Breitburn Energy Partners LP
Breitburn Energy Partners LP (Form: 10-K, Received: 03/08/2017 16:57:45)


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
x
Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2016
or
o
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from ___ to ___
 
Commission file number 001-33055
 Breitburn Energy Partners LP
(Exact Name of Registrant as Specified in Its Charter)

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

Registrant’s telephone number, including area code: (213) 225-5900
Securities registered pursuant to Section 12(b) of the Act: None
 
Securities registered pursuant to Section 12(g) of the Act:
Common Units Representing Limited Partner Interests

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o                         Accelerated filer o
Non-accelerated filer x (Do not check if a smaller reporting company)     Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
The aggregate market value of the Common Units held by non-affiliates was approximately $17.0 million on June 30, 2016 , the last business day of the registrant’s most recently completed second fiscal quarter, based on $0.08 per unit, the last reported sales price on the OTC Pink on such date.
As of March 7, 2017 , there were 213,789,296 Common Units outstanding.
Documents Incorporated by Reference: Certain information called for in Items 10, 11, 12, 13 and 14 of Part III of this report will be incorporated by reference from the registrant’s definitive proxy statement for the 2017 annual meeting of unitholders or included in an amendment to this Annual Report on Form 10-K.





BREITBURN ENERGY PARTNERS LP AND SUBSIDIARIES
TABLE OF CONTENTS

 
 
Page
 
 
No.
 
 
 
 
 
PART I
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
PART III
 
 
 
 
 
 
 
 
PART IV
 
 
 
 
 
 
 






GLOSSARY OF OIL AND GAS TERMS
 
The following is a description of the meanings of some of the oil and gas industry terms that may be used in this report. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(6), (22) and (31) of Regulation S-X.

API: The specific gravity or density of oil expressed in terms of a scale devised by the American Petroleum Institute.
 
ASC: Accounting Standards Codification.

Bbl: One stock tank barrel, or 42 U.S. gallons of liquid volume, of oil or other liquid hydrocarbons.
 
Bbl/d: Bbl per day.
 
Bcf: One billion cubic feet of natural gas.
 
Bcfe: One billion cubic feet equivalent, determined using the ratio of one Bbl of oil to six Mcf of natural gas.
 
Boe: One barrel of oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel 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 barrel of oil equivalent for natural gas is significantly less than the price for a barrel of oil.
 
Boe/d: Boe per day.

Btu: British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

CO 2 : Carbon dioxide.

CO 2 Flooding: A tertiary recovery method whereby carbon dioxide is injected into a reservoir to enhance hydrocarbon recovery.

completion: The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

deterministic method: The method of estimating revenues using a single value for each parameter (from the geoscience engineering economic data) in reserves calculations.

development well: A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
 
differential: The difference between a benchmark price of oil and natural gas, such as the WTI spot oil price, and the wellhead price received.

dry hole or well: A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
 
economically producible: A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
 
exploitation: A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
 
exploratory well: A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is not a development well.
 

1



field: An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
 
gross acres or gross wells: The total acres or wells, as the case may be, in which a working interest is owned.
 
MBbls: One thousand barrels of oil or other liquid hydrocarbons.

MBoe: One thousand barrels of oil equivalent.
 
MBoe/d: One thousand barrels of oil equivalent per day.
 
Mcf: One thousand cubic feet of natural gas.
 
Mcf/d: One thousand cubic feet of natural gas per day.
 
Mcfe: One thousand cubic feet of natural gas equivalent, determined using the ratio of one Bbl of oil to six Mcf of natural gas.
 
MMBbls: One million barrels of oil or other liquid hydrocarbons.
 
MMBoe: One million barrels of oil equivalent.
 
MMBtu: One million British thermal units.
 
MMBtu/d: One million British thermal units per day.
 
MMcf: One million cubic feet of natural gas.
 
MMcfe: One million cubic feet of natural gas equivalent, determined using the ratio of one Bbl of oil to six Mcf of natural gas.
 
MMcfe/d: One million cubic feet of natural gas equivalent per day, determined using the ratio of one Bbl of oil to six Mcf of natural gas.
 
net acres or net wells: The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
 
NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.
 
oil: Crude oil and condensate.
 
productive well: A well that is producing or that is mechanically capable of production.
 
proved developed reserves: Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment or operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. This definition of proved developed reserves has been abbreviated from the applicable definition contained in Rule 4-10(a)(6) of Regulation S-X.
 
proved reserves: The estimated quantities of oil, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. This

2



definition of proved reserves has been abbreviated from the applicable definition contained in Rule 4-10(a)(22) of Regulation S-X.
 
proved undeveloped reserves or PUDs: Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(31) of Regulation
S-X.
 
recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
 
reserve: Estimated remaining quantities of mineral deposits anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.
 
reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
 
standardized measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions.

undeveloped acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
 
West Texas Intermediate (“WTI”): Light, sweet oil with high API gravity and low sulfur content used as the benchmark for U.S. crude oil refining and trading. WTI is deliverable at Cushing, Oklahoma to fill NYMEX futures contracts for light, sweet crude oil.
 
working interest: The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.
 
workover: Operations on a producing well to restore or increase production.
 
 

3



CERTAIN TERMS USED IN THIS ANNUAL REPORT ON FORM 10-K

References in this Annual Report on Form 10-K (this “report”) to “the Partnership,” “we,” “our,” “us” or like terms refer to Breitburn Energy Partners LP and its subsidiaries. References in this filing to “PCEC” refer to Pacific Coast Energy Company LP, formerly named Breitburn Energy Company L.P., our predecessor, and its predecessors and subsidiaries. References in this filing to “Breitburn GP” or the “General Partner” refer to Breitburn GP LLC, our general partner and our wholly-owned subsidiary. References in this filing to The Strand Energy Company refer to a corporation owned by Randall Breitenbach, a member of the board of directors of our General Partner, and Halbert Washburn, the Chief Executive Officer and a member of the board of directors of our General Partner. References in this filing to “Breitburn Management” refer to Breitburn Management Company LLC, our administrative manager and wholly-owned subsidiary. References in this filing to “BOLP” or “Breitburn Operating” refer to Breitburn Operating LP, our wholly-owned operating subsidiary. References in this filing to “BOGP” refer to Breitburn Operating GP LLC, the general partner of BOLP. References in this filing to “Breitburn Finance” refer to Breitburn Finance Corporation, our wholly-owned subsidiary, incorporated on June 1, 2009. References in this filing to “Breitburn Utica” refer to Breitburn Collingwood Utica LLC, our wholly-owned subsidiary formed on September 17, 2010.

Unless the context otherwise requires, references in this report to the following terms have the meanings set forth below:

FASB: Financial Accounting Standards Board.

ICE: Intercontinental Exchange.

LIBOR: London Interbank Offered Rate.
 
MichCon: Michigan Consolidated Gas Company.

US GAAP: Generally accepted accounting principles in the United States.



4



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.


5



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 :
ORGCHARTA06.JPG
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.


6



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

7



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

8



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

9



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.


10



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

11



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.
    
    

12



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.


13



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


14




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 .

15




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.


16



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.


17



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.


18



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.
  

19



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

20



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

21



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

22



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.


23



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

24



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.


25



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.


26



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.


27



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

28



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

29



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

30



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 ,

31



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

32



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.


33



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

34



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

35



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

36



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.


37



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

38



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.

39



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.

40



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.

 

41



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

42



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.

43



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.


44



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.”


45



  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

46



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.


47



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.



48



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).

49




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

GRAPH2016.JPG

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.


50



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 .


51



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