demand for oil, NGLs and natural gas;

•	market prices of oil, NGLs and natural gas;

•	level of consumer product demand;

•	overall domestic and global political and economic conditions;

•	political and economic conditions in producing countries, including those in the Middle East, Russia, South America and Africa;

•	actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

•	weather conditions;

•	impact of the U.S. dollar exchange rates on commodity prices;

•	technological advances affecting energy consumption and energy supply;

•	domestic and foreign governmental regulations and taxation;

•	impact of energy conservation efforts;

•	capacity, cost and availability of oil and natural gas pipelines, processing, gathering and other transportation facilities and the proximity of these facilities to our wells;

•	increase in imports of liquid natural gas in the United States; and

•	price and availability of alternative fuels.

 

Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because oil, NGLs and natural gas accounted for approximately 55% , 9% and 36% of our estimated proved reserves as of December 31, 2016 ,

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respectively, and approximately 52% , 11% and 37% of our 2016 production on an MBoe basis, respectively, our financial results will be sensitive to movements in oil, NGLs and natural gas prices.

In the past, prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2016 , the monthly average WTI spot price ranged from a high of $52 per Bbl in December to a low of $30 per Bbl in February while the monthly average Henry Hub natural gas price ranged from a high of $3.59 per MMBtu in December to a low of $1.73 per MMBtu in March . During the year ended December 31, 2015, the monthly average WTI spot price ranged from a high of $59.82 per Bbl in June to a low of $37.19 per Bbl in December while the monthly average Henry Hub natural gas price ranged from a high of $2.99 per MMBtu in January to a low of $1.93 per MMBtu in December. As of February 28, 2017 , the WTI spot price during 2017 has averaged $53 per Bbl and the natural gas spot price at Henry Hub has averaged approximately $3.10 per MMBtu. Price discounts or differentials between WTI spot prices and what we actually receive are also historically very volatile.

Our revenue, profitability and cash flow depend upon the prices and demand for oil, NGLs and natural gas, and the steep drop in prices has significantly affected our financial results and impeded our growth, and could continue to do so. In particular, continuance of the current low oil and natural gas price environment, further declines in oil or natural gas prices or a lack of natural gas storage will negatively impact:

•	the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically;

•	the amount of cash flow available for capital expenditures;

•	our ability to replace our production and future rate of growth;

•	our ability to borrow money or raise additional capital and our cost of such capital; and

•	our ability to meet our financial obligations.

Historically, higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services. Although commodity prices have steeply declined recently, the costs associated with drilling may not decline as rapidly. Accordingly, a high cost environment could adversely affect our ability to pursue our drilling program and our results of operations.

Oil and natural gas prices have declined substantially and are expected to remain depressed for the foreseeable future. Sustained depressed prices of oil and natural gas will materially adversely affect our assets, development plans, results of operations and financial position.

The monthly average WTI posted prices during 2016 ranged from a high of $52 per Bbl in December to a low of $30 per Bbl in February , and the monthly average Henry Hub posted price ranged from a high of $3.59 per MMBtu in December to a low of $1.73 per MMBtu in March . As of December 31, 2016 and March 2, 2017, none of our expected 2017 production was hedged. In 2015 and 2016, we wrote down the value of our oil and natural gas properties and revised our development plans, due to the expectation of an extended period of lower commodity prices. See “Future oil and natural gas price declines may result in further write-downs of our asset carrying values” below. In addition, sustained low prices for oil and natural gas will reduce the amounts we would otherwise have available to pay expenses.

The Chapter 11 Cases, low oil and natural gas prices and declines in the trading prices of our debt and equity securities have limited our ability to obtain funding in the capital and credit markets on terms we find acceptable, and could limit our ability to obtain additional or continued funding under the DIP Credit Agreement or obtain funding at all.

 

Historically, we have used cash flow from operations, borrowings available under our revolving credit facility and amounts raised in the debt and equity capital markets to fund our operations, capital expenditures, acquisitions and cash distributions. More recently, since late 2014, we have had limited access to the credit and capital markets as a result of declines and volatility in oil and natural gas prices. Although oil and natural gas prices have increased since we filed the Chapter 11 Petitions, they remain low historically, and the uncertainty resulting from the Chapter 11 Cases, combined with the uncertainty surrounding future commodity prices has significantly increased the cost of obtaining money in these markets and limited our ability to access these markets currently as a source of funding.

 

Due to these factors, we cannot be certain that funding will be available, if needed and to the extent required, on acceptable terms. If funding is not available when needed, or if funding is available only on unfavorable terms, we may be unable to complete our restructuring in the Chapter 11 Cases, meet our obligations as they come due,implement our

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development plans, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues, results of operations or financial condition. Without funding to make acquisitions of additional properties containing proved oil or natural gas reserves, our total level of estimated proved reserves will decline.

Our credit ratings have been withdrawn, which could further restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

Moody’s Investor’s Service and Standard & Poor’s downgraded our credit ratings following the filing of the Chapter 11 Petitions, and withdrew all ratings for the Partnership shortly thereafter. Because our ability to obtain financings and trade credit are, in part, dependent on the credit ratings assigned to the Partnership by independent credit rating agencies, the withdrawals of our credit ratings 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.

The price of our Common Units has recently declined significantly and could decline further for a variety of reasons, resulting in a substantial loss on investment and negatively impacting our ability to raise equity capital.

The closing price of our Common Units decreased from $7.63 per unit on January 2, 2015 to $0.25 per unit on December 30, 2016, and was $0.14 per unit as of the close of business on March 7, 2017 , and it could decline further. Such further decline could result from a variety of factors, including, among other things, the impact of the Chapter 11 Cases, sustained or further declines in commodity prices, actual or anticipated fluctuations in our operating results or financial condition, new laws or regulations or new interpretations of existing laws or regulations impacting our business, our customers’ businesses, sales of our Common Units by our unitholders or by us, a downgrade or cessation in coverage from one or more of our analysts, broad market fluctuations and general economic conditions and any other factors described in this “Risk Factors” section of this report. See “Risks Related to the Chapter 11 Cases—We believe it is highly likely that our Series A Preferred Units, Series B Preferred Units and Common Units will be canceled in our Chapter 11 Cases” and “Risks Related to the Chapter 11 Cases—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” in this report.

The liquidity of our Common Units could be adversely affected because we are trading on the OTC Pink.

On May 16, 2016, the Partnership received a letter from the Listing Qualifications Department of The Nasdaq Stock Market LLC (“NASDAQ”) notifying the Partnership of its determination to delist the Partnership’s securities from NASDAQ based on the Partnership filing a voluntary petition for relief under chapter 11 of the Bankruptcy Code and associated public interest concerns. The Partnership did not request an appeal of this determination, and our securities were suspended at the opening of business on May 25, 2016. On June 10, 2016, NASDAQ filed a Form 25-NSE with the SEC to remove the Partnership’s securities from listing and registration on NASDAQ.

Upon delisting from the NASDAQ Global Select Market, our securities have traded over-the-counter on the OTC Pink operated by the OTC Markets Group Inc. OTC transactions involve risks in addition to those associated with transactions in securities traded on the NASDAQ Global Select Market. Many OTC stocks trade less frequently and in smaller volumes than securities traded on the NASDAQ Global Select Market, which could adversely impact the liquidity of our securities and potentially result in even lower bid prices for our securities. Such market place volatility could also adversely affect our ability to raise additional capital.

Future oil and natural gas price declines may result in further write-downs of our asset carrying values.

 

Declines in oil and natural gas prices in 2015 and 2016 resulted in our having to make substantial downward adjustments to our estimated proved reserves resulting in increased depletion and depreciation charges. Accounting rules require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write-down. During the year ended December 31, 2016 , we recorded non-cash impairment charges of approximately $0.3 billion primarily due to the impact that the sustained drop in commodity strip prices had on our projected future net revenues.

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We also may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred.

The production from our Oklahoma properties could be adversely affected by the cessation or interruption of the supply of CO ₂ to those properties.

We use enhanced recovery technologies to produce oil and natural gas. For example, we inject water and CO ₂ into formations on substantially all of our Oklahoma properties to increase production of oil and natural gas. The additional production and reserves attributable to the use of enhanced recovery methods are inherently difficult to predict. If we are unable to produce oil and gas by injecting CO ₂ in the manner or to the extent that we anticipate, our future results of operations and financial condition could be materially adversely affected. Additionally, our ability to utilize CO ₂ to enhance production is subject to our ability to obtain sufficient quantities of CO ₂ . If, under our CO ₂ supply contracts, the supplier is unable to deliver its contractually required quantities of CO ₂ to us, or if our ability to access adequate supplies is impeded, then we may not have sufficient CO ₂ to produce oil and natural gas in the manner or to the extent that we anticipate, and our future oil and gas production volumes will be negatively impacted.

Drilling for and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition and results of operations.

 

The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce enough oil and natural gas to be commercially viable after drilling, operating and other costs. Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including, among other things:

 

•	high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;

•	unexpected operational events and drilling conditions;

•	sustained depressed oil and natural gas prices and further reductions in oil and natural gas prices;

•	limitations in the market for oil and natural gas;

•	problems in the delivery of oil and natural gas to market;

•	adverse weather conditions;

•	facility or equipment malfunctions;

•	equipment failures or accidents;

•	title problems;

•	pipe or cement failures;

•	casing collapses;

•	compliance with environmental and other governmental requirements;

•	environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

•	lost or damaged oilfield drilling and service tools;

•	unusual or unexpected geological formations;

•	loss of drilling fluid circulation;

•	pressure or irregularities in formations;

•	fires, blowouts, surface craterings and explosions;

•	natural disasters; and

•	uncontrollable flows of oil, natural gas or well fluids.

 

If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.

 

We may be unable to compete effectively with other companies in the oil and gas industry, which may adversely affect our ability to generate revenue.

 

The oil and gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major independent oil and gas companies and possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Factors that affect our ability to acquire

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properties include availability of desirable acquisition targets, staff and resources to identify and evaluate properties and available funds. Many of our larger competitors not only drill for and produce oil and gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the oil and gas industry. Other companies may have a greater ability to continue drilling activities during periods of low oil and gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with other companies could have a material adverse effect on our business activities, financial condition and results of operations.

We will require substantial capital expenditures to replace our production and reserves. We may be unable to obtain needed capital due to our financial condition, which could adversely affect our ability to replace our production and estimated proved reserves.

 

To fund our capital expenditures, we will be required to use cash on hand, cash generated from our operations or borrowings under the DIP Credit Agreement, or some combination thereof. In 2017 , our oil and gas capital spending program is expected to be approximately $100 million . In the future, our ability to borrow and to access the capital and credit markets may be limited by our financial condition at the time of any such financing or offering and the covenants in our debt agreements, as well as by oil and natural gas prices, the value and performance of our equity securities, and adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, results of operations and financial condition. Even if we are successful in obtaining the necessary funds, the terms of such financings could be onerous.

 

Our inability to replace our reserves could result in a material decline in our reserves and production, which could adversely affect our financial condition.

 

As a result of the significant decline in commodity prices, the impact on our liquidity and access to capital and the pendency of the Chapter 11 Cases, we expect that our ability to make acquisitions will be limited in 2017. We also believe that our capital program in 2017 will not be sufficient to offset overall production declines.

Producing oil and natural gas reservoirs are characterized by declining production rates that vary based on reservoir characteristics and other factors. The rate of decline of our reserves and production included in our reserve report at December 31, 2016 will change if production from our existing wells declines in a different manner than we have estimated and may change when we drill additional wells, make acquisitions and under other circumstances. Our future oil and natural gas reserves and production and our cash flow depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

 

On July 21, 2010, new comprehensive financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”) was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Partnership, that participate in that market. Dodd-Frank requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing Dodd-Frank. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

 

In one of its rulemaking proceedings still pending under Dodd-Frank, the CFTC issued on December 5, 2016, re-proposed rules imposing position limits for certain futures and option contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. As these new position limits rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and exchange trading. To the extent we engage in such transactions or transactions that become subject to such rules in the future, we will

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be required to comply or to take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception to the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception from such margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, rules that require end-users to post initial or variation margin could impact our liquidity and reduce cash available for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows.

The full impact of Dodd-Frank and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. Dodd-Frank and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts or reduce the availability of some derivatives to protect against risks that we encounter. If we limit our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material, adverse effect on us, our financial condition, our results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations on us is uncertain.

 

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate.  Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves.

 

It is not possible to measure underground accumulations of oil or natural gas in an exact way.  Oil and gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs.  Our independent reserve engineers do not independently verify the accuracy and completeness of information and data furnished by us.  In estimating our level of oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

 

•	future oil and natural gas prices;

•	production levels;

•	capital expenditures;

•	operating and development costs;

•	the effects of regulation;

•	the accuracy and reliability of the underlying engineering and geologic data; and

•	the availability of funds.

If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.  For example, if the SEC prices used for our December 31, 2016 reserve report had been 10% less per Bbl and 10% less per MMBtu, respectively, then the standardized measure of our estimated proved reserves as of December 31, 2016 would have decreased by $253 million , from $804 million , to $551 million .

Our standardized measure is calculated using unhedged oil prices and is determined in accordance with SEC rules and regulations.  Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.

The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories.  A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures.

The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves.  We base the current market value of estimated proved

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reserves on prices and costs in effect on the day of the estimate.  However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

•	the actual prices we receive for oil and natural gas;

•	our actual operating costs in producing oil and natural gas;

•	the amount and timing of actual production;

•	the amount and timing of our capital expenditures;

•	supply of and demand for oil and natural gas; and

•	changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and thus their actual present value.  In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the FASB Accounting Standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

Our actual production could differ materially from our forecasts.

From time to time, we provide forecasts of expected quantities of future oil and gas production.  These forecasts are based on a number of estimates, including expectations of production from existing wells.  In addition, our forecasts assume that none of the risks associated with our oil and gas operations summarized in this Item 1A occur, such as facility or equipment malfunctions, adverse weather effects, or significant declines in commodity prices or material increases in costs, which could make certain production uneconomical.

In 2016 , we depended on two customers for a substantial amount of our sales.  If these customers reduce the volumes of oil and natural gas that they purchase from us, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production.  In addition, if the parties to our purchase contracts default on these contracts, we could be materially and adversely affected.

In 2016 , two customers accounted for approximately 28% of our net sales revenues.  If these customers reduce the volumes of oil and natural gas that they purchase from us and we are not able to find new customers for our production, our revenue and cash available for distribution will decline.  In 2016 , Shell Trading accounted for approximately 17% of our net sales revenues and Plains Marketing accounted for approximately 11% of our net sales revenues.

Natural gas purchase contracts account for a significant portion of revenues relating to our Michigan, Indiana and Kentucky properties.  We cannot assure you that the other parties to these contracts will continue to perform under the contracts.  If the other parties were to default after taking delivery of our natural gas, it could have a material adverse effect on our cash flows for the period in which the default occurred.  A default by the other parties prior to taking delivery of our natural gas could also have a material adverse effect on our cash flows for the period in which the default occurred depending on the prevailing market prices of natural gas at the time compared to the contractual prices.

We have limited control over the activities on properties we do not operate.

On a net production basis, we operated approximately 89% of our production in 2016 .  We have limited ability to influence or control the operation or future development of the non-operated properties in which we have interests or the amount of capital expenditures that we are required to fund for their operation.  The success and timing of drilling development or production activities on properties operated by others depend upon a number of factors that are outside of our control, including the timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other participants, and selection of technology.  Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns on capital or lead to unexpected future costs.

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Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

There are a variety of operating risks inherent in our wells, gathering systems, pipelines and other facilities, such as leaks, explosions, fires, mechanical problems and natural disasters including earthquakes and tsunamis, all of which could cause substantial financial losses.  Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses.  The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.

We currently possess property and general liability insurance at levels that we believe are appropriate; however, we are not fully insured for these items and insurance against all operational risk is not available to us.  We are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance.  In addition, pollution and environmental risks generally are not fully insurable.  Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented.  Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage.  Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms.  Changes in the insurance markets after natural disasters and terrorist attacks have made it more difficult for us to obtain certain types of coverage.  There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses.  Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you.

If third party pipelines and other facilities interconnected to our wells and gathering and processing facilities become partially or fully unavailable to transport natural gas, oil or NGLs, our revenues and cash available for distribution could be adversely affected.

We depend upon third party pipelines and other facilities that provide delivery options to and from some of our wells and gathering and processing facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third party pipelines and other facilities become partially or fully unavailable to transport natural gas, oil or NGLs, or if the gas quality specifications for the natural gas gathering or transportation pipelines or facilities change so as to restrict our ability to transport natural gas on those pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

For example, in Florida, there are a limited number of alternative methods of transportation for our production, and substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in us having to find transportation alternatives, increased transportation costs, or involuntary curtailment of our oil production in Florida, which could have a negative impact on our future consolidated financial position, results of operations or cash flows.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the EPAct of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. In addition, Congress may enact legislation or FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalty liability.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

 

Our oil and natural gas exploration, production, gathering and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental

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authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, in California, there have been proposals at the legislative and executive levels in the past for tax increases which have included a severance tax as high as 12.5% on all oil production in California. Although the proposals have not passed the California Legislature, the State of California could impose a severance tax on oil in the future. We have significant oil production in California and while we cannot predict the impact of such a tax without having more specifics, the imposition of such a tax could have severe negative impacts on both our willingness and ability to incur capital expenditures in California to increase production, could severely reduce or completely eliminate our California profit margins and would result in lower oil production in our California properties due to the need to shut-in wells and facilities made uneconomic either immediately or at an earlier time than would have previously been the case.

 

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas we produce.

In response to findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. In December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. More recently, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The BLM finalized similar rules in November 2016 that limit methane emissions from new and existing oil and gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements, but it is unclear when and whether these rules will be implemented. Compliance with rules to control methane emissions will likely require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks and the increased frequency of maintenance and repair activities to address emissions leaks. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance with these new and proposed rules and could increase the cost of our operations. These new and proposed rules could result in increased compliance costs for the Partnership.

In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and many states have already established greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

California has been one of the leading states in adopting greenhouse gas emission reduction requirements, and has implemented a cap and trade program as well as mandates for renewable fuels sources. California's cap and trade program requires us to report our greenhouse gas emissions and essentially sets maximum limits or caps on total emissions of greenhouse gases from all industrial sectors that are or become subject to the program. This includes the oil and natural gas extraction sector of which we are a part. Our main sources of greenhouse gas emissions for our Southern California oil and gas operations are primarily attributable to emissions from internal combustion engines powering generators to produce electricity, flares for the disposal of excess field gas, and fugitive emission from equipment such as tanks and components. Under the California program, the cap declines annually from 2013 through 2020. In January 2017, California proposed to extend the cap and trade program beyond 2020 based on California’s greenhouse gas emission reduction requirements being extended through 2030. Under the cap and trade program, we are required to obtain authorizations for each metric ton of greenhouse gases that we emit, either in the form of allowances (each the equivalent of one ton of carbon dioxide) or qualifying offset credits. A portion of the allowance will be granted by the state, but any shortfall between the state-granted allowance and the facility's emissions will have to be addressed through the purchase of additional allowances either from the state or a third party. The availability of allowances will decline over time in accordance with the declining cap, and the cost to acquire such allowances may increase over time. However, we do not expect the cost to be material to our operations.

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The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements, or they could promote the use of alternative fuels and thereby decrease demand for the oil and gas that we produce. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. Such climatic events could have an adverse effect on our financial condition and results of operations.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could cause us to incur increased costs and experience additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand, and chemicals under pressure into dense subsurface rock formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel, and in February 2014 issued guidance for such activities. The EPA has also issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and finalized effluent limitation guidelines in June 2015 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing activities on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.

At the state level, several states, including California, Florida, Indiana, Michigan, Oklahoma, Texas and Wyoming, have adopted and/or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example, the California Department of Conservation rules, effective July 2015, require the approval of Well Stimulation Treatment Notices before starting stimulation treatment, disclosure of the fluids used and, adoption of groundwater monitoring and water management plans. They also govern resident notifications, storage and handling of fluids and well integrity. We do not expect any material adverse impact to result from these rules. In addition, several local jurisdictions in California and Florida have proposed or adopted various forms of moratoria or bans on hydraulic fracturing. In some cases, these measures include broad terms which, if enacted or upheld, could affect current operations. We do not believe that any current local proposal or measures will have a material adverse effect on the Partnership as a whole.

In December 2016, at the federal level, the EPA released its final report on the potential impacts of hydraulic fracturing on water resources. The EPA report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water sources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.

A change in the jurisdictional characterization of our gathering assets by federal, state or local regulatory agencies or a change in policy by those agencies with respect to those assets may result in increased regulation of those assets.

Failure to comply with federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production of, oil and natural gas could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you. Please read Part I—Item 1 “—Business—Environmental Matters and Regulation” and “—Business—Other Regulation of the Oil and Gas Industry” for a description of the laws and regulations that affect us.

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Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.

 

We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas exploration and production activities. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions that could require us to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.

 

Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to make distributions to you could be adversely affected. Please read Part I—Item 1 “—Business—Environmental Matters and Regulation” for more information.

Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions.

As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities, essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows. Cybersecurity attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

Risks Related to Our Structure

 

We may issue additional limited partner interests, including Common Units and Preferred Units, without your approval, which would dilute your existing ownership interests.

 

We may issue an unlimited number of limited partner interests of any type, including Common Units and Preferred Units, without the approval of our unitholders, including in connection with potential acquisitions of oil and gas properties or the reduction of debt, which would dilute your existing ownership interests. For example, in October 2014, we issued 18.3 million Common Units (or approximately 15% of our outstanding Common Units immediately prior to the issuance), including 4.3 million Common Units in connection with the Antares Acquisition. In November 2014, we issued approximately 71.5 million Common Units (or approximately 52% of our outstanding Common Units immediately prior to issuance) in connection with the QRE Merger. In May 2014, we issued 8.0 million Series A Preferred Units. In April 2015, we issued 46.7 million Series B Preferred Units (or approximately 18% of our outstanding Common Units immediately prior to issuance) in a private offering. We elected to pay distributions on the Series B Preferred Units 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). As of February 25, 2016, 49.4 million Series B Preferred Units were outstanding.

 

The issuance of additional Common Units, Preferred Units or other equity securities may have the following effects:

 

•	your proportionate ownership interest in us may decrease;

•	the relative voting strength of each previously outstanding Common Unit may be diminished; and

•	the market price of the Common Units may decline.

 

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Our partnership agreement limits our General Partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

 

Our partnership agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

 

•	provides that our General Partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were in the best interests of the Partnership;

•

generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the Board and not involving a vote of unitholders will not constitute a breach of our partnership agreement or of any fiduciary duty if they are on terms no less favorable to us than those generally provided to or available from unrelated third parties or are “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

•

provides that in resolving conflicts of interest where approval of the conflicts committee of the Board is not sought, it will be presumed that in making its decision the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

•	provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

 

Unitholders are bound by the provisions of our partnership agreement, including the provisions described above.

 

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our Common Units.

 

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board, cannot vote on any matter. In addition, solely with respect to the election of directors, our partnership agreement provides that (x) our General Partner and the Partnership will not be entitled to vote their units, if any, and (y) if at any time any person or group beneficially owns 20% or more of the outstanding Partnership securities of any class then outstanding and otherwise entitled to vote, then all Partnership securities owned by such person or group in excess of 20% of the outstanding Partnership securities of the applicable class may not be voted, and in each case, the foregoing units will not be counted when calculating the required votes for such matter and will not be deemed to be outstanding for purposes of determining a quorum for such meeting. Such Common Units will not be treated as a separate class of Partnership securities for purposes of our partnership agreement. Notwithstanding the foregoing, the Board may, by action specifically referencing votes for the election of directors, determine that the limitation set forth in clause (y) above will not apply to a specific person or group. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.

 

Our partnership agreement has provisions that discourage takeovers.

 

Certain provisions of our partnership agreement may have the effect of delaying or preventing a change in control. Our directors are elected to staggered terms. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove our General Partner. The provisions contained in our partnership agreement, alone or in combination with each other, may discourage transactions involving actual or potential changes of control.

 

Unitholders who are not “Eligible Holders” will not be entitled to receive distributions on or allocations of income or loss on their Common Units, and their Common Units will be subject to redemption.

 

In order to comply with U.S. laws with respect to the ownership of interests in oil and gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our Common Units. As used herein, an Eligible

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Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof and only for so long as the alien is not from a country that the United States federal government regards as denying similar privileges to citizens or corporations of the United States. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder will not be entitled to receive distributions or allocations of income and loss on their units and they run the risk of having their units redeemed by us at the lower of their purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner.

 

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions to you.

 

We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries. As a result, our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations. On November 30, 2015, we elected to suspend the distributions on our Common Units effective with the third monthly payment of the distribution relating to the third quarter of 2015. Given the filing of the Chapter 11 Cases and the impact that low commodity prices has had on our cash flows and operations, we did not reinstate distributions in 2016 and do not expect to reinstate distributions in 2017.

 

Unitholders may not have limited liability if a court finds that unitholder action constitutes participation in control of our business.

 

The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could have unlimited liability for our obligations if a court or government agency determined that:

 

•	we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•	your right to act with other unitholders to elect the directors of our General Partner, to remove or replace our General Partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted participation in “control” of our business.

 

Unitholders may have liability to repay distributions.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of Common Units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the Partnership that are known to such purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

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Tax Risks to Unitholders

 

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then the value of our units may be substantially reduced.

 

A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations we believe that we satisfy the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.

 

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and would likely pay state income tax at varying rates. Any distributions to you would generally be taxed again as corporate distributions and no income, gains, losses, or deductions would flow through to you. Because a tax would be imposed on us as a corporation, our treatment as a corporation may result in a substantial reduction in the value of our units.

 

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such tax on us by any such state may result in a substantial reduction in the value of our units.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

 

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to qualify as a partnership for federal income tax purposes. However, any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.

If the IRS contests the federal income tax positions we take, the market for our units may be adversely impacted, and the cost of any IRS contest may substantially reduce the value of our units.

 

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs may substantially reduce the value of our units.

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If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, which would reduce our cash available to service our debt and distribute to our unitholders and may substantially reduce the value of our units.

Pursuant to the Bipartisan Budget Act of 2015, for taxable years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes due (including applicable penalties and interest) as a result of an audit. To the extent possible under the new rules, our General Partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedules K-1 to our unitholders with respect to an audited and adjusted return. Although our General Partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available to service our debt and for distribution to our unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas and oil extraction may be imposed, as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation including changes to cost recovery rules and to the deductibility of interest expense may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on the Company’s financial position, results of operations and cash flows.

You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

 

Because you will be treated as a partner to whom we will allocate a share of our taxable income which could be different than the cash we distribute, you may be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, even if you receive no cash distribution from us. You may not receive a cash distribution from us equal to your share of our taxable income or even equal to the actual tax liability resulting from that income.

For a discussion regarding the tax risks of cancellation of indebtedness income to the holders of our common units, please read “—Risks Related to the Chapter 11 Cases—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.”

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  Tax gain or loss on the disposition of our units could be more or less than expected.

 

If you sell your units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those units. Because distributions to you in excess of your allocable share of our net taxable income decrease your tax basis in your units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. In addition, because the amount realized will include your share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

A substantial portion of the amount realized from the sale of your units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture.  Thus, you may recognize both ordinary income and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in the units.  Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.  In the taxable period in which you sell your units, you may recognize ordinary income from our allocations of income and gain to you prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them.

 

Investment in units by tax-exempt entities, including individual retirement accounts (“IRAs”), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Our partnership agreement generally prohibits non-U.S. persons from owning our units. However, if non-U.S. persons own our units, distributions to such non-U.S. persons will be subject to withholding taxes imposed at the highest tax rate applicable to such non-U.S. person, and each non-U.S. person will be required to file U.S. federal income tax returns and pay tax on its share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our units.

 

We treat each purchaser of our Common Units as having the same tax benefits without regard to the Common Units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the Common Units.

 

Due to a number of factors, including our inability to match transferors and transferees of Common Units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of Common Units and could have a negative impact on the value of our Common Units or result in audit adjustments to our unitholders' tax returns.

 

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

 

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular Common Unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the General Partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

 

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and

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the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

 

We will be considered to have constructively terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest are counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders receiving two Schedules K-1) for one calendar year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder's taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine in a timely manner that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, the partnership may be permitted to provide only a single Schedule K-1 to its unitholders for the tax year in which the termination occurs.

 

You may be subject to state and local taxes and return filing requirements in jurisdictions where you do not live as a result of investing in our units.

In addition to federal income taxes, you may be subject to return filing requirements and other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. Further, you may be subject to penalties for failure to comply with those return filing requirements. We currently conduct business and own assets in multiple states. Each of these states other than Florida, Texas and Wyoming currently imposes a personal income tax on individuals, and all of these states impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may conduct business or own assets in additional states that impose a personal income tax. It is the responsibility of each unitholder to file all U.S. federal, state and local tax returns.

Item 1B. Unresolved Staff Comments.

None.

 

Item 2. Properties.

 

The information required to be disclosed in this Item 2 is incorporated herein by reference to Part I—Item 1 “—Business.”

Item 3. 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 pending legal proceedings or know of any such procedures contemplated by government authorities. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. For information relating to the Chapter 11 Cases, see Item 1 “—Business” — “Chapter 11 Cases,” which we incorporate herein by reference.

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

Our Common Units traded on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “BBEP” until May 25, 2016, at which time they were removed from trading on NASDAQ, and began trading on the OTC Pink under the symbol “BBEPQ”. For more information relating to the delisting of our Common Units, see Part I—Item 1A “—Risk Factors”—Risks Related to Our Business—The liquidity of our Common Units could be adversely affected because we are trading on the OTC Pink.” As of December 31, 2016 , based upon information received from our transfer agent and brokers and nominees, we had approximately 65,000 common unitholders of record.

The following table sets forth high and low intraday sales prices per Common Unit for the periods indicated. The last reported sales price for our Common Units on March 7, 2017 was $0.14 per unit.

		Unit Price Range
Quarter		High				Low
2016
Fourth Quarter		$	0.58			$	0.06
Third Quarter		$	0.12			$	0.05
Second Quarter		$	0.70			$	0.05
First Quarter		$	1.25			$	0.46
2015
Fourth Quarter		$	2.95			$	0.47
Third Quarter		$	4.76			$	1.95
Second Quarter		$	6.87			$	4.55
First Quarter		$	9.40			$	4.55

Distributions on Common Units

On November 30, 2015, we elected to suspend distributions on our Common Units effective with the third monthly payment of the distribution relating to the third quarter of 2015. Given the filing of the Chapter 11 Cases and the impact that low commodity prices has had on our cash flows and operations, we did not reinstate distributions in 2016 and do not expect to reinstate distributions in 2017. See Item 7 “—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—DIP Credit Agreement” and Note 9 to the consolidated financial statements in this report.

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The following table provides a summary of Common Unit distributions related to and declared during the year ended December 31, 2015. There were no Common Unit distributions declared or paid during the year ended December 31, 2016.

Thousands of dollars, except per unit amounts		Cash Distributions
Period		Total (a)				Per Common Unit				Declaration Date			Payment Date
2015
December 2015		(b)				—				—			—
November 2015		(b)				—				—			—
October 2015		(b)				—				—			—
September 2015		(b)				—				—			—
August 2015		$	8,827			$	0.04166			10/30/2015			11/13/2015
July 2015		8,825				0.04166				10/1/2015			10/16/2015
June 2015		8,823				0.04166				8/27/2015			9/11/2015
May 2015		8,820				0.04166				7/31/2015			8/14/2015
April 2015		8,818				0.04166				7/1/2015			7/17/2015
March 2015		8,816				0.04166				5/28/2015			6/12/2015
February 2015		8,790				0.04166				4/24/2015			5/15/2015
January 2015		$	8,787			$	0.04166			4/1/2015			4/17/2015
2014
December 2014		$	17,570			$	0.0833			2/24/2015			3/13/2015
November 2014		17,571				0.0833				1/27/2015			2/13/2015
October 2014		$	17,571			$	0.0833			1/2/2015			1/16/2015
(a)   Does not include distribution equivalents paid under our long-term incentive plans.
(b) Distributions on Common Units were suspended by the Board effective as of November 30, 2015. Thus, there were no Common Unit distributions payable with respect to 2016, the fourth quarter of 2015 and the third monthly payment of the distribution attributable to the third quarter of 2015.

Distributions on Preferred Units

On April 8, 2015, we issued in a private offering $350 million of Series B Preferred Units to EIG Redwood Equity Aggregator, LP (“EIG Equity”), ACMO BBEP Corp. (“ACMO”) and certain other purchasers at an issue price of $7.50 per unit. The Series B Preferred Units rank senior to the Common Units and on parity with the Series A Preferred Units with respect to the payment of distributions. We have the option through April 2018 to pay distributions on our Series B Preferred Units in kind by issuing additional Series B Preferred Units in lieu of cash (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) and we have paid such distributions in kind since the Series B Preferred Units were issued. During the three months ended March 31, 2016, we declared distributions on our Series B Preferred Units in the form of 0.8 million Series B Preferred Units and 0.2 million Common Units. During the twelve months ended December 31, 2015, we declared distributions on our Series B Preferred Units in the form of 2.2 million Series B Preferred Units and 0.4 million Common Units.

On May 21, 2014, we sold 8.0 million Series A Preferred Units in a public offering at a price of $25.00 per unit. The Series A Preferred Units rank senior to our Common Units with respect to the payment of distributions. Distributions on Series A Preferred Units are cumulative from the date of original issue and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our Board out of legally available funds for such purpose. Through April 30, 2016, we paid 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, totaling $5.5 million during the four months ended April 30, 2016 and $16.5 million during the twelve months ended December 31, 2015.

On April 14, 2016, we elected to suspend the declaration of any further distributions on our Series B Preferred Units and Series A Preferred Units (see Note 14 to the consolidated financial statements in this report for further information).

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Equity Compensation Plan Information

See Part III—Item 12 “—Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding securities authorized for issuance under equity compensation plans.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

There were no purchases of our Common Units by us or any affiliated purchasers during the fourth quarter of 2016 .

Common Unit Performance Graph

The graph below compares our cumulative total unitholder return on our Common Units over the five years ended December 31, 2016 with the cumulative total returns over the same period of the Russell 2000 index and the Alerian MLP index. The graph assumes that the value of the investment in our Common Units, in the Russell 2000 index and in the Alerian MLP index was $100 on December 31, 2011 . Cumulative return is computed assuming reinvestment of dividends.

Comparison of Cumulative Total Return among the Partnership, the Russell 2000 Index and the Alerian MLP Index

The information in this report appearing under the heading “Common Unit Performance Graph” is being furnished pursuant to Item 2.01(e) of Regulation S-K and shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.

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Item 6. Selected Financial Data.

 

We have derived the selected financial data set forth in the following table for each of the years ended December 31, 2016 , 2015 and 2014 , with the exception of consolidated balance sheet data for the year ended December 31, 2014, from our audited consolidated financial statements appearing elsewhere in this report. We derived the financial data for the years ended December 31, 2013 and 2012 , as well as consolidated balance sheet data for the year ended December 31, 2014 , from our prior year audited consolidated financial statements, which are not included in this report.

We filed the Chapter 11 Petitions on May 15, 2016. See Note 2 to the consolidated financial statements in this report for more information regarding the Chapter 11 Cases. No trustee has been appointed and we continue to manage ourselves and our affiliates and operate our businesses as “debtors in possession” subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

In March 2016, we completed the Mid-Continent Sale for net proceeds of $11.9 million . The sale included most of the Mid-Continent properties acquired in the QRE Merger in 2014, effective January 1, 2016.

In March 2015, we completed the CO ₂ Acquisition for a purchase price of $70.5 million.

In October 2014, we completed the Antares Acquisition for 4.3 million Common Units and $50.0 million in cash. In November 2014 we acquired QRE in exchange for approximately 71.5 million Common Units and $350 million in cash, and the assumption of approximately $1.1 billion of QRE debt.

In July 2013, we completed the acquisition of principally oil properties and midstream assets located in Oklahoma, New Mexico and Texas, certain CO ₂ supply contracts, certain oil swaps and interests in certain entities from Whiting Oil and Gas Corporation for approximately $845 million and the acquisition of additional interests in the Oklahoma Panhandle for an additional $30 million. In December 2013, we completed acquisitions of oil and natural gas properties located in the Permian Basin in Texas from CrownRock, L.P. for approximately $282 million and the acquisition of additional interests in certain of the acquired assets in the Permian Basin from other sellers for an additional $20 million.

In June 2012, we completed the acquisition of oil properties located in Park County in the Big Horn Basin of Wyoming from Legacy Energy, Inc., a wholly-owned subsidiary of NiMin Energy Corp., for approximately $95 million. In July 2012, we completed acquisitions of oil and natural gas properties located in the Permian Basin in Texas from Element Petroleum, LP and CrownRock, L.P. for approximately $148 million and $70 million, respectively. In November 2012, we completed the acquisition of principally oil properties in the Belridge Field in the San Joaquin Basin in Kern County, California from American Energy Operations, Inc. for approximately $38 million in cash and approximately 3 million Common Units. In December 2012, we completed the acquisition of oil and natural gas properties located in the Permian Basin in Texas from CrownRock, L.P., Lynden USA Inc. and Piedra Energy I, LLC for approximately $164 million, $25 million and $10 million, respectively. Effective April 1, 2012, our ownership interest in properties at two California fields decreased from approximately 95% to approximately 62%.

See Note 4 to the consolidated financial statements in this report for further details about our dispositions and acquisitions in 2016 , 2015 and 2014 .

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You should read the following selected financial data in conjunction with Part II—Item 7 “—Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes in this report.

		Year Ended December 31,
Thousands of dollars, except per unit amounts		2016				2015				2014				2013				2012
Statement of Operations Data:
Oil, natural gas and NGL sales		$	504,254			$	645,272			$	855,820			$	660,665			$	413,867
(Loss) gain on commodity derivative instruments, net		(53,091		)		438,614				566,533				(29,182		)		5,580
Other revenue, net		17,842				24,829				7,616				3,175				3,548
Total revenue		469,005				1,108,715				1,429,969				634,658				422,995
Impairment of oil and natural gas properties		283,270				2,377,615				149,000				54,373				12,313
Impairment of goodwill		—				95,947				—				—				—
Operating (loss) income		(576,807		)		(2,376,582		)		545,967				44,276				21,700
Net (loss) income		(816,133		)		(2,583,013		)		421,316				(43,671		)		(40,739		)
Less: Net (loss) income attributable to noncontrolling interest		(1,182		)		326				(17		)		—				62
Net (loss) income attributable to the partnership		$	(814,951	)		$	(2,583,339	)		$	421,333			$	(43,671	)		$	(40,801	)
Basic net (loss) income per unit		$	(3.90	)		$	(12.39	)		$	3.04			$	(0.43	)		$	(0.56	)
Diluted net (loss) income per unit		$	(3.90	)		$	(12.39	)		$	3.02			$	(0.43	)		$	(0.56	)
Cash Flow Data:
Net cash provided by operating activities		$	174,460			$	436,705			$	357,755			$	257,166			$	191,782
Net cash used in investing activities		(72,428		)		(274,003		)		(837,004		)		(1,465,805		)		(697,159		)
Net cash (used in) provided by financing activities		(41,372		)		(164,866		)		489,419				1,206,590				504,556
Balance Sheet Data (at period end):
Cash		$	71,124			$	10,464			$	12,628			$	2,458			$	4,507
Other current assets		559,632				577,863				588,080				114,604				109,158
Net property, plant and equipment		3,413,646				3,932,882				6,454,201				3,915,376				2,711,893
Other assets		71,006				314,178				583,425				163,844				89,936
Total assets		$	4,115,408			$	4,835,387			$	7,638,334			$	4,196,282			$	2,915,494
Current liabilities		$	1,354,200			$	318,006			$	361,556			$	182,889			$	115,240
Liabilities subject to compromise		1,879,176				—				—				—				—
Long-term debt		3,094				2,830,342				3,247,160				1,889,675				1,100,696
Other long-term liabilities		272,911				281,144				263,442				133,898				110,022
Partners' equity		599,016				1,398,571				3,759,291				1,989,820				1,589,536
Noncontrolling interest		7,011				7,324				6,885				—				—
Total liabilities and partners' equity		$	4,115,408			$	4,835,387			$	7,638,334			$	4,196,282			$	2,915,494
Cash distributions declared per unit outstanding:		$	—			$	0.3333			$	1.7581			$	1.9125			$	1.8300

The following table presents a non-GAAP financial measure, “Adjusted EBITDA,” which we use in our business. This measure is not calculated or presented in accordance with US GAAP.

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We believe the presentation of Adjusted EBITDA provides useful information to investors to evaluate the operations of our business excluding certain items and for the reasons set forth below. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with US GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

We use Adjusted EBITDA to assess:

•	the financial performance of our assets, without regard to financing methods, capital structure or historical cost basis;

•	our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure;

•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities; and

•	the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and, historically, to pay distributions.

The following table presents a reconciliation of Adjusted EBITDA to net income (loss) attributable to the Partnership and cash flows provided by operating activities, our most directly comparable US GAAP financial performance measures, for each of the periods indicated.

		Year Ended December 31,
Thousands of dollars		2016				2015				2014				2013				2012
Reconciliation of consolidated net income (loss) to Adjusted EBITDA:
Net (loss) income attributable to the partnership		$	(814,951	)		$	(2,583,339	)		$	421,333			$	(43,671	)		$	(40,801	)
Loss (gain) on commodity derivative instruments (a)		53,091				(438,614		)		(566,533		)		29,182				(5,580		)
Commodity derivative instrument settlements (b)(c)(d)		612,708				499,985				27,825				8,083				87,605
Settlements on terminated commodity derivative (b) instruments		(438,490		)		—				—				—				—
Depletion, depreciation and amortization		318,528				460,047				291,709				216,495				137,252
Impairment of oil and natural gas properties		283,270				2,377,615				149,000				54,373				12,313
Impairment of goodwill		—				95,947				—				—				—
Interest expense, net of capitalized interest		148,214				203,027				126,960				87,067				61,206
Loss (gain) on interest rate swaps (e)		2,021				2,691				(490		)		—				1,101
(Gain) loss on sale of assets		(11,203		)		(8,864		)		663				(2,015		)		486
Income tax (benefit) expense		(1,708		)		1,527				(73		)		905				84
Unit based compensation		24,693				26,805				23,387				19,955				22,184
Reorganization items, net		91,156				—				—				—				—
Adjusted EBITDA		$	267,329			$	636,827			$	473,781			$	370,374			$	275,850
(a) We enter into certain derivative instrument contracts such as put options that require the payment of premiums at contract inception. Loss (gain) on commodity derivative instruments includes the reduction of premium value for derivative instruments over time. Our calculation of Adjusted EBITDA does not include premiums paid for derivative instruments at contract inception as these payments pertain to future contract settlement periods.
(b) Includes net cash settlements on derivative instruments (including contracts terminated in connection with the filing of the Chapter 11 Cases):
- Oil settlements received (paid) of:		$	556,529			$	431,073			$	18,230			$	(36,183	)		$	3,855
- Natural gas settlements received of:		56,179				68,912				9,595				44,266				83,750
(c) Includes premiums deferred and paid at the time of derivative contract settlements each period of:		5,372				97				657				892				—
(d) Excludes premiums paid at contract inception related to those derivative contracts that settled during the periods of:		9,123				6,672				8,494				4,893				859
(e) Includes settlements paid on interest rate derivatives including terminated interest rate derivatives of:		6,146				5,751				1,019				—				5,469

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		Year Ended December 31,
Thousands of dollars		2016				2015				2014				2013				2012
Reconciliation of net cash flows from operating activities to Adjusted EBITDA:
Net cash provided by operating activities		$	174,460			$	436,705			$	357,755			$	257,166			$	191,782
Increase in assets (net of liabilities) relating to operating activities		(68,628		)		16,369				(4,057		)		32,105				22,492
Interest expense, net of capitalized interest (a)		124,093				183,852				120,143				80,617				61,807
Cash reorganization items		36,727				—				—				—				—
Income from equity affiliates, net		593				104				(178		)		(55		)		(487		)
Other		—				—				—				(21		)		(82		)
Income taxes		(634		)		258				101				562				400
Non-controlling interest		1,182				(326		)		17				—				(62		)
Gain on marketable securities		(464		)		(135		)		—				—				—
Adjusted EBITDA		$	267,329			$	636,827			$	473,781			$	370,374			$	275,850

(a) Includes settlement payments on interest rate swaps, and excludes amortization of debt issuance costs and net premium on senior notes.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the financial statements and related notes included elsewhere in this report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are discussed in “Risk Factors” contained in Part I—Item 1A of this report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Information” in the front of this report.

Overview

We are an independent oil and gas partnership and are focused on the exploitation and development of oil, NGL and natural gas properties in the United States. Our long-term goals have been to manage our current and future oil, NGL and natural gas producing properties for the purpose of generating cash flow. Our assets consist primarily of producing and non-producing oil, NGL and natural gas reserves located in the following producing areas: (i) the Permian Basin in Texas and New Mexico, (ii) Midwest (Michigan, Indiana, and Kentucky), (iii) Ark-La-Tex (Arkansas, Louisiana and East Texas), (iv) Mid-Continent (Oklahoma), (v) the Rockies (Wyoming and Colorado), (vi) California, and (vii) Southeast (Florida and Alabama).

Prior to the decline in commodity prices and the filing of the Chapter 11 Cases, our core investment strategy included the following principles:

•	acquire long-lived assets with low-risk exploitation and development opportunities;

•	use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;

•	reduce cash flow volatility through commodity price and interest rate derivatives; and

•	maximize asset value and cash flow stability through our operating and technical expertise.

In response to the steep and continued decline in commodity prices during 2014, 2015 and the first part of 2016, we adjusted our business strategies by suspending distributions to common and preferred unitholders, significantly reducing our capital budget, cutting operating and overhead costs, scaling back derivative activity and reducing our acquisition expectations. Sustained low commodity prices eventually led to the filing of the Chapter 11 Petitions, as described below.

Chapter 11 Cases

On May 15, 2016, the Debtors filed the Chapter 11 Petitions. The Chapter 11 Cases are being administered jointly under the caption “In re Breitburn Energy Partners LP, et al.”, Case No. 16-11390 . The Debtors include the Partnership, Breitburn Management, BOGP, BOLP, Breitburn Finance, Breitburn GP, Breitburn Sawtelle LLC, Breitburn Oklahoma LLC, Phoenix Production Company, QR Energy, LP, QRE GP, LLC, QRE Operating, LLC, Breitburn Transpetco LP LLC, Breitburn Transpetco GP LLC, Transpetco Pipeline Company, L.P., Terra Energy Company LLC, Terra Pipeline Company LLC, Breitburn Florida LLC, Mercury Michigan Company, LLC, Beaver Creek Pipeline, L.L.C., GTG Pipeline LLC and Alamitos Company. No trustee has been appointed and we continue to manage the Partnership and our affiliates and operate our businesses as “debtors in possession” subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. To assure ordinary course operations, we received approval from the Bankruptcy Court on a variety of “first day” motions, including motions that authorize us to maintain our existing cash management system, to secure debtor-in-possession financing and other customary relief. In August 2016, the Bankruptcy Court entered a final order approving the DIP Credit Agreement. In December 2016, the Bankruptcy Court entered an order approving an extension of the DIP Credit Agreement to June 30, 2017.

The commencement of the Chapter 11 Cases resulted in the acceleration of the Debtors’ obligations under the RBL Credit Agreement and the indentures governing the Senior Secured Notes and Senior Unsecured Notes. Any efforts to enforce such obligations are automatically stayed as a result of the filing of the Chapter 11 Petitions and the holders’ rights of enforcement in respect of these obligations are subject to the applicable provisions of the Bankruptcy Code. We are making adequate protection payments with respect to the lenders under the RBL Credit Agreement consisting of the payment of interest (at the default rate) and the payment of all reasonable fees and expenses of professionals retained by our lenders, as provided for in the RBL Credit Agreement. We are also making adequate protection payments with respect to the Senior Secured Notes in the form of the payment of all reasonable fees and expenses of professionals retained by the holders of the Senior Secured Notes.

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The commencement of the Chapter 11 Cases constituted an event of default under our commodity and interest rate derivative instruments, resulting in a termination right by our counterparties. All of our counterparties exercised this termination right during the year ended December 31, 2016, and the terminated transactions are reflected in accounts and other receivables, net and other current liabilities on the consolidated balance sheet at December 31, 2016. The termination of these transactions has since exposed our cash flows to fluctuations in commodity prices. The terminated derivative instruments resulted in estimated settlements receivable and payable of $460.0 million and $4.1 million , respectively, at December 31, 2016 .

We have incurred and will continue to incur significant costs associated with the reorganization in connection with the Chapter 11 Cases. These costs are being expensed as incurred, and are expected to significantly affect our results. Reorganization items, net on the consolidated statements of operations include professional expenses, gains and losses that are the result of the reorganization and restructuring of the business, and deferred and unamortized financing costs related to the Senior Notes. Reorganization items, net totaled $91.2 million for the year ended December 31, 2016 .  See Note 2 to the consolidated financial statements in this report for additional details.

Effect of Filing on Creditors and Unitholders

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 $46.6 million in interest payments due with respect to our Senior Unsecured Notes, with such interest payments due on April 15, 2016 and subject to a 30-day grace period. As a consequence of the commencement of the Chapter 11 Cases, such interest payments have not been made.

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities and post-petition liabilities must be satisfied in full before the holders of our Series A Preferred Units, Series B Preferred Units and Common Units are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or unitholders, if any, will not be determined until confirmation and implementation of a plan of reorganization. No assurance can be given as to what distributions, if any, will be made to each of these constituencies or the nature thereof. If certain requirements of the Bankruptcy Code are met, a plan of reorganization can be confirmed notwithstanding its rejection or deemed rejection by the holders of our Series A Preferred Units, Series B Preferred Units and Common Units and notwithstanding the fact that such holders do not receive or retain any property on account of their equity interests under the plan. Because of such possibilities, the value of our securities, including our Series A Preferred Units, Series B Preferred Units and Common Units, is highly speculative. There can be no assurance that the holders of our Series A Preferred Units, Series B Preferred Units and Common Units will retain any value under a plan of reorganization. We believe it is highly likely that our Series A Preferred Units, Series B Preferred Units and Common Units will be canceled in our Chapter 11 Cases and that the holders thereof will not receive any distribution on account of their holdings.

Executory Contracts . Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired

lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory

contract or unexpired lease, but may give rise to a pre-petition general unsecured claim for damages caused by such deemed

breach. The assumption of an executory contract or unexpired lease generally requires the Debtors to cure existing monetary

defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. By order of the Bankruptcy Court dated December 12, 2016, the Debtors assumed all of their executory contracts and unexpired leases related to their oil and gas operations to the extent such contracts and leases constituted commercial property leases under the purview of the Bankruptcy Code.

Process for Plan of Reorganization . In order to successfully emerge from Chapter 11, the Debtors will need to obtain confirmation by the Bankruptcy Court of a plan of reorganization that satisfies the requirements of the Bankruptcy Code. A plan of reorganization generally provides for how pre-petition obligations and equity interests will be treated in satisfaction and discharge thereof, and provides for the means by which the plan of reorganization will be implemented.

Fresh Start Accounting . We may be required to adopt fresh start accounting upon emergence from Chapter 11. Adopting fresh start accounting would result in the allocation of the reorganization value to individual assets based on their estimated fair values. The enterprise value of the equity of the emerging company is based on several assumptions and inputs contemplated in the future projections of the plan of reorganization and are subject to significant uncertainties. We currently cannot estimate the potential financial effect of fresh start accounting on our consolidated financial statements

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upon the emergence from Chapter 11, although we would expect to recognize material adjustments upon implementation of fresh start accounting guidance upon emergence pursuant to a plan of reorganization. The assumptions for which there is a reasonable possibility of material impact affecting the reorganization value include management’s assumptions and capital expenditure plans related to the estimation of our oil and gas reserves.

 

Distributions

        

During the four months ended April 30, 2016, we paid cumulative distributions in cash on the Series A Preferred Units on a monthly basis at a monthly rate of $0.171875 per unit, totaling $5.5 million . During the four months ended April 30, 2016, we paid-in-kind cumulative distributions on the Series B Preferred Units on a monthly basis at a monthly rate of 0.006666 Series B Preferred Units per unit, totaling 0.8 million Series B Preferred Units and 0.2 million Common Units.

On April 14, 2016, we elected to suspend the declaration of any further distributions on our Preferred Units. Because the Partnership failed to make any distribution on the Series B Preferred Units as required under the partnership agreement, the annual distribution rate was increased by 2.00% effective as of such date until the date on which all required distributions have been made. We accrued for earned but undeclared distributions on each series of Preferred Units for the period from April 15, 2016 to May 15, 2016, the filing date of the Chapter 11 Petitions. As of December 31, 2016 , accrued but unpaid distributions of $7.0 million were reflected as liabilities subject to compromise.

During the year ended December 31, 2016, we recognized $11.7 million of 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.

Capital Expenditures

In 2016 , our oil and gas capital expenditures, including capitalized engineering costs and excluding expenditures to acquire properties, totaled approximately $65 million , compared with approximately $209 million in 2015 . In 2016 , we spent approximately $19 million in Ark-La-Tex, $15 million in Mid-Continent, $14 million in the Permian Basin, $8 million in California, $5 million in Southeast, $3 million in Midwest and $1 million in the Rockies. In 2016, we drilled or participated in 25 new gross productive wells, 17 gross recompletions and completed 53 workovers. Primarily due to our reduced capital spending and natural field declines, our 2016 production was 18,279 MBoe, which was 9% lower than our 2015 production.

    

2017 Outlook

In 2016, oil and natural gas prices continued to remain low and volatile. In 2016, the monthly average WTI posted price ranged from a low of $30 per Bbl in February to a high of $52 per Bbl in December , and the monthly average Henry Hub posted price ranged from a low of $1.73 per MMBtu in March to a high of $3.59 MMBtu in December . Declines in commodity prices that began at the end of 2014 led us to file for relief under the Bankruptcy Code, as described above. We have been managing, and plan to continue to evaluate, our operating activities and liquidity carefully in light of the uncertainty regarding future oil and natural gas prices and the Chapter 11 Cases. We do not expect increased production as a result of our 2017 capital program to entirely offset production declines; we expect overall decreases to our production in 2017, without taking into account acquisitions, divestitures or further modifications to our capital and operating plan based on price changes through 2017.

 

We expect our full year 2017 oil and gas capital spending program to be approximately $100 million , including capitalized engineering costs, compared with approximately $65 million in 2016 , approximately $209 million in 2015 and approximately $389 million in 2014. The increase in capital expenditures primarily reflects higher CO ₂ purchases for our Postle field in Mid-Continent to counteract production declines and our continued development in Ark-La-Tex and the Permian Basin. We anticipate that 60% of our total capital spending will be focused on drilling and rate-generating projects and CO ₂ purchases primarily in our core operating areas of Ark-La-Tex, the Permian Basin and Mid-Continent that are designed to increase or add to production or reserves. We plan to drill 20 operated and non-operated wells primarily in Ark-La-Tex and the Permian Basin.

Operational Focus

We use a variety of financial and operational measures to assess our performance. Among these measures are the following: volumes of oil and natural gas produced, amount of reserves replaced, realized prices, operating expenses, general and administrative expenses (“G&A”) and Adjusted EBITDA.

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As of December 31, 2016 , our total estimated proved reserves were 205.3 MMBoe, of which approximately 55% was oil, 9% was NGLs and 36% was natural gas. As of December 31, 2015 , our total estimated proved reserves were 239.3 MMBoe, of which approximately 54% was oil, 8% was NGLs, and 38% was natural gas. The change to our total estimated proved reserves from December 31, 2015 to December 31, 2016 was a net decrease of 34.0 MMBoe, and included negative reserve revisions of 34.4 MMBoe, 18.3 MMBoe of production and a 2.0 MMBoe sale of reserves-in-place, partially offset by 20.6 MMBoe in extensions and discoveries. The reserve revisions in 2016 were primarily the result of a 22.0 MMBbl decrease in oil reserves and a 1.4 MMBbl decrease in NGL reserves, driven primarily by a decrease in oil and NGL prices and a 66.3 Bcf decrease in natural gas reserves primarily due to a decrease in natural gas prices. The unweighted average first-day-of-the-month oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2016 were $42.75 per Bbl of oil for the WTI spot price and $2.48 per MMBtu of natural gas for the Henry Hub spot price, compared to $50.28 per Bbl of oil for the WTI spot price and $2.59 per MMBtu of natural gas for the Henry Hub spot price in 2015 .

Our revenues and net income are highly sensitive to oil, NGL and natural gas prices. Our operating expenses are also highly correlated to oil prices, and as oil prices rise and fall, our operating expenses will directionally rise and fall. Significant factors that will impact near-term commodity prices include global supply and demand for oil and natural gas, political developments in oil producing countries including, without limitation, the extent to which members of OPEC and other oil exporting nations are able to manage oil supply through export quotas, and variations in key North American natural gas and refined products supply and demand indicators.

In 2016 , the WTI spot price averaged approximately $43 per Bbl, compared with approximately $48 per Bbl a year earlier. During 2016 , the WTI monthly average ranged from a high of $52 per Bbl in December to a monthly average low of $30 per Bbl in February . In 2015 , prices ranged from a monthly average high of $60 per Bbl in June to a monthly average low of $37 per Bbl in December . As of February 28, 2017 , the WTI spot price during 2017 has averaged $53 per Bbl. Historically, there has been a strong relationship between changes in NGL and crude oil prices. NGL prices are correlated to North American supply and petrochemical demands. Lower crude oil prices may not only decrease our revenues, but may also reduce the amount of crude oil that we can produce economically and therefore potentially lower our crude oil reserves.

Prices for natural gas in many markets are aligned both with supply and demand conditions in their respective regional markets and with the overall U.S. market. Natural gas prices are also typically higher during the winter period when demand for heating is greatest in the U.S. From January 2014 to February 2017 , the natural gas spot prices at Henry Hub have ranged from a high of $8.15 per MMBtu in February 2014 to a low of $1.49 per MMBtu in March 2016. During 2016 , the natural gas spot price at Henry Hub ranged from a high of $3.80 per MMBtu to a low of $1.49 per MMBtu, with the monthly average ranging from a high of $3.59 per MMBtu in December to a low of $1.73 per MMBtu in March , and averaged approximately $2.51 per MMBtu for the year. During 2015 , the natural gas spot price at Henry Hub ranged from a high of $3.32 per MMBtu to a low of $1.63 per MMBtu, and averaged approximately $2.62 per MMBtu. As of February 28, 2017 , the natural gas spot price at Henry Hub for 2017 has averaged approximately $3.10 per MMBtu.

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. Lower commodity prices could also cause us to recognize further asset impairments.

The continued volatility and sustained low 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.  Changing commodity prices, whether lower or higher, can have a significant impact on the volumetric quantities of our proved reserve portfolio. 

In evaluating our production operations, we frequently monitor and assess our operating expenses per Boe produced. These measures allow us to better evaluate our operating efficiency and are used in reviewing the economic feasibility of a development project or potential acquisition.

Operating expenses are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses. A majority of our operating cost components are variable and increase or decrease along with our levels of production. For example, we incur power costs in connection with various production related activities such as pumping

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to recover oil and gas, separation and treatment of water produced in connection with our oil and gas production and re-injection of water produced into the oil producing formation to maintain reservoir pressure. Although these costs typically vary with production volumes, they are driven not only by volumes of oil and gas produced but also volumes of water produced. Consequently, fields that have a high percentage of water production relative to oil and gas production, also known as a high water cut, will experience higher levels of power costs for each Boe produced. Certain items, however, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased expenses in periods during which they are performed. Our operating expenses are highly correlated to oil prices, and we can experience upward pressure on material and service costs depending on how oil prices change. These costs include specific expenditures such as lease fuel, electricity, drilling services and severance and property taxes. Pre-tax lease operating expenses, including processing fees and excluding unit-based compensation, were $16.24 per Boe in 2016 and $19.02 per Boe in 2015 .

Production taxes vary by state. All states in which we operate impose ad valorem taxes on our oil and gas properties. Various states regulate the drilling for, and the production, gathering and sale of, oil, NGLs and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Currently, Alabama, Arkansas, Florida, Indiana, Kansas, Kentucky, Louisiana, Michigan, New Mexico, Oklahoma, Texas, and Wyoming impose severance taxes on producers at rates ranging from 1% to 13% of the value of the gross product extracted. Wyoming and Oklahoma wells that reside on Native American or federal land are subject to an additional tax of 8.5% and 8.0% , respectively. Florida sulfur sales are subject to a tax of $6.13 per long ton. California does not currently impose a severance tax; rather it imposes an ad valorem tax based in large part on the value of the mineral interests in place. See Part I—Item 1A “—Risk Factors” — “Risks Related to Our Business — We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations” in this report.

We recorded non-cash oil and natural gas asset impairment charges of $283.3 million during 2016 , and non-cash oil and natural gas asset impairments of $2.4 billion during 2015 . A further decline in future commodity prices could result in additional oil and gas impairment charges. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future production, market outlook on forward commodity prices, operating and development costs and discount rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward commodity prices alone could potentially result in impairment. Given the number of assumptions involved in the estimates, estimates as to sensitivities to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable. Favorable changes to some assumptions could have increased the undiscounted cash flows thus further avoiding the need to impair any assets in this period, whereas other unfavorable changes could have caused an unknown number of assets to become impaired. Additionally, the oil and gas assets may be further adjusted in the future due to the outcome of Chapter 11 Cases or adjusted to fair value if we are required to apply fresh start accounting upon emergence from Chapter 11.

Net loss attributable to the Partnership was $815.0 million in 2016 and $2,583.3 million in 2015. Adjusted EBITDA, a non-GAAP measure, was $267.3 million in 2016 and $636.8 million in 2015 . The decrease in Adjusted EBITDA was primarily due to lower commodity derivative instrument settlement receipts (excluding terminations) and lower crude oil and natural gas sales revenues due to lower commodity prices, partially offset by lower operating expenses and G&A. For a reconciliation of Adjusted EBITDA to net income (loss) attributable to the Partnership, see the second table under Item 6 “Selected Financial Data.”

Breitburn Management

Breitburn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. Our employees, including our executives, are employees of Breitburn Management.

Breitburn Management also provided administrative services to Pacific Coast Energy Company LP (“PCEC”), our predecessor, under an administrative services agreement (“ASA”), 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 years ended December 31, 2015 and 2014 , and the six months ended June 30, 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 ASA, which became effective on June 30, 2016.

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Results of Operations

The table below summarizes certain of the results of operations and period-to-period comparisons attributable to our operations for the periods indicated. These results are presented for illustrative purposes only and are not indicative of our future results. The data reflect our results as they are presented in our consolidated financial statements.

		Year Ended December 31,												Increase / decrease %
Thousands of dollars, except as indicated		2016				2015				2014				2016-2015			2015-2014
Total production (MBoe) (a)		18,279				20,180				14,114				(9	)%		43	%
Oil (MBbl)		9,504				11,248				7,931				(16	)%		42	%
NGLs (MBbl)		1,984				1,953				1,157				2	%		69	%
Natural gas (MMcf)		40,747				41,876				30,159				(3	)%		39	%
Average daily production (Boe/d)		49,943				55,288				38,670				(10	)%		43	%
Sales volumes (MBoe) (b)		18,474				20,219				13,956				(9	)%		45	%
Average realized sales price (per Boe) (c)		$	27.30			$	31.80			$	61.30			(14	)%		(48	)%
Oil (per Bbl)		38.93				44.46				86.08				(12	)%		(48	)%
NGLs (per Bbl)		14.97				15.02				35.46				—	%		(58	)%
Natural gas (per Mcf)		2.38				2.67				4.82				(11	)%		(45	)%
Oil sales		$	377,569			$	504,035			$	669,355			(25	)%		(25	)%
NGL sales		29,695				29,336				41,031				1	%		(29	)%
Natural gas sales		96,990				111,901				145,434				(13	)%		(23	)%
Gain (loss) on commodity derivative instruments		(53,091		)		438,614				566,533				(112	)%		(23	)%
Other revenues, net (d)		17,842				24,829				7,616				(28	)%		n/a
Total revenues		469,005				1,108,715				1,429,969				(58	)%		(22	)%
Lease operating expenses including processing fees (e)		303,275				383,827				291,395				(21	)%		32	%
Production and property taxes (f)		37,399				51,174				62,071				(27	)%		(18	)%
Total lease operating expenses		340,674				435,001				353,466				(22	)%		23	%
Purchases and other operating costs		9,364				3,056				725				n/a			n/a
Salt water disposal costs		13,911				14,687				2,168				(5	)%		n/a
Change in inventory		(23		)		2,445				(678		)		(101	)%		n/a
Total operating costs		$	363,926			$	455,189			$	355,681			(20	)%		28	%
Lease operating expenses before taxes per Boe (g)		$	16.24			$	19.02			$	20.65			(15	)%		(8	)%
Production and property taxes per Boe		2.05				2.54				4.40				(19	)%		(42	)%
Total lease operating expenses per Boe		$	18.29			$	21.56			$	25.05			(15	)%		(14	)%
Depletion, depreciation and amortization		$	318,528			$	460,047			$	291,709			(31	)%		58	%
DD&A per Boe		$	17.43			$	22.80			$	20.67			(24	)%		10	%
Impairment of oil and natural gas properties		283,270				2,377,615				149,000				(88	)%		n/a
Impairment of goodwill		—				95,947				—				(100	)%		n/a
G&A excluding unit based compensation (h)		$	69,210			$	73,537			$	63,562			(6	)%		16	%
G&A excluding unit based compensation per Boe		$	3.79			$	3.64			$	4.50			4	%		(19	)%
(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 187 MBoe, 62 MBoe and zero MBoe of condensate purchased from third parties during 2016, 2015 and 2014, respectively.
(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 $6.4 million, zero, and zero during 2016, 2015 and 2014.
(h) Excludes non-cash unit-based compensation expense of $17.8 million, $25.5 million, and $23.4 million during 2016, 2015 and 2014.

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Comparison of Results of Operations for the Years Ended December 31, 2016 , 2015 and 2014

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

Production

For the year ended December 31, 2016 , compared to the year ended December 31, 2015 , production volumes decreased by 1,901 MBoe, or 9% , primarily from our Permian Basin, Mid-Continent, Southeast and California properties as a result of natural field declines, our curtailed capital program and the sale of certain of our Mid-Continent assets in March 2016. In 2016 , oil, NGLs and natural gas accounted for 52% , 11% and 37% of our production, respectively.

For the year ended December 31, 2015 , compared to the year ended December 31, 2014 , production volumes increased by 6,066 MBoe, or 43% , primarily due to 6,730 MBoe of production from the properties acquired in the QRE Merger in November 2014 (the “QRE Properties”), partially offset by 203 MBoe lower Rockies production, 194 MBoe lower legacy Permian production, 133 MBoe lower Midwest production and 107 MBoe lower California production, primarily due to natural field declines. In 2015, oil, NGLs and natural gas accounted for 56%, 9% and 35% of our production, respectively.

Oil, NGL and natural gas sales

Total oil, NGL and natural gas sales revenues decreased $141.0 million for the year ended December 31, 2016 , compared to the year ended December 31, 2015 . Crude oil revenues decreased $126.5 million due to lower production and lower average crude oil prices. Realized prices for oil, excluding the effect of derivative instruments, decreased $5.53 per Bbl, or 12% , for the year ended December 31, 2016 compared to the year ended December 31, 2015 . NGL revenues increased $0.4 million due to slightly higher production, partially offset by slightly lower average NGL prices. Realized prices for NGLs decreased $0.05 per Bbl for the year ended December 31, 2016 compared to the year ended December 31, 2015 . Natural gas revenues decreased $14.9 million , primarily due to lower average natural gas prices and slightly lower production from our Mid-Continent, Midwest, Permian and Rockies properties. Realized prices for natural gas, excluding the effect of derivative instruments, decreased $0.29 per Mcf, or approximately 11% , for the year ended December 31, 2016 compared to the year ended December 31, 2015 .

Total oil, NGL and natural gas sales revenues decreased $210.5 million for the year ended December 31, 2015, compared to the year ended December 31, 2014. Crude oil revenues decreased $165.3 million due to lower average crude oil prices, partially offset by production from the QRE Properties. Realized prices for oil, excluding the effect of derivative instruments, decreased $41.62 per Bbl, or 48%, for the year ended December 31, 2015 compared to the year ended December 31, 2014. NGL revenues decreased $11.7 million due to lower average NGL prices, partially offset by the full year effect of production from the QRE Properties. Realized prices for NGLs decreased $20.44 per Bbl, or 58%, for the year ended December 31, 2015 compared to the year ended December 31, 2014. Natural gas revenues decreased $33.5 million, primarily due to lower average natural gas prices, partially offset by production from the QRE Properties. Realized prices for natural gas, excluding the effect of derivative instruments, decreased $2.15 per Mcf, or approximately 45%, for the year ended December 31, 2015 compared to the year ended December 31, 2014.

(Loss) gain on commodity derivative instruments

Loss on commodity derivative instruments for the year ended December 31, 2016 was $53.1 million , compared to a gain of $438.6 million for the year ended December 31, 2015 . Net settlements received on oil derivative instruments for the year ended December 31, 2016 were $556.5 million , which included $402.1 million in terminations, compared to net settlements received of $431.1 million for the year ended December 31, 2015 , primarily due to the termination of our derivative instruments in the second quarter of 2016. Net settlements received on natural gas derivative instruments for the year ended December 31, 2016 were $56.2 million , which included $36.4 million in terminations, compared to $68.9 million for the year ended December 31, 2015 , primarily due to higher natural gas futures prices and lower hedge volumes in 2016, partially offset by the termination of our derivative instruments in the second quarter of 2016.

Mark-to-market loss on oil derivative instruments for the year ended December 31, 2016 was $599.9 million compared to mark-to-market loss of $45.2 million for the year ended December 31, 2015 , primarily due to the termination of our derivative instruments in the second quarter of 2016. Mark-to-market loss on natural gas commodity derivative instruments for the year ended December 31, 2016 was $65.9 million compared to a loss of $16.2 million for the year ended December 31, 2015 , primarily due to the termination of our derivative instruments in the second quarter of 2016.

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Gain on commodity derivative instruments for the year ended December 31, 2015 was $438.6 million compared to a gain of $566.5 million for the year ended December 31, 2014. Net settlements received on oil derivative instruments for the year ended December 31, 2015 were $431.1 million compared to net settlements received of $18.2 million for the year ended December 31, 2014, primarily due to significantly lower commodity prices compared to our average oil hedge prices in 2015. Net settlements received on natural gas derivative instruments for the year ended December 31, 2015 were $68.9 million compared to $9.6 million for the year ended December 31, 2014, primarily due to lower commodity prices compared to our average natural gas hedge prices in 2015.

Mark-to-market loss on oil derivative instruments for the year ended December 31, 2015 was $45.2 million compared to mark-to-market gain of $508.1 million for the year ended December 31, 2014, primarily due to a significant decrease in oil future prices during 2015. Mark-to-market loss on natural gas commodity derivative instruments for the year ended December 31, 2015 was $16.2 million compared to a gain of $30.6 million for the year ended December 31, 2014, primarily due to lower natural gas future prices during 2015 compared to natural gas futures prices in 2014.

Other Revenues

Other revenues decreased $7.0 million for the year ended December 31, 2016 compared to the year ended December 31, 2015 , primarily due to $3.4 million lower salt water disposal revenue, $2.2 million lower pipeline revenue and $1.3 million lower sulfur sales revenue.

Other revenues increased $17.2 million for the year ended December 31, 2015 compared to the year ended December 31, 2014, primarily due to $14.3 million higher salt water disposal revenue, $1.9 million higher sulfur sales revenue and $1.1 million CO ₂ gas revenue.

Lease operating expenses

Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the year ended December 31, 2016 totaled $303.3 million , which was $80.6 million lower than 2015 . The decrease in pre-tax lease operating expenses primarily reflects cost-cutting efforts, lower fuel and utility costs and lower oil and natural gas production leading to lower overall costs. On a per Boe basis, pre-tax lease operating expenses were 13% lower than the year ended December 31, 2015 at $16.59 per Boe, primarily due to cost-cutting efforts and lower fuel and utility costs due to lower commodity prices. On a per Boe basis, pre-tax lease operating expenses excluding $6.4 million of non-cash unit based compensation expense were 15% lower than the year ended December 31, 2015 at $16.24 per Boe, primarily due to lower commodity prices, cost-cutting efforts, and lower well service expenses.

Production and property taxes for the year ended December 31, 2016 totaled $37.4 million , which was $13.8 million lower than the year ended December 31, 2015 , primarily due to the impact that lower commodity prices had on production taxes and lower oil production. On a per Boe basis, production and property taxes for the year ended December 31, 2016 were $2.05 per Boe, which was 19% lower than the year ended December 31, 2015 , primarily due to lower commodity prices.

Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the year ended December 31, 2015 totaled $383.8 million, $92.4 million higher than 2014. The increase in pre-tax lease operating expenses reflects the full year effect of lease operating costs for the QRE Properties. On a per Boe basis, pre-tax lease operating expenses were 8% lower than the year ended December 31, 2014 at $19.02 per Boe, primarily due to lower commodity prices.

Production and property taxes for the year ended December 31, 2015 totaled $51.2 million, which was $10.9 million lower than the year ended December 31, 2014, primarily due to lower crude oil and natural gas prices, partially offset by higher production. On a per Boe basis, production and property taxes for the year ended December 31, 2015 were $2.54 per Boe, which was 42% lower than the year ended December 31, 2014.

Change in inventory

In Florida, our oil sales are a function of the number and size of oil shipments in each year and thus oil sales do not always coincide with volumes produced in a given year. Sales occur on average every 12 to 14 weeks. We match production expenses with oil sales. Production expenses associated with unsold 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. In 2016 , the change in inventory account amounted to a credit of less than $0.1

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million primarily due to a similar volume of barrels sold as produced during the year. In 2015, the change in inventory account amounted to a charge of $2.4 million, primarily due to a higher volume of barrels sold than produced during the year and a $0.6 million write-off of crude oil inventory due to a decrease in oil prices in the fourth quarter of 2015. In 2014, the change in inventory account amounted to a credit of $0.7 million primarily due to a lower volume of barrels sold than produced during the year and a $0.6 million credit for physical inventory adjustments, partially offset by a $1.0 million write-off of crude oil inventory due to a decrease in oil prices in the fourth quarter of 2014.

Depletion, depreciation and amortization

Depletion, depreciation and amortization (“DD&A”) expense totaled $318.5 million for the year ended December 31, 2016 , compared to $460.0 million for the year ended December 31, 2015 . The 31% decrease in DD&A was primarily due to impairments of proved properties during 2015 and 2016, driven by decreases in commodity prices, and the effect the impairments had on our reserve volumes and DD&A rates, as well as lower oil production. For the years ended December 31, 2016 and December 31, 2015 , DD&A included zero and $2.2 million , respectively, of amortization of intangible assets related to CO ₂ contracts acquired in the 2013 Mid-Continent acquisitions. For the year ended December 31, 2016 , DD&A per Boe was 24% lower than prior year at $17.43 per Boe compared to $22.80 per Boe for the year ended December 31, 2015 , primarily due to the effect the impairments had on our DD&A rates.

DD&A expense totaled $460.0 million for the year ended December 31, 2015, compared to $291.7 million for the year ended December 31, 2014. The 58% increase in DD&A was primarily due to lower oil and natural gas prices, and the effect those prices had on our reserve volumes and DD&A rates, as well as the addition of QRE Properties acquired at higher values and capital expenditures incurred during the year ended December 31, 2015. For the years ended December 31, 2015 and December 31, 2014, DD&A included $2.2 million and $3.9 million, respectively, of amortization of intangible assets related to CO ₂ contracts acquired in the 2013 Mid-Continent acquisitions. For the year ended December 31, 2015, DD&A per Boe was 10% higher than prior year at $22.80 per Boe compared to $20.67 per Boe for the year ended December 31, 2014, primarily due to lower commodity prices and their impact on our reserve volumes and DD&A rates.

Impairments

At December 31, 2016, we incorporated the assumptions from our business plan into our impairment reserve analyses. For certain impaired fields, recent operating results incorporated in the business plan resulted in lower production estimates and higher operating cost estimates than previously forecast. Our business plan was prepared with the assumption that we emerge from Chapter 11 and continue to hold and use our assets for their economic lives up to and including final dispositions. There are no material asset sales planned or contemplated in this business plan. Other assumptions and or revisions in our business plan could have resulted in material changes to the undiscounted cash flows used in our impairment analysis. We are in the process of reviewing our business plan with our creditors. Accordingly, we cannot estimate what impact, if any, other assumptions or courses of action or their probabilities of occurrence could have had on our undiscounted cash flows at December 31, 2016.

During the year ended December 31, 2016 , we recorded non-cash impairments related to our oil, NGL and natural gas properties of $283.3 million , including $177.9 million in the Permian Basin, $92.1 million in the Rockies, $5.7 million in the Midwest, $4.2 million in Ark-La-Tex, $2.2 million in the Southeast, and $1.2 million in California. The impairments were primarily related to revisions in our business plan for future production and cost estimates at certain of our lower margin oil properties, as well as the impact that the drop in natural gas prices in the out years had on projected future revenues for certain of our lower margin natural gas properties.

During the year ended December 31, 2015, we recorded impairments of $2.4 billion, including $740.6 million in the Midwest, $512.8 million in Ark-La-Tex, $443.8 million in the Southeast, $256.5 million in the Permian Basin, $213.0 million in California, $147.9 million in the Rockies and $63.0 million in Mid-Continent. The impairments were primarily due to the impact that the prolonged drop in commodity prices had on our projected future net revenues.

During the year ended December 31, 2014, we recorded impairments of $149.0 million, including $124.8 million in the Southeast, $11.2 million in the Rockies and $8.5 million in the Midwest, $2.3 million in the Permian Basin, $2.2 million in Mid-Continent. The impairments in the Southeast were due to reserve adjustments primarily related to lower crude oil prices and well performance. The Rockies impairments were due to reserve adjustments related to a combination of lower commodity prices, well performance and higher expense projections. The Midwest impairments related to lower commodity prices and the write-off of investments associated with expiring leases that we elected not to renew. The Permian Basin and Mid-Continent property impairments related to lower commodity prices.

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Goodwill Impairment

During the year ended December 31, 2015, we had $95.9 million of goodwill related to the 2014 QRE Merger. See Note 4 to the consolidated financial statements in this report for more information relating to the QRE Merger. Due to a decrease in the price of our Common Units during the second quarter of 2015, we performed a qualitative goodwill impairment assessment. In the first step of the goodwill impairment test, we determined that the fair value of our goodwill was less than the carrying amount, primarily due to the decrease in the price of our Common Units. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there was no remaining implied fair value attributable to goodwill.  Based on this assessment, we recorded a non-cash goodwill impairment charge of $95.9 million during the second quarter of 2015.

General and administrative expenses

G&A totaled $87.0 million and $99.0 million in 2016 and 2015 , respectively. For the year ended December 31, 2016 , G&A included $17.8 million of non-cash unit based incentive compensation expense and $22.1 million of cash based incentive compensation expense. For the year ended December 31, 2015 , G&A included $25.5 million in non-cash unit-based compensation expense related to employee incentive plans. For 2016 , G&A, excluding all incentive compensation expense was $47.1 million, which was $19.4 million lower than 2015 . The decrease was primarily due to $12.8 million lower integration costs incurred during the year ended December 31, 2016 , compared to the year ended December 31, 2015 , as well as cost cutting efforts including work force reductions during 2016 and 2015. On a per Boe basis, G&A excluding all incentive compensation expense was $2.59 in 2016 , which was a 22% decrease from 2015 . Excluding all incentive compensation expense and acquisition and integration related costs, G&A per Boe was $2.59 and $2.67 for the years ended December 31, 2016 and 2015 , respectively.

G&A totaled $99.0 million and $86.9 million in 2015 and 2014, respectively. This included $25.5 million and $23.4 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans. For 2015, G&A, excluding non-cash unit-based compensation, was $73.5 million, which was $10.0 million higher than 2014. The increase was primarily due to higher payroll expense for additional personnel attributable to our 2014 acquisitions. Excluding all incentive compensation expense and acquisition and integration costs, G&A was $53.9 million and $42.9 million for the years ended December 31, 2015 and 2014, respectively, or $2.67 per Boe and $3.04 per Boe, respectively.

Restructuring costs

During 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. In addition, we executed workforce reductions during 2016 in connection with the termination of PCEC’s administrative services agreement with Breitburn Management, effective as of June 30, 2016.

The 2016 workforce reductions were communicated to affected employees on various dates during the period, and all such notifications were completed by June 30, 2016. The plans resulted in a reduction of approximately 76 employees. For the year ended December 31, 2016, we recognized a total cost of $4.3 million , which included severance cash payments, accelerated vesting of LTIP grants for certain individuals and other employee-related termination costs.

The 2015 workforce reductions were communicated to affected employees on various dates during the period, and all such notifications were completed by March 31, 2015. The plan resulted in a reduction of approximately 45 employees, primarily in administrative and support positions. For the year ended December 31, 2015, we recognized a total cost of $6.4 million, which included severance cash payments, accelerated vesting of LTIP grants for certain individuals and other employee-related termination costs. Total workforce reductions in 2015 as a result of the workforce reduction plan, voluntary resignations and early retirement exceeded 60 positions.

    Interest expense, net of amounts capitalized

 

Interest expense totaled $148.2 million and $203.0 million for the years ended December 31, 2016 and 2015 , respectively. The $54.8 million decrease in interest expense was primarily attributable to $58.3 million and $21.2 million lower interest expense on our Senior Unsecured Notes and Senior Secured Notes, respectively, due to the filing of the Chapter 11 Petitions, partially offset by $23.5 million higher credit facility interest expense due to a higher interest rate under the RBL Credit Agreement resulting from the commencement of the Chapter 11 Cases and $1.2 million higher amortization of debt issuance costs, premiums and discounts, primarily due to debt issuance cost write-offs in 2016. Interest

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expense, excluding debt amortization, totaled $122.1 million and $178.1 million for the years ended December 31, 2016 and 2015 , respectively.

Interest expense totaled $203.0 million and $127.0 million for the years ended December 31, 2015 and 2014, respectively. The increase of $76.1 million in interest expense was primarily attributable to $43.8 million of interest on our Senior Secured Notes issued in April 2015, approximately $17.5 million higher credit facility interest expense as a result of increased borrowings under the RBL Credit Agreement and $10.6 million write-off of debt issuance costs associated with the reduction of our credit facility borrowing base in April 2015. Interest expense, excluding debt amortization, totaled $178.1 million and $119.1 million for the years ended December 31, 2015 and 2014, respectively.

Loss on interest rate swaps

We are subject to interest rate risk associated with loans under the RBL Credit Agreement that bear interest based on floating rates. In order to mitigate our interest rate exposure, as of December 31, 2015 and March 31, 2016, we had interest rate swaps, indexed to 1-month LIBOR, to fix a portion of floating LIBOR-based debt under the RBL Credit Agreement 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. The commencement of the Chapter 11 Cases on May 15, 2016 resulted in an event of default under our commodity and interest rate derivative agreements, resulting in a termination right by our counterparties. All of our derivative transactions were terminated in connection with the commencement of the Chapter 11 Cases. Accordingly, they are no longer accounted for at fair value, and have been recognized as payables at termination value.

We recognized a loss of $2.0 million , a loss of $2.7 million and a gain of $0.5 million on interest rate swaps for the years ended December 31, 2016, 2015 and 2014, respectively.

Liquidity and Capital Resources

Overview

Historically, we have used cash flow from operations, borrowings available under our revolving credit facility and amounts raised in the debt and equity capital markets to fund our operations, capital expenditures, acquisitions and cash distributions. More recently, since late 2014, we have had limited access to the credit and capital markets as a result of declines and volatility in oil and natural gas prices. Although oil and natural gas prices have increased since we filed the Chapter 11 Petitions, they remain low historically, and the uncertainty resulting from the Chapter 11 Cases, combined with the uncertainty surrounding future commodity prices, has significantly increased the cost of obtaining money in these markets and limited our ability to access these markets currently as a source of funding. Since the filing of the Chapter 11 Petitions, our principal sources of liquidity have been limited to cash on hand, cash flow from operations and borrowings available under the DIP Credit Agreement. As of December 31, 2016, we had no amounts borrowed and $37.9 million in letters of credit outstanding under the DIP Credit Agreement. As of December 31, 2016, we had $460 million of estimated derivative instrument settlements receivable from the termination of all of our outstanding derivative transactions. Each of our counterparties is required to hold any proceeds due to us in a book entry account maintained by it pursuant to and subject to the provisions of the order of the Bankruptcy Court approving the DIP Credit Agreement, with the rights of all of the parties reserved as to the ultimate disposition of the proceeds. As such, we currently do not have access to these proceeds and cannot predict with certainty when, if at all, we will have access to these proceeds.

Liquidity and Ability to Continue as a Going Concern

Although we believe our cash on hand, cash flow from operations and borrowings available under the DIP Credit Agreement will be adequate to meet the operating costs of our existing business, there are no assurances that we will have sufficient liquidity to continue to fund our operations or allow us to continue as a going concern until a plan of reorganization is confirmed by the Bankruptcy Court and becomes effective, and thereafter. Our long-term liquidity requirements, the adequacy of our capital resources and our ability to continue as a going concern are difficult to predict at this time and ultimately cannot be determined until a plan of reorganization has been confirmed, if at all, by the Bankruptcy Court. In addition, we have incurred and continue to incur significant professional fees and costs in connection with the preparation and administration of the Chapter 11 Cases, including the fees and expenses of the professionals retained by two statutory committees appointed in the Chapter 11 Cases. We are making adequate protection payments with respect to the lenders under the RBL Credit Agreement consisting of the payment of interest (at the default rate) and the payment of all reasonable fees and expenses of professionals retained by our lenders, as provided for in the RBL Credit Agreement. We are also making adequate protection payments with respect to the Senior Secured Notes in the form of the payment of all

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reasonable fees and expenses of professionals retained by the holders of the Senior Secured Notes. We anticipate that we will continue to incur significant professional fees and costs during the pendency of the Chapter 11 Cases.

Given the uncertainty surrounding the Chapter 11 Cases, there is substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of the Chapter 11 Cases. In particular, the consolidated financial statements do not purport to show (i) as to assets, their realizable value on a liquidation basis or their fair value or their availability to satisfy liabilities; (ii) as to certain pre-petition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (iii) as to unitholders’ equity accounts, the effect of any changes that may be made in our capitalization; or (iv) as to operations, the effect of any changes that may be made to our business. While operating as debtors in possession under chapter 11 of the Bankruptcy Code, the Debtors may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected in our consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a plan of reorganization could materially change the amounts and classifications in our historical consolidated financial statements.

In addition to the uncertainty resulting from the Chapter 11 Cases, oil and natural gas prices continue to remain low historically. In 2016, the WTI posted price averaged approximately $43 per Bbl, compared with $48 per Bbl in 2015 and $93 per Bbl in 2014. In 2016, the Henry Hub posted price averaged approximately $2.51 per MMBtu, compared with $2.62 per MMBtu in 2015 and $4.37 per MMBtu in 2014. Our revenue, profitability and cash flow are highly sensitive to movements in oil and natural gas prices. Sustained depressed prices of oil and natural gas will materially adversely affect our assets, development plans, results of operations and financial condition. The filing of the Chapter 11 Petitions triggered an event of default under each of the agreements governing our derivative transactions. As a result, our counterparties were permitted to terminate, and did terminate, all outstanding derivative transactions. As of December 31, 2016, none of our estimated future production was covered by commodity derivatives, and we may not be able to enter into commodity derivatives covering our estimated future production on favorable terms or at all. As a result, we have significant exposure to fluctuations in oil and natural gas prices and our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, results of operations and financial condition.

If our future sources of liquidity are insufficient, we could face substantial liquidity constraints and be unable to continue as a going concern and will likely be required to implement further cost reductions, significantly reduce, delay or eliminate capital expenditures, seek other financing alternatives or seek the sale of some or all of our assets. If we (i) continue to limit, defer or eliminate future capital expenditure plans, (ii) are unsuccessful in developing reserves and adding production through our capital program or (iii) implement cost-cutting efforts that are too overreaching, the value of our oil and natural gas properties and our financial condition and results of operations could be adversely affected. We have been managing our operating activities and liquidity carefully in light of the uncertainty regarding future oil and natural gas prices and the Chapter 11 Cases. To fund capital expenditures, we will be required to use cash on hand, cash generated from operations or borrowings under the DIP Credit Agreement, or some combination thereof. We expect our full year 2017 capital spending program to be approximately $100 million, compared with approximately $65 million in 2016, approximately $209 million in 2015 and approximately $389 million in 2014. We anticipate that 60% of our total capital spending will be focused on drilling and rate-generating projects and CO ₂ purchases in our core operating areas of Ark-La-Tex, the Permian Basin and Mid-Continent that are designed to increase or add to production or reserves.

DIP Credit Agreement

In connection with the Chapter 11 Cases, BOLP entered into the DIP Credit Agreement, as borrower, with the DIP Lenders and Wells Fargo, National Association, as administrative agent. The other Debtors have guaranteed all obligations under the DIP Credit Agreement. Pursuant to the terms of the DIP Credit Agreement, the DIP Lenders made available a revolving credit facility in an aggregate principal amount of $75 million, which included a letter of credit facility available for the issuance of letters of credit in an aggregate principal amount not to exceed a sublimit of $50 million, and a swingline facility in an aggregate principal amount not to exceed a sublimit of $5 million, in each case, to mature on the earlier to occur of (A) the effective date of a plan of reorganization in the Chapter 11 Cases or (B) the stated maturity of the DIP Credit Agreement of January 15, 2017. The maturity date of the DIP Credit Agreement may be accelerated upon the occurrence of certain events as set forth therein.

On December 13, 2016, the Bankruptcy Court approved the First Amendment to the DIP Credit Agreement which, among other things, (i) extended the DIP Credit Agreement’s scheduled maturity date to June 30, 2017, (ii) increased certain pricing, (iii) increased the committed amount available under the DIP Credit Agreement from $75 million to $150 million, (iv) increased the letter of credit sublimit from $50 million to $100 million and (v) provided for the payment of certain fees to the Administrative Agent and the DIP Lenders. The DIP Credit Agreement also permits the cash collateralization of

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letters of credit issued for ordinary course of business purposes by Wells Fargo Bank, National Association. The DIP Credit Agreement does not permit us to make distributions on our Common Units.

The proceeds of the DIP Credit Agreement may be used: (i) to pay the costs and expenses of administering the Chapter 11 Cases, (ii) to fund our working capital needs, capital improvements, and other general corporate purposes, in each case, in accordance with an agreed budget and (iii) to provide adequate protection to existing secured creditors as described above.

Acceleration of Debt Obligations

The commencement of the Chapter 11 Cases resulted in the acceleration of the Debtors’ obligations under the RBL Credit Agreement, the Senior Unsecured Notes and the Senior Secured Notes. Any efforts to enforce such obligations are automatically stayed as a result of the filing of the Chapter 11 Petitions and the holders’ rights of enforcement in respect of these obligations are subject to the applicable provisions of the Bankruptcy Code.

RBL Credit Agreement

BOLP, as borrower, and we and our wholly-owned subsidiaries, as guarantors, are party to 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. We entered into the RBL Credit Agreement on November 19, 2014. The RBL Credit Agreement limits the amounts we can borrow to a borrowing base amount determined by the lenders at their sole discretion based on their valuation of our proved reserves and their internal criteria. At the Chapter 11 Filing Date, the borrowing base for the RBL Credit Agreement was $1.8 billion , and the aggregate commitment of all lenders was $1.4 billion . At each of March 7, 2017 , December 31, 2016 and December 31, 2015 , we had $1.2 billion in indebtedness outstanding under the RBL Credit Agreement.

As of the Chapter 11 Filing Date, we had $1.2 billion in aggregate principal amount outstanding under the RBL Credit Agreement. The RBL Credit Agreement is secured by a first priority security interest in and lien on substantially all of the Debtors’ assets, including the proceeds thereof and after-acquired property. We determined at the Chapter 11 Filing Date that the RBL Credit Agreement was fully collateralized. As a result of the automatic acceleration of our obligations under the RBL Credit Agreement as a consequence of the commencement of the Chapter 11 Cases, we reclassified the entire RBL Credit Agreement balance to current portion of long-term debt on the consolidated balance sheet. As of the Chapter 11 Filing Date, we recognized $15.7 million of interest expense for the full write-off of unamortized debt issuance costs related to the RBL Credit Agreement.

We are required to make adequate protection payments to the lenders under the RBL Credit Agreement, which includes the payment of interest (at the default rate) and the payment of all reasonable fees and expenses of professionals retained by our lenders, as provided for in the RBL Credit Agreement. We are recognizing the default interest accrued on the RBL Credit Agreement as interest expense, net of capitalized interest on the consolidated statements of operations, and we are recognizing the adequate protection payments as accrued interest payable on the consolidated balance sheets, rather than in liabilities subject to compromise.

Senior Unsecured Notes

As of March 2, 2017, we had $850 million in aggregate principal amount of 2022 Senior Notes outstanding and $305 million in aggregate principal amount of 2020 Senior Notes outstanding. Interest on the Senior Unsecured Notes is payable twice a year in April and October.

On April 14, 2016, 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. As a consequence of the commencement of the Chapter 11 Cases on May 15, 2016, such interest payments have not been made.

As of December 31, 2016 , the Senior Unsecured Notes were reflected as liabilities subject to compromise on the consolidated balance sheet, with the carrying values equal to the face values.

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Senior Secured Notes

On April 8, 2015, we issued $650 million Senior Secured Notes in a private offering to EIG Redwood Debt Aggregator, LP and certain other purchasers at a purchase price of 97% of the principal amount. We received approximately $606.9 million from this offering, net of fees and estimated expenses, which we primarily used to repay borrowings under the RBL Credit Agreement. As of March 2, 2017, we had $650 million in aggregate principal amount of Senior Secured Notes outstanding. Interest on the Senior Secured Notes is payable quarterly in March, June, September and December.

As a consequence of the commencement of the Chapter 11 Cases on May 15, 2016, no interest has been paid to the holders of the Senior Secured Notes.

As of December 31, 2016 , the Senior Secured Notes were reflected as liabilities subject to compromise on the consolidated balance sheet, with the carrying value equal to the face value.

Common Units

    

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

Preferred Units

On May 21, 2014, we sold 8.0 million Series A Preferred Units in a public offering at a price of $25.00 per unit, resulting in proceeds of $193.2 million , net of underwriting discounts and offering expenses of $6.8 million , which we primarily used to repay borrowings under the RBL Credit Agreement. The 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.

On April 8, 2015, we issued in a private offering $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 the RBL Credit Agreement. 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 distributions.

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. As of the Chapter 11 Filing Date, we had 8.0 million Series A Preferred Units issued and outstanding and 49.6 million Series B Preferred Units issued and outstanding. Commencing as of the Chapter 11 Filing Date, distributions are no longer being accrued on the Series A Preferred Units and Series B Preferred Units.

During the years ended December 31, 2016 , 2015 and 2014 , we recognized $6.1 million , $16.5 million and $10.1 million , respectively, 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.

Distributions on the Series B Preferred Units are cumulative from the date of original issue and are payable monthly in arrears on the 15 ^th day of each month of each year, when, as and if declared by our Board out of legally available funds for such purpose.  We began making regular monthly distributions on the Series B Preferred Units of 0.006666 Series B Preferred Units per unit beginning with the June 15, 2015 payment.  During the years ended December 31, 2016 and 2015, we recognized $11.7 million and $20.8 million , respectively, of accrued distributions on the Series B Preferred Units, which are included in non-cash distributions to Series B preferred unitholders on the consolidated statements of operations. The accrued distributions on Series B Preferred Units recognized during the three months ended September 30, 2016 of $0.6 million reflect the 2.00% default distribution rate increase attributable to the earned but undeclared distributions effective April 15, 2016 through the Chapter 11 Filing Date.

Cash Flows

Operating activities. Our cash flow from operating activities in 2016 was $174.5 million compared to $ 436.7 million in 2015 . The decrease in cash flows from operating activities was primarily due to $322.0 million lower commodity derivative settlement receipts primarily due to the termination of our derivative transactions in connection with the filing of the Chapter 11 Petitions. In addition, sales revenues were lower in 2016, driven by lower commodity prices, which reduced sales revenue by approximately $67 million, a 9% decrease in sales volume primarily due to lower Permian Basin, Mid-Continent, and Southeast oil production, which reduced sales revenue by approximately $74 million, and $43.5 million of cash reorganization costs, partially offset by approximately $119.8 million lower cash interest expense, and $91.3 million

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lower operating costs primarily at our Ark-La-Tex, Permian Basin, Mid-Continent, and Southeast properties. Cash flow from other working capital changes during the year ended December 31, 2016 was approximately $17.3 million higher than the year ended December 31, 2015 .

Our cash flow from operating activities in 2015 was $436.7 million compared to $357.8 million in 2014. The increase in cash flows from operating activities was primarily due to higher sales revenues in 2015 driven by a 45% increase in sales volume from the QRE Properties, which increased sales revenue by approximately $383.9 million and $472.2 million in higher commodity derivative settlement receipts primarily due to lower commodity prices. These positive factors were partially offset by lower physical sales revenue driven by lower commodity prices, which decreased sales revenue by approximately $596.5 million, $99.5 million of additional operating costs primarily from the full year effect related to the QRE Properties, and $64.6 million higher cash interest expense paid due to higher debt levels.

Investing activities. Net cash flows used in investing activities during the years ended December 31, 2016 and 2015 were $72.4 million and $274.0 million , respectively. During the year ended December 31, 2016 , we spent $75.6 million on capital expenditures, consisting of approximately $72.8 million primarily for drilling and completion activities, and approximately $2.8 million for IT and other capital expenditures, $8.9 million on property acquisitions, primarily for CO ₂ producing properties and additional leases in Ark-La-Tex and $7.1 million on purchases of available-for-sale securities, partially offset by $12.7 million in net proceeds from sale of assets and $6.4 million in proceeds from the sale of available-for-sale securities.

Net cash used in investing activities for the year ended December 31, 2015 was $274.0 million, which was predominantly spent on capital expenditures. In 2015, we spent $269.4 million on capital expenditures, consisting of $255.8 million primarily for drilling and completion activities, and approximately $13.6 million for IT and other capital expenditures, $18.2 million on property acquisitions, primarily for CO ₂ producing properties, $4.0 million on purchases of available-for-sale securities and $0.9 million in advances made for the purchase of future CO ₂ supply for our Oklahoma properties, partially offset by $14.5 million in proceeds from sale of assets and $3.9 million in proceeds from the sale of available-for-sale securities.

Net cash used in investing activities for the year ended December 31, 2014 was $837.0 million, which was predominantly spent on property acquisitions. Property acquisitions of $401.5 million in 2014 primarily included $344.9 million for the QRE Merger and $50.0 million for the Antares Acquisition. In 2014, we also spent $417.8 million for capital expenditures, primarily for drilling and completions, and $11.7 million in advances made for the purchase of future CO ₂ supply for our Mid-Continent properties.

Financing activities. Net cash used in financing activities for the year ended December 31, 2016 was $41.4 million compared to $164.9 million for the year ended December 31, 2015 . We had net repayments from the issuance of long-term debt under the RBL Credit Agreement of $31 million in 2016 compared to net proceeds of $966 million in 2015 . In addition, for the year ended December 31, 2016 , we made cash distributions of $5.5 million on the Series A Preferred Units and paid $5.0 million in debt issuance costs associated with the DIP Credit Agreement.

Net cash used in financing activities for the year ended December 31, 2015 was $164.9 million compared to provided by financing activities of $489.4 million for the year ended December 31, 2014. We had net repayments from the issuance of long-term debt under our credit facility of $966 million in 2015 compared to net proceeds of $672.6 million in 2014. We had net proceeds of $606.9 million in connection with the issuance of the Senior Secured Notes. In addition, for the year ended December 31, 2015, we received net cash proceeds from the issuance of Common Units of $3.0 million, received net cash proceeds of $337.2 million from the issuance of the Series B Preferred Units, made cash distributions of $142.7 million and paid $29.3 million in debt issuance costs.

Net cash provided by financing activities for the year ended December 31, 2014 was $489.4 million. We had net proceeds from the issuance of long-term debt under the RBL Credit Agreement of $672.6 million in 2014. During the year ended December 31, 2014, we received net cash proceeds from the issuance of Common Units of $277.6 million, received net cash proceeds of $193.2 million from the issuance of Series A Preferred Units, paid $352.5 million to redeem the senior notes assumed in the QRE Merger, made cash distributions of $273.9 million and paid $25.1 million in debt issuance costs.

Off-Balance Sheet Arrangements

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

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Contractual Obligations and Commitments

The following table summarizes our financial contractual obligations as of December 31, 2016 . Some of these contractual obligations are reflected in the balance sheet, while others are disclosed as future obligations under US GAAP.

		Payments Due by Year
Thousands of dollars		2017				2018				2019				2020				2021				Thereafter				Total
Credit Agreement (a)		$	1,198,259			$	—			$	—			$	—			$	—			$	—			$	1,198,259
Senior Notes (b)		1,805,000				—				—				—				—				—				1,805,000
Promissory note		—				—				2,938				—				—				—				2,938
Operating lease obligations		4,866				3,467				2,570				2,476				2,460				5,714				21,553
Asset retirement obligations (c)		5,905				8,382				263				3,405				2,718				237,821				258,494
Total		$	3,014,030			$	11,849			$	5,771			$	5,881			$	5,178			$	243,535			$	3,286,244
(a) The commencement of the Chapter 11 Cases resulted in the acceleration of our obligations under the RBL Credit Agreement and, as such, the RBL Credit Agreement balance is reflected in current portion of long-term debt on the consolidated balance sheet at December 31, 2016. Interest expense continues to be recognized and paid on the RBL Credit Agreement subsequent to the Chapter 11 Filing Date, at the default rate of 7.00% at December 31, 2016. This table does not include future commitment fees or interest expense related to the RBL Credit Agreement, as we cannot determine with accuracy the timing of emergence from Chapter 11. The unused portion of the credit facility under the RBL Credit Agreement is subject to a commitment fee of 0.50% per annum.
(b) Represents 9.25% Senior Secured Notes due 2020 with a face value of $650 million, 8.625% Senior Notes due 2020 with a face value of $305 million and 7.875% Senior Notes due 2022 with a face value of $850 million. As of December 31, 2016, the Senior Notes were in default and reflected in liabilities subject to compromise on the consolidated balance sheet. Accrued interest payable as of the Chapter 11 Filing Date was approximately $61.9 million. This amount is not included in this table but is reflected in liabilities subject to compromise on the consolidated balance sheets. No interest expense has been recognized subsequent to the Chapter 11 Filing Date.
(c) Amounts represent our estimate of future asset retirement obligations on an discounted basis. See Note 11 to the consolidated financial statements in this report.

Surety Bonds and Letters of Credit

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily 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 December 31, 2016 , we had $26.4 million in surety bonds and $50.9 million in letters of credit outstanding. At December 31, 2015 , we had $27.1 million in surety bonds and $25.8 million in letters of credit outstanding.

Credit and Counterparty Risk

The filing of the Chapter 11 Petitions triggered an event of default under each of our ISDA Agreements. As a result, our counterparties were permitted to terminate, and did terminate, all outstanding transactions governed by the ISDA Agreements. The termination date for each outstanding transaction is the termination date specified to us by our counterparties.

All of our derivative counterparties are also lenders, or affiliates of lenders, under the RBL Credit Agreement (see Note 9 to the consolidated financial statements in this report). In connection with Bankruptcy Court approval of the DIP Credit Agreement, our counterparties were permitted to terminate any outstanding derivative transactions and to calculate the amounts due to or from the Debtors as a result of such terminations, in accordance with the terms of the governing agreements. Each such counterparty is required to hold any proceeds due to the Debtors in a book entry account maintained by it pursuant to and subject to the provisions of the order of the Bankruptcy Court approving the DIP Credit Agreement, with the rights of all of the parties reserved as to the ultimate disposition of the proceeds. Payables due to our counterparties with respect to our derivative obligations constitute secured obligations under the RBL Credit Agreement. Because the RBL Credit Agreement was fully collateralized at the Chapter 11 Filing Date, and is excluded from liabilities subject to compromise, settlements payable due to our counterparties are reflected in accounts payable on the consolidated balance sheet at December 31, 2016 rather than in liabilities subject to compromise.

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At December 31, 2016 , we had $460.0 million of estimated derivative instrument settlements receivable and $4.1 million of estimated derivative instrument settlements payable, reflected in accounts and other receivables, net and other current liabilities on the consolidated balance sheet at December 31, 2016 , respectively.

Prior to the termination of the derivative transactions, as discussed above, our derivative counterparties were Bank of Montreal, Barclays Bank PLC, BNP Paribas, Canadian Imperial Bank of Commerce, Citibank, N.A, Comerica Bank, Credit Suisse Energy LLC, Credit Suisse International, ING Capital Markets LLC, Fifth Third Bank, JP Morgan Chase Bank N.A., Merrill Lynch Commodities, Inc., Morgan Stanley Capital Group Inc., PNC Bank, N.A, Royal Bank of Canada, The Bank of Nova Scotia, The Toronto-Dominion Bank, MUFG Union Bank N.A. and Wells Fargo Bank, N.A. 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 historically obtained credit default swap information on our counterparties.  As of December 31, 2016 , each of these financial institutions and/or their parent company had an investment grade credit rating from Moody’s Investors Service and Standard & Poor’s. As of December 31, 2016 , our largest derivative instrument receivables were with Wells Fargo Bank, N.A. , Barclays Bank PLC , Credit Suisse Energy LLC and Morgan Stanley Capital Group Inc. , which accounted for approximately 15% , 13% , 11% and 11% of our total derivative instrument receivables, respectively.

The remaining balance in accounts receivable are primarily from purchasers of oil and natural gas products. We have a portfolio of oil, NGL and natural gas sales contracts with large, established refiners and utilities. Our sales contracts are sold at market-sensitive or spot prices. Because our products are commodity products sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. For the years ended December 31, 2016 , 2015 and 2014 , we sold oil, NGL and natural gas production representing 10% or more of total revenue to the following purchasers:

		Year Ended December 31,
		2016			2015			2014
Shell Trading		17	%		24	%		22	%
Plains Marketing		11	%		12	%		(a)
Phillips 66		(a)			(a)			10	%

(a) Represented less than 10% of total sales revenue for the respective year end.

As of December 31, 2016 , Shell Trading and Plains Marketing , the only customers who accounted for 10% or more of our trade accounts receivables, comprised 15% and 14% , respectively, of our outstanding trade receivables.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with US GAAP. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. The development, selection and disclosure of each of these policies is reviewed by our audit committee. We believe these accounting policies reflect the more significant estimates and assumptions used in preparation of our financial statements. See Note 3 to the consolidated financial statements in this report for a discussion of additional accounting policies and estimates made by management.

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Successful Efforts Method of Accounting

We account for oil and gas properties using the successful efforts method. Under this method of accounting, leasehold acquisition costs are capitalized. Subsequently, if proved reserves are found on unproved property, the leasehold costs are transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.

DD&A of producing oil and gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, both developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves.

Geological, geophysical and dry hole costs on oil and gas properties relating to unsuccessful exploratory wells are charged to expense as incurred.

Oil and gas properties are reviewed for impairment periodically and when facts and circumstances indicate that their carrying amounts may exceed their fair values and may not be recoverable. Under the successful efforts method of accounting, the carrying amount of an oil and gas property to be held and used is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the property. Due to the nature of the recoverability test, certain oil and gas properties may have carrying values which exceed their fair values, but an impairment charge is not recognized because their carrying values are less than their undiscounted cash flows. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for market supply and demand conditions for oil and natural gas. For purposes of assessing our oil and gas properties for potential impairment, management reviews the expected undiscounted future cash flows for our total proved and, in certain instances, risk-adjusted probable and possible reserves on a held and used basis based in large part on future capital and operating plans. 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.

During 2015, undiscounted future cash flows were forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2% per year. Beginning 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 where applicable to reflect the commodity price strip used.

For impairment charges, the associated property’s expected future net cash flows were discounted using a market-based long-term weighted average cost of capital rate that approximated 10% at December 31, 2015 and 13% at December 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.

Reserves are calculated based upon reports from third party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Unproved properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.

Management prepared its undiscounted cash flow estimates on a held and used basis which assumes oil and gas

properties will be held and used for their economic lives. If a decision is reached to sell a particular asset, that asset would

be classified as held for sale and could potentially be impaired if the carrying value exceeded the estimated sales value less

the costs of disposal. It is also possible that further periods of prolonged lower commodity prices, future declines in

commodity prices, changes to our future plans in response to a final plan of reorganization, or increases in operating costs

could result in future impairments. Given the number of assumptions involved in the estimates, estimates as to other sensitivities to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable. Favorable changes to some assumptions could have increased the undiscounted cash flows thus further avoiding the need to impair any assets in this period, whereas other unfavorable changes could have caused an unknown number of

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assets to become impaired. Additionally the oil and gas assets may be further adjusted in the future due to the outcome of Chapter 11 Cases or adjusted to fair value due to the application of fresh start accounting upon emergence from Chapter 11.

We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method.

We carry out tertiary recovery methods on certain of our oil and gas properties in Oklahoma in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Acquisition costs of tertiary injectants, such as nitrogen and purchased CO ₂ , for enhanced oil recovery activities that are used prior to the recognition of proved tertiary recovery reserves are expensed as incurred. After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project. As CO ₂ is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO ₂ recycling costs are expensed as incurred. Likewise, costs incurred to maintain reservoir pressure are also expensed.

Business Combinations

We account for all business combinations using the acquisition method. Under the acquisition method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if material, is recognized as a gain at the time of acquisition. Similarly, the deficit of the fair value of assets acquired and liabilities assumed under the cost of an acquired entity, if material, is recognized as goodwill at the time of acquisition. All purchase price allocations are finalized within one year from the acquisition date.

We recognized $95.9 million of goodwill as part of the final purchase price related to the 2014 QRE Merger, which was fully impaired in 2015.

Oil and Gas Reserve Quantities

The estimates of our proved reserves are based on the quantities of oil, NGLs and gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Annually, CGA and NSAI prepare reserve and economic evaluations of all our properties on a well-by-well basis.

Estimated proved reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our disclosures for reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firms described above adhere to the same guidelines when preparing their reserve reports. The accuracy of the reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil, NGLs and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.

Our estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of producing properties for impairment. For example, if the SEC prices used for our December 31, 2016 reserve report had been 10% less per Bbl and 10% less per MMBtu,

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respectively, then the standardized measure of our estimated proved reserves as of December 31, 2016 would have decreased by approximately $253 million , from $804 million to $551 million .

Please see Part I—Item 1A “—Risk Factors” — “Risks Related to Our Business — Our estimated proved reserves are based on many assumptions that may prove to be inaccurate.  Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves.”

Asset Retirement Obligations

Estimated asset retirement obligation (“ARO”) costs are recognized when the asset is placed in service and are amortized over proved reserves using the units of production method. Our engineers estimate asset retirement costs using existing regulatory requirements and anticipated future inflation rates. Projecting future ARO cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of future oil and gas reserves, future labor and equipment rates, future inflation rates, and our credit adjusted risk free interest rate. Because of the intrinsic uncertainties present when estimating asset retirement costs as well as asset retirement settlement dates, our ARO estimates are subject to ongoing volatility.

Derivative Instruments

We have used derivative financial instruments to achieve more predictable cash flow from our oil and natural gas production by reducing their exposure to price fluctuations. Additionally, we may use derivative financial instruments in the form of interest rate swaps to mitigate interest rate exposure. Derivative instruments (including certain derivative instruments embedded in other contracts) are recorded at fair market value and are included in the balance sheet as assets or liabilities. The accounting for changes in the fair market value of a derivative instrument depends on the intended use of the derivative instrument and the resulting designation, which is established at the inception of a derivative instrument. We do not account for our derivative instruments as cash flow hedges for financial accounting purposes and are recognizing changes in the fair value of our derivative instruments immediately in earnings. See Part II—Item 7A “—Quantitative and Qualitative Disclosures About Market Risk” and Note 5 to the consolidated financial statements in this report for additional information related to our financial instruments.

New Accounting Standards

See Note 3 to the consolidated financial statements in this report for a discussion of new accounting standards issued but not yet effective.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. See “ Cautionary Statement Regarding Forward-Looking Information” in Part I—Item 1 “—Business” in this report.

See Note 5 to the consolidated financial statements in this report for additional information related to our financial instruments and a discussion of credit and counterparty risk.

Commodity Derivatives

Due to the historical volatility of oil and natural gas prices, we have, in the past, entered into various derivative instruments to manage exposure to volatility in the market price of oil and natural gas to achieve more predictable cash flows. We used swaps, collars and options for managing risk relating to commodity prices. All contracts were settled with cash and did not require the delivery of physical volumes to satisfy settlement. While this strategy may have resulted in us having lower revenues than we would otherwise have had if we had not utilized these instruments in times of higher oil and natural gas prices, management believes that the resulting reduced volatility of prices and cash flow was beneficial. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.

Our commodity derivative instruments other than our basis swaps provided for monthly settlement based on the differential between the agreement price and the actual ICE Brent oil price, NYMEX WTI oil price, NYMEX Henry Hub natural gas price or MichCon City-Gate natural gas price. Our basis swaps provided for monthly settlement based on the differential between Henry Hub and various points.

The derivative instruments we utilized were based on index prices that may and often do differ from the actual oil and natural gas prices realized in our operations. These variations often resulted in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges. Accordingly, we did not designate any of our derivative instruments as cash flow hedges for financial accounting purposes and instead recognized changes in fair value in earnings.

All of our derivative instruments were recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or confirmed by the counterparty. Changes in the fair value of our commodity derivatives were recorded in gain or loss on commodity derivative instruments, net on our consolidated statements of operations.

Interest Rate Swaps

We are subject to interest rate risk associated with loans under the RBL Credit Agreement that bear interest based on floating rates. At December 31, 2016 , prime-based long-term debt outstanding under the RBL Credit Agreement was $1.20 billion . Prior to the filing of the Chapter 11 Cases, in order to mitigate our interest rate exposure, we had various interest rate swaps to fix a portion of floating LIBOR-based debt under the RBL Credit Agreement. As of December 31, 2016, we had no interest rate swaps outstanding.

Chapter 11 Cases

The filing of the Chapter 11 Petitions triggered an event of default under each of our ISDA agreements. As a result, our counterparties were permitted to terminate, and did terminate, all outstanding transactions governed by the ISDA Agreements. The termination date for each outstanding transaction is the termination date specified to us by our counterparties.

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The derivative transactions that we had previously entered into are no longer accounted for at fair value under ASC 815, because they were terminated in connection with our filing of the Chapter 11 Petitions and have been evaluated as receivables or payables at their termination value. At the termination dates, expected settlement receipts on terminated contracts were reclassified from current and long-term derivative instrument assets to accounts and other receivables, net on the consolidated balance sheets and expected settlement payments on terminated contracts were reclassified from current and long-term derivative instrument liabilities to other current liabilities on the consolidated balance sheets. As of December 31, 2016 , we had $460.0 million of estimated derivative instrument settlements receivable and $4.1 million in estimated derivative instrument settlements payable, reflected in accounts and other receivables, net and other current liabilities on the consolidated balance sheet, respectively.

All of our derivative counterparties are also lenders, or affiliates of lenders, under the RBL Credit Agreement (see Note 9 to the consolidated financial statements in this report). In connection with Bankruptcy Court approval of the DIP Credit Agreement, our counterparties were permitted to terminate any outstanding derivative transactions and to calculate the amounts due to or from the Debtors as a result of such terminations, in accordance with the terms of the governing agreements. Each such counterparty is required to hold any proceeds due to the Debtors in a book entry account maintained by it pursuant to and subject to the provisions of the order of the Bankruptcy Court approving the DIP Credit Agreement, with the rights of all of the parties reserved as to the ultimate disposition of the proceeds.

Commodity Prices and Differentials

Our Permian Basin oil trades at a discount to WTI posted prices due to the deduction of transportation costs and our Permian Basin NGLs trade at a discount to WTI posted prices due to processing fees, profit sharing and transportation costs. Our Mid-Continent oil trades at a discount to WTI posted prices primarily due to transportation and quality, and our Mid-Continent NGLs trade at a discount to WTI posted prices due to lower regional market demand and transportation costs. Our Rockies oil trades at a significant discount to WTI posted prices because of its distance from a major refining market and the fact that our central Wyoming production is priced relative to the Western Canadian Select benchmark. Our Southwestern Wyoming production is priced relative to Flint Hills Resources Wyoming Sweet posted prices. Our Ark-La-Tex oil trades at a premium to WTI posted prices due to local refinery market supply. Our oil from the Sunniland Trend in Florida trades at a discount to WTI posted prices primarily because this heavy crude is transported via barge to market. Our oil from the Jay Field in Florida trades at a discount to WTI posted prices due to transportation costs and quality. Our California oil is generally in proximity to the extensive Los Angeles refining market, and trades in accordance with that local market, which competes with waterborne crude imports.

In 2016 , the WTI spot price averaged approximately $43 per Bbl, compared with approximately $48 in 2015. Monthly average WTI spot prices during 2016 ranged from a high of $52 per Bbl in December to a low of $30 per Bbl in February .

Our Michigan properties have favorable natural gas supply and demand characteristics due to their Northeastern US location, allowing us to sell our natural gas production at a slight premium to posted prices. Our Rockies area natural gas generally trades at a discount to NYMEX due to its relative location and the regional supply and demand market balances. Prices for natural gas have historically fluctuated widely and many regional markets are aligned with the local supply and demand conditions in those regional markets rather than with the overall U.S. market. Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the inventory in underground storage relative to customer demand. U.S. natural gas prices are also typically higher during the winter period when demand for heating is greatest.

Interest Rate Risk

For the year ended December 31, 2016 , the weighted average debt balance under the RBL Credit Agreement was $1.23 billion. If interest rates on our prime-based debt increased or decreased by 100 basis points, our annual interest cost would have increased or decreased by approximately $12.3 million.

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Item 8. Financial Statements and Supplementary Data.

The information required by this Item 8 is incorporated herein by reference from the consolidated financial statements beginning on page F-1.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our General Partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our General Partner's principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure, and that such information is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the 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 December 31, 2016 at the reasonable assurance level.

Management’s Report on Internal Control Over Financial Reporting

 

The information required by this Item is incorporated by reference from “Management’s Report on Internal Control Over Financial Reporting” located on page F-2.

 

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2016 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information .

There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2016 that has not previously been reported.

77

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Other than the information set forth hereunder, the information required by this Item is incorporated herein by reference to our definitive proxy statement for the 2017 Annual Meeting of Limited Partners (“2017 Proxy Statement”) or will be included in an amendment to this report, which will be filed with the SEC not later than 120 days after December 31, 2016.

Directors and Executive Officers of Breitburn GP LLC

 

The following table sets forth certain information with respect to the members of the board of directors and the executive officers of our General Partner. Executive officers and directors will serve until their successors are duly appointed or elected.

Name		Age		Position with Breitburn GP LLC
Halbert S. Washburn		56		Chief Executive Officer, Director
Mark L. Pease		60		President and Chief Operating Officer
James G. Jackson		52		Executive Vice President and Chief Financial Officer
Gregory C. Brown		65		Executive Vice President, General Counsel and Chief Administrative Officer
W. Jackson Washburn		54		Senior Vice President
Thomas E. Thurmond		43		Senior Vice President
Bruce D. McFarland		60		Vice President and Treasurer
Lawrence C. Smith		63		Vice President, Controller and Chief Accounting Officer
John R. Butler, Jr.*		78		Chairman of the Board
Randall H. Breitenbach		56		Vice Chairman of the Board
David B. Kilpatrick*		67		Director
Gregory J. Moroney*		65		Director
Charles S. Weiss*		64		Director
Donald D. Wolf*		73		Director

* Independent Directors

Item 11. Executive Compensation.

The information required by this Item is incorporated herein by reference to the 2017 Proxy Statement or will be included in an amendment to this report, which will be filed with the SEC not later than 120 days after December 31, 2016 .

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

The information required by this Item is incorporated herein by reference to the 2017 Proxy Statement or will be included in an amendment to this report, which will be filed with the SEC not later than 120 days after December 31, 2016 .

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information required by this Item is incorporated herein by reference to the 2017 Proxy Statement or will be included in an amendment to this report, which will be filed with the SEC not later than 120 days after December 31, 2016 .

Item 14. Principal Accounting Fees and Services.

The information required by this Item is incorporated herein by reference to the 2017 Proxy Statement or will be included in an amendment to this report, which will be filed with the SEC not later than 120 days after December 31, 2016 .

78

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PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) (1) Financial Statements

 

See “Index to the Consolidated Financial Statements” set forth on Page F-1.

(a) (2) Financial Statement Schedules

All schedules are omitted because they are not applicable or the required information is presented in the consolidated financial statements or notes thereto.

(a) (3) Exhibits

The information in the Exhibit Index of this Annual Report on Form 10-K is incorporated in this Item 15(a)(3) by reference.

Item 16. Form 10-K Summary.

Not Applicable.

79

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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:	March 8, 2017	By:	/s/ Halbert S. Washburn
			Halbert S. Washburn
			Chief Executive Officer

80

---

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name		Title		Date
/s/ Halbert S. Washburn		Chief Executive Officer and Director of		March 8, 2017
Halbert S. Washburn		Breitburn GP LLC
		(Principal Executive Officer)
/s/ James G. Jackson		Chief Financial Officer of		March 8, 2017
James G. Jackson		Breitburn GP LLC
		(Principal Financial Officer)
/s/ Lawrence C. Smith		Vice President, Controller and Chief		March 8, 2017
Lawrence C. Smith		Accounting Officer of
		Breitburn GP LLC
		(Principal Accounting Officer)
/s/ John R. Butler, Jr.		Chairman of the Board of		March 8, 2017
John R. Butler, Jr.		Breitburn GP LLC
/s/ Randall H. Breitenbach		Vice Chairman of the Board		March 8, 2017
Randall H. Breitenbach		Breitburn GP LLC
/s/ David B. Kilpatrick		Director of		March 8, 2017
David B. Kilpatrick		Breitburn GP LLC
/s/ Gregory J. Moroney		Director of		March 8, 2017
Gregory J. Moroney		Breitburn GP LLC
/s/ Charles S. Weiss		Director of		March 8, 2017
Charles S. Weiss		Breitburn GP LLC
/s/ Donald D. Wolf		Director of		March 8, 2017
Donald D. Wolf		Breitburn GP LLC

81

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BREITBURN ENERGY PARTNERS LP AND SUBSIDIARIES

INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS

Management's Report on Internal Control Over Financial Reporting	F-2
Report of Independent Registered Public Accounting Firm	F-3
Consolidated Balance Sheets	F-4
Consolidated Statements of Operations	F-5
Consolidated Statements of Comprehensive (Loss) Income	F-6
Consolidated Statements of Cash Flows	F-7
Consolidated Statements of Partners’ Equity	F-8
Notes to Consolidated Financial Statements	F-9
Supplemental Information  (unaudited)	F-52
Exhibit Index

F-1

---

Management’s Report on Internal Control Over Financial Reporting

The management of Breitburn Energy Partners LP (the “Partnership”) is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The term “internal control over financial reporting” is defined as a process designed by, or under the supervision of, the Partnership’s principal executive and principal financial officers, or persons performing similar functions, and effected by the Partnership’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Partnership; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Partnership are being made only in accordance with authorizations of management and directors of the Partnership; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Partnership’s assets that could have a material effect on the financial statements.

Internal control over financial reporting, no matter how well designed, has inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

As required by Rule 13a-15(c) under the Exchange Act, the Partnership’s management, with the participation of our General Partner’s principal executive officers and principal financial officer, assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2016 . In making this assessment, the Partnership’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control Integrated Framework (2013). Based on this assessment, the Partnership’s management, including our General Partner’s principal executive officer and principal financial officer, concluded that, as of December 31, 2016 , the Partnership’s internal control over financial reporting was effective based on those criteria.

 

PricewaterhouseCoopers LLP, the independent registered public accounting firm who audited the consolidated financial statements included in this Annual Report on Form 10-K, has also audited the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2016 , which appears on page F-3.

/s/ Halbert S. Washburn		/s/ James G. Jackson
Halbert S. Washburn		James G. Jackson
Chief Executive Officer of Breitburn GP LLC		Chief Financial Officer of Breitburn GP LLC

F-2

---

Report of Independent Registered Public Accounting Firm

To the Board of Directors of Breitburn GP, LLC and

Unitholders of Breitburn Energy Partners LP

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, comprehensive (loss) income, partners’ equity and cash flows present fairly, in all material respects, the financial position of Breitburn Energy Partners LP and its subsidiaries at December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

The accompanying consolidated financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 2 to the financial statements, on May 15, 2016, the Partnership and 21 of its subsidiaries filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code. Uncertainties inherent in the bankruptcy process raise substantial doubt about the Partnership’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

March 8, 2017

F-3

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Breitburn Energy Partners LP and Subsidiaries

(Debtor-in-possession)

Consolidated Balance Sheets

		December 31,
Thousands of dollars		2016				2015
ASSETS
Current assets
Cash		$	71,124			$	10,464
Accounts and other receivables, net (note 3)		549,544				128,589
Derivative instruments (note 5)		—				439,627
Related party receivables (note 6)		860				2,274
Inventory		998				926
Prepaid expenses and other current assets		8,230				6,447
Total current assets		630,756				588,327
Equity investments		7,160				6,567
Property, plant and equipment
Oil and natural gas properties (note 4)		7,907,136				7,898,117
Other property, plant and equipment (note 4)		192,724				188,795
		8,099,860				8,086,912
Accumulated depletion, depreciation and impairment (note 7)		(4,686,214		)		(4,154,030		)
Net property, plant and equipment		3,413,646				3,932,882
Other long-term assets
Derivative instruments (note 5)		—				226,764
Other long-term assets (note 8)		63,846				80,847
Total assets		$	4,115,408			$	4,835,387
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	47,838			$	50,412
Current portion of long-term debt (note 9)		1,198,259				154,000
Derivative instruments (note 5)		—				4,462
Distributions payable		—				733
Current asset retirement obligation		5,905				2,341
Revenue and royalties payable		37,271				35,462
Wages and salaries payable		11,057				21,654
Accrued interest payable		21,064				19,517
Production and property taxes payable		15,340				24,292
Other current liabilities		17,466				5,133
Total current liabilities		1,354,200				318,006
Liabilities subject to compromise (note 2)		1,879,176				—
Credit agreement (note 9)		—				1,075,000
Senior notes, net (note 9)		—				1,752,194
Other long-term debt (note 9)		3,094				3,148
Total long-term debt (note 9)		3,094				2,830,342
Deferred income taxes		2,771				3,844
Asset retirement obligation (note 11)		252,589				252,037
Derivative instruments (note 5)		—				255
Other long-term liabilities		17,551				25,008
Total liabilities		3,509,381				3,429,492
Commitments and contingencies (note 13)
Equity:
Series A cumulative redeemable preferred units, 8.0 million units issued and outstanding at December 31, 2016 and 2015 (note 14)		193,215				193,215
Series B perpetual convertible preferred units, 49.6 million and 48.8 million units issued and outstanding at December 31, 2016 and 2015, respectively (note 14)		359,611				353,471
Common units, 213.8 million and 213.5 million units issued and outstanding at December 31, 2016 and 2015, respectively (note 14)		45,158				852,114
Accumulated other comprehensive income (loss) (note 15)		1,032				(229		)
Total partners' equity		599,016				1,398,571
Noncontrolling interest		7,011				7,324
Total equity		606,027				1,405,895
Total liabilities and equity		$	4,115,408			$	4,835,387

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Breitburn Energy Partners LP and Subsidiaries

(Debtor-in-possession)

Consolidated Statements of Operations

		Year Ended December 31,
Thousands of dollars, except per unit amounts		2016				2015				2014
Revenues and other income items:
Oil, natural gas and natural gas liquid sales		$	504,254			$	645,272			$	855,820
(Loss) gain on commodity derivative instruments, net (note 5)		(53,091		)		438,614				566,533
Other revenue, net		17,842				24,829				7,616
Total revenues and other income items		469,005				1,108,715				1,429,969
Operating costs and expenses:
Operating costs		363,926				455,189				355,681
Depletion, depreciation and amortization		318,528				460,047				291,709
Impairments of oil and natural gas properties (note 7)		283,270				2,377,615				149,000
Impairment of goodwill (note 7)		—				95,947				—
General and administrative expenses		86,988				98,999				86,949
Restructuring costs (note 18)		4,303				6,364				—
(Gain) loss on sale of assets (note 4)		(11,203		)		(8,864		)		663
Total operating costs and expenses		1,045,812				3,485,297				884,002
Operating (loss) income		(576,807		)		(2,376,582		)		545,967
Interest expense, net of capitalized interest (note 9)		148,214				203,027				126,960
Loss (gain) on interest rate swaps (note 5)		2,021				2,691				(490		)
Other income, net		(357		)		(814		)		(1,746		)
Reorganization items, net (note 2)		91,156				—				—
(Loss) income before taxes		(817,841		)		(2,581,486		)		421,243
Income tax (benefit) expense		(1,708		)		1,527				(73		)
Net (loss) income		(816,133		)		(2,583,013		)		421,316
Less: Net (loss) income attributable to noncontrolling interest		(1,182		)		326				(17		)
Net (loss) income attributable to the partnership		(814,951		)		(2,583,339		)		421,333
Less: Distributions to Series A preferred unitholders		6,142				16,500				10,083
Less: Non-cash distributions to Series B preferred unitholders		11,744				20,817				—
Less: Net income attributable to participating units		—				—				5,348
Less: Distributions on participating units in excess of earnings		—				1,731				—
Net (loss) income used to calculate basic and diluted net (loss) income per unit		$	(832,837	)		$	(2,622,387	)		$	405,902
Basic net (loss) income per unit (note 14)		$	(3.90	)		$	(12.39	)		$	3.04
Diluted net (loss) income per unit (note 14)		$	(3.90	)		$	(12.39	)		$	3.02
Weighted average number of units used to calculate basic and diluted net (loss) income per unit (in thousands):
Basic		213,755				211,575				133,451
Diluted		213,755				211,575				134,206

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Breitburn Energy Partners LP and Subsidiaries

(Debtor-in-possession)

Consolidated Statements of Comprehensive (Loss) Income

		Year Ended December 31,
Thousands of dollars		2016				2015				2014
Net (loss) income		$	(816,133	)		$	(2,583,013	)		$	421,316
Other comprehensive income (loss), net of tax:
Change in fair value of available-for-sale securities (a)		986				(402		)		(189		)
Pension and post-retirement benefits actuarial gain (loss) (b)		1,145				677				(473		)
Total other comprehensive income (loss), net of tax		2,131				275				(662		)
Total comprehensive (loss) income		(814,002		)		(2,582,738		)		420,654
Less: Comprehensive (loss) income attributable to noncontrolling interest		(313		)		438				(287		)
Comprehensive (loss) income attributable to the partnership		$	(813,689	)		$	(2,583,176	)		$	420,941

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Breitburn Energy Partners LP and Subsidiaries

(Debtor-in-possession)

Consolidated Statements of Cash Flows

		Year Ended December 31,
Thousands of dollars		2016				2015				2014
Cash flows from operating activities
Net (loss) income		$	(816,133	)		$	(2,583,013	)		$	421,316
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization		318,528				460,047				291,709
Impairments of oil and natural gas properties		283,270				2,377,615				149,000
Impairment of goodwill		—				95,947				—
Unit-based compensation expense		24,693				26,805				23,387
Loss (gain) on derivative instruments		55,112				(435,923		)		(567,024		)
Derivative instrument settlement receipts		172,199				494,234				26,806
Income from equity affiliates, net		(593		)		(104		)		178
Deferred income taxes		(1,074		)		1,269				(174		)
(Gain) loss on sale of assets		(11,203		)		(8,864		)		663
Non-cash reorganization items		47,632				—				—
Amortization and write-off of debt issuance costs		24,959				22,768				7,950
Other		5,340				(6,626		)		(1,746		)
Changes in net assets and liabilities:
Accounts receivable and other assets		4,284				35,367				41,754
Inventory		(72		)		2,801				163
Net change in related party receivables and payables		1,414				188				142
Accounts payable and other liabilities		66,104				(45,806		)		(36,369		)
Net cash provided by operating activities		174,460				436,705				357,755
Cash flows from investing activities
Property acquisitions, net of cash acquired (note 4)		(8,882		)		(18,201		)		(401,465		)
Capital expenditures		(75,576		)		(269,350		)		(417,755		)
Proceeds from sale of assets		12,705				14,547				499
Proceeds from sale of available-for-sale securities		6,389				3,875				—
Purchases of available-for-sale securities		(7,064		)		(4,021		)		—
Other		—				(853		)		(18,283		)
Net cash used in investing activities		(72,428		)		(274,003		)		(837,004		)
Cash flows from financing activities
Proceeds from issuance of preferred units, net		—				337,238				193,215
Proceeds from issuance of common units, net		—				3,008				277,613
Distributions to preferred unitholders		(5,501		)		(16,502		)		(9,350		)
Distributions to common unitholders		—				(126,188		)		(264,585		)
Proceeds from issuance of long-term debt, net		38,260				1,378,338				2,457,600
Repayments of long-term debt		(69,001		)		(1,711,500		)		(1,785,000		)
Senior note redemption		—				—				(352,531		)
Principal payments on capital lease obligations		(39		)		—				—
Change in bank overdraft		(75		)		11				(2,434		)
Debtor-in-possession debt issuance costs		(4,997		)		—				—
Debt issuance costs		(19		)		(29,271		)		(25,109		)
Net cash (used in) provided by financing activities		(41,372		)		(164,866		)		489,419
Increase (decrease) in cash		60,660				(2,164		)		10,170
Cash beginning of period		10,464				12,628				2,458
Cash end of period		$	71,124			$	10,464			$	12,628

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Breitburn Energy Partners LP and Subsidiaries

(Debtor-in-possession)

Consolidated Statements of Partners’ Equity

		Units																					Accumulated
Thousands		Preferred Series A			Preferred Series B			Common			Preferred Series A				Preferred Series B				Common				Other Comprehensive Loss				Partner's Equity
Balance, December 31, 2013		—			—			119,170			$	—			$	—			$	1,989,820			$	—			$	1,989,820
Sales of Series A preferred units		8,000			—			—			193,215				—				—				—				193,215
Sales of common units		—			—			15,272			—				—				277,605				—				277,605
Distributions on Series A preferred units		—			—			—			(10,083		)		—				—				—				(10,083		)
Distributions on common units		—			—			—			—				—				(260,958		)		—				(260,958		)
Common units issued for acquisitions		—			—			75,837			—				—				1,131,146				—				1,131,146
Common units issued under incentive plans		—			—			615			—				—				17,985				—				17,985
Distributions paid on unissued units under incentive plans		—			—			—			—				—				(3,626		)		—				(3,626		)
Unit-based compensation		—			—			—			—				—				3,246				—				3,246
Net income attributable to the partnership		—			—			—			10,083				—				411,250				—				421,333
Other comprehensive loss		—			—			—			—				—				—				(392		)		(392		)
Balance, December 31, 2014		8,000			—			210,894			193,215				—				3,566,468				(392		)		3,759,291
Sales of Series B preferred units		—			46,667			—			—				337,238				—				—				337,238
Sales of common units		—			—			544			—				—				3,115				—				3,115
Distributions on Series A preferred units		—			—			—			(16,500		)		—				—				—				(16,500		)
Distributions paid-in-kind Series B preferred units		—			2,164			—			—				—				—				—				—
Distributions paid-in-kind common units		—			—			448			—				(3,359		)		3,359				—				—
Distributions payable on Series B preferred units		—			—			—			—				(1,225		)		—				—				(1,225		)
Distributions on common units		—			—			—			—				—				(123,217		)		—				(123,217		)
Common units issued under incentive plans		—			—			1,595			—				—				28,500				—				28,500
Distributions paid on unissued units under incentive plans		—			—			—			—				—				(2,971		)		—				(2,971		)
Unit-based compensation		—			—			—			—				—				(2,484		)		—				(2,484		)
Net loss attributable to the partnership		—			—			—			16,500				20,817				(2,620,656		)		—				(2,583,339		)
Other comprehensive income		—			—			—			—				—				—				163				163
Balance, December 31, 2015		8,000			48,831			213,481			193,215				353,471				852,114				(229		)		1,398,571
Distributions on Series A preferred units		—			—			—			(6,142		)		—				—				—				(6,142		)
Distributions paid-in-kind Series B preferred units		—			819			—			—				—				—				—				—
Distributions paid-in-kind common units		—			—			163			—				(1,225		)		1,225				—				—
Distributions payable on Series B preferred units		—			—			—			—				(4,379		)		—				—				(4,379		)
Common units issued under incentive plans		—			—			145			—				—				1,583				—				1,583
Unit-based compensation		—			—			—			—				—				23,073				—				23,073
Net loss attributable to the partnership		—			—			—			6,142				11,744				(832,837		)		—				(814,951		)
Other comprehensive income		—			—			—			—				—				—				1,261				1,261
Balance, December 31, 2016		8,000			49,650			213,789			$	193,215			$	359,611			$	45,158			$	1,032			$	599,016

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Notes to Consolidated Financial Statements

1. Organization

Organization

We are a Delaware limited partnership. Our general partner is Breitburn GP LLC, a wholly-owned Delaware limited liability company (the “General Partner”), and the board of directors of our General Partner (the “Board”) has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly-owned subsidiary, Breitburn Operating LP (“BOLP”), BOLP’s general partner, Breitburn Operating GP LLC (“BOGP”), and through BOLP’s operating subsidiaries. Our wholly-owned subsidiary, Breitburn Management Company LLC (“Breitburn Management”), manages our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. See Note 6 for information regarding our relationship with Breitburn Management. Our wholly-owned subsidiary, Breitburn Finance Corporation (“Breitburn Finance”), is incorporated under the laws of the State of Delaware. Breitburn Finance has no assets or liabilities, and its activities are limited to co-issuing debt securities and engaging in other activities incidental thereto. Our wholly-owned subsidiary, Breitburn Collingwood Utica LLC (“Breitburn Utica”), holds certain non-producing oil and gas zones in the Collingwood-Utica shale play in Michigan and is classified as an unrestricted subsidiary under our credit facilities. We own 100% of our General Partner, BOLP, Breitburn Management, Breitburn Finance and Breitburn Utica.

Chapter 11 Cases

On May 15, 2016 (the “Chapter 11 Filing Date”), we and certain of our subsidiaries filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York. See Note 2 for a discussion of the Chapter 11 Cases (as defined in Note 2).

The accompanying consolidated financial statements have been prepared assuming that we will continue as a going concern, which contemplates continuity of operations, the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. 

See Note 2 for a discussion of our liquidity and ability to continue as a going concern.

2.  Chapter 11 Cases and Liquidity

Chapter 11 Cases

On May 15, 2016, we and 21 of our subsidiaries (collectively, the “Debtors”) filed voluntary petitions for relief (collectively, the “Chapter 11 Petitions” and the cases commenced thereby, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The Chapter 11 Cases are being jointly administered under the caption In re Breitburn Energy Partners LP, et al, Case No. 16-11390. No trustee has been appointed and we continue to manage ourselves and our affiliates and operate our businesses as “debtors in possession” subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. To assure ordinary course operations, we received approval from the Bankruptcy Court on a variety of “first day” motions, including motions that authorize us to maintain our existing cash management system, to secure debtor-in-possession financing and other customary relief.

In connection with the Chapter 11 Cases, BOLP entered into the Debtor-in-Possession Credit Agreement, dated as of May 19, 2016, among itself, as borrower, Breitburn Energy Partners LP, as parent guarantor, the financial institutions from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender (the “DIP Credit Agreement”). The other Debtors have guaranteed all obligations under the DIP Credit Agreement. See Note 9 for a discussion of the DIP Credit Agreement. On December 13, 2016, the Bankruptcy Court entered an order approving that certain First Amendment to the DIP Credit Agreement, effective as of December 15, 2016, by and among the DIP Borrower, the lenders party thereto (the “DIP Lenders”) and the Administrative Agent (the “First Amendment”). The First Amendment, among other things, (i) extended the DIP Credit Agreement’s scheduled

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maturity date to June 30, 2017, (ii) increased certain pricing, (iii) increased the committed amount available under the DIP Credit Agreement from $75 million to $150 million, (iv) increased the letter of credit sublimit from $50 million to $100 million and (v) provided for the payment of certain fees to the Administrative Agent and the DIP Lenders.

ASC 852-10, Reorganizations , applies to entities that have filed a petition for relief under chapter 11 of the Bankruptcy Code. In accordance with ASC 852-10, transactions and events directly associated with the reorganization are required to be distinguished from the ongoing operations of the business. In addition, the guidance requires changes in the accounting and presentation of liabilities, as well as expenses and income directly associated with the Chapter 11 Cases.

The commencement of the Chapter 11 Cases resulted in the acceleration of the Debtors’ obligations under the Third Amended and Restated Credit Agreement, dated as of November 19, 2014, by and among BOLP, as borrower, Breitburn Energy Partners LP, as parent guarantor, the lenders from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender (as amended, the “RBL Credit Agreement”), and the indentures governing our 9.25% Senior Secured Second Lien Notes due 2020 (“Senior Secured Notes”), our 8.625% Senior Notes due 2020 (“2020 Senior Notes”) and our 7.875% Senior Notes due 2022 (“2022 Senior Notes” and together with the 2020 Senior Notes, the “Senior Unsecured Notes”). Any efforts to enforce such obligations are automatically stayed as a result of the filing of the Chapter 11 Petitions and the holders’ rights of enforcement in respect of these obligations are subject to the applicable provisions of the Bankruptcy Code. See Note 9 for a discussion of the RBL Credit Agreement (which has been reclassified from long-term debt to current portion of long-term debt on our consolidated balance sheets) and our Senior Secured Notes and Senior Unsecured Notes (which have been reclassified from long-term debt to liabilities subject to compromise on our consolidated balance sheets).

We are making adequate protection payments with respect to the RBL Credit Agreement, reflected in interest expense, net of capitalized interest on the consolidated statements of operations, consisting of the payment of interest (at the default rate) and the payment of all reasonable fees and expenses provided for in the RBL Credit Agreement. We are also making adequate protection payments with respect to the Senior Secured Notes in the form of the payment of all reasonable fees and expenses of professionals retained by the holders of the Senior Secured Notes.

The commencement of the Chapter 11 Cases also resulted in a termination right by our counterparties on our commodity and interest rate derivative instruments. See Note 5 for a discussion of the derivative instruments, which were terminated, and resulted in $460.0 million of estimated derivative instrument settlements receivable and $4.1 million of estimated derivative instrument settlements payable, reflected in accounts and other receivables, net and other current liabilities on the consolidated balance sheet at December 31, 2016 , respectively.

Effect of Filing on Creditors and Unitholders

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 (each, as defined below). 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. As a consequence of the commencement of the Chapter 11 Cases, such interest payments have not been made, and are classified as liabilities subject to compromise on the consolidated balance sheet at December 31, 2016 .

On May 15, 2016, we filed the Chapter 11 Petitions. Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities and post-petition liabilities must be satisfied in full before the holders of our Series A Preferred Units, Series B Preferred Units and common units representing limited partner interests in us (“Common Units”) are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or unitholders, if any, will not be determined until confirmation and implementation of a plan of reorganization. No assurance can be given as to what distributions, if any, will be made to each of these constituencies or the nature thereof. As discussed below, if certain requirements of the Bankruptcy Code are met, a plan of reorganization can be confirmed notwithstanding its rejection or deemed rejection by the holders of our Series A Preferred Units, Series B Preferred Units and Common Units and notwithstanding the fact that such holders do not receive or retain any property on account of their equity interests under the plan. Because of such possibilities, the value of our securities, including our Series A Preferred Units, Series B Preferred Units and Common Units, is highly

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speculative. We believe it is highly likely that our Series A Preferred Units, Series B Preferred Units and Common Units will be canceled in our Chapter 11 Cases and that the holders thereof will not receive any distribution on account of their holdings.

Executory Contracts . Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease, but may give rise to a pre-petition general unsecured claim for damages caused by such deemed breach. The assumption of an executory contract or unexpired lease generally requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. By order of the Bankruptcy Court dated December 12, 2016, the Debtors assumed all of their executory contracts and unexpired leases related to their oil and gas operations to the extent such contracts and leases constituted commercial property leases under the purview of the Bankruptcy Code.

Process for Plan of Reorganization . In order to successfully emerge from Chapter 11, the Debtors will need to obtain confirmation by the Bankruptcy Court of a plan of reorganization that satisfies the requirements of the Bankruptcy Code. A plan of reorganization generally provides for how pre-petition obligations and equity interests will be treated in satisfaction and discharge thereof, and provides for the means by which the plan of reorganization will be implemented.

Fresh Start Accounting . We may be required to adopt fresh start accounting upon emergence from Chapter 11. Adopting fresh start accounting would result in the allocation of the reorganization value to individuals assets based on their estimated fair values. The enterprise value of the equity of the emerging company is based on several assumptions and inputs contemplated in the future projections of the plan of reorganization and are subject to significant uncertainties. We currently cannot estimate the potential financial effect of fresh start accounting on our consolidated financial statements upon the emergence from Chapter 11, although we would expect to recognize material adjustments upon implementation of fresh-start accounting guidance upon emergence pursuant to a plan of reorganization. The assumptions for which there is a reasonable possibility of material impact affecting the reorganization value include management’s assumptions and capital expenditure plans related to the estimation of our oil and gas reserves.

Debtors Condensed Combined Financial Statements. Two of our subsidiaries, ETSWDC and Breitburn Collingwood Utica LLC, are non-debtors (“Non-Debtors”). Accordingly, these entities will be accounted for under GAAP for entities not in bankruptcy and outside the scope of ASC 852. The Non-Debtors are minor subsidiaries, and, as such, we have not presented Debtors Condensed Combined Financial Statements.

Costs of Reorganization

The Debtors have incurred and will continue to incur significant costs associated with the Chapter 11 Cases. The amount of these costs, which are being expensed as incurred, are expected to significantly affect our results. The following table summarizes the components included in reorganization items, net on our consolidated statements of operations for the year ended December 31, 2016 :     

		Year Ended
Thousands of dollars		December 31, 2016
Debt discounts/premiums and issuance costs		$	48,832
Advisory and professional fees		36,075
DIP Credit Agreement debt issuance costs		6,797
Other		(548		)
Reorganization items, net		$	91,156

We use this category to reflect the net expenses and gains and losses that are the result of the reorganization and restructuring of the business. Professional fees included in reorganization items, net represent professional fees for post-petition expenses. Deferred financing costs and unamortized discounts are related to the Senior Secured Notes and Senior Unsecured Notes (together, the “Senior Notes”), and are included in reorganization items, net as we believe these

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debt instruments will be impacted by the Chapter 11 Cases. As of December 31, 2016 , we had $11.6 million of accrued reorganization costs included in accounts payable on the consolidated balance sheet, consisting primarily of advisory and professional fees.

Liabilities Subject to Compromise

Liabilities subject to compromise in our consolidated financial statements include pre-petition liabilities that may be affected by a plan of reorganization at the amounts expected to be allowed, even if they may be settled for lesser amounts. If there is uncertainty about whether a secured claim is under-secured, or will be impaired under the plan of reorganization, the entire amount of the claim is included in liabilities subject to compromise. Differences between liabilities we have estimated and the claims to be filed will be investigated and resolved in connection with the claims resolution process in the Chapter 11 Cases. We will continue to evaluate these liabilities throughout the Chapter 11 Cases and adjust amounts as necessary. Such adjustments may be material.

Our consolidated financial statements include amounts classified as liabilities subject to compromise that we believe the Bankruptcy Court will allow as claim amounts resulting from the Debtors’ rejection of various executory contracts and unexpired leases and defaults under the debt agreements. Additional amounts may be included in liabilities subject to compromise in future periods if other executory contracts and unexpired leases are rejected. Conversely, the Debtors expect that the assumption of certain executory contracts and unexpired leases may convert certain liabilities currently shown in our financial statements as subject to compromise to post-petition liabilities. Due to the uncertain nature of many of the potential claims, the magnitude of such claims is not reasonably estimable at this time. Such claims may be material. The RBL Credit Agreement was fully collateralized at the Chapter 11 Filing Date and, as a result, has been classified as current portion of long-term debt on our consolidated balance sheets, rather than being classified as liabilities subject to compromise.

The following table summarizes the components of liabilities subject to compromise included in our consolidated balance sheet as of December 31, 2016 :

		As of
Thousands of dollars		December 31, 2016
Senior Unsecured Notes		$	1,155,000
Senior Secured Notes		650,000
Accrued interest payable		61,908
Accounts payable		5,294
Distributions payable		6,974
Total liabilities subject to compromise		$	1,879,176

Liquidity and Ability to Continue as a Going Concern

Although we believe our cash on hand, cash flow from operations and borrowings available under the DIP Credit Agreement will be adequate to meet the operating costs of our existing business, there are no assurances that we will have sufficient liquidity to continue to fund our operations or allow us to continue as a going concern until a plan of reorganization is confirmed by the Bankruptcy Court and becomes effective, and thereafter. Our long-term liquidity requirements, the adequacy of our capital resources and our ability to continue as a going concern are difficult to predict at this time and ultimately cannot be determined until a plan of reorganization has been confirmed, if at all, by the Bankruptcy Court. In addition, we have incurred and continue to incur significant professional fees and costs in connection with the preparation and administration of the Chapter 11 Cases, including the fees and expenses of the professionals retained by two statutory committees appointed in the Chapter 11 Cases. We are making adequate protection payments with respect to the lenders under the RBL Credit Agreement consisting of the payment of interest (at the default rate) and the payment of all reasonable fees and expenses of professionals retained by our lenders, as provided for in the RBL Credit Agreement. We are also making adequate protection payments with respect to the Senior Secured Notes in the form of the payment of all reasonable fees and expenses of professionals retained by the holders of the Senior Secured Notes. We anticipate that we will continue to incur significant professional fees and costs during the pendency of the Chapter 11 Cases.

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Given the uncertainty surrounding the Chapter 11 Cases, there is substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of the Chapter 11 Cases. In particular, the consolidated financial statements do not purport to show (i) as to assets, their realizable value on a liquidation basis or their fair value or their availability to satisfy liabilities; (ii) as to certain pre-petition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (iii) as to unitholders’ equity accounts, the effect of any changes that may be made in our capitalization; or (iv) as to operations, the effect of any changes that may be made to our business. While operating as debtors in possession under chapter 11 of the Bankruptcy Code, the Debtors may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected in our consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a plan of reorganization could materially change the amounts and classifications in our historical consolidated financial statements.

In addition to the uncertainty resulting from the Chapter 11 Cases, oil and natural gas prices continue to remain low historically. In 2016, the WTI posted price averaged approximately $43 per Bbl, compared with $48 per Bbl in 2015 and $93 per Bbl in 2014. In 2016, the Henry Hub posted price averaged approximately $2.51 per MMBtu, compared with $2.62 per MMBtu in 2015 and $4.37 per MMBtu in 2014. Our revenue, profitability and cash flow are highly sensitive to movements in oil and natural gas prices. Sustained depressed prices of oil and natural gas will materially adversely affect our assets, development plans, results of operations and financial condition. The filing of the Chapter 11 Petitions triggered an event of default under each of the agreements governing our derivative transactions. As a result, our counterparties were permitted to terminate, and did terminate, all outstanding derivative transactions. As of December 31, 2016, none of our estimated future production was covered by commodity derivatives, and we may not be able to enter into commodity derivatives covering our estimated future production on favorable terms or at all. As a result, we have significant exposure to fluctuations in oil and natural gas prices and our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, results of operations and financial condition.

If our future sources of liquidity are insufficient, we could face substantial liquidity constraints and be unable to continue as a going concern and will likely be required to implement further cost reductions, significantly reduce, delay or eliminate capital expenditures, seek other financing alternatives or seek the sale of some or all of our assets. If we (i) continue to limit, defer or eliminate future capital expenditure plans, (ii) are unsuccessful in developing reserves and adding production through our capital program or (iii) implement cost-cutting efforts that are too overreaching, the value of our oil and natural gas properties and our financial condition and results of operations could be adversely affected. We have been managing our operating activities and liquidity carefully in light of the uncertainty regarding future oil and natural gas prices and the Chapter 11 Cases. To fund our capital expenditures, we will be required to use cash on hand, cash generated from our operations or borrowings under the DIP Credit Agreement, or some combination thereof. We expect our full year 2017 capital spending program to be approximately $100 million , compared with approximately $65 million in 2016, approximately $209 million in 2015 and approximately $389 million in 2014. We anticipate that 60% of our total capital spending will be focused on drilling and rate-generating projects and CO ₂ purchases in our core operating areas of Ark-La-Tex, the Permian Basin and Mid-Continent that are designed to increase or add to production or reserves.

3. Summary of Significant Accounting Policies

Principles of consolidation and basis of presentation

The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2016 and 2015 . These financial statements also include the results of our operations, our changes in comprehensive income (loss), changes in partners’ capital and cash flows for the years ended December 31, 2016 , 2015 , and 2014 .

 

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). All intercompany accounts and transactions have been eliminated in consolidation. In addition, our financial statements assume that we will continue as a going concern, including continuity of operations and the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. 

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The consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Investments in affiliated companies with a 20% or greater ownership interest, and in which we have significant influence but do not have control, are accounted for on an equity basis. Investments in affiliated companies with less than a 20% ownership interest, and in which we do not have control, are accounted for on the cost basis. Investments in which we own greater than a 50% interest and in which we have control are consolidated. Investments in which we own less than a 50% interest but are deemed to have control, or where we have a variable interest in an entity in which we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated.

Certain reclassifications were made to the prior years’ 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 Annual Report on Form 10-K for the fiscal year ended December 31, 2015 as $2.9 million compared to $3.1 million in this report due to $0.2 million in capital lease obligations that were segregated from other long-term liabilities and reclassified to other long-term debt.

Changes in accounting principles

In August 2014, the Financial Accounting Standards Board (“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 amendment was effective for the year ended December 31, 2016. The implementation did not impact our financial position or results of operations, but required management to perform a formal going concern assessment. See Note 2 for a discussion of our liquidity and ability to continue as a going concern.

In April 2015, the 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 changes in accounting principles. The unamortized debt issuance costs of approximately $37.0 million associated with our outstanding Senior Notes (as defined in Note 9), which were formerly presented as a component of other long-term assets on the consolidated balance sheets, were reflected as a reduction to the carrying liability of our Senior Notes. Debt issuance costs associated with the RBL Credit Agreement (as defined in Note 9) remained classified in other long-term assets.

As a result of these changes in accounting principles, the consolidated balance sheet at December 31, 2015 was adjusted as follows:

		As of 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

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During the year ended December 31, 2016 , unamortized debt issuance costs associated with our outstanding Senior Notes were expensed to reorganization items, net on the consolidated statement of operations (see Note 2 and Note 9).

Use of estimates

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including acquisition purchase price allocations, debt subject to acceleration, fair value of derivative instruments, unit-based compensation, pension and post-retirement obligations, future cash flow from oil, NGL and natural gas properties and oil, NGL and natural gas reserve quantities, which are the basis for the calculation of depletion, depreciation and amortization (“DD&A”), asset retirement obligations and impairment of oil, NGL and natural gas properties and goodwill.

Business segment information

We report our operations in one segment because our oil and gas operating areas have similar economic characteristics. We acquire, exploit, develop and produce oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas.

Cash and cash equivalents

 

We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.  Our cash and cash equivalents consist of cash in banks and investments in money market accounts. The majority of cash and cash equivalents are maintained with a major financial institution in the United States. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk.

Accounts and other receivables

Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2016 and 2015 , we had an allowance for doubtful accounts receivable of $2.6 million and $2.1 million , respectively. At December 31, 2016, we had $460.0 million of derivative instrument settlements receivable included in accounts and other receivables, net on the consolidated balance sheet.

Inventory

Our inventory consists of oil held in storage tanks related to our Florida operations pending shipment by barge to the point of sale. Oil inventories are carried at the lower of cost to produce or market price. We match production expenses with oil sales. Production expenses associated with unsold oil inventory are recorded as inventory. When using lower of cost or market to value inventory, market is the net realizable value or the estimated selling price less costs of completion and disposal. We assessed our crude oil inventory at December 31, 2016 and 2015, and we recognized write-downs of $0.8 million and $0.6 million , respectively.

Property, plant and equipment

Oil and natural gas properties

We follow the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred.

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We carry out tertiary recovery methods on certain of our oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Acquisition costs of tertiary injectants, such as purchased CO ₂ , for enhanced oil recovery activities that are used prior to the recognition of proved tertiary recovery reserves are expensed as incurred. After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project. As CO ₂ is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO ₂ recycling costs are expensed as incurred. Likewise, other costs incurred to maintain reservoir pressure are also expensed.

Upon sale or retirement of proved properties, the cost thereof and the DD&A are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, is generally computed on a field-by-field basis where applicable and recognized using the units of production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using the straight-line method over their estimated useful lives, generally over 20 years.

We capitalize interest costs to oil and gas properties on expenditures made in connection with major projects and the drilling and completion of new oil and natural gas wells. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. During 2016 , 2015 and 2014 , interest of $0.1 million , $0.2 million and $0.3 million , respectively, was capitalized and included in our capital expenditures.

Other property, plant and equipment

Buildings and non-oil and gas assets, including property and equipment related to the disposal of salt water at our East Texas fields, are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to 25 years.

In March 2015, we acquired certain CO ₂ producing properties located in Harding County, New Mexico for the purpose of accessing CO ₂ reserves for our tertiary activities (“CO ₂ Assets”). See Note 4 for more information. The lease acquisition and development costs (tangible and intangible) incurred relating to CO ₂ Assets are capitalized. Lease acquisition and any additional development costs are depleted using the units of production method and the tangible equipment are depreciated on a straight-line method over 40 years.

Oil and natural gas reserve quantities

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with the Securities and Exchange Commission (the “SEC”) guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports.

Investments

 

Investments consist of debt and equity securities, all of which are classified as available-for-sale and stated at fair value on our consolidated balance sheet. Accordingly, unrecognized changes in fair value and the related deferred tax effect are excluded from earnings and reported as a separate component within our consolidated statement of other comprehensive income. Changes in fair value of securities sold are computed based on the specific identification of the securities sold, and are reclassified from other comprehensive income into earnings (reflected in other income, net on the consolidated statements of operations) in the period sold.

Pensions and other postretirement benefits

We recognize the overfunded or underfunded status of the pension and postretirement benefit plans as either assets or liabilities on our consolidated balance sheet. A plan’s funded status is the difference between the fair value of the plan assets and the plan’s benefit obligation. The plan’s benefit obligation is based on estimates using management’s best estimate and judgments which includes independent actuarial service assumptions to determine the plan obligation. We

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record the plan’s cost and income – unrecognized losses and gains, unrecognized prior service costs and credits and transition obligations, if any – in our consolidated statement of other comprehensive income until they are amortized into earnings as a component of benefit costs.

Debt issuance costs

The costs incurred to obtain financing are generally capitalized. Debt issuance costs are charged to interest expense over the term of the related debt instrument. With the implementation of Accounting Standards Update ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs , unamortized debt issuance costs associated with our outstanding Senior Notes (as defined in Note 9), which were formerly presented as a component of other long-term assets, were classified as a reduction to the carrying liability amount of our Senior Notes at December 31, 2015.

Asset retirement obligations

We have significant obligations to plug and abandon oil, natural gas and salt water disposal wells and related equipment at the end of oil and natural gas production operations or salt water disposal operations. The fair value of a liability for an asset retirement obligation (“ARO”) is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and recorded as part of DD&A on the consolidated statements of operations. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance.

Revenue recognition

We recognize revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest (“entitlement” method of accounting). We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold. As of December 31, 2016 and 2015 , our natural gas producer imbalance liability was $7.0 million and $11.4 million , respectively, reflected in other long-term liabilities on the consolidated balance sheets.

Impairments

Long-lived assets and finite lived intangible assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. A long-lived asset or finite lived intangible asset is tested for impairment periodically and when events or circumstances indicate that its carrying value may not be recoverable. Under the successful efforts method of accounting, the carrying value of a long-lived asset or finite lived intangible asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Due to the nature of the recoverability test, certain oil and gas properties may have carrying values which exceed their fair values, but an impairment charge is not recognized because their carrying values are less than their undiscounted cash flows. 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, in certain instances, risk-adjusted probable and possible reserves on a held and used basis based in large part on future capital and operating plans. The undiscounted cash flow review includes inputs such as applicable NYMEX forward strip prices, estimated basis price differentials, expenses and capital estimates, volumetric risk weighting and escalation factors.  Management also considers the impact future price changes are likely to have on our future operating plans.

Reserves are calculated based upon reports from third party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Unproved properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. We assess our long-lived assets for impairment generally on a field-by-field basis where applicable. See Note 7 for a discussion of impairments of oil and natural gas assets.

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Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is not amortized, but is tested for impairment annually or whenever indicators of impairment exist and charged to impairments. The analysis of the potential impairment of goodwill is a two step process. Step one of the impairment test consists of comparing the fair value of the reporting unit with the aggregate carrying value, including goodwill. If the carrying value of a reporting unit exceeds the reporting unit’s fair value, step two must be performed to determine the amount, if any, of the goodwill impairment. Step two of the goodwill impairment test consists of comparing the implied fair value of the reporting unit’s goodwill against the carrying value of the goodwill. Determining the implied fair value of goodwill requires the valuation of a reporting unit’s identifiable tangible and intangible assets and liabilities as if the reporting unit had been acquired in a business combination on the testing date. The fair value of the tangible and intangible assets and liabilities is based upon various assumptions including a discounted cash flow approach to value our oil and gas reserves (the “Income Approach”). The Income Approach valuation method requires projections of revenue and operating costs over a multi-year period. The valuation of assets and liabilities in step two is performed only for purposes of assessing goodwill for impairment.

Equity-based compensation

Breitburn Management has had various forms of equity-based compensation under employee compensation plans that are described more fully in Note 16. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period, which is included in general and administrative (“G&A”) expenses and operating expenses on the consolidated statements of operations. We recognize equity-based compensation costs on a straight-line basis over the requisite service periods.

Fair market value of financial instruments

The carrying amount of our cash, accounts receivable, accounts payable, related party receivables and payables, current portion of long-term debt, payables and accrued expenses approximate their respective fair value due to the relatively short term of the related instruments. See Note 9 for a discussion of the fair value of our Senior Notes.

Accounting for business combinations

We account for all business combinations using the acquisition method. Under the acquisition method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets acquired and liabilities assumed are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if material, is recognized as a gain at the time of acquisition. Similarly, the deficit of the fair value of assets acquired and liabilities assumed under the cost of an acquired entity, if material, is recognized as goodwill at the time of acquisition. All purchase price allocations are finalized within one year from the acquisition date.

We recognized $95.9 million of goodwill as part of the final purchase price related to the 2014 QRE Merger, which was fully impaired in 2015.

Concentration of credit risk

 

We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk. At times, such balances may be in excess of the Federal Insurance Corporation insurance limit. As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers and pay vendors on behalf of joint owners for oil and gas services. We periodically monitor our major purchasers’ credit ratings. We enter into commodity and interest rate derivative instruments. Our derivative counterparties are all lenders under the RBL Credit Agreement, and we periodically monitor their credit ratings.

For our properties in Florida, there are a limited number of alternative methods of transportation for our production. Substantially all of our crude oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs or involuntary curtailment of our crude oil production, which could have a negative impact on our future consolidated financial position, results of operations and cash flows.

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Derivatives

FASB Accounting Standards establish accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. These standards require recognition of all derivative instruments as assets or liabilities on our balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. We currently do not designate any of our derivatives as hedges for financial accounting purposes. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities.

Fair value measurement is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date. The objective of fair value measurement is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If we have a principal market for the asset or liability, the fair value measurement shall represent the price in that market, otherwise the price will be determined based on the most advantageous market. See Note 5 for detail on our derivative instruments.

Income taxes

Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided.

We have three wholly-owned subsidiaries and a controlling interest in an additional subsidiary that are subject to corporate income taxes. Deferred income taxes are recorded under the asset and liability method. Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities.

FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize an uncertain tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition that is intended to provide better financial-statement comparability among different companies.

We have concluded that our income tax expense (benefit) and cash paid for federal income taxes for the years ended December 31, 2016 , 2015 and 2014 and our net federal income tax liability as of December 31, 2016 and 2015

were immaterial.

We performed an analysis as of December 31, 2016 and 2015 and concluded that there were no uncertain tax positions requiring recognition in our financial statements.

Net income or loss per unit

FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of Common Unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”) participate in dividends on an equal basis with Common Units; therefore, there is no difference in undistributed earnings allocated to each participating security. Participating securities are not allocated losses in periods where net losses occur. Our 8.25% Series A Cumulative Redeemable Perpetual Preferred Units and 8.0% Series B Perpetual Convertible Preferred Units (collectively, the “Preferred Units”) rank senior to our Common Units with respect to the payment of distributions and, therefore, distributions on Preferred Units are deducted from net income when calculating net income attributable to common unitholders and participating securities. Accordingly, our calculation is prepared on a combined basis and is presented as net income (loss) per Common Unit. See Note 14 for our earnings per Common Unit calculation.

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Environmental expenditures

We review, on an annual basis and when new information becomes available, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. At each of December 31, 2016 and 2015 , we had $0.6 million of undiscounted environmental liabilities accrued that included cost estimates related to the maintenance of ground water monitoring wells associated with certain former well sites in Michigan that are no longer producing.

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 update provides clarifications in the assessment of principal versus agent considerations in the new revenue standard. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update reduces the potential for diversity in practice at initial application of Topic 606 and the cost and complexity of applying Topic 606. In May 2016, the FASB issued ASU 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This update rescinds certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. These ASUs are effective for annual and interim periods beginning after December 15, 2017. The standard permits the use of either the full retrospective or cumulative effect transition method upon adoption. We are assessing the impact that the adoption of these standards will have on our consolidated financial statements.

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. This ASU will primarily be applicable to existing office leases and equipment leasing arrangements with terms in excess of 12 months.

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 future issuances of equity awards. As of December 31, 2016, all unvested equity awards were canceled, and, therefore the adoption of this ASU will not have an impact on our 2017 opening retained earnings. The impact of the reclassification of cash paid for employee tax withholdings from cash flow from operating activities to cash flow from financing activities on the consolidated statements of cash flows will not be significant.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses: Measurement of Credit Losses on Financial Instruments. The objective of this update is to provide more decision-useful information about the expected credit

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losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The amendments in this update replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. ASU 2016-13 is effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted. We are assessing the impact that ASU 2016-13 will have on our consolidated financial statements.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This update was issued to reduce diversity in practice of how certain cash receipts and cash payments are presented and classified in the statement of cash flows, including debt prepayment or debt extinguishment costs, proceeds from the settlement of insurance claims and distributions received from equity method investees. ASU 2016-15 is effective for annual and interim periods beginning after December 15, 2017, with early adoption permitted. We are assessing the impact that ASU 2016-15 will have on our consolidated financial statements.

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. To reduce diversity in practice, this update requires that the statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. ASU 2016-18 is effective for annual and interim periods beginning after December 15, 2017, with early adoption permitted. The adoption of this ASU will impact the reconciliation of beginning and ending cash flow on our statements of cash flows, as it requires the inclusion of restricted cash.

4. Acquisitions and Other Transactions

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

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

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

The fair value measurements of oil and natural gas properties, other assets and ARO are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties, other assets and ARO were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and a market-based weighted average cost of capital rate. ARO assumptions include inputs such as expected economic recoveries of oil and natural gas and time to abandonment. These inputs require significant judgments and estimates by management at the time of the valuation and are subject to change.

2016 Disposition

In March 2016, we completed the sale of certain of our Mid-Continent assets (the “Mid-Continent Sale”) for net proceeds of $11.9 million . The sale included substantially all Mid-Continent properties acquired in the merger with QR Energy, LP in 2014, excluding five wells for which we have asset retirement obligations and over-riding royalty interests

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and royalty interests in an additional 42 wells. This transaction was effective January 1, 2016. We recognized a gain of $11.3 million from the Mid-Continent Sale.

2015 Acquisitions & Other Transactions

On March 31, 2015, we completed the acquisition of certain CO ₂ producing properties located in Harding County, New Mexico (“CO ₂ Assets”), for a total purchase price of $70.5 million (the “CO ₂ Acquisition”), of which $13.7 million was paid in cash at closing and $0.6 million was paid in cash during the fourth quarter of 2015. The purchase price included $70.5 million reflected in other property, plant and equipment on the consolidated balance sheet (including $49.9 million of CO ₂ supply advances and deposits paid in 2013 and 2014 and reclassified from other long-term assets to other property, plant and equipment during the six months ended June 30, 2015 and $5.1 million of intangibles reclassified from intangibles to other property, plant and equipment during the six months ended June 30, 2015) and $0.3 million of ARO reflected in asset retirement obligation on the consolidated balance sheet.

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

In August 2015, we granted a three-year term assignment of our interests in certain oil and gas leases in the Mississippian, Woodford, and Hunton formations in Kingfisher County, Oklahoma for cash consideration of $3.2 million . We reserved all existing wellbores and the production therefrom and reserved an overriding royalty interest equal to the difference between existing lease burdens appearing of record and 20% , which was later sold in December 2015 for cash consideration of $3.6 million .

In September 2015, we entered into an agreement to exchange certain of our non-contiguous acres in Martin County, Texas for non-operated producing assets in Weld County, Colorado and cash consideration of $4.8 million . We recorded a gain of $7.8 million on this transaction. The trade was for all future horizontal and vertical development rights in the oil and gas leases exchanged. We reserved all existing wellbores and the production therefrom in these Martin County, Texas acres.

2014 Acquisitions

QR Energy, LP

On November 19, 2014, we completed the merger with QR Energy, LP, a Delaware limited partnership (“QRE”), in exchange for approximately 71.5 million Common Units and $350 million in cash (the “QRE Merger”). Pursuant to the terms of the merger agreement, QRE merged with a subsidiary of the Partnership, with QRE continuing as the surviving entity and as a direct wholly-owned subsidiary of the Partnership. Immediately thereafter, the Partnership transferred 100% of the limited partner interests of QRE to BOLP. Each outstanding common unit representing a limited partner interest in QRE (a “QRE Common Unit”) and Class B Unit representing a limited partner interest in QRE (a “ QRE Class B Unit”) was converted into the right to receive 0.9856 newly issued Common Units (the “Merger Consideration”). A total of 6,748,067 QRE Class B Units, issuable upon a change of control of QRE, were issued and treated as outstanding and along with 6,133,558 previously issued QRE Class B Units were converted into the right to receive the Merger Consideration. Each outstanding Class C Unit (a “QRE Class C Unit”) of QRE was converted into the right to receive cash in an amount equal to $350 million divided by the number of QRE Class C Units outstanding immediately prior to the effective time of the QRE Merger.

In connection with the consummation of the QRE Merger, the New York Stock Exchange (the “NYSE”) was notified that each outstanding QRE Common Unit was converted into the right to receive the Merger Consideration described above, subject to the terms and conditions of the merger agreement. On November 21, 2014, the NYSE filed a notification of removal from listing on Form 25 with the SEC delisting the QRE Common Units.

In connection with the QRE Merger, we acquired a 59% controlling interest in ETSWDC and have consolidated ETSWDC into our consolidated financial statements. The main purpose of ETSWDC is to dispose of salt water generated as a by-product from oil produced in certain East Texas oil fields.

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The final purchase price for the QRE Merger, which was determined by management with the assistance of outside valuation consulting firms, was allocated to the assets acquired and liabilities assumed as follows:

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

Acquisition-related costs for the QRE Merger were $11.8 million for the year ended December 31, 2014 and are reflected in G&A expenses on the consolidated statement of operations. For the year ended December 31, 2014, we recorded $42.1 million in revenue and $24.9 million in lease operating expenses, including production and property taxes, from the QRE Merger.

On November 19, 2014, we entered into a Transition Services Agreement (“TSA”) with Quantum Resources Management, LLC (“QRM”).  Under the terms of the TSA, each party agreed to provide certain land administrative, accounting, IT and marketing services to the other party. The term of the TSA commenced on November 19, 2014 and terminated on May 19, 2015.

 

In connection with the QRE Merger, we assumed QRE’s 9.25% Senior Notes due 2020 (the “QRE Notes”), with an aggregate principal amount of $300 million , and a carrying amount of $297.0 million , net of $3.0 million of unamortized discount. We recognized the QRE Notes at their fair value at the close of the QRE Merger of $344.1 million . Upon the closing of the QRE Merger, on November 19, 2014, QRE issued notices of redemption to the holders of the QRE Notes, specifying a redemption date of December 19, 2014 for 35% of the QRE Notes at a redemption price of 109.25% and a redemption date of December 22, 2014 for the remaining QRE Notes at a redemption price equal to 117.67% in accordance with the terms of its indenture, plus accrued and unpaid interest to the redemption dates. On November 19, 2014, QRE also placed in trust with the trustee sufficient funds to redeem all of the outstanding QRE Notes and pay accrued and unpaid interest thereon to, but not including, the applicable redemption dates. As a result, on November 19, 2014, QRE was released from its obligations under the QRE Notes and the indenture governing the QRE Notes pursuant to the satisfaction and discharge provisions described therein.

Antares Acquisition

On October 24, 2014, we completed the acquisition of certain oil and gas properties located in the Midland Basin, Texas from Antares Energy Company, a Delaware corporation, in exchange for 4.3 million Common Units and $50.0 million in cash (the “Antares Acquisition”), for a total purchase price of $122.3 million . The final purchase price was allocated to oil and natural gas assets as follows: $110.9 million to unproved properties, $13.1 million to proved properties and $1.7 million to ARO.

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Pro Forma (unaudited)

    

The following unaudited pro forma financial information presents a summary of our combined statements of operations for the year ended December 31, 2014 assuming the QRE Merger was completed on January 1, 2014. The pro forma results reflect the results of combining our statements of operations with the results of operations from the QRE Merger, adjusted for (1) the assumption of ARO and accretion expense for the properties acquired, (2) depletion and depreciation expense applied to the adjusted purchase price of the properties acquired, (3) interest expense on additional borrowings necessary to finance the acquisitions, including the amortization of debt issuance costs, and (4) the effect on the denominator for calculating net income (loss) per unit of common unit issuances necessary to finance the acquisitions. The pro forma financial information is not necessarily indicative of the results of operations if these acquisitions had been effective January 1, 2015 or 2014 . The Antares Acquisition in 2014 was not included in the pro forma information as Antares represented less than 0.1% of our 2014 revenue, and is considered immaterial.

		Pro Forma Year Ended December 31,
Thousands of dollars, except per unit amounts		2014
Revenues		$	1,947,315
Net income attributable to the partnership		542,164
Net income per common unit:
Basic		$	2.56
Diluted		$	2.55

5. Financial Instruments and Fair Value Measurements

Our risk management programs are intended to reduce our exposure to commodity prices and interest rates and to assist with stabilizing cash flows. 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.

Chapter 11 Cases

The filing of the Chapter 11 Petitions triggered an event of default under each of the agreements governing our derivative transactions (“ISDA Agreements”). As a result, our counterparties were permitted to terminate, and did terminate, all outstanding transactions governed by the ISDA Agreements. The termination date for each outstanding transaction is the termination date specified to us by our counterparties.

The derivative transactions are no longer accounted for at fair value under ASC 815, because they were terminated in connection with our filing of the Chapter 11 Petitions and have been evaluated as receivables or payables at termination value. At the termination dates, expected settlement receipts on terminated contracts were reclassified from current and long-term derivative instrument assets to accounts and other receivables, net and expected settlement payments on terminated contracts were reclassified from current and long-term derivative instrument liabilities to other current liabilities on the consolidated balance sheet. As of December 31, 2016 , we had $460.0 million of estimated derivative instrument settlements receivable and $4.1 million in estimated derivative instrument settlements payable, reflected in accounts and other receivables, net and other current liabilities on the consolidated balance sheet, respectively.

All of our derivative counterparties are also lenders, or affiliates of lenders, under the RBL Credit Agreement (see Note 9). In connection with Bankruptcy Court approval of the DIP Credit Agreement, our counterparties were permitted to terminate, and did terminate, all outstanding derivative transactions and to calculate the amounts due to or from the Debtors as a result of such terminations, in accordance with the terms of the governing agreements. Each such counterparty is required to hold any proceeds due to the Debtors in a book entry account maintained by it pursuant to and

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subject to the provisions of the order of the Bankruptcy Court approving the DIP Credit Agreement, with the rights of all of the parties reserved as to the ultimate disposition of the proceeds.

  

Payables due to our counterparties with respect to our derivative obligations constitute secured obligations under the RBL Credit Agreement. Because the RBL Credit Agreement was fully collateralized at the Chapter 11 Filing Date, and is excluded from liabilities subject to compromise and settlement payables due to our counterparties are reflected in accounts payable on the consolidated balance sheets rather than in liabilities subject to compromise.

Fair Value of Derivative Instruments

As discussed above, our derivative instruments were terminated during the year ended December 31, 2016 , and reclassified to accounts and other receivables, net and other current liabilities on the consolidated balance sheet at December 31, 2016 . The following table presents the fair value of our derivative instruments not designated as hedging instruments at December 31, 2015:

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 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 our ISDA Agreements, which allow for netting of oil and natural gas commodity derivative instruments. These derivative instruments are reflected net on the consolidated balance sheets.

During the years ended December 31, 2016 and 2015 , we did not enter into any derivative instruments that required prepaid premiums.

During the years ended December 31, 2016 , 2015 and 2014 , $9.1 million , $6.7 million and $8.5 million , respectively, of premiums paid in 2012 related to oil and gas derivatives settled.

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

Location of gain (loss), thousands of dollars		Oil Commodity Derivatives (a)				Natural Gas Commodity Derivatives (a)				Interest Rate Derivatives (b)				Total Financial Instruments
Year Ended December 31, 2016
Net loss		$	(43,344	)		$	(9,747	)		$	(2,021	)		$	(55,112	)
Year Ended December 31, 2015
Net gain (loss)		$	385,887			$	52,727			$	(2,691	)		$	435,923
Year Ended December 31, 2014
Net gain		$	526,335			$	40,198			$	490			$	567,023

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

(b) Included in loss (gain) 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 other than quoted prices that are included in Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. We consider the over the counter (“OTC”) commodity and interest rate swaps in our portfolio to be Level 2. Level 3 – Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Certain OTC derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. As of December 31, 2016 and 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 years ended December 31, 2016 , 2015 and 2014 . Our policy is to recognize transfers between levels as of the end of the period.

Our assessment of the significance of an input to its fair value measurement requires judgment and can affect the valuation of the assets and liabilities as well as the category within which they are classified.

Derivative Instruments

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 that we receive from the 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 option 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

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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 were estimated using a combined income and market valuation methodology based upon forward commodity prices and volatility curves. The curves were obtained from independent pricing services reflecting broker market quotes. We validated 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.

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Fair Value Hierarchy

The following table sets forth, by level within the hierarchy, the fair value of our financial instrument assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 and 2015 . 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 December 31, 2016
Assets
Available-for-sale securities
Equities		$	1,492			$	—			$	—			$	1,492
Mutual funds		11,229				—				—				11,229
Exchange traded funds		7,675				—				—				7,675
Net assets		$	20,396			$	—			$	—			$	20,396
As of December 31, 2015
Assets (liabilities)
Oil derivative instruments
Oil swaps		$	—			$	552,552			$	—			$	552,552
Oil collars		—				—				29,737				29,737
Oil puts		—				—				17,584				17,584
Natural gas derivative instruments
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

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

		Year End December 31,
		2016								2015								2014
Thousands of dollars		Oil				Natural Gas				Oil				Natural Gas				Oil				Natural Gas
Assets (a):
Beginning balance		$	47,321			$	11,744			$	61,410			$	19,892			$	8,957			$	1,848
Derivative instrument settlements (b)		26,834				2,580				44,647				16,815				4,094				815
(Loss) gain (b)(c)		(74,155		)		(14,324		)		(58,736		)		(24,963		)		37,189				5,357
Purchases (b)(d)		—				—				—				—				11,170				11,872
Ending balance		$	—			$	—			$	47,321			$	11,744			$	61,410			$	19,892

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

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

(c) Represents gain (loss) on mark-to-market of derivative instruments.

(d) 2014 purchases related to derivative instruments novated to us in connection with the QRE Merger.

    

For Level 3 derivatives 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, which potentially subject us to concentrations of credit risk consist principally of accounts receivable, including hedge settlements receivable. Our hedge settlements receivable expose us to credit risk from counterparties. As of December 31, 2016 , our hedge settlements receivable were due from Bank of Montreal, Barclays Bank PLC, BNP Paribas, Canadian Imperial Bank of Commerce, Citibank, N.A, Comerica Bank, Credit Suisse Energy LLC, Credit Suisse International, ING Capital Markets LLC, Fifth Third Bank, JP Morgan Chase Bank N.A., Merrill Lynch Commodities, Inc., Morgan Stanley Capital Group Inc., PNC Bank, N.A, Royal Bank of Canada, The Bank of Nova Scotia, The Toronto-Dominion Bank, MUFG Union Bank N.A. and Wells Fargo Bank, N.A. Our counterparties are all lenders, or affiliates of lenders, that participate in the RBL Credit Agreement. The RBL Credit Agreement is secured by our oil, NGL and natural gas reserves, so we are not required to post any collateral, and we conversely do not receive collateral from our counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to fail to perform in accordance with the terms of the contract. This risk is managed by diversifying our derivatives portfolio. As of December 31, 2016 , each of these financial institutions and/or their parent company had an investment grade credit rating from Moody’s Investors Service and Standard & Poor’s.  

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6. Related Party Transactions

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 provided administrative services to Pacific Coast Energy Company LP (“PCEC”), our predecessor, under an administrative services agreement (“ASA”), 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 six months ended June 30, 2016 and each of the years ended December 31, 2015 , and 2014 , 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 ASA, which became effective on June 30, 2016.

Upon termination of the ASA on June 30, 2016, PCEC was no longer considered a related party, as Breitburn Management and its management team no longer manage or have significant influence over PCEC. At December 31, 2016 and 2015 , we had net current receivables of $0.7 million and $1.7 million , respectively, due from PCEC related to the ASA and employee related costs. At December 31, 2016 and 2015, the receivables due from PCEC were reflected in accounts and other receivables net and related party receivables, respectively, on the consolidated balance sheets. For the years ended December 31, 2016 , 2015 , and 2014 , the monthly charges to PCEC for indirect expenses totaled $4.2 million , $8.4 million and $8.4 million , respectively, and charges for direct expenses including direct payroll and other direct costs totaled $4.9 million , $9.6 million and $10.9 million , respectively.

At December 31, 2016 and 2015 , we had receivables of $0.9 million and $0.1 million , respectively, due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf.

Effective on April 8, 2015, the closing date of private offerings of the Senior Secured Notes and Series B Preferred Units (see Note 9 and Note 14, respectively), Kurt A. Talbot, then Vice Chairman and Co-Head of the Investment Committee of EIG Global Energy Partners (“EIG”), was appointed to the Board. We paid EIG Management Company, LLC, an affiliate of EIG, a transaction fee of $13 million with respect to the purchase of the Senior Secured Notes and a transaction fee of $7 million with respect to the purchase of the Series B Preferred Units. Kurt A. Talbot resigned from the Board in March 2016.

7. Impairments

Long-Lived Assets

We review our oil and gas properties for impairment periodically or when events or circumstances indicate that their

carrying amounts may exceed their fair values and may not be recoverable. Under the successful efforts method of

accounting, the carrying amount of an oil and gas property to be held and used is not recoverable if it exceeds the sum of the

undiscounted cash flows expected to result from the use and eventual disposition of the property. Due to the nature of the

recoverability test, certain oil and gas properties may have carrying values which exceed their fair values, but an impairment

charge is not recognized because their carrying values are less than their undiscounted cash flows. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for market supply and demand conditions for oil and natural gas. For purposes of assessing our oil and gas properties for potential impairment, management reviews the expected undiscounted future cash flows for our total proved and, in certain instances, risk-adjusted probable and possible reserves on a held and used basis based in large part on future capital and operating plans. 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.

Undiscounted future cash flows were forecast using five-year NYMEX forward strip prices at December 31, 2015 and escalated along with expenses and capital starting year six and thereafter at 2% per year. Beginning in 2016, the estimated

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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 where applicable to reflect the commodity price strip used.

For impairment charges, the associated property’s expected future net cash flows were discounted using a market-based long-term weighted average cost of capital rate that approximated 10% at December 31, 2015 and 13% at December 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.

At December 31, 2016, we incorporated the assumptions from our business plan into our impairment reserves analysis. For certain impaired fields, recent operating results incorporated in the business plan resulted in lower production estimates and higher operating cost estimates than previously forecast. Our business plan was prepared with the assumption that we emerge from Chapter 11 and continue to hold and use our assets for their economic lives up to and including final dispositions. There are no material asset sales planned or contemplated in this business plan. Other assumptions and or revisions in our business plan could result in material changes to the undiscounted cash flows used in our impairment analysis. Accordingly, we cannot estimate what impact, if any, other assumptions or courses of action or their probabilities of occurrence could have on our undiscounted cash flows at December 31, 2016.

During the year ended December 31, 2016 , we recorded non-cash impairments related to our oil, NGL and natural gas properties of $283.3 million , including $177.9 million in the Permian Basin, $92.1 million in the Rockies, $5.7 million in the Midwest, $4.2 million in Ark-La-Tex, $2.2 million in the Southeast, and $1.2 million in California. The impairments were primarily related to revisions in our business plan for future production and cost estimates at certain of our lower margin oil properties, as well as the impact that the drop in natural gas prices in the out years had on projected future revenues for certain of our lower margin natural gas properties.

During the year ended December 31, 2015 , we recorded non-cash impairments related to our oil, NGL and natural gas properties of $2.4 billion , including $740.6 million in the Midwest, $512.8 million in Ark-La-Tex, $443.8 million in the Southeast, $256.5 million in the Permian Basin, $213.0 million in California, $147.9 million in the Rockies, and $63.0 million in Mid-Continent. The impairments were primarily due to the impact that the sustained drop in commodity strip prices had on our projected future net revenues.

During the year ended December 31, 2014, we recorded non-cash impairments related to our oil, NGL and natural gas properties of $149.0 million , including $124.8 million in the Southeast, $11.2 million in the Rockies, $8.5 million in the Midwest, $2.3 million in the Permian Basin and $2.2 million in Mid-Continent. The impairments in the Southeast were due to reserve adjustments primarily related to lower crude oil prices and well performance. The Rockies impairments were due to reserve adjustments related to a combination of lower oil prices, well performance and higher expense projections. The Midwest impairments related to lower commodity prices and the write-off of investments associated with expiring leases that we elected not to renew. The Permian Basin and Mid-Continent property impairments related to lower commodity prices.

Management prepared its undiscounted cash flow estimates on a held and used basis which assumes oil and gas properties will be held and used for their economic lives. If a decision is reached to sell a particular asset, that asset would be classified as held for sale and could potentially be impaired if the carrying value exceeded the estimated sales value less the costs of disposal. It is also possible that further periods of prolonged lower commodity prices, future declines in commodity prices, changes to our future plans in response to a final plan of reorganization, or increases in operating costs could result in future impairments. Given the number of assumptions involved in the estimates, estimates as to sensitivities to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable. Favorable changes to some assumptions could have increased the undiscounted cash flows thus further avoiding the need to impair any assets in this period, whereas other unfavorable changes could have caused an unknown number of assets to become impaired. Additionally the oil and gas assets may be further adjusted in the future due to the outcome of Chapter 11 Cases or adjusted to fair value if we are required to apply fresh start accounting upon emergence from Chapter 11.

Goodwill

As of March 31, 2015, we had $95.9 million of goodwill related to the QRE Merger (see Note 4). Due to a decrease in the price of our Common Units during the second quarter of 2015, we performed an impairment assessment. We performed

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both steps of the goodwill impairment test. We concluded that there was no remaining implied fair value attributable to goodwill and recorded a non-cash goodwill impairment charge of $95.9 million during the second quarter of 2015.

8. Other Long-Term Assets

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

		As of December 31,
Thousands of dollars		2016				2015
Debt issuance costs (Note 9)		$	—			$	22,142
Available-for-sale securities		20,396				18,691
Deposit for Jay Field net profit interest obligation		18,263				18,263
Property reclamation deposit		10,738				10,736
Other		14,449				11,015
Total		$	63,846			$	80,847

During the year ended December 31, 2016 , we wrote off $20.4 million of unamortized debt issuance costs associated with the RBL Credit Agreement in connection with the commencement of the Chapter 11 Cases and the reduction of the elected commitment amount under the RBL Credit Agreement. The write-offs were recognized in interest expense, net of capitalized interest on the consolidated statements of operations. See Note 9 for a discussion of the RBL Credit Agreement.

Available-for-sale Securities

Our available-for-sale securities are comprised primarily of equity, mutual funds and exchange traded funds. They consist of investments not classified as trading securities or as held-to-maturity. Our investments are included in other long-term assets on our consolidated balance sheets.

As of December 31, 2016 , we had the following available-for-sale investments outstanding:

						Gross				Gross
Thousands of dollars		Cost Basis				Unrealized Gains				Unrealized Losses				Fair Value
Available-for-sale securities:
Equities		$	1,416			$	164			$	(88	)		$	1,492
Mutual funds		12,838				175				(1,784		)		11,229
Exchange traded funds		5,545				2,158				(28		)		7,675
Total available-for-sale securities		$	19,799			$	2,497			$	(1,900	)		$	20,396

As of December 31, 2015 , we had the following available-for-sale investments outstanding:

						Gross				Gross
Thousands of dollars		Cost Basis				Unrealized Gains				Unrealized Losses				Fair Value
Available-for-sale securities:
Equities		$	2,591			$	141			$	(208	)		$	2,524
Mutual funds		13,276				1,737				(3,823		)		11,190
Exchange traded funds		3,721				1,494				(238		)		4,977
Total available-for-sale securities		$	19,588			$	3,372			$	(4,269	)		$	18,691

During the years ended December 31, 2016 and 2015 , we received $6.4 million and $3.9 million , respectively, in proceeds from the sale of available-for-sale securities, and recognized a realized loss of $0.5 million and $0.1 million , respectively, reflected in other income, net on the consolidated statements of operations.

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We evaluate securities for other than temporary impairment on a quarterly basis and more frequently when economic or market concerns warrant such an evaluation. The unrealized losses in the table above have been outstanding for less than two months. We have evaluated the unrealized losses and have determined that these losses do not represent an other than temporary impairment.

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.

NPI Obligation

We have a net profit interest (“NPI”) related to the Jay Field. Under the arrangement, the NPI is payable after: (i) funds are withheld, to the extent allowable each month under the arrangement, to pay for the NPI holder’s share of future development costs and abandonment obligations, and (ii) we are reimbursed for the NPI holder’s share of excess historical productions costs. Once the NPI holder’s share of the excess historical costs is reimbursed, the NPI will be payable monthly to the extent the NPI for that month exceeds the amount withheld for that month for future development costs and abandonment obligations. The NPI holder’s share of excess historical production costs amounted to $13.6 million and $9.8 million at December 31, 2016 and 2015 , respectively. In addition, we will retain the NPI holder’s shares of future development costs and abandonment obligations, subject to future production, production costs, and capital spending level, which will be paid using the funds withheld. The NPI holder’s share along with our share of the abandonment costs as of December 31, 2016 and 2015 are reflected in asset retirement obligation on the consolidated balance sheet. Under the arrangement, we have the option to deposit into a separate account the funds withheld from the NPI holder for their portion of the future development costs and abandonment obligations. The funds totaled $18.3 million at each of December 31, 2016 and 2015 , which is reflected in other long-term assets on the consolidated balance sheet.

Property Reclamation Deposit

At each of December 31, 2016 and 2015 , we had a property reclamation deposit of $10.7 million , included in other long-term assets, held in an escrow account as security for future abandonment and remediation obligations for the Jay Field. We are required to maintain the escrow account in effect for three years after all abandonment and remediation obligations have been completed. The funds in the escrow account are not to be returned to us until the later of three years after satisfaction of all abandonment obligations or December 31, 2026. At certain dates subsequent to closing, we have the right to request a refund of a portion or all of the property reclamation deposit. Granting of the request is at the seller’s sole discretion. In addition to the cash deposit, we are required to provide letters of credit. At December 31, 2016 and 2015 , we had $22.9 million and $23.4 million in letters of credit related to the property reclamation deposit.

    

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9. Debt

Our debt is detailed in the following table:

		As of December 31,
Thousands of dollars		2016				2015
Credit Agreement		$	1,198,259			$	1,229,000
Promissory note		2,938				2,938
Senior Secured Notes		650,000				650,000
2020 Senior Notes		305,000				305,000
2022 Senior Notes		850,000				850,000
Unamortized debt issuance costs and net discount/premium on Senior Notes (a)		—				(52,806		)
Capital lease obligations		156				210
Total debt		3,006,353				2,984,342
Less: Current portion of long-term debt		(1,198,259		)		(154,000		)
Less: Amounts reclassified to liabilities subject to compromise		(1,805,000		)		—
Total long-term debt		$	3,094			$	2,830,342

(a) In connection with the adoption of ASU 2015-03, unamortized debt issuance costs associated with the Senior Notes at December 31, 2015 of $37.0 million were reclassified from other long-term assets to debt. See Note 3 for a detailed discussion of the adoption of the change in accounting principle. In connection with the Chapter 11 Cases, unamortized debt issuance costs, discounts and premiums on the Senior Notes as of the Chapter 11 Filing Date of May 15, 2016 were expensed and recognized in reorganization items, net on the consolidated statement of operations. See below for more information.

DIP Credit Agreement

In connection with the Chapter 11 Cases, BOLP entered into the DIP Credit Agreement, as borrower, with the lenders party thereto (the “DIP Lenders”) and Wells Fargo, National Association, as administrative agent. The other Debtors have guaranteed all obligations under the DIP Credit Agreement. Pursuant to the terms of the DIP Credit Agreement, the DIP Lenders made available a revolving credit facility in an aggregate principal amount of $75 million , which includes a letter of credit facility available for the issuance of letters of credit in an aggregate principal amount not to exceed a sub-limit of $50 million , and a swingline facility in an aggregate principal amount not to exceed a sub-limit of $5 million , in each case, to mature on the earlier to occur of (A) the effective date of a plan of reorganization in the Chapter 11 Cases or (B) the stated maturity of the DIP Credit Agreement of January 15, 2017. The maturity date of the DIP Credit Agreement may be accelerated upon the occurrence of certain events as set forth therein.

On December 13, 2016, the Bankruptcy Court approved the First Amendment to the DIP Credit Agreement which, among other things, (i) extended the DIP Credit Agreement’s scheduled maturity date to June 30, 2017, (ii) increased certain pricing, (iii) increased the committed amount available under the DIP Credit Agreement from $75 million to $150 million, (iv) increased the letter of credit sublimit from $50 million to $100 million and (v) provided for the payment of certain fees to the Administrative Agent and the DIP Lenders.

At December 31, 2016 , we had no borrowings outstanding and approximately $37.9 million in letters of credit outstanding under the DIP Credit Agreement.

The proceeds of the DIP Credit Agreement may be used: (i) to pay the costs and expenses of administering the Chapter 11 Cases, (ii) to fund our working capital needs, capital improvements, and other general corporate purposes, in each case, in accordance with an agreed budget and (iii) to provide adequate protection to existing secured creditors.

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Acceleration of Debt Obligations

The commencement of the Chapter 11 Cases resulted in the acceleration of the Debtors’ obligations under the RBL Credit Agreement and the acceleration of all obligations with respect to the Senior Secured Notes and the Senior Notes. Any efforts to enforce such obligations are automatically stayed as a result of the filing of the Chapter 11 Petitions and the holders’ rights of enforcement in respect of these obligations are subject to the applicable provisions of the Bankruptcy Code.

RBL Credit Agreement

BOLP, as borrower, and we and our wholly-owned subsidiaries, as guarantors, are party to 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. We entered into the RBL Credit Agreement on November 19, 2014.

On April 8, 2015, in connection with financing and related party transactions with EIG Global Energy Partners, we entered into the First Amendment (the “First Amendment”) to the RBL Credit Agreement (as amended, the “Credit Agreement”). Among other changes, the First Amendment: (i) established a borrowing base of $1.8 billion until the April 1, 2016 scheduled redetermination date subject, starting with the October 1, 2015 scheduled redetermination date, to our having liquidity (inclusive of borrowing base availability) of 10% of the borrowing base; (ii) permitted $650 million of second lien indebtedness; (iii) increased the base rate and LIBOR margins by 0.25%; (iv) added a requirement that we have liquidity (inclusive of borrowing base availability) of 10% of the borrowing base after giving effect to any distribution on our Common Units or voluntary prepayment of second lien indebtedness; and (v) added a requirement that we have liquidity (inclusive of borrowing base availability) of 5% of the borrowing base after giving effect to any distribution on our Series B Preferred Units.

On March 28, 2016, we entered into a Consent (the “Consent”) to the RBL 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 .

 

At the Chapter 11 Filing Date, we had $1.20 billion in unpaid principal outstanding under the RBL Credit Agreement. The RBL Credit Agreement is secured by a first priority security interest in and lien on substantially all of the Debtors’ assets, including the proceeds thereof and after-acquired property. The RBL Credit Agreement was fully collateralized at the Chapter 11 Filing Date. As a result of the automatic acceleration of our obligations under the RBL Credit Agreement as a consequence of the commencement of the Chapter 11 Cases, we reclassified the entire RBL Credit Agreement balance to current portion of long-term debt on the consolidated balance sheet. Any efforts to enforce our payment obligations under the RBL Credit Agreement are automatically stayed as a result of the filing of the Chapter 11 Petitions. At the Chapter 11 Filing Date, we recognized $15.7 million for the full write-off of unamortized debt issuance costs related to the RBL Credit Agreement.

We are required to make adequate protection payments to the lenders under the RBL Credit Agreement, which includes payment of interest (at the default rate) and the payment of all reasonable fees and expenses of professionals retained by our lenders, as provided for in the RBL Credit Agreement. We are recognizing the default interest accrued on the RBL Credit Agreement as interest expense, net of capitalized interest on the consolidated statements of operations, and we are recognizing the adequate protection payments as accrued interest payable on the consolidated balance sheets, rather than in liabilities subject to compromise. At December 31, 2016 , the default interest rate on the RBL Credit Agreement was 7.00% .

As of December 31, 2016 and 2015 , we had $1.20 billion and $1.23 billion , respectively, in indebtedness outstanding under the RBL Credit Agreement. During the year ended December 31, 2016 , we recognized $20.4 million in write-offs of debt issuance costs associated with the RBL Credit Agreement in connection with the commencement of the Chapter 11 Cases and reduction of the elected commitment amount under the RBL Credit Agreement. During the year ended December 31, 2015, we recognized a write-off of  $10.6 million of debt issuance costs related to the reduction of the RBL Credit Agreement borrowing base from  $2.5 billion  to  $1.8 billion  in connection with the EIG financing. The write-offs are reflected in interest expense, net of capitalized interest on the consolidated statement of operations. At

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December 31, 2016 and 2015 , we had zero and $22.1 million , respectively, of unamortized debt issuance costs related to the RBL Credit Agreement.

Borrowings under the RBL Credit Agreement are secured by first-priority liens on and security interests in substantially all of our and certain of our subsidiaries’ assets, representing not less than 80% of the total value of our oil and gas properties.

The carrying value of the RBL Credit Agreement as of December 31, 2016 approximated fair value. We consider the fair value of the RBL Credit Agreement to be Level 2, as it is based on the current active market prime rate.

Promissory Note

ETSWDC, as borrower, has a secured $6.0 million Promissory Note with Texas Capital Bank, NA, with a maturity date of November 13, 2019. At each of December 31, 2016 and 2015 , ETSWDC had $2.9 million outstanding under the Promissory Note. At December 31, 2016 , the 1-month LIBOR interest rate plus an applicable spread was 2.7164% .

Senior Secured Notes

On April 8, 2015, we issued $650 million of 9.25% Senior Secured Second Lien Notes due 2020 (“Senior Secured Notes”) in a private offering to EIG Redwood Debt Aggregator, LP and certain other purchasers at a purchase price of 97% of the principal amount. We received approximately $606.9 million from this offering, net of fees and estimated expenses, which we primarily used to repay borrowings under the RBL Credit Agreement. Interest on the Senior Secured Notes is payable quarterly in March, June, September and December.

We paid $15.0 million in interest on the Senior Secured Notes during the year ended December 31, 2016, for interest incurred during the three months ended March 31, 2016. Since the commencement of the Chapter 11 Cases on May 15, 2016, no interest has been paid to the holders of the Senior Secured Notes. As of December 31, 2016 , the Senior Secured Notes were reflected as liabilities subject to compromise on the consolidated balance sheet, with the carrying value equal to the face value of the notes. The unamortized discount of $16.1 million and the unamortized debt issuance costs of $18.9 million as of the Chapter 11 Filing Date were expensed and recognized in reorganization items, net on the consolidated statements of operations. In addition, as of the Chapter 11 Filing Date, the accrued but unpaid interest expense on the Senior Secured Notes of $7.5 million was reflected as liabilities subject to compromise. No interest expense was recognized on the Senior Secured Notes after the commencement of the Chapter 11 Cases. Unrecognized, contractual interest expense on the Senior Secured Notes for the year ended December 31, 2016 was $37.6 million .

As a result of the filing of the Chapter 11 Cases, the fair value of our Senior Secured Notes at December 31, 2016 cannot be reasonably determined. As of December 31, 2015 , the fair value of our Senior Secured Notes was estimated to be approximately $518 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.

Senior Unsecured Notes

As of December 31, 2016 , we had $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the “2020 Senior Notes”). The 2020 Senior Notes were offered at a discount price of 98.358% , or $300 million . The $5 million discount was being amortized over the life of the 2020 Senior Notes. In addition, as of December 31, 2016 , we had $850 million in aggregate principal amount of 7.875% Senior Notes due 2022 (the “2022 Senior Notes”). Interest on the 2020 Senior Notes and the 2022 Senior Notes is payable twice a year in April and October.

As of December 31, 2016 , the Senior Unsecured Notes were reflected as liabilities subject to compromise on the consolidated balance sheet, with the carrying value equal to the face value of the notes. As of December 31, 2015 , the 2020 Senior Notes had a carrying value of $302.1 million , net of unamortized discount of $2.9 million . As of December 31, 2015 , the 2022 Senior Notes had a carrying value of $854.5 million , net of unamortized premium of $4.5 million . As of December 31, 2015 , unamortized debt issuance costs related to our 2020 Senior Notes were $4.2 million , and unamortized debt issuance costs related to our 2022 Senior Notes were $12.2 million .

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On April 14, 2016, 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. As a consequence of the commencement of the Chapter 11 Cases, such interest payments have not been made, and are classified as liabilities subject to compromise on the consolidated balance sheet at December 31, 2016 .

Since the commencement of the Chapter 11 Cases on May 15, 2016, no interest has been paid to the holders of the Senior Unsecured Notes. As of December 31, 2016 , the Senior Unsecured Notes are reflected as liabilities subject to compromise on the consolidated balance sheet, with the carrying values equal to the face values of the notes. The net unamortized premium of $1.5 million and the unamortized debt issuance costs of $15.4 million as of the Chapter 11 Filing Date were recognized in reorganization items, net on the consolidated statements of operations. In addition, as of the Chapter 11 Filing Date, the accrued but unpaid interest expense on the Senior Unsecured Notes of $54.4 million was reflected as liabilities subject to compromise. No interest expense was recognized on the Senior Unsecured Notes after the filing of the Chapter 11 Petitions. Unrecognized contractual interest expense on the Senior Unsecured Notes for the year ended December 31, 2016 was $58.3 million .

As a result of the filing of the Chapter 11 Cases, the fair value of our Senior Unsecured Notes at December 31, 2016 cannot be reasonably determined. As of December 31, 2015 , the fair value of the 2020 Senior Notes and the 2022 Senior Notes was estimated to be $59 million and $157 million , respectively. 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.

The indentures governing both our 2020 Senior Notes and 2022 Senior Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) sell assets including equity interests in our subsidiaries; (ii) pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in transactions with affiliates; (ix) create unrestricted subsidiaries; or (x) engage in certain business activities.

As of December 31, 2015 , we were in compliance with the covenants on our 2020 Senior Notes and 2022 Senior Notes.

Interest Expense

 

Our interest expense is detailed in the following table:

		Year Ended December 31,
Thousands of dollars		2016				2015				2014
Credit Agreement (including commitment fees) and other long-term debt		$	64,713			$	41,254			$	23,788
Senior Secured Notes (a)		22,547				43,758				—
Senior Unsecured Notes (a)		34,966				93,244				95,662
Amortization of discount/premium and deferred issuance costs (b)		26,137				24,926				7,836
Capitalized interest		(149		)		(155		)		(326		)
Total		$	148,214			$	203,027			$	126,960
Cash paid for interest		$	62,056			$	181,873			$	119,488

(a) The year ended December 31, 2016 reflects interest through the Chapter 11 Filing Date. Unrecognized contractual interest expense on the Senior Secured Notes and the Senior Unsecured Notes for the year ended December 31, 2016 was $37.6 million and $58.3 million , respectively.

(b) The years ended December 31, 2016 and December 31, 2015 include the write-off of $20.4 million and $10.6 million of RBL Credit Agreement debt issuance costs.

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10. Condensed Consolidating Financial Statements

We and Breitburn Finance (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 our Senior Notes. Our only non-guarantor subsidiaries, Breitburn Utica 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, the subsidiary co-issuer, which does not guarantee the Senior Notes, is a wholly-owned finance subsidiary; all of our material subsidiaries are wholly-owned, have guaranteed the Senior Notes, and all of the guarantees are full, unconditional, joint and several.

Each guarantee 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 or 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 in accordance with the applicable indenture,

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

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

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

11. Asset Retirement Obligation

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 that approximated 14% for each of the years ended December 31, 2016 and 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 years ended December 31, 2016 and 2015 , are presented in the following table:

		Year Ended December 31,
Thousands of dollars		2016				2015
Carrying amount, beginning of period		$	254,378			$	238,411
Liabilities added from acquisitions		78				796
Liabilities incurred from drilling		224				2,268
Liabilities settled		(3,162		)		(7,744		)
Liabilities related to divested properties		(8,380		)		(261		)
Revision of estimates		(2,362		)		3,954
Accretion expense		17,718				16,954
Carrying amount, end of period		258,494				254,378
Less: Current portion of ARO		(5,905		)		(2,341		)
Non-current portion of ARO		$	252,589			$	252,037

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12. Pensions and Postretirement Benefits

ETSWDC sponsors a non-contributory defined benefit pension plan and a contributory other post-retirement benefit plan (collectively, the “Plans”) covering substantially all ETSWDC employees who were employed prior to March 31, 2008. Subsequent to March 31, 2008, the Plans were closed to new employees. The tables below set forth the benefit obligation, fair value of plan assets, and the funded status of the Plans; amounts recognized in our financial statements; and the principal weighted average assumptions used. ETSWDC is a Non-Debtor with respect to the Chapter 11 Cases. See Note 2 for a discussion of the Chapter 11 Cases.

    

Obligation and Funded Status

The Plans had accumulated benefit obligations in excess of plan assets at December 31, 2016 and 2015 as follows:

		December 31, 2016								December 31, 2015
Thousands of dollars		Pension Benefits				Postretirement Benefits				Pension Benefits				Postretirement Benefits
Projected benefit obligation		$	22,227			$	1,414			$	25,320			$	3,971
Accumulated benefit obligation		21,917				1,414				24,424				3,971
Fair value of plan assets		15,955				841				20,022				1,468

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The change in the combined projected benefit obligation of the Plans and the change in the assets at fair value are as follows:

		Year Ended December 31, 2016								Year Ended December 31, 2015
Thousands of dollars		Pension Benefits				Postretirement Benefits				Pension Benefits				Postretirement Benefits
Change in Benefit Obligation
Benefit obligation at beginning of year		$	25,320			$	3,971			$	27,829			$	4,240
Service cost		165				31				271				34
Interest cost		905				121				1,014				155
Plan participant contributions		—				31				—				28
Actuarial (gain) loss		221				(24		)		(2,360		)		(333		)
Benefits paid		(1,536		)		(183		)		(1,434		)		(153		)
Estimated lump sums (early retirement incentive program)		(3,500		)		—				—				—
Special termination benefit		376				—				—				—
Effect of curtailment		276				—				—				—
Effect of change to participant contributions		—				(884		)		—				—
Effect of early retirement incentive program		—				(1,053		)		—				—
Effect of settlements		—				(596		)		—				—
Benefit obligation at end of year		22,227				1,414				25,320				3,971
Change in Plan Assets
Fair value of plan assets at beginning of year		20,022				1,468				21,219				1,527
Actual return on plan assets		969				(15		)		(163		)		(63		)
Employer contributions		—				136				400				129
Plan participant contributions		—				31				—				28
Benefits paid		(1,536		)		(183		)		(1,434		)		(153		)
Estimated lump sums (early retirement incentive program)		(3,500		)		—				—				—
Effects of settlements		—				(596		)		—				—
Fair value of plan assets at end of year		15,955				841				20,022				1,468
Underfunded status at end of year		$	(6,272	)		$	(573	)		(5,298		)		(2,503		)

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Amounts Recognized on the Consolidated Balance Sheet

Amounts recognized on the consolidated balance sheet at December 31, 2016 and 2015 are as follows:

		December 31, 2016								December 31, 2015
Thousands of dollars		Pension Benefits				Postretirement Benefits				Pension Benefits				Postretirement Benefits
Long-term liabilities		$	6,272			$	573			$	5,298			$	2,503

Components of Net Periodic Benefit Cost and Other Comprehensive Income

Net periodic benefit costs recognized on the consolidated statements of operations for the years ended December 31, 2016 and 2015 consist of the following:

		Year Ended December 31, 2016								Year Ended December 31, 2015
Thousands of dollars		Pension Benefits				Postretirement Benefits				Pension Benefits				Postretirement Benefits
Service cost		$	165			$	31			$	271			$	34
Interest cost		905				121				1,014				155
Expected return on plan assets		(1,146		)		(74		)		(1,342		)		(99		)
Special termination benefit		376				—				—				—
Effect of curtailment		276				—				—				—
Effect of settlement		245				57				—				—
Amortization of prior service cost/(credit)		—				(41		)		—				—
Net periodic benefit costs		$	821			$	94			$	(57	)		$	90

Amounts recognized in accumulated other comprehensive loss for the years ended December 31, 2016 and 2015 consist of the following:

		Year Ended December 31, 2016								Year Ended December 31, 2015
Thousands of dollars		Pension Benefits				Postretirement Benefits				Pension Benefits				Postretirement Benefits
Prior service credit		$	—			$	(1,936	)		$	—			$	—
Net actuarial (gain) loss:
Liability loss (gain) due to assumption change		673				322				(2,045		)		(220		)
Liability (gain) loss due to participant experience		(452		)		(346		)		(315		)		(113		)
Loss due to settlement		(245		)		(57		)		—				—
Asset return loss		178				89				1,505				162
Amortization of prior service credit		—				41				—				—
Net actuarial (gain) loss		154				49				(855		)		(171		)
Total		$	154			$	(1,887	)		$	(855	)		$	(171	)

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Estimated Future Benefit Payments

As of December 31, 2016 the following estimated benefit payments under the Plans, which reflect expected future service, as appropriate, are expected to be paid as follows:

Thousands of dollars		Pension Benefits				Postretirement Benefits
2017		$	1,530			$	81
2018		1,510				89
2019		1,490				84
2020		1,480				85
2021		1,460				93
2022-2026		7,150				340

ETSWDC expects to contribute approximately $0.6 million and $0.1 million to the pension plan and other postretirement plan, respectively, in 2017 .

Assumptions

Assumptions used to determine the Plans’ projected benefit obligations and costs as of December 31, 2016 and 2015 are as follows:

		December 31, 2016						December 31, 2015
		Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
Discount rate		3.85	%		3.85	%		4.10	%		4.10	%
Rate of compensation increase		3.00	%		N/A			3.00	%		N/A
Health care cost trend rate:
Pre - 65 rate		N/A			7.00	%		N/A			7.00	%
Post - 65 rate		N/A			7.00	%		N/A			7.00	%
Expected long-term rates of return on plan assets		6.00	%		6.00	%		6.75	%		6.75	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)		N/A			4.50	%		N/A			4.50	%
Year that the rate reaches the ultimate trend rate		N/A			2025			N/A			2023

    

Assumptions used to determine net periodic benefit costs for the years ended December 31, 2016 and 2015 are as follows:

		Year Ended December 31, 2016						Year Ended December 31, 2015
		Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
Discount rate		3.81	%		3.81	%		3.75	%		3.75	%
Expected long-term return on plan assets		6.75	%		6.75	%		6.50	%		6.50	%
Rate of compensation increase		3.00	%		N/A			3.00	%		N/A

Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage point increase or decrease in assumed health care cost trend rates would increase or decrease total postretirement benefit service and interest costs by less than $0.1 million and would increase or decrease the postretirement benefit obligation by less than $0.1 million and approximately $0.2 million , respectively.

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As of December 31, 2016 and 2015 , we had $7.9 million and $8.0 million , respectively, of equity securities, consisting primarily of pooled separate accounts which focus on long-term growth of capital through U.S. and international services, and $8.0 million and $12.0 million , respectively, of fixed income securities, consisting primarily of pooled separate accounts which focus on long-term growth of capital and preservation of equity through U.S. and international securities.

As of December 31, 2016 and 2015 , we had less than $0.1 million and $0.1 million , respectively, in cash and cash equivalents and $0.8 million and $1.4 million , respectively, in mutual funds, which focus on growth of capital and income maximization.

Plan Investment Policies and Strategies

The investment policies for the Plans reflect the funded status of the Plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with the legal requirements of all applicable laws; (2) produce investment returns which meet or exceed the rates of return achievable in the capital markets while maintaining the risk parameters set by the Plans’ investment committees and protecting the assets from any erosion of purchasing power; and (3) position the portfolios with a long-term risk/return orientation.

Historical performance and future expectations suggest that common stocks will provide higher total investment returns than fixed income securities over a long-term investment horizon. Short-term investments are utilized for pension payments, expenses, and other liquidity needs. As such, the Plan’s targeted asset allocation is comprised of approximately 50 percent equity securities and approximately 50 percent high-yield bonds and other fixed income securities but may be adjusted to better match the plan's liabilities over time as the funded ratio (as defined by the investment policy) changes.

The Plans’ assets are managed by a third party investment manager. The investment manager is limited to pursuing the investment strategies regarding asset mix and purchases and sales of securities within the parameters defined in the investment policy guidelines and investment management agreement. Investment performance and risk is measured and monitored on an ongoing basis through annual investment meetings and periodic cash flow studies.

Expected long-term return on plan assets

The overall expected long-term return on plan assets assumption is determined based on an asset rate-of-return modeling tool developed by a third party investment group. The tool utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account the Plan’s asset allocations to derive an expected long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook. The assumptions for equity and fixed income investments are developed using a building-block approach, reflecting observable inflation information and interest rate information available in the fixed income markets. Long-term assumptions for other asset categories are based on historical results, current market characteristics and the professional judgment of our internal and external investment teams.

Fair Value Measurements

Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset class at December 31, 2016 and 2015 .

Cash and cash equivalents – Cash and cash equivalents include cash on deposit which are valued using a market approach and are considered Level 1.

Mutual funds – Investments in mutual funds are valued using a market approach. The shares or units held are traded on the public exchanges and such prices are Level 1 inputs.

Pooled funds – Investments in pooled funds are valued using a market approach at the net asset value of units held, but investment opportunities in such funds are limited to institutional investors on the behalf of defined benefit plans.

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The various funds consist of either an equity or fixed income investment portfolio with underlying investments held in U.S. and non-U.S. securities. Nearly all of the underlying investments are publicly-traded. The majority of the pooled funds are benchmarked against a relative public index. These are considered Level 2.

13. Commitments and Contingencies

Lease Rental and Purchase Obligations

We have operating leases for office space and other property and equipment having initial or remaining non-cancelable lease terms in excess of one year. Our future minimum rental payments for operating leases at December 31, 2016 are presented below:

		Payments Due by Year
Thousands of dollars		2017				2018				2019				2020				2021				Thereafter				Total
Operating leases		$	4,866			$	3,467			$	2,570			$	2,476			$	2,460			$	5,714			$	21,553

Net rental expense under non-cancelable operating leases was $6.3 million , $8.9 million and $5.2 million in 2016 , 2015 and 2014 , respectively.

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court (see Note 2). During the year ended December 31, 2016, the Bankruptcy Court approved the rejection of our leases at 600 Travis Street, Houston, Texas and 1401 McKinney Street, Houston, Texas.

Surety Bonds and Letters of Credit

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily 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 December 31, 2016 , we had $26.4 million in surety bonds and $50.9 million in letters of credit outstanding, including $22.9 million in letters of credit related to the property reclamation deposit. At December 31, 2015 , we had $27.1 million in surety bonds and $25.8 million in letters of credit outstanding, including $23.4 million in letters of credit related to the property reclamation deposit. The increase in letters of credit during the year ended December 31, 2016 was primarily due to the filing of the Chapter 11 Petitions.  At December 31, 2016 and December 31, 2015 , we had approximately $37.9 million and zero , respectively, in letters of credit outstanding under the DIP Credit Agreement.

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. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we are subject. For information relating to the Chapter 11 Cases, see Item 1 “—Business” — “Chapter 11 Cases” within this report.

14. Partners’ Equity

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities and post-petition liabilities must be satisfied in full before the holders of our Series A Preferred Units, Series B Preferred Units and Common Units are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or unitholders, if any, will not be determined until confirmation and implementation of a plan of reorganization. No assurance can be given as to what distributions, if any, will be made to each of these constituencies or the nature thereof. As discussed below, if certain requirements of the Bankruptcy Code are met, a plan of reorganization can be confirmed notwithstanding its rejection or deemed rejection by the holders of our Series A Preferred Units, Series B Preferred Units and Common Units and notwithstanding the fact that such holders do

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not receive or retain any property on account of their equity interests under the plan. Because of such possibilities, the value of our securities, including our Series A Preferred Units, Series B Preferred Units and Common Units, is highly speculative. We believe it is highly likely that our Series A Preferred Units, Series B Preferred Units and Common Units will be canceled in our Chapter 11 Cases and that the holders thereof will not receive any distribution on account of their holdings.

Preferred Units

On April 8, 2015, we issued in private offerings $350 million of 8.0% Series B Perpetual Convertible Preferred Units (“Series B Preferred Units”) to EIG Redwood Equity Aggregator, LP (“EIG Equity”), ACMO BBEP Corp. (“ACMO”) and certain other purchasers at an issue price of $7.50 per unit. We received approximately $337.2 million from this offering, net of fees and estimated expenses, which we primarily used to repay borrowings under the RBL Credit Agreement. The Series B Preferred Units rank senior to the Common Units and on parity with the Series A Preferred Units with respect to the payment of current distributions.

Distributions on the Series B Preferred Units are cumulative from the date of original issue and are payable monthly in arrears on the 15 ^th day of each month of each year, when, as and if declared by our Board out of legally available funds for such purpose.  We began making regular monthly distributions of 0.006666 Series B Preferred Units per unit beginning with the June 15, 2015 payment.  During the years ended December 31, 2016 and 2015 , we recognized $11.7 million and $20.8 million , respectively, of accrued distributions on the Series B Preferred Units, which are included in non-cash distributions to Series B preferred unitholders on the consolidated statements of operations.

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

The 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. Distributions on Series A Preferred Units are cumulative from the date of original issue and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our Board out of legally available funds for such purpose. We paid cumulative distributions in cash on the Series A Preferred Units on a monthly basis at a monthly rate of $0.171875 per unit through March 15, 2016 and during the year ended December 31, 2015. During the years ended December 31, 2016 and 2015 , we recognized $6.1 million and $16.5 million , respectively, of accrued distributions on the Series A Preferred Units, which are included in the distributions to preferred unitholders on the consolidated statements of operations, and paid $5.5 million and $9.4 million , respectively.

The Series A Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into Common Units in connection with a change in control.

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 the event we fail to make any distribution on the Series B Preferred Units as required under the partnership agreement, the annual distribution rate is increased by 2.00% effective as of such date until the date on which all required distributions have been made. As of the Chapter 11 Filing Date, we had 8.0 million Series A Preferred Units issued and outstanding and 49.6 million Series B Preferred Units issued and outstanding. We will continue to account for our Series A Preferred Units and Series B Preferred Units at their carrying value until a plan of reorganization is confirmed by the Bankruptcy Court and becomes effective. We accrued for earned but undeclared distributions on each series of Preferred Units for the period from April 1, 2016 to the Chapter 11 Filing Date. As of December 31, 2016 , total accrued but unpaid distributions on our Series A Preferred Units and Series B Preferred Units of $7.0 million were reflected as liabilities subject to compromise.

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Common Units

At of the Chapter 11 Filing Date, we had 213.8 million Common Units outstanding. We will continue to account for our Common Units at their carrying value until a plan of reorganization is confirmed by the Bankruptcy Court and becomes effective.

At December 31, 2016 and 2015 , we had 213.8 million and 213.5 million in Common Units outstanding, respectively.

During the years ended December 31, 2016 , 2015 and 2014, approximately 0.1 million , 1.6 million and 0.6 million Common Units, respectively, were issued to employees and outside directors pursuant to vested grants under our First Amended and Restated 2006 Long Term Incentive Plan (as amended, “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 distribution rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested RPUs and CPUs participate in distributions on an equal basis with Common Units. Accordingly, the presentation below is prepared on a combined basis and is presented as net income (loss) per common unit.

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

		Year Ended December 31,
Thousands, except per unit amounts		2016				2015				2014
Net (loss) income attributable to the partnership		$	(814,951	)		$	(2,583,339	)		$	421,333
Less:
Net income attributable to participating units		—				—				5,348
Distributions on participating units in excess of earnings		—				1,731				—
Distributions to Series A preferred unitholders		6,142				16,500				10,083
Non-cash distributions to Series B preferred unitholders		11,744				20,817				—
Net (loss) income used to calculate basic and diluted net (loss) income per unit		$	(832,837	)		$	(2,622,387	)		$	405,902
Weighted average number of units used to calculate basic and diluted net (loss) income per unit:
Common Units		213,755				211,575				133,451
Dilutive units (a)		—				—				755
Denominator for diluted net (loss) income per unit		213,755				211,575				134,206
Net (loss) income per common unit
Basic		$	(3.90	)		$	(12.39	)		$	3.04
Diluted		$	(3.90	)		$	(12.39	)		$	3.02

(a) The years ended December 31, 2016 and 2015 exclude 361 and 725 weighted average anti-dilutive units, respectively, from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position.

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Cash Distributions on Common Units

The partnership agreement requires us to distribute all of our available cash quarterly. Available cash is cash on hand, including cash from borrowings, at the end of a quarter after the payment of expenses and the establishment of reserves for future capital expenditures and operational needs. We may fund a portion of capital expenditures with additional borrowings. In addition, the partnership agreement does not restrict our ability to borrow to pay distributions. The cash distribution policy reflects a basic judgment that unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it. Distributions are not cumulative. Consequently, if distributions on Common Units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future.

We do not have a legal obligation to pay distributions at any rate except as provided in the partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under the partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves our General Partner determines is necessary or appropriate to provide for the conduct of the business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters. The partnership agreement provides that any determination made by our General Partner in its capacity as general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity.

In response to commodity and financial market conditions, the Board suspended distributions on Common Units effective November 30, 2015. During the years ended December 31, 2016 , 2015 and 2014 , we paid cash distributions of zero , $123.2 million , and $261.0 million , respectively, to our common unitholders. The distributions that were paid to unitholders totaled zero , $0.58 and $2.00 per Common Unit, respectively. We also paid cash equivalent to the distributions paid to our unitholders of zero , $3.0 million and $3.8 million , respectively, to holders of outstanding RPUs and CPUs issued under our LTIP.

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15. Accumulated Other Comprehensive Income (Loss)

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

		Gain (loss) on
Thousands of dollars		Available-For-Sale Securities				Pension and Postretirement Benefits				Total
Accumulated comprehensive loss as of December 31, 2014		$	(112	)		$	(280	)		$	(392	)
Other comprehensive (loss) income before reclassification		(267		)		677				410
Amounts reclassified from accumulated other comprehensive (loss) income (a)		(135		)		—				(135		)
Net current period other comprehensive (loss) income		(402		)		677				275
Accumulated comprehensive (loss) income as of December 31, 2015		(514		)		397				(117		)
Less: Accumulated comprehensive (loss) income attributable to non-controlling interest		(164		)		276				112
Accumulated comprehensive (loss) income attributable to the Partnership as of December 31, 2015		(350		)		121				(229		)
Other comprehensive income before reclassification		1,450				1,145				2,595
Amounts reclassified from accumulated other comprehensive loss (a)		(464		)		—				(464		)
Net current period other comprehensive income		986				1,145				2,131
Accumulated comprehensive income as of December 31, 2016		636				1,266				1,902
Less: Accumulated comprehensive income attributable to non-controlling interest		402				468				870
Accumulated comprehensive income attributable to the Partnership as of December 31, 2016		$	234			$	798			$	1,032

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

16. Unit-Based and Other Compensation Plans

FASB Accounting Standards establish requirements for charging compensation expenses based on fair value provisions . At December 31, 2015, the RPUs, CPUs and Phantom Units granted to employees and directors under LTIP were all classified as equity awards. These awards were being recognized as compensation expense on a straight line basis over the annual vesting periods as prescribed in the award agreements. In the fourth quarter of 2016, in connection with the Chapter 11 Cases, all unvested RPUs, CPUs and Phantom Units were canceled and all remaining compensation expense related to the canceled awards was expensed.

 

We recognized $24.7 million , $26.8 million and $23.4 million of unit-based compensation expense related to our various awards for the years ended December 31, 2016 , 2015 and 2014 , respectively. For the years ended December 31, 2016 and 2015 , unit-based compensation expense included in general and administrative expenses was $17.8 million and $25.5 million , respectively, unit-based compensation expense included in operating costs was $6.4 million and zero , respectively, and unit-based compensation expense included in restructuring costs was $0.6 million and $1.3 million , respectively. For the year ended December 31, 2014, all unit-based compensation expense was included in general and administrative expenses. See Note 18 for a discussion of restructuring costs.

Restricted Phantom Units

RPUs are phantom equity awards that, to the extent vested, represented the right to receive actual partnership units upon specified payment events. Certain of our employees, including our executives, were eligible to receive RPU

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awards. RPUs generally vested in three equal annual installments on each anniversary of the vesting commencement date of the award. In addition, each RPU was granted in tandem with a distribution equivalent right that remained outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitled the grantee to receive payment of amounts equal to distributions paid to each holder of an actual partnership unit during such period. RPUs that did not vest for any reason were forfeited upon a grantee’s termination of employment.

The fair value of the RPUs was determined based on the fair market value of our units on the date of grant. RPU awards were granted to our employees during the years ended December 31, 2016 , 2015 and 2014 as shown in the table below. We recorded compensation expense of $21.1 million , $20.2 million and $18.3 million in 2016 , 2015 and 2014 , respectively, related to the amortization of outstanding RPUs over their related vesting periods. In connection with workforce reductions (see Note 18), during the years ended December 31, 2016 and 2015, $0.6 million and $1.3 million , respectively, were recognized as restructuring costs for accelerated vesting of 0.1 million and 0.1 million LTIP grants, respectively, for certain individuals. As of December 31, 2016 , there were no unrecognized compensation costs remaining for the unvested RPUs, as all outstanding RPUs were canceled in the fourth quarter of 2016. The total grant date fair value of units that vested during the years ended December 31, 2016 , 2015 and 2014 was $1.1 million , $19.7 million and $18.4 million , respectively.

 

The following table summarizes information about RPUs:

		Year Ended December 31,
		2016							2015							2014
		Number			Weighted				Number			Weighted				Number			Weighted
		of			Average				of			Average				of			Average
Thousands, except per unit amounts		RPUs			Fair Value				RPUs			Fair Value				RPUs			Fair Value
Outstanding, beginning of period		3,038			$	7.90			957			$	20.98			896			$	21.05
Granted		7,000			0.68				4,739			6.46				1,025			20.21
Vested (a)		(146	)		7.53				(2,012	)		10.63				(906	)		20.22
Canceled		(9,892	)		2.74				(646	)		8.24				(58	)		20.36
Outstanding, end of period		—			$	—			3,038			$	7.90			957			$	20.98

(a) Includes 25 , 613 and 298 units canceled at the time of distribution for income tax liability payments we made on behalf of the restricted unit grantees for years ended December 31, 2016 , 2015 and 2014 , respectively.

Convertible Phantom Units

In January 2013, we issued CPUs in tandem with a corresponding Performance Distribution Right (“PDR”) which remained outstanding from the Grant Date until the earlier to occur of a Payment Date or the forfeiture of the CPU to which such PDR corresponds. The corresponding PDR entitled the participant to receive an amount determined by reference to Partnership distributions and which was credited to the participant in the form of additional CPUs.

In January 2013, 0.3 million CPUs (“2013 CPUs”) were granted at a price of $20.98 per Common Unit and in January 2014, an additional 0.3 million CPUs (“2014 CPUs”) were granted at a price of $20.29 per Common Unit. We recorded compensation expense for the 2013 and 2014 CPUs of approximately $2.0 million for the year ended December 31, 2016, and $4.3 million in each of the years ended December 31, 2015 and 2014. As of December 31, 2016 , there were no unrecognized compensation costs remaining, as the 2013 CPUs were fully vested and the remaining unvested 2014 CPUs were canceled in fourth quarter of 2016.

Director Restricted Phantom Units

We have made grants of RPUs to the non-employee directors of our General Partner that are substantially similar to the ones granted to employees. The estimated fair value associated with these phantom units was expensed over the vesting period.

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We recorded compensation expense for the director’s phantom units of approximately $1.0 million , $0.9 million and $0.8 million in 2016 , 2015 and 2014 , respectively. As of December 31, 2016 , there were no unrecognized compensation costs remaining, as all outstanding Director Restricted Phantom Units were canceled in the fourth quarter of 2016.

The following table summarizes information about the Director Restricted Phantom Units:

		Year Ended December 31,
		2016							2015							2014
		Number			Weighted				Number			Weighted				Number			Weighted
		of			Average				of			Average				of			Average
Thousands, except per unit amounts		Units			Fair Value				Units			Fair Value				Units			Fair Value
Outstanding, beginning of period		201			$	9.42			78			$	20.44			67			$	20.69
Granted		631			0.68				160			6.56				43			20.29
Vested		(80	)		10.89				(37	)		20.35				(32	)		20.77
Canceled		(752	)		1.89				—			—				—			—
Outstanding, end of period		—			$	—			201			$	9.42			78			$	20.44

Phantom Units

During the year ended December 31, 2016, the Board approved the grant of 10.5 million phantom units (“Phantom Units”) at $0.68 per unit, to the executives and certain key employees of Breitburn Management and 0.5 million Phantom Units to outside directors. Phantom Units were scheduled to vest one-half after 18 months and one-half after 24 months and were to be settled in cash (or Common Units if elected by us). The Phantom Units were to be 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.

During the year ended December 31, 2016, we recorded zero in compensation expense for the Phantom Units, and all outstanding Phantom Units were canceled in fourth quarter of 2016.

Key Employee Program

In April 2016, the Partnership adopted the Key Employee Program (“KEP”), which was approved by the Bankruptcy Court in September 2016. Participants must be employed on the scheduled payment dates in order to receive a payment under the KEP. Participants in the KEP are eligible to receive quarterly cash payments, which are contingent on meeting performance thresholds tied to production and lease operating expense and satisfactory individual performance. During the year ended December 31, 2016 , we recognized $11.0 million in general and administrative expenses, and $6.6 million , respectively, in operating costs, related to the 2016 KEP.

Key Executive Incentive Program

In September 2016, the Bankruptcy Court approved the Partnership’s Key Executive Incentive Program (“KEIP”). The participants in the KEIP are the following named executive officers of Breitburn GP LLC, the general partner of the Partnership: Halbert S. Washburn, Mark L. Pease, James G. Jackson and Gregory C. Brown. Participants must be employed on the scheduled payment dates in order to receive a payment under the KEIP. Participants in the KEIP are eligible to receive two cash payments made at the conclusion of the fiscal quarters ending September 30, 2016 (for the performance period covering the second and third quarters of 2016 ending September 30, 2016) and December 31, 2016 (for the performance period covering the fourth quarter of 2016 ending December 31, 2016). Payments are contingent on the Partnership meeting the same basic performance thresholds utilized in the KEP, which are tied to production and lease operating expense. The performance metrics were measured for each performance period, and were adjusted relative to cumulative performance at the end of 2016. The maximum aggregate amount payable to the participants is approximately $9.7 million , which reflects a 10% reduction of the original aggregate award amount filed with the Bankruptcy Court for the key executive incentive program.

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During the year ended December 31, 2016 , we recognized $7.7 million in general and administrative expenses, respectively, related to the 2016 KEIP.

17. Significant Customers

We sell oil, NGLs and natural gas primarily to large, established domestic refiners and utilities.  For the years ended December 31, 2016 , 2015 and 2014 , sales of oil, NGL and natural gas production to each of the following purchasers represented 10% or more of total sales revenue:

		Year Ended December 31,
Purchaser		2016			2015			2014
Shell Trading		17	%		24	%		22	%
Plains Marketing		11	%		12	%		(a)
Phillips 66		(a)			(a)			10	%

(a) Represented less than 10% of total sales revenue for the respective year end.

Our sales contracts are sold at market-sensitive or spot prices.  Because commodity products are sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers.  As a result, the loss of any one purchaser would not have a long-term material adverse effect on our ability to sell our production.

18. Restructuring Costs

During the first half of 2016 and 2015 , we executed workforce reduction plans as part of our company-wide reorganization efforts intended to reduce costs, due in part to lower commodity prices. In addition, we executed further workforce reductions in the first half of 2016 in connection with PCEC’s termination of the administrative services agreement with Breitburn Management, which was effective June 30, 2016 (see Note 6).

The 2016 reductions were communicated to affected employees on various dates during the first half of 2016, and all such notifications were completed by June 30, 2016. The 2015 reduction was communicated to affected employees on various dates during the first half of 2015, and all such notifications were completed by April 30, 2015. The plans resulted in a reduction of approximately 76 and 45 employees in 2016 and 2015, respectively. 

For the years ended December 31, 2016 and 2015, we recognized the following restructuring costs:

		Year Ended December 31,
Thousands of dollars		2016				2015
Severance payments		$	3,585			$	4,768
Unit-based compensation expense		554				1,343
Other termination costs		164				253
Total		$	4,303			$	6,364

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Supplemental Information (Unaudited)

A. Oil, NGL and Natural Gas Activities (Unaudited)

Our proved reserves are estimated by third party reservoir engineers and in accordance with SEC guidelines. We are reasonably certain that the estimated quantities will equal or exceed the estimates. Reserve estimates are expected to change as economic assumptions change and additional engineering and geoscience data becomes available. For reserve reporting purposes, we use unweighted average first-day-of-the-month pricing for the 12 calendar months prior to the end of the reporting period. Costs are held constant throughout the projected reserve life. While SEC guidelines permit a company to establish undeveloped reserves as proved with appropriate degrees of reasonable certainty established absent actual production tests and without artificially limiting such reserves to spacing units adjacent to a producing well, we have elected not to add such undeveloped reserves as proved.

Costs incurred

The following table summarizes our costs incurred for the past three years:

		Year Ended December 31,
Thousands of dollars		2016				2015				2014
Property acquisition costs
Proved		$	972			$	7,943			$	1,707,528
Unproved (a)		4,296				2,593				734,603
Pipelines and processing facilities		—				—				—
Asset retirement costs		—				492				91,097
Development costs		60,582				201,859				388,807
Asset retirement costs - development		224				2,268				4,020
Total costs incurred		$	66,074			$	215,155			$	2,926,055

(a) Primarily reflects amounts attributable to unproved reserves located within acquired producing oil and gas properties.

Capitalized costs

The following table presents the aggregate capitalized costs subject to DD&A relating to oil and gas activities, and the aggregate related accumulated allowance:

		December 31,
Thousands of dollars		2016				2015
Proved properties and related producing assets		$	6,535,209			$	6,502,029
Pipelines and processing facilities		316,248				342,224
Unproved properties (a)		1,055,679				1,053,834
Accumulated depreciation, depletion and amortization		(4,627,441		)		(4,113,741		)
Net capitalized costs		$	3,279,695			$	3,784,346

(a) Primarily reflects amounts attributable to unproved reserves located within acquired producing oil and gas properties.

The average DD&A rate per equivalent unit of production for the years ended December 31, 2016 and 2015 , excluding impairments and non-oil and gas related DD&A, were $16.59 per Boe and $22.24 per Boe, respectively.

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Results of operations for oil, NGL and natural gas producing activities

The results of operations from oil, NGL and natural gas producing activities below exclude G&A expenses, interest expenses and interest income:

		Year Ended December 31,
Thousands of dollars		2016				2015				2014
Oil, NGL and natural gas sales		$	504,254			$	645,272			$	855,820
(Loss) gain on commodity derivative instruments, net		(53,091		)		438,614				566,533
Operating costs		(350,015		)		(440,533		)		(352,906		)
Depletion, depreciation and amortization		(303,298		)		(448,791		)		(288,503		)
Impairment of oil and natural gas properties		(283,270		)		(2,377,615		)		(149,000		)
Income tax benefit (expense)		1,117				(214		)		91
Results of operations from producing activities (a)		$	(484,303	)		$	(2,183,267	)		$	632,035

(a) Excludes gain (loss) on sale of assets.

Supplemental reserve information

The following information summarizes our estimated proved reserves of oil, NGLs and natural gas and the present values thereof for the years ended December 31, 2016 , 2015 and 2014 . The following reserve information is based upon reports by Netherland, Sewell & Associates, Inc. (“NSAI”) and Cawley, Gillespie & Associates, Inc. (“CGA”), independent petroleum engineering firms. NSAI prepared reserve data for all our properties, except for our Postle and North East Hardesty fields in Oklahoma, which was prepared by CGA. The estimates are prepared in accordance with SEC regulations. We only utilize large, widely known, highly regarded and reputable engineering consulting firms. Not only the firms, but the technical persons that sign and seal the reports are licensed and certify that they meet all professional requirements. Licensing requirements formally require mandatory continuing education and professional qualifications. They are independent petroleum engineers, geologists, geophysicists and petrophysicists.

Our reserve estimation process involves petroleum engineers and geoscientists. As part of this process, all reserves volumes are estimated using a forecast of production rates, current operating costs and projected capital expenditures. Reserves are based upon the unweighted average first-day-of-the-month prices for each year. Price differentials are then applied to adjust these prices to the expected realized field price. Specifics of each operating agreement are then used to estimate the net reserves. Production rate forecasts are derived by a number of methods, including decline curve analyses, volumetrics, material balance or computer simulation of the reservoir performance. Operating costs and capital costs are forecast using current costs combined with expectations of future costs for specific reservoirs. In many cases, activity-based cost models for a reservoir are utilized to project operating costs as production rates and the number of wells for production and injection vary.

The technical person, employed by our General Partner, primarily responsible for overseeing preparation of the reserves estimates and the third party reserve reports is Mark L. Pease, the President and Chief Operating Officer of our General Partner. Mr. Pease received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines in 1979. Prior to joining our General Partner, Mr. Pease was Senior Vice President, E&P Technology & Services for Anadarko Petroleum Corporation.  Mr. Pease has over 30 years of experience working in various capacities in the energy industry, including acquisition analysis, reserve estimation, reservoir engineering and operations engineering. Mr. Pease consults with CGA and NSAI during the reserve estimation process to review properties, assumptions and relevant data.

Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves reports included in this report as Exhibit 99.1 are Mr. C. Ashley Smith and Mr. Mike K. Norton.  Mr. Smith, a Licensed Professional Engineer in the State of Texas (No. 100560), has been practicing consulting petroleum engineering at NSAI since 2006 and has over 5 years of prior industry experience. He graduated from University of Missouri-Rolla (Missouri University of Science & Technology) in 2000 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Norton has been practicing consulting petroleum geology at NSAI since 1989 and has over 10 years of prior industry experience.  Mr. Norton is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 441), has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years

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of prior industry experience. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. These technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Within CGA, the technical persons primarily responsible for preparing the estimates set forth in the CGA reserves report included in this report as Exhibit 99.2 is Mr. Todd Brooker, who has been a Petroleum Consultant for CGA since 1992. Todd joined CG&A in October 1992 as a reservoir engineer. His responsibilities include reserves and economics evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures. He is currently President of the firm and has managed the Austin office since its opening in 2002. Prior to joining CG&A, Todd worked in Gulf of Mexico drilling and production engineering at Chevron USA in New Orleans, Louisiana. He graduated Magna Cum Laude from the University of Texas at Austin in 1989 with a BS degree in Petroleum Engineering, and is a registered professional engineer in Texas.

Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation methods and procedures consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of the estimated proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil, NGLs and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil, NGL and natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure of discounted net future cash flows shown below represents estimates only and should not be construed as the current market value of the estimated oil, NGL and natural gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Decreases in the prices of oil, NGLs, and natural gas and increases in operating expenses have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and revenues, profitability and cash flow.

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The following table sets forth certain data pertaining to our estimated proved reserves, all of which are located within the United States, for the years ended December 31, 2016 , 2015 and 2014 .

			Oil (in MBbls)			NGLs (in MBbls)			Natural Gas (in MMcf)			Total (MBoe)
Estimated Proved Reserves
December 31, 2013			113,209			15,690			512,233			214,271
	Revision of previous estimates		(20,005	)		(5,798	)		(1,589	)		(26,067	)
	Purchase of previous reserves in-place		82,394			14,399			211,317			132,012
	Sale of reserves in-place		—			—			—			—
	Extensions, discoveries and other		7,172			651			8,297			9,206
	Production		(7,931	)		(1,157	)		(30,159	)		(14,114	)
December 31, 2014			174,839			23,785			700,099			315,308
	Revision of previous estimates		(44,387	)		(3,553	)		(141,618	)		(71,544	)
	Purchase of previous reserves in-place		334			11			2,268			723
	Sale of reserves in-place		—			—			—			—
	Extensions, discoveries and other		9,538			1,322			24,293			14,910
	Production		(11,190	)		(1,953	)		(41,876	)		(20,123	)
December 31, 2015			129,134			19,612			543,166			239,274
	Revision of previous estimates		(21,957	)		(1,385	)		(66,304	)		(34,392	)
	Purchase of previous reserves in-place		49			4			7			54
	Sale of reserves in-place		(918	)		(62	)		(6,051	)		(1,989	)
	Extensions, discoveries and other		15,880			2,697			12,091			20,592
	Production		(9,504	)		(1,984	)		(40,747	)		(18,279	)
December 31, 2016			112,684			18,882			442,162			205,260
Proved developed reserves
	December 31, 2014		126,495			16,485			604,723			243,768
	December 31, 2015		95,096			13,759			498,606			191,956
	December 31, 2016		71,844			11,001			414,498			151,928
Proved undeveloped reserves
	December 31, 2014		48,344			7,300			95,376			71,540
	December 31, 2015		34,038			5,853			44,560			47,318
	December 31, 2016		40,840			7,881			27,664			53,332

Revisions of Previous Estimates

In 2016 , we had negative revisions of 34.4 MMBoe, driven primarily by a decrease in commodity prices partially offset by an increase of 20.6 MMBoe related to extensions and discoveries primarily in the Permian Basin. Unweighted average first-day-of-the-month oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2016 were $42.75 per Bbl of oil and $2.48 per MMBtu of gas, compared to $50.28 per Bbl of oil and $2.59 per MMBtu of natural gas in 2015 . In 2015 , we had negative revisions of 71.5 MMBoe, driven primarily by a decrease in commodity prices partially offset by an increase of 14.9 MMBoe related to extensions and discoveries.

Unweighted average first-day-of-the-month market prices for the reserve reports for the year ended December 31, 2014 were $94.99 per Bbl of oil, and $4.35 per MMBtu of gas. In 2014 , we had negative revisions of 26.1 MMBoe, driven primarily by a decrease oil and NGL prices in the Permian Basin, California, and Florida and performance revisions in the Permian Basin and Oklahoma and 9.2 MMBoe of extensions and discoveries.

    

F-55

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Conversion of Proved Undeveloped Reserves

During the years ended December 31, 2016 , 2015 and 2014 , we incurred $16.8 million , $63.0 million and $272.0 million in capital expenditures, respectively, and drilled seven net wells, 45 net wells, and 161 net wells, respectively, related to the conversion of proved undeveloped to proved developed reserves. During the years ended December 31, 2016 , 2015 and 2014 , we converted 3.5 MMBoe, 6.0 MMBoe and 10.5 MMBoe, respectively, from proved undeveloped to proved developed reserves. As of December 31, 2016 , we had no estimated proved undeveloped reserves that have remained undeveloped for more than five years, and we expect to develop substantially all estimated proved undeveloped reserves within five years of the recognition of those reserves.

The increase in proved undeveloped reserves during the year ended December 31, 2016 was primarily due to extensions and discoveries, partially offset by the conversion of 3.5 MMBoe proved undeveloped to proved developed reserves. The decrease in proved undeveloped reserves during the year ended December 31, 2015 was primarily due to the decrease in commodity prices partially offset by the conversion of 6.0 MMBoe proved undeveloped to proved developed reserves. The increase in proved undeveloped reserves during the year ended December 31, 2014 was primarily due to the QRE Merger, which added 36.0 MMBoe, and due to our expanded drilling program, primarily in California and the Permian Basin, partially offset by the conversion of proved undeveloped to proved developed reserves.

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows relating to our estimated proved oil and natural gas reserves as of December 31, 2016 , 2015 and 2014 is presented below:

		December 31,
Thousands of dollars		2016				2015				2014
Future cash inflows		$	5,837,660			$	7,910,652			$	20,014,316
Future development costs		(1,134,465		)		(1,070,048		)		(1,904,400		)
Future production expense		(3,224,728		)		(4,394,562		)		(8,445,646		)
Future net cash flows		1,478,467				2,446,042				9,664,270
Discounted at 10% per year		(674,808		)		(1,165,229		)		(5,160,166		)
Standardized measure of discounted future net cash flows		$	803,659			$	1,280,813			$	4,504,104

The standardized measure of discounted future net cash flows discounted at 10% from production of proved reserves was developed as follows:

1.	An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

2.

In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our estimated proved properties and the present value thereof are made using unweighted average first-day-of-the-month oil and gas sales prices and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. Representative unweighted average first-day-of-the-month market prices for the reserve reports for the year ended December 31, 2016 were $42.75 per Bbl of oil and $2.48 per MMBtu of natural gas, compared to $50.28 per Bbl of oil and $2.59 per MMBtu of natural gas in 2015 . Unweighted average first-day-of-the-month market prices for the reserve reports for the year ended December 31, 2014 were $94.99 per Bbl of oil and $4.35 per MMBtu of natural gas.

3.

The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs. Future net cash flows assume no future income tax expense as we are essentially a non-taxable entity except for four tax-paying corporations whose future income tax liabilities on a discounted basis are insignificant.

F-56

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The principal sources of changes in the standardized measure of the future net cash flows for the years ended December 31, 2016 , 2015 and 2014 are presented below:

		Year Ended December 31,
Thousands of dollars		2016				2015				2014
Beginning balance		$	1,280,813			$	4,504,104			$	3,225,848
Sales, net of production expense		(154,238		)		(204,739		)		(500,139		)
Net change in sales and transfer prices, net of production expense		(457,339		)		(3,787,527		)		(29,497		)
Previously estimated development costs incurred during year		69,589				501,097				315,792
Changes in estimated future development costs		31,790				106,577				(68,949		)
Extensions, discoveries and improved recovery, net of costs		54,562				86,726				175,335
Purchase of reserves in place		972				7,943				1,707,528
Sale of reserves in place		(8,513		)		—				—
Revision of quantity estimates and timing of estimated production		(142,058		)		(383,778		)		(644,399		)
Accretion of discount		128,081				450,410				322,585
Ending balance		$	803,659			$	1,280,813			$	4,504,104

F-57

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B.   Quarterly Financial Data (Unaudited)

		Year ended December 31, 2016
		First				Second				Third				Fourth
Thousands of dollars except per unit amounts		Quarter				Quarter				Quarter				Quarter
Oil, NGL and natural gas sales		$	105,450			$	127,282			$	129,259			$	142,263
Gain (loss) on derivative instruments, net		37,923				(92,210		)		—				1,196
Other revenue, net		4,593				4,362				4,310				4,577
Total revenue		147,966				39,434				133,569				148,036
Operating loss		(45,487		)		(145,028		)		(333,968		)		(52,324		)
Net loss (a)		(104,006		)		(261,550		)		(364,823		)		(85,754		)
Net loss attributable to the partnership		$	(103,786	)		$	(261,315	)		$	(364,600	)		$	(85,250	)
Basic net loss per common unit (b)		$	(0.54	)		$	(1.25	)		$	(1.71	)		$	(0.40	)
Diluted net loss per common unit (b)		$	(0.54	)		$	(1.25	)		$	(1.71	)		$	(0.40	)

(a) In the first, third and fourth quarters of 2016, we recognized impairment charges of $2.8 million , $275.0 million and $5.5 million , respectively. See Note 7 for discussion of impairments.

(b) Due to changes in the number of weighted average common units outstanding that may occur each quarter, the sum of the earnings per unit amounts for the quarters may not be additive to the full year earnings per unit amount.

		Year ended December 31, 2015
		First				Second				Third				Fourth
Thousands of dollars except per unit amounts		Quarter				Quarter				Quarter				Quarter
Oil, NGL and natural gas sales		$	162,623			$	189,636			$	153,325			$	139,688
(Loss) gain on derivative instruments, net		137,192				(93,432		)		253,012				141,842
Other revenue, net		6,469				6,504				5,922				5,934
Total revenue		306,284				102,708				412,259				287,464
Operating income (loss)		(17,826		)		(243,280		)		(1,276,046		)		(839,430		)
Net (loss) income (a)		(58,918		)		(305,581		)		(1,327,838		)		(890,676		)
Net (loss) income attributable to the partnership		$	(58,825	)		$	(305,707	)		$	(1,327,929	)		$	(890,878	)
Basic net (loss) income per common unit (b)		$	(0.29	)		$	(1.46	)		$	(6.17	)		$	(4.25	)
Diluted net (loss) income per common unit (b)		$	(0.29	)		$	(1.46	)		$	(6.17	)		$	(4.25	)

(a) In the first quarter, third quarter and fourth quarter of 2015, we recognized impairment charges of $59.1 million , $1.4 billion and $878.3 million , respectively. The fourth quarter included $30.7 million in impairment charges for the correction of an error in the third quarter. This correction was not material to the results of the third and fourth quarters of 2015. In the second quarter of 2015, we recorded a goodwill impairment charge of $95.9 million . See Note 7 for discussion of impairments.

(b) Due to changes in the number of weighted average common units outstanding that may occur each quarter, the sum of the earnings per unit amounts for the quarters may not be additive to the full year earnings per unit amount.

F-58

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EXHIBIT INDEX

NUMBER		DOCUMENT
2.1		Agreement and Plan of Merger, dated as of July 23, 2014, by and among Breitburn Energy Partners LP, Breitburn GP LLC, Boom Merger Sub, LLC, QR Energy LP and QRE GP, LLC (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by QR Energy, LP on July 29, 2014).
3.1		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 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 filed on April 14, 2015).
3.4*		First Amendment to Third Amended and Restated Limited Partnership Agreement of Breitburn Energy Partners LP, effective as of May 13, 2016.
3.5		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 filed on April 9, 2011).
3.6		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 filed on January 6, 2011).
3.7		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 filed on July 2, 2014).
3.8*		Amendment No. 3 to the Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC, effective as of May 13, 2016.
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 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 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 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 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 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).

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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		Third Amended and Restated Credit Agreement, dated November 19, 2014, by and among Breitburn Operating LP, as borrower, Breitburn Energy Partners LP, as parent guarantor, and Wells Fargo Bank National Association as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 29, 2014).
10.2		First Amendment to Third Amended and Restated Credit Agreement, dated as of April 8. 2015, by and among Breitburn Operating LP, as borrower, Breitburn Energy Partners LP, as parent guarantor, Breitburn GP LLC, Breitburn Operating GP LLC, the subsidiary guarantors named therein, each lender signatory thereto and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K filed on April 14, 2015).
10.3		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 herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 1, 2016).
10.4		Debtor-in-Possession Credit Agreement, dated as of May 19, 2016 (among Breitburn Operating LP, as borrower, Breitburn Energy Partners LP, as parent guarantor, the financial institutions from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 26, 2016).
10.5		First Amendment to Debtor-in-Possession Credit Agreement, dated effective as of December 15, 2016, among Breitburn Operating LP, as borrower, Breitburn Energy Partners LP, as parent guarantor, the financial institutions from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 16, 2016).
10.6		Second Amendment to Debtor-in-Possession Credit Agreement, dated effective as of December 15, 2016, among Breitburn Operating LP, as borrower, Breitburn Energy Partners LP, as parent guarantor, the financial institutions from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 16, 2016).
10.7		Amended and Restated Series B Preferred Unit Purchase Agreement, dated as of April 8, 2015, by and among Breitburn Energy Partners LP, EIG Redwood Equity Aggregator, LP, ACMO BBEP Corp. and the other purchasers listed on Schedule A thereto (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 14, 2015).
10.8		Board Representation and Standstill Agreement, dated as of April 8, 2015, by and among Breitburn GP LLC, Breitburn Energy Partners LP and EIG Redwood Equity Aggregator, LP (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 14, 2015).
10.9		Amended and Restated Purchase Agreement, dated as of April 8, 2015, by and among Breitburn Energy Partners LP, Breitburn Operating LP, Breitburn Finance Corporation, the guarantors party thereto and the purchasers listed on Schedule I thereto (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on April 14, 2015).
10.10		Security Agreement, dated as of April 8, 2015, by and among Breitburn Operating LP, Breitburn Energy Partners LP, Breitburn Finance Corporation, each of the subsidiary entities named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8- K filed on April 14, 2015).
10.11		Intercreditor Agreement, dated as of April 8, 2015, by and among Wells Fargo Bank, National Association, U.S. Bank National Association, Breitburn Energy Partners LP, Breitburn Finance Corporation, Breitburn Operating LP and each of the subsidiary entities named therein (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K filed on April 14, 2015).
10.12		Third Amended and Restated Administrative Services Agreement, dated May 8, 2012, by and between Pacific Coast Energy Company L.P. and Breitburn Management Company LLC (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 filed on August 8, 2012).
10.13		Amendment No. 1 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated March 18, 2014 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 20, 2014).

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10.14		Amendment No. 2 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated June 30, 2014 (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 filed on November 5, 2014).
10.15		Amendment No. 3 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated July 31, 2014 (incorporated herein by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 filed on November 5, 2014).
10.16		Amendment No. 4 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated August 29, 2014 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 filed on November 5, 2014).
10.17		Amendment No. 5 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated May 1, 2015 (incorporated hereby by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 filed on May 5, 2015.
10.18		Amendment No. 6 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated December 22, 2015 (incorporated herein by reference to Exhibit 10.14 to the Annual Report on Form 10-K for the year ended December 31, 2015 filed on February 26, 2016).
10.19		Amendment No. 7 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated January 29, 2016 (incorporated herein by reference to Exhibit 10.15 to the Annual Report on Form 10-K for the year ended December 31, 2015 filed on February 26, 2016).
10.20		Omnibus Agreement, dated August 26, 2008, by and among Breitburn Energy Holdings LLC, BEC (GP) LLC, Breitburn Energy Company LP, Breitburn GP LLC, Breitburn Management Company LLC and Breitburn Energy Partners LP (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on September 2, 2008).
10.21		First Amendment to Omnibus Agreement, dated May 8, 2012, by and among Breitburn Energy Partners LP, Breitburn GP LLC, Breitburn Management Company LLC, Pacific Coast Energy Company L.P., Pacific Coast Energy Holdings LLC and PCEC (GP) LLC (incorporated herein by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 filed on August 8, 2012).
10.22		Amendment No. 1 to the Operations and Proceeds Agreement, relating to the Dominguez Field and dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and Breitburn Operating LP (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K filed on June 23, 2008).
10.23		Amendment No. 1 to the Surface Operating Agreement dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and its predecessor BreitBurn Energy Corporation and Breitburn Operating LP (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.24		Indemnity Agreement between Breitburn Energy Partners LP, Breitburn GP LLC and Halbert S. Washburn, together with a schedule identifying other substantially identical agreements between Breitburn Energy Partners LP, Breitburn GP LLC and each of its executive officers and non-employee directors identified on the schedule (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 4, 2009).
10.25		Third Amended and Restated Employment Agreement dated December 30, 2010 among Breitburn Management Company LLC, Breitburn GP LLC, Breitburn Energy Partners LP and Halbert S. Washburn (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 6, 2011).
10.26		Amended and Restated Employment Agreement dated December 30, 2010 among Breitburn Management Company LLC, Breitburn GP LLC, Breitburn Energy Partners LP and Mark L. Pease (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on January 6, 2011).
10.27		Second Amended and Restated Employment Agreement dated December 30, 2010 among Breitburn Management Company LLC, Breitburn GP LLC, Breitburn Energy Partners LP and James G. Jackson (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed on January 6, 2011).

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10.28		Amended and Restated Employment Agreement dated December 30, 2010 among Breitburn Management Company LLC, Breitburn GP LLC, Breitburn Energy Partners LP and Gregory C. Brown (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K filed on January 6, 2011).
10.29†		Retirement Agreement, dated as of November 30, 2012, among Breitburn Energy Partners LP, Breitburn GP LLC and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 6, 2012).
10.30†		First Amended and Restated Breitburn Energy Partners LP 2006 Long-Term Incentive Plan effective as of October 29, 2009 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 filed on November 6, 2009).
10.31†		First Amendment to the First Amended and Restated Breitburn Energy Partners LP 2006 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 to the Form S-8 Registration Statement (File No. 333-181526) filed on May 18, 2012).
10.32†		Second Amendment to First Amended and Restated BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan effective as of June 18, 2015 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 18, 2015).
10.33†		Omnibus First Amendment to the Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreements, dated as of November 30, 2012, among Breitburn Energy Partners LP, Breitburn GP LLC and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.2 to the Current Report on form 8-K filed on December 6, 2012).
10.34†		Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Deferred Payment Award) for 2013 grants (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 filed on May 3, 2013).
10.35†		Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Employment Agreement Form) for 2015 grants (incorporated herein by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2014 filed on March 2, 2015).
10.36†		Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Employment Agreement Form) for 2015 grants (incorporated herein by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2014 filed on March 2, 2015).
10.37†		Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Director Form) for 2015 grants (incorporated herein by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2014 filed on March 2, 2015).
10.38†		Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Stock-Settled) (Employment Agreement Form) for 2016 grants (incorporated herein by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on February 26, 2016).
10.39†		Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Stock-Settled) (Non-Employment Agreement Form) for 2016 grants (incorporated herein by reference to Exhibit 10.40 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on February 26, 2016).
10.40†		Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Stock-Settled) (Director Form) for 2016 grants (incorporated herein by reference to Exhibit 10.41 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on February 26, 2016).
10.41†		Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Cash-Settled) (Employment Agreement Form) for 2016 grants (incorporated herein by reference to Exhibit 10.42 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on February 26, 2016).
10.42†		Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Cash-Settled) (Non-Employment Agreement Form) for 2016 grants (incorporated herein by reference to Exhibit 10.43 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on February 26, 2016).
10.43†		Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Cash-Settled) (Director Form) for 2016 grants (incorporated herein by reference to Exhibit 10.44 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on February 26, 2016).

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10.44†		Breitburn Energy Partners LP Incentive Bonus Award Agreement for 2016 grants (incorporated herein by reference to Exhibit 10.45 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on February 26, 2016).
10.45†		Form of Breitburn Energy Partners LP Amended and Restated Incentive Bonus Award (Employment Agreement Form) for 2016 grants (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 filed on November 8, 2016).
10.46†		Form of Breitburn Energy Partners LP Incentive Bonus Award Agreement (Non-Employment Agreement Form) for 2016 grants (incorporated herein by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 filed on November 8, 2016).
10.47†		Form of First Amendment to Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Cash-Settled) (Employment Agreement Form) for 2016 grants (incorporated herein by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 filed on November 8, 2016).
12.1*		Computation of Ratio of Earnings to Fixed Charges.
14.1		Code of Ethics for Chief Executive Officers and Senior Officers (as amended and restated on February 28, 2007) (incorporated herein by reference to Exhibit 14.1 to the Current Report on Form 8-K filed on March 5, 2007).
21.1*		List of Subsidiaries of Breitburn Energy Partners LP.
23.1*		Consent of PricewaterhouseCoopers LLP.
23.2*		Consent of Netherland, Sewell & Associates, Inc.
23.3*		Consent of Cawley, Gillespie & Associates, Inc.
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.
99.1*		Netherland, Sewell & Associates, Inc. reserve report.
99.2*		Cawley, Gillespie & Associates, Inc. reserve report.
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Taxonomy Extension Schema Document.
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.
*		Filed herewith.
**		Furnished herewith.
†		Management contract or compensatory plan or arrangement.