10-K 1 bbep12311510k.htm 10-K 10-K


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, 2015
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:
 
Title of each class
 
Name of each exchange on which registered
Common Units Representing Limited Partner Interests
 
The NASDAQ Stock Market LLC
 
Securities registered pursuant to section 12(g) of the Act: None

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
The aggregate market value of the Common Units held by non-affiliates was approximately $1.0 billion on June 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, based on $4.76 per unit, the last reported sales price on The NASDAQ Global Select Market on such date.
As of February 25, 2016, there were 213,670,116 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 are incorporated by reference from the registrant’s definitive proxy statement for the 2016 annual meeting of unitholders to be held on April 28, 2016.





BREITBURN ENERGY PARTNERS LP AND SUBSIDIARIES
TABLE OF CONTENTS

 
 
Page
 
 
No.
 
 
 
 
 
PART I
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
PART III
 
 
 
 
 
 
 
 
PART IV
 
 
 
 
 
 
 
Exhibit Index
 
 







GLOSSARY OF OIL AND GAS TERMS; DESCRIPTION OF REFERENCES
 
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.

CO2: Carbon dioxide.

CO2 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.
 

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FASB: Financial Accounting Standards Board.

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.
 
ICE: Intercontinental Exchange.

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

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

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

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.
 _____________________________________
 


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References in 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” or the “Predecessor” refer to Pacific Coast Energy Company LP, formerly named Breitburn Energy Company LP, 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 September 17, 2010.



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PART I

Cautionary Statement Regarding Forward-Looking Information
 
Certain statements and information in this Annual Report on Form 10-K (“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.


Item 1. Business.

Overview

We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil, NGL and natural gas properties in the United States. Our objective is to manage our oil, NGL and natural gas producing properties for the purpose of generating cash flow and making distributions to our unitholders. Our assets consist primarily of producing and non-producing oil, NGL and natural gas reserves located in seven producing areas:

Midwest (Michigan, Indiana and Kentucky);
Ark-La-Tex (Arkansas, Louisiana and East Texas);
Permian Basin in Texas and New Mexico;
Mid-Continent (Oklahoma, Kansas and the Texas Panhandle);
Rockies (Wyoming and Colorado);
Southeast (Florida and Alabama); and
California.

Our assets are characterized by stable, long-lived production and proved reserve life indexes averaging greater than 15 years. 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. Our production in 2015 was 20,180 MMBoe, of which approximately 56% was oil, 9% was NGLs and 35% was natural gas.

We are a Delaware limited partnership formed in 2006 and have been publicly traded since October 2006. Our general partner is Breitburn GP, a Delaware limited liability company, also formed in 2006, and has been our wholly-owned subsidiary since June 2008. 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, and BOLP’s general partner, BOGP. We own all of the ownership interests in BOLP and BOGP.

    

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In 2008, we acquired Breitburn Management and its interest in our General Partner, resulting in Breitburn Management and our General Partner becoming our wholly-owned subsidiaries. Breitburn Management manages our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. See Note 5 to the consolidated financial statements in this report for more information regarding our relationship with Breitburn Management.

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.

Structure

The following diagram depicts our organizational structure as of December 31, 2015:

As of December 31, 2015 and February 25, 2016, we had approximately 213.5 million and 213.7 million, respectively, common units representing limited partner interests in us (“Common Units”) outstanding. As of December 31, 2015 and February 25, 2016, we had 8.0 million 8.25% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”) outstanding. As of December 31, 2015 and February 25, 2016, we had 48.8 million and 49.4 million, respectively, 8.0% Series B Perpetual Convertible Preferred Units (“Series B Preferred Units”) outstanding.

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 and making distributions to our unitholders. Our core investment strategy has included the following principles:

acquire long-lived assets with low-risk exploitation and development opportunities;
use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;
reduce cash flow volatility through commodity price and interest rate derivatives; and
maximize asset value and cash flow stability through our operating expertise.


6



We have adjusted our business strategies in response to the steep and continued decline in commodity prices, which began at the end of 2014, by suspending distributions to common unitholders, significantly reducing our capital budgets, cutting operating and overhead costs, scaling back derivative activity and reducing our acquisition expectations. We continue to actively reassess our business strategies to address the lower commodity price environment.

Acquisitions

2015 Acquisitions

CO2 Acquisition. On March 31, 2015, we completed the acquisition of certain CO2 producing properties located in Harding County, New Mexico, for a total purchase price of $70.5 million (the “CO2 Acquisition”), which is primarily reflected in other property, plant and equipment on the consolidated balance sheet. See Note 3 to the consolidated financial statements within this report for a discussion of this 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 completed the merger with QR Energy, LP, a Delaware limited partnership (“QRE”), in exchange for approximately 71.5 million Common Units and $350 million in cash (the “QRE Merger”). 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.

2013 Acquisitions

Oklahoma Panhandle Acquisitions. On July 15, 2013, we completed the acquisition of principally oil properties and midstream assets located in Oklahoma, New Mexico and Texas, certain CO2 supply contracts, certain oil swaps and interests in certain entities from Whiting Oil and Gas Corporation (“Whiting”) for approximately $845 million in cash (the “Whiting Acquisition”), including post-closing adjustments. We also completed the acquisition of additional interests in certain of the acquired assets in the Oklahoma Panhandle from other sellers for an additional $30 million in July 2013.

2013 Permian Basin Acquisitions. On December 30, 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 in cash (the “CrownRock III Acquisition”). We also completed the acquisition of additional interests in certain of the acquired assets in the Permian Basin from other sellers for an additional $20 million in December 2013 (together with the CrownRock III Acquisition, the “2013 Permian Basin Acquisitions”).

Properties

Our properties include oil, NGL and natural gas assets as well as midstream assets located in the following producing areas: i) Midwest (Michigan, Indiana, and Kentucky), ii) Ark-La-Tex (Arkansas, Louisiana and East Texas), iii) the Permian Basin in Texas and New Mexico, iv) Mid-Continent (Oklahoma, Kansas and the Texas Panhandle), v) the Rockies (Wyoming and Colorado), vi) Southeast (Florida and Alabama) and vii) California. 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 69% of our total production in 2015. 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.


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2016 Outlook

In 2015, oil and natural gas prices continued the rapid and substantial decline that began at the end of 2014 and that has continued into the first quarter of 2016. Due to the uncertainty regarding future commodity prices, we plan to manage our operating activities and liquidity carefully. We do not expect increased production as a result of our 2016 capital program to entirely offset production declines, and expect that will result in decreases to our production, without taking into account acquisitions, divestitures or further modifications to our capital and operating plan based on price changes through 2016. We plan to continuously evaluate our operating activity in light of commodity prices and the changes we are able to make to both our costs of operations and to our capital budget.

We expect our full year 2016 oil and gas capital spending program to be approximately $80 million, including capitalized engineering costs and excluding potential acquisitions, compared with approximately $209 million in 2015. The reduction in capital expenditures reflects our outlook for 2016 performance measured against the ongoing weakness in commodity prices. We anticipate 60% of our total capital spending will be focused on drilling and rate-generating projects and CO2 purchases, in our core operating areas of East Texas, the Permian Basin and the Mid-Continent, that are designed to increase or add to production or reserves. We plan to drill 17 wells in Ark-La-Tex and Mid-Continent. We expect our 2016 production to be between 17.0 MMBoe and 19.7 MMBoe.

Commodity hedging remains an important part of our strategy to reduce cash flow volatility. We use swaps, collars and options for managing risk relating to commodity prices. As of February 25, 2016, we had approximately 77% of our expected 2016 production hedged, approximately 48% of our expected 2017 production hedged, approximately 10% of our 2018 production hedged and approximately 5% of our 2019 production hedged. For 2016, we have 24.8 MBbl/d of oil and 83.0 BBtu/d of natural gas hedged at average prices of approximately $85.79 per Bbl and $3.98 per MMBtu, respectively. For 2017, we have 14.8 MBbl/d of oil and 56.1 BBtu/d of natural gas hedged at average prices of approximately $83.11 per Bbl and $3.98 per MMBtu, respectively. For 2018, we have 1.5 MBbl/d of oil and 20.4 BBtu/d of natural gas hedged at average prices of approximately $64.02 per Bbl and $3.19 per MMBtu, respectively. For 2019, we have 1.0 MBbl/d of oil and 10.0 BBtu/d of natural gas hedged at average prices of approximately $56.35 per Bbl and $3.15 per MMBtu, respectively.

Reserves and Production

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. As of December 31, 2014, our total estimated proved reserves were 315.3 MMBoe, of which approximately 55% was oil, 8% was NGLs and 37% was natural gas. Net changes to our total estimated proved reserves included negative reserve revisions of 71.5 MMBoe and 20.1 MMBoe of production, resulting in a net decrease of 76.0 MMBoe from 2014 partially offset by 14.9 MMBoe in extensions and discoveries. The reserve revisions in 2015 were primarily the result of a 44.4 MMBoe decrease in oil reserves and a 3.6 MMBoe decrease in NGL reserves, driven primarily by a decrease in oil and NGL prices and a 141.6 Bcf decrease in natural gas reserves primarily due to a decrease in natural gas prices. The unweighted average first-day-of-the-month oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2015, were $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, compared to $94.99 per Bbl of oil for the WTI spot price, $101.30 per Bbl of oil for the ICE Brent spot price and $4.35 per MMBtu of natural gas for the Henry Hub spot price in 2014.

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The following table summarizes our estimated proved reserves and production by state as of December 31, 2015:
 
 
As of December 31, 2015
 
Year Ended
 
 
Proved Reserves
 
December 31, 2015
 
 
Total
 
Oil
 
NGLs
 
Natural
Gas
 
% Proved
 
 
 
Production
 
Average
Daily Production
 
 
(MMBoe) (a)
 
(MMBbl)
 
(MMBbl)
 
(Bcf)
 
Developed
 
% Total
 
(MBoe)
 
(Boe/d)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midwest
 
51.5

 
4.1

 
0.5

 
281.3

 
98
%
 
21
%
 
3,091

 
8,468

Ark-La-Tex
 
46.9

 
21.4

 
5.4

 
120.4

 
85
%
 
20
%
 
3,658

 
10,022

Permian Basin
 
44.6

 
27.9

 
7.9

 
53.2

 
68
%
 
19
%
 
4,498

 
12,322

Mid-Continent
 
32.3

 
25.6

 
4.2

 
14.7

 
44
%
 
13
%
 
2,814

 
7,710

Rockies
 
25.7

 
14.2

 

 
68.8

 
97
%
 
11
%
 
2,311

 
6,332

Southeast
 
20.4

 
18.8

 
1.6

 
0.8

 
82
%
 
9
%
 
2,038

 
5,585

California
 
17.9

 
17.2

 

 
4.1

 
88
%
 
7
%
 
1,770

 
4,849

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
239.3

 
129.2

 
19.6

 
543.3

 
80
%
 
100
%
 
20,180

 
55,288

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Antrim Shale (b)
 
42.6

 

 

 
255.6

 
100
%
 
18
%
 
2,233

 
6,118

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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, 2015, the Antrim Shale, included in “Midwest” above, was the only field which contained 15% or more of our total proved reserves.

The following table summarizes our production volumes, sales prices and production costs for the Antrim Shale, which accounted for 18% of our total proved reserves as of December 31, 2015:
 
 
Antrim Shale
 
 
2015
 
2014
 
2013
Net Production
 
 
 
 
 
 
Natural Gas (MMcf)
13,390

 
13,902

 
14,468

 
Total (MBoe)
2,233

 
2,317

 
2,411

Average Realized Sales Price
 
 
 
 
 
 
Natural Gas price per Mcf
$
2.94

 
$
5.29

 
$
3.90

 
Total price per Boe
$
17.66

 
$
31.79

 
$
23.40

Average Production Cost per Boe
 
 
 
 
 
 
Pre-tax lease operating expense
$
8.54

 
$
10.35

 
$
11.68


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, 2015, proved undeveloped reserves were 47.3 MMBoe compared to 71.5 MMBoe as of December 31, 2014. During 2015, we incurred $63.0 million in capital expenditures and drilled 51 wells related to the conversion of estimated proved undeveloped reserves to estimated proved developed reserves. During 2015, we converted 2.4 MMBbl of oil, 1.0 MMBbl of NGLs and 15.9 Bcf of natural gas from estimated proved undeveloped reserves to estimated proved developed reserves. As of December 31, 2015, 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, 2015, the total standardized measure of discounted future net cash flows was $1.3 billion. During 2015, we filed estimates of oil and gas reserves as of December 31, 2014 with the U.S. Department of Energy, which were consistent with the reserve data as of December 31, 2014 as reported in Note A in the supplemental information to the consolidated financial statements in this report.


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Uncertainties are inherent in estimating quantities of proved reserves, including many factors 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, 2015. 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 Regulation S-X Rule 4-10(a)(22) 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 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, employed by our General Partner, primarily responsible for overseeing preparation of the reserves estimates and the third party reserve reports is Mark L. Pease, the President and Chief Operating Officer of our General Partner. Mr. Pease received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines in 1979. Prior to joining our General Partner, Mr. Pease was Senior Vice President, E&P Technology & Services for Anadarko Petroleum Corporation.  Mr. Pease has over 30 years of experience working in various capacities in the energy industry, including acquisition analysis, reserve estimation, reservoir engineering and operations engineering. Mr. Pease consults with 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
    
Midwest (Michigan, Indiana, Kentucky)

As of December 31, 2015, our estimated proved reserves attributable to our Midwest properties were 51.5 MMBoe, or approximately 21% of our total estimated proved reserves. As of December 31, 2015, approximately 91% of our Midwest total estimated proved reserves were natural gas. For the year ended December 31, 2015, our average production from our Midwest properties was approximately 8.5 MBoe/d or 50.8 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 2015, we had two recompletions and completed one workover in Midwest. Our capital spending in Midwest for the year ended December 31, 2015 was approximately $3 million. We have interests in 3,719 productive wells in Midwest, and we operated approximately 59% 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 19 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.

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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.
    
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, 2015, estimated proved reserves attributable to our Ark-La-Tex properties were 46.9 MMBbls, or approximately 20% of our total estimated proved reserves, of which, approximately 46% were oil. For the year ended December 31, 2015 our average production was approximately 10.0 MBoe/d. Our capital spending in Ark-La-Tex for the year ended December 31, 2015 was approximately $58 million. As of December 31, 2015, we had interests in 3,103 productive wells in Ark-La-Tex, and we operated 96% of those wells. During 2015, we drilled 28 gross wells and completed 47 workovers.
    
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, 2015, estimated proved reserves attributable to our Permian Basin properties were 44.6 MMBoe, or approximately 19% of our total estimated proved reserves. As of December 31, 2015, approximately 63% of our Permian Basin total estimated proved reserves were oil, 17% were NGLs and 20% were natural gas. For the year ended December 31, 2015, our average production from the Permian Basin was approximately 12.3 MBoe/d. In 2015, we drilled 23 gross new productive development wells, three recompletion and completed six workovers in the Permian Basin. Our capital spending in the Permian Basin for the year ended December 31, 2015 was approximately $65 million. In total, we have interests in 3,164 productive wells in the Permian Basin, and we operated approximately 45% of those wells.

Mid-Continent

Our Mid-Continent area includes properties located in western Oklahoma, southwestern Kansas and the Texas Panhandle. These properties produce from regionally significant geologic formations such as the Cottage Grove, Morrow, Atoka, Redfork and Lansing. As of December 31, 2015, estimated proved reserves attributable to our Mid-Continent properties were 32.3 MMBoe, or approximately 13% of our total estimated proved reserves. Approximately 79% of our Mid-Continent total estimated proved reserves were oil, 13% were NGLs and 8% were natural gas. For the year ended December 31, 2015, the properties produced approximately 7.7 MBoe/d. In 2015, we drilled two gross new productive development wells and completed 5 workovers in the Mid-Continent. Our capital spending in the Mid-Continent for the year ended December 31, 2015 was approximately $26 million primarily attributable to CO2 purchases. In total, we have interests in 784 productive wells, and we operated approximately 86% 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. CO2 miscible flooding has been on-going in the Postle Field since 1995. CO2 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, each with a processing capacity of approximately 40 MMcf/d. Gas is processed to recover marketable hydrocarbon components from the wellhead stream and capture CO2 gas for recompression and reuse in the flooding process. In addition, we are the sole owner of a collection of facilities and CO2 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.

    

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As of December 31, 2015, estimated proved reserves attributable to our properties in the Rockies were 25.7 MMBoe, or approximately 11% of our total estimated proved reserves. As of December 31, 2015, approximately 55% of our Wyoming total estimated proved reserves were oil and 45% were natural gas. For the year ended December 31, 2015, our average production from our fields in Wyoming and Colorado were approximately 6.3 MBoe/d. In 2015, we drilled two gross new productive development wells, and completed three workovers in Wyoming. Our capital spending in Wyoming for the year ended December 31, 2015 was approximately $1 million. In total, we have interests in 980 productive wells in Wyoming, and we operated approximately 66% of those wells. Our non-operated assets in Colorado consist of 338 productive wells.

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.

Both of 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, 2015, estimated proved reserves attributable to our assets in the Southeast were 20.4 MMBoe, or approximately 9% of our total estimated proved reserves, of which approximately 92% were oil. For the year ended December 31, 2015, our average Southeast production was approximately 5.6 MBoe/d. In 2015, we drilled two new gross productive development wells and completed 15 workovers in our assets in the Southeast. Our capital spending for the year ended December 31, 2015 was approximately $42 million. As of December 31, 2015, we had interests in 94 productive wells in the Southeast, and we operated 96% of those wells.

California

As of December 31, 2015, estimated proved reserves attributable to our California properties were 17.9 MMBoe, or approximately 7% of our total estimated proved reserves. As of December 31, 2015, approximately 96% of our California total estimated proved reserves were oil. For the year ended December 31, 2015, our average California production was approximately 4.8 MBoe/d. In 2015, we drilled five gross productive wells, four recompletions and one workover in California. Our capital spending in California for the year ended December 31, 2015 was approximately $14 million. In total, we have interests in 570 productive wells in California, and we operated 100% of those wells.

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.


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Productive Wells

The following table sets forth information for our properties as of December 31, 2015, 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 43 wells with multiple completions as of December 31, 2015.
 
 
Oil Wells
 
Gas Wells
 
 
Gross
 
Net
 
Gross
 
Net
Operated
 
5,329

 
5,055

 
3,234

 
2,439

Non-operated
 
1,776

 
88

 
2,075

 
710

Total
 
7,105

 
5,143

 
5,309

 
3,149

 
Developed and Undeveloped Acreage

The following table sets forth information for our properties as of December 31, 2015 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
Midwest
 
510,777

 
266,724

 
28,289

 
27,084

 
539,066

 
293,808

Ark-La-Tex
 
116,685

 
75,535

 
1,367

 
765

 
118,052

 
76,300

Permian Basin
 
91,401

 
62,090

 
31,876

 
22,698

 
123,277

 
84,788

Mid-Continent
 
140,982

 
81,328

 
3,826

 
3,826

 
144,808

 
85,154

Rockies
 
176,392

 
100,492

 
28,666

 
9,653

 
205,058

 
110,145

Southeast
 
54,668

 
48,836

 
8,020

 
3,268

 
62,688

 
52,104

California
 
3,997

 
3,257

 
41

 
41

 
4,038

 
3,298

Total
 
1,094,902

 
638,262

 
102,085

 
67,335

 
1,196,987

 
705,597


The following table lists the net undeveloped acres as of December 31, 2015, 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.
 
 
 
 
2016 Expirations
 
2017 Expirations
 
2018 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
Midwest
 
27,084

 
1,181

 
10,847

 
544

 
917

 
40

 

Ark-La-Tex
 
765

 
3

 
30

 

 
13

 
29

 
7

Permian Basin
 
22,698

 
140

 

 
63

 
321

 
260

 
3

Mid-Continent
 
3,826

 

 

 
3

 

 

 

Rockies
 
9,653

 
120

 

 
960

 

 
36

 

Southeast
 
3,268

 
2,207

 

 
330

 

 
3,292

 

California
 
41

 

 

 

 

 
34

 

Total
 
67,335

 
3,651

 
10,877

 
1,900

 
1,251

 
3,691

 
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As of December 31, 2015, we held more than 117,000 net acres in the developing Utica-Collingwood shale play in Michigan. Approximately 94% of this acreage is held by production and is included in the developed acreage in the above table. As of December 31, 2015, we also held more than 57,000 net acres in the developing A1-Carbonate play in Michigan, approximately 97% of which is held by production.


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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, 2015, 2014 and 2013. 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,
 
 
2015
 
2014
 
2013
Gross development wells:
 
 
 
 
 
 
Productive
 
62

 
170

 
119

Dry
 

 
1

 
3

Total
 
62

 
171

 
122

Net development wells:
 
 
 
 

 
 

Productive
 
45

 
160

 
105

Dry
 

 
1

 
3

Total
 
45

 
161

 
108

 
As of December 31, 2015, we had the following wells in progress: two gross and one net well in Ark-La-Tex and one gross and one net well in the Southeast.

Delivery Commitments

As of December 31, 2015, we had no material delivery commitments.

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 2015, our largest purchasers were Shell Trading (US) Company (“Shell Trading”), which accounted for approximately 24% of our net sales revenues, and Plains Marketing (“Plains Marketing”), which accounted for approximately 12% of our net sales revenues. See Note 20 to the consolidated financial statements in this report for a discussion of significant customers for the years ended December 31, 2015, 2014 and 2013.

Commodity Prices

We analyze the prices we realize from the sales of all our produced products, including our crude oil, NGLs, and natural gas and the impact on those prices of differences in market-based index prices and the effects of our derivative activities. 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

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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 2015, the WTI posted price averaged approximately $48 per Bbl, compared with $93 a year earlier. The monthly average WTI posted prices during 2015 ranged from a high of $60 per Bbl in June to a low of $37 per Bbl in December. As of February 16, 2016, the WTI spot price during 2016 has averaged $31 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 2015, the monthly average Henry Hub posted price ranged from a high of $2.99 per MMBtu in January to a low of $1.93 per MMBtu in December. During 2015, the Henry Hub posted price averaged approximately $2.62 per MMBtu. As of February 16, 2016, the Henry Hub posted price during 2016 has averaged $2.22 per MMBtu.

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, ability to reinstate distributions, access to the capital markets and ability to grow. ” We ceased paying distributions in late 2015, and we do not expect to reinstate distributions in 2016. Sustained depressed prices of oil and natural gas will also adversely affect our assets, development plans, results of operations and financial position, perhaps materially. — “Low oil and natural gas prices, declines in the trading prices of our debt and equity securities and concern about the global financial markets 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 our credit facility or obtain funding at all.” in this report.

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.

Derivative Activity

Our revenues and net income are sensitive to oil and natural gas prices. We enter 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. We currently maintain derivative arrangements for a significant portion of our oil and gas production. Currently, we use a combination of fixed price swap and option arrangements to economically hedge NYMEX WTI, ICE Brent and LLS oil prices and Henry Hub and MichCon City-Gate natural gas prices. By removing the price volatility from a significant portion of our oil and natural gas production, we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flow from operations for those periods. While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected. For a more detailed discussion of our derivative activities, see Part II—Item 7A “—Quantitative and Qualitative Disclosures About Market Risk” and Note 4 to the consolidated financial statements included in this report.

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.


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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 has delayed development drilling and other exploitation activities and has 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 sufficient revenue to allow us to pay distributions to our unitholders.” 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. Under our credit facility, we have granted the lenders a lien on substantially all of our oil and gas properties. Under our Senior Secured Notes (as defined below), we also have granted our noteholders a second 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.

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

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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. 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 within the meaning of 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.

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. 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.


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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 such 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 these seismic activity concerns within the state. 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 and January 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.
  
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 promising to comply with the EPA’s directives through a combination of rulemaking and administrative orders. This increased scrutiny of Class II wells has resulted in the California Department of Oil, Gas and Geothermal Resources ordering the closure of 15 injection wells in October 2015; additional closures are expected. 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 and storage vessels. The Clean Air Act also imposes leak detection requirements for new or modified 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. 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.

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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 proposed in April 2015 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management 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, 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. At this time, we cannot predict the impact of these rules on the Partnership’s operations; however, we do not expect any material adverse impact to result from the implementation of these rules. In addition, several local jurisdictions in California have proposed and several jurisdictions in 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 will have a material adverse effect on the Partnership as a whole.
The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. 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. Recently, 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. In addition, in August 2015, the EPA announced proposed rules that would 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, as part of an overall effort to reduce methane emissions by up to 45 percent by 2025. These new and proposed rules could result in increased compliance costs for the Partnership.


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In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and many of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the implementation of state and/or regional 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 drilling rigs. Under the California program, the cap declines annually from 2013 through 2020. We will be 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. More recently, 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. Additional future regulatory action expanding PHMSA jurisdiction and imposing stricter integrity management requirements is likely. For example, in December 2015, the Senate Commerce Committee approved 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 could also require 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. If enacted, this legislation could result in PHMSA proposing additional integrity management requirements for our regulated

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pipelines. At this time, we cannot predict the cost of such requirements, 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. We have had fines and penalties imposed or threatened based on claimed paperwork and documentation omissions. 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. For example, in March 2014, the U.S. Fish and Wildlife Service listed as threatened the lesser prairie chicken, whose habitat includes portions of the Partnership’s areas of operations. As a result, landowners and drilling companies are restricted from undertaking activities that harm the lesser prairie chicken without a permit. Landowners and businesses can, however, enter into certain range-wide conservation planning agreements to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee in order to limit the regulatory impact of the species’ presence. 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, 2015. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2016. 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.

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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.

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.

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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 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.

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

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

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


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

In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1 million per violation per day. In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the CFTC to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to liquids swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to liquids purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation. For a description of FERC’s anti market manipulation rules, see “Energy Policy Act of 2005” below.
Our sales of oil, natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation can be subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting the interstate transportation of natural gas, and to a lesser extent, the interstate transportation of oil and NGLs. These initiatives also may indirectly affect the intrastate transportation of oil, natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of these regulatory changes to our oil, natural gas and NGL marketing operations, and we do not believe that we would be affected by any such FERC action materially differently than other oil, natural gas and NGL marketers with whom we compete.

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

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


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Employees

Breitburn Management, our wholly-owned subsidiary, operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of Breitburn Management. As of December 31, 2015, Breitburn Management had 833 full time employees. Breitburn Management provides services to us as well as to our Predecessor. 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 1401 McKinney Street, Houston, Texas 77010 and at JP Morgan Chase Tower at 600 Travis 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.


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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 Common Units could decline, we may not be able to reinstate the distributions on our Common Units and you could lose part or all of your investment.
 
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, ability to reinstate distributions, 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 54%, 8% and 38% of our estimated proved reserves as of December 31, 2015, respectively, and approximately 56%, 9% and 35% of our 2015 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, 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. During the year ended December 31, 2014, the monthly average WTI spot price ranged from a high of $106 per Bbl in June to a low of $59 per Bbl in December while the monthly average Henry Hub natural gas price ranged from a high of $6.00 per MMBtu in February to a low of $3.48 per MMBtu in December. As of February 16, 2016, the WTI spot price during 2016 has averaged $31 per Bbl and the natural gas spot price at Henry Hub has averaged approximately $2.22 per MMBtu. Price discounts or differentials between WTI spot prices and what we actually receive are also historically very volatile.


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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:
 
our ability to reinstate Common Unit distributions;
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;
our ability to meet our financial obligations; and
the amount that we are allowed to borrow or have outstanding under our credit facility and our liquidity position in the event we cannot borrow or must repay amounts under our credit facility.
 
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.
In the past, we have raised our distribution levels on our Common Units in response to increased cash flow during periods of relatively high commodity prices. However, we have not been able to sustain those distribution levels during subsequent periods of lower commodity prices. For example, we did not pay a distribution from February 2009 until May 2010. In November 2015, in response to sustained lower commodity prices, we again elected to suspend distributions on our Common Units effective with the third monthly payment attributable to the third quarter of 2015. There is no guarantee that we will reinstate distributions on our Common Units.
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 2015 ranged from a high of $59.82 per Bbl in June to a low of $37.19 per Bbl in December, and the monthly average Henry Hub posted price ranged from a high of $2.99 per MMBtu in January to a low of $1.93 per MMBtu in December. As of December 31, 2015, we had approximately 77% of our expected 2016 production hedged at prices higher than those currently prevailing. In 2015, 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, service our indebtedness and reinstate distributions to our unitholders.

Low oil and natural gas prices, declines in the trading prices of our debt and equity securities and concern about the global financial markets 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 our credit facility or obtain funding at all.
 
Historically, we have used our cash flow from operations, borrowings under our credit facility and issuances of senior notes and additional partnership units to fund our capital expenditures and acquisitions. Low oil and natural gas prices and concern about the global financial markets could make it challenging to obtain funding in the capital and credit markets in the future. In 2013, 2014 and 2015, to a limited extent, we were able to access the debt and equity capital markets. However, the recent declines and volatility in oil and natural gas prices and in the trading prices of our debt and equity securities have significantly increased the cost of obtaining money in the capital and credit markets and limited our ability to access those markets currently as a source of funding.
 

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These events affect our ability to access capital in a number of ways, which include the following:
 
Our ability to access new debt or credit markets on acceptable terms is currently limited, and this condition may last for an unknown period of time.
Our credit facility limits the amounts we can borrow to a borrowing base amount determined by the lenders at their sole discretion based on their valuation of our proved reserves and their internal criteria.
We may be unable to obtain adequate funding under our credit facility because our lenders may simply be unwilling or unable to meet their funding obligations.
The operating and financial restrictions and covenants in our credit facility and Senior Notes limit (and any future financing agreements likely will limit) our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to reinstate distributions.
 
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 meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our 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, financial condition or ability to reinstate distributions. Without funding to make acquisitions of additional properties containing proved oil or natural gas reserves, our total level of estimated proved reserves will decline as a result of our production, and we may be unable to reinstate distributions on our Common Units.

Our credit facility has substantial conditions, restrictions and financial covenants that may restrict our business and financing activities and our ability to reinstate distributions.

As of February 25, 2016, we had approximately $1.2 billion in borrowings under our credit facility outstanding. In 2015, we repaid $860 million borrowed under our credit facility. Our credit facility limits the amounts we can borrow to a borrowing base amount determined by the lenders at their sole discretion based on their valuation of our proved reserves and their internal criteria. The borrowing base at December 31, 2015 was $1.8 billion and the next semi-annual redetermination is scheduled for April 2016. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements or regulations or certain other circumstances. Based upon current commodity prices and other factors at the time of future redeterminations, we expect a significant decrease in our borrowing base. Although our lenders have the discretion to redetermine the borrowing base below our current outstanding borrowings, we do not expect that to occur in April 2016. Without a waiver from our lenders, our credit facility currently provides that if the borrowing base is reduced below our current outstanding borrowings, we are required to repay the deficiency in five equal monthly installments.  

We believe our existing cash resources and hedge positions should provide us with sufficient funds to meet our expected working capital needs for 2016, assuming that our borrowing base is redetermined above our current outstanding borrowings. Although we currently expect our sources of capital to be sufficient to meet our near-term liquidity needs, there can be no assurance that the lenders under our credit facility will not reduce the borrowing base to an amount below our current outstanding borrowings or that our liquidity requirements will continue to be satisfied, given current commodity prices and the discretion of our lenders to decrease our borrowing base. In addition, due to the steep declines in commodity prices and the trading prices of our debt and equity securities, we may not be able to obtain funding in the equity or capital markets on terms we find acceptable. The cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, and reduced and, in many cases, ceased to provide any new funding. If we cannot access the capital markets and repay debt under our credit facility in connection with the borrowing base determination in April 2016, we may take other actions to raise funds to repay debt, such as selling assets or restructuring derivative contracts.
 

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The operating and financial restrictions and covenants in our credit facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to reinstate distributions. Our credit facility restricts, and any future credit facility likely will restrict, our ability to:
 
incur indebtedness;
grant liens;
make certain acquisitions and investments;
lease equipment;
make capital expenditures above specified amounts;
redeem or prepay other debt;
make distributions to unitholders or repurchase units;
enter into transactions with affiliates; and
enter into a merger, consolidation or sale of assets.
 
Our credit facility restricts our ability to make distributions to unitholders or repurchase Common Units unless after giving effect to such distribution or repurchase, we remain in compliance with all terms and conditions of our credit facility and satisfy certain minimum liquidity requirements. While we currently are not restricted by our credit facility from declaring a distribution, we may be restricted from paying a distribution in the future.

We also are required to comply with certain financial covenants and ratios under the credit facility. Our ability to comply with these restrictions, covenants and conditions in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. In light of the deterioration of oil and natural gas prices, our ability to comply with these covenants and conditions may be impaired in the future. If we violate any of the restrictions, covenants, ratios or tests in our credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be prohibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders can seek to foreclose on our assets.
 
See Part II—Item 7 “—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in this report for a discussion of our credit facility covenants.

Even if we are able to pay distributions on our Common Units under the terms of our credit facility and the indenture governing our Senior Secured Notes, we may not elect to pay distributions on our Common Units because we do not have sufficient cash flow from operations following establishment of cash reserves, reduction of debt and payment of fees and expenses.
 
Our credit facility restricts our ability to make distributions to unitholders or repurchase units unless after giving effect to such distribution or repurchase, no event of default exists and we remain in compliance with all terms and conditions of our credit facility. For example, we were restricted from declaring a distribution on our Common Units and did not pay a distribution from February 2009 until May 2010. The indenture governing our Senior Secured Notes also restricts our ability to make distributions to our unitholders. While we currently are not restricted by our credit facility or the indenture governing our Senior Secured Notes from declaring a distribution, we have elected to suspend distributions on our Common Units and could be restricted from paying a distribution in the future.

Even if we are able to pay distributions on our Common Units under the terms of our credit facility and the indenture governing our Senior Secured Notes, we may not have sufficient available cash each quarter to pay distributions on our Common Units. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses, debt reduction and the amount of any cash reserve amounts that our General Partner establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. We may reserve a substantial portion of our cash flow from operations for debt reduction. In the future, we may reserve a substantial portion of our cash generated from operations to develop our oil and natural gas properties and to acquire additional oil and natural gas properties in order to maintain and grow our level of oil and natural gas reserves.

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The amount of cash that we actually generate will depend upon numerous factors related to our business that may be beyond our control, including among other things:
 
the amount of oil and natural gas we produce;
demand for and prices at which we sell our oil and natural gas, which prices decreased significantly in 2015 and have continued to decrease in 2016;
the effectiveness of our commodity price derivatives;
the level of our operating costs;
prevailing economic conditions;
our ability to replace declining reserves;
continued development of oil and natural gas wells and proved undeveloped reserves;
our ability to acquire oil and natural gas properties from third parties in a competitive market and at an attractive price;
the level of competition we face;
fuel conservation measures;
alternate fuel requirements;
government regulation and taxation; and
technical advances in fuel economy and energy generation devices.
 
In addition, the actual amount of cash that we will have available for distribution will depend on other factors, including:
 
our ability to borrow under our credit facility to pay distributions;
debt service requirements and restrictions on distributions contained in our credit facility, the indenture governing our Senior Secured Notes or future debt agreements;
the level of our capital expenditures;
sources of cash used to fund acquisitions;
fluctuations in our working capital needs;
general and administrative expenses (“G&A”);
costs of operations;
cash settlement of hedging positions;
timing and collectability of receivables; and
the amount of cash reserves established for the proper conduct of our business.
 
In November 2015, effective with the third monthly payment attributable to the third quarter of 2015, we elected to suspend distributions on our Common Units in light of declining commodity prices. There is no guarantee that we will reinstate distributions on our Common Units.

For a description of additional restrictions and factors that may affect our ability to reinstate cash distributions, please read Part II—Item 7 “—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in this report.

Restrictive covenants under our indentures governing our senior notes may adversely affect our operations.
 
The indentures governing our $650 million 9.25% Senior Secured Second Lien Notes due 2020 (the “Senior Secured Notes”), $305 million 8.625% Senior Notes due 2020 (the “2020 Senior Notes”) and $850 million 7.875% Senior Notes due 2022 (the “2022 Senior Notes”) (together with the Senior Secured Notes and the 2020 Senior Notes, the “Senior Notes”) contain, and any future indebtedness we incur may contain, a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:
 
sell assets, including equity interests in our restricted subsidiaries;
pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt;
make investments;
incur or guarantee additional indebtedness or issue preferred units;

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create or incur certain liens;
enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets;
engage in transactions with affiliates;
create unrestricted subsidiaries; and
engage in certain business activities.
 
As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
 
A failure to comply with the covenants in the indentures governing our Senior Notes or any future indebtedness could result in an event of default under the indentures governing the Senior Notes or the future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.

Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities. We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful.

As of February 25, 2016, our total debt was $2.99 billion. Our existing and future indebtedness could have important consequences to us, including:

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on terms acceptable to us;
covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
our access to the capital markets may be limited;
our borrowing costs may increase;
we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and
our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
 
Our ability to service, or to refinance, our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. We cannot assure you that our business will generate sufficient cash flows from operating activities or that future sources of capital will be available to us in an amount sufficient to permit us to service our indebtedness or repay our indebtedness as it becomes due or to fund our other liquidity needs. In addition, there can be no assurance that we will have the ability to borrow or otherwise raise the amounts necessary to repay or refinance our indebtedness as it matures. If our operating results are not sufficient to service our current or future indebtedness or meet our debt obligations as they become due, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing all or a portion of our indebtedness, or seeking additional financing. We may not be able to effect any of these remedies on satisfactory terms or at all. We may be unable to restructure or refinance our debt, obtain additional financing or capital or sell assets on satisfactory terms, if at all. If we cannot make scheduled payments on our debt, we will be in default under the terms of the agreements governing our debt and, as a result:

our debt holders could declare all outstanding principal and interest to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements;
the lenders under our credit facility could terminate their commitments to lend us money and foreclose against the assets securing their borrowings; and
we could be forced into bankruptcy or liquidation.

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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 price of our Common Units decreased from $7.63 per unit on January 2, 2015 to $0.67 per unit on December 31, 2015, and was $0.53 per unit as of the close of business on February 25, 2016, and it could decline further. Such further decline could result from a variety of factors, including, among other things, 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.

The liquidity of our Common Units could be adversely affected if we are delisted from NASDAQ.

On January 21, 2016, we received a deficiency notice from the Listing Qualifications Department of The NASDAQ Stock Market LLC (“NASDAQ”) notifying us that our Common Units closed below the $1.00 per unit minimum bid price required by NASDAQ Listing Rule 5450(a)(1) for 30 consecutive business days. The notice also indicated that, in accordance with NASDAQ Listing Rule 5810(c)(3)(A), we have a period of 180 calendar days, or until July 19, 2016, to achieve compliance with the minimum bid price requirement. We will regain compliance with the minimum bid price requirement if at any time before July 19, 2016, the bid price for our Common Units closes at $1.00 per unit or above for a minimum of 10 consecutive business days. In the event we do not regain compliance with the minimum bid price requirement by July 19, 2016, we may be eligible for an additional 180 calendar day compliance period if we elect to transfer to the NASDAQ Capital Market so as to take advantage of the additional compliance period offered on that market. To qualify, we would be required to meet the continued listing requirement for market value of publicly held shares and all other initial listing standards for the NASDAQ Capital Market, with the exception of the bid price requirement, and would need to provide written notice of our intention to cure the deficiency during the second compliance period.

Upon delisting from the NASDAQ Global Select Market or the NASDAQ Capital Market, our Common Units would be traded over-the-counter, more commonly known as OTC. 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. We are currently evaluating our alternatives to resolve the listing deficiency. To the extent that we are unable to resolve the listing deficiency, there is a risk that our Common Units may be delisted from NASDAQ, which would adversely impact the liquidity of our Common Units and potentially result in even lower bid prices for our Common Units. 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 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, 2015, we recorded non-cash impairment charges of approximately $2.4 billion primarily due to the impact that the sustained drop in commodity strip prices had on our projected future net revenues.

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 and on our ability to borrow funds under our credit facility, which in turn may adversely affect our ability to make cash distributions to our unitholders.


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The production from our Oklahoma properties could be adversely affected by the cessation or interruption of the supply of CO2 to those properties.

We use enhanced recovery technologies to produce oil and natural gas. For example, we inject water and CO2 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 CO2 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 CO2 to enhance production is subject to our ability to obtain sufficient quantities of CO2. If, under our CO2 supply contracts, the supplier is unable to deliver its contractually required quantities of CO2 to us, or if our ability to access adequate supplies is impeded, then we may not have sufficient CO2 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.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to reinstate distributions will be limited.
 
Our ability to grow and to reinstate distributions to unitholders depends in part on our ability to make acquisitions that result in an increase in pro forma available cash per unit. We may be unable to make such acquisitions because:
 
we cannot obtain financing for these acquisitions on economically acceptable terms;
we cannot identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
we are outbid by competitors; or
our Common Units are not trading at a price that would make the acquisition accretive.
 
If we are unable to acquire properties containing proved reserves, our total level of estimated proved reserves may decline as a result of our production, and we may be limited in our ability to reinstate our cash distributions.
 
Any acquisitions that we complete are subject to substantial risks that could reduce our ability to reinstate distributions to our unitholders. The integration of the oil and natural gas properties that we acquire may be difficult and could divert our management’s attention away from our other operations.
 
If we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:
 
a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
the validity of our assumptions about reserves, future production, revenues and costs, including synergies;
an inability to integrate successfully the businesses we acquire;
a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
the diversion of management’s attention from other business concerns;
an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;
the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;
unforeseen difficulties encountered in operating in new geographic areas; and
customer or key employee losses at the acquired businesses.
 
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.
 

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Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

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 and, as a result, our ability to reinstate distributions to our unitholders.
 
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 sufficient revenue to allow us to pay distributions to our unitholders.
 
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 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

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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, which will reduce our cash available for distribution. 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 generated from our operations, additional borrowings or the issuance of additional partnership interests, or some combination thereof. In 2016, our oil and gas capital spending program is expected to be approximately $80 million, compared to approximately $209 million in 2015 and approximately $389 million in 2014. Our planned reduction of capital expenditures in 2016, compared to 2015 and 2014, reflects our expectations of lower commodity prices in the future and declining costs of oil field equipment, drilling and other services. We expect to use cash generated from operations to fund future capital expenditures, which will reduce cash available for distribution to our unitholders. 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, financial condition and ability to pay distributions. Even if we are successful in obtaining the necessary funds, the terms of such financings could be onerous and could limit our ability to reinstate distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution.
 
Our inability to replace our reserves could result in a material decline in our reserves and production, which could adversely affect our financial condition. We are unlikely to be able to reinstate distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base.
 
As a result of the significant decline in commodity prices and the impact on our liquidity and access to capital, we expect that our ability to make acquisitions will be limited in 2016. We also believe that our reduced capital program in 2016 will not be sufficient to offset 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, 2015 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 and ability to make distributions 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 and reduce cash available for distribution.
 
We are unlikely to be able to reinstate distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution. Because the timing and amount of these capital expenditures fluctuate each quarter, we expect to reserve cash each quarter to finance these expenditures over time. We may use the reserved cash to reduce indebtedness until we make the capital expenditures.
 

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Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain and expand our asset base, we will be unable to pay distributions from cash generated from operations.

Our derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to reinstate distributions to our unitholders. To the extent we have hedged a significant portion of our expected production and actual production is lower than expected or the costs of goods and services increase, our profitability would be adversely affected.
 
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently and may in the future enter into derivative arrangements for a significant portion of our expected oil and natural gas production that could result in both realized and unrealized commodity derivative losses. As of February 25, 2016, we had hedged, through swaps, options (including collar instruments) and physical contracts, approximately 77% of our expected 2016 production.

The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. The reference prices of the derivative instruments we utilize may differ significantly from the actual oil and natural gas prices we realize in our operations. Furthermore, we have adopted a policy that requires, and our credit facility also mandates, that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we will continue to have direct commodity price exposure on the portion of our production volumes not covered by these derivative transactions.
 
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution in our profitability and liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.
 
In addition, our derivative activities are subject to the following risks:
 
we may be limited in receiving the full benefit of increases in oil and natural gas prices as a result of these transactions;
a counterparty may not perform its obligation under the applicable derivative instrument or seek bankruptcy protection;
there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and
the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

As of February 25, 2016, our derivative counterparties were Bank of Montreal, Barclays Bank PLC, BNP Paribas, Canadian Imperial Bank of Commerce, Citibank, N.A., Citizens Bank, National Association, Comerica Bank, Credit Agricole Corporate and Investment Bank, Credit Suisse Energy LLC, Credit Suisse International, ING Capital Markets LLC, JP Morgan Chase Bank N.A., Merrill Lynch Commodities, Inc., Morgan Stanley Capital Group Inc., Royal Bank of Canada, The Bank of Nova Scotia, The Toronto-Dominion Bank, Union Bank N.A. and Wells Fargo Bank, N.A. We periodically obtain credit default swap information on our counterparties. As of December 31, 2015 and February 25, 2016, each of these financial institutions had an investment grade credit rating. Although we currently do not believe that we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default. As of December 31, 2015, our largest derivative asset balances were with Wells Fargo Bank, N.A., Barclays Bank PLC, Credit Suisse Energy LLC and Morgan Stanley Capital Group Inc., which accounted for approximately 15%, 13%, 11% and 11% of our derivative asset balances, respectively.


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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 November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for, or linked to, certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit 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 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.

In addition, Dodd-Frank was intended, in part, to reduce the volatility of oil and gas prices. To the extent oil and gas prices are unhedged, our revenues could be adversely affected if a consequence of Dodd-Frank and implementing regulations is to lower commodity prices.

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, reduce the availability of some derivatives to protect against risks that we encounter or reduce our ability to monetize or restructure our existing derivative contracts. If we reduce 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 and make distributions to our unitholders. Any of these consequences could have a material, adverse effect on us, our financial condition, our results of operations and our ability to make distributions to our unitholders. 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.
 

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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, 2015 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, 2015 would have decreased by $0.4 billion, from $1.3 billion, to $0.9 billion.

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 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.


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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 2015, 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 2015, two customers accounted for approximately 36% 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 2015, Shell Trading accounted for approximately 24% of our net sales revenues and Plains Marketing accounted for approximately 12% 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 69% of our production in 2015.  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.

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

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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.

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 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. Recently, 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. In addition, in August 2015, the EPA announced proposed rules that would establish

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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, as part of an overall effort to reduce methane emissions by up to 45 percent by 2025. 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 taken legal measures to reduce emissions of greenhouse gases primarily through the implementation of state and/or regional 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. We will be 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.

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 Safe Drinking Water Act 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 proposed in April 2015 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management 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.

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At the state level, several states, including California, Texas, Oklahoma, 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. At this time, we cannot predict the impact of these rules on the Partnership’s operations; however, we do not expect any material adverse impact to result from the implementation of these rules. In addition, several local jurisdictions in California have proposed various forms of moratoria or bans on hydraulic fracturing. In some cases, these discussed measures include broad terms which, if enacted, could affect current operations. We do not believe that any current local proposal will have a material adverse effect on the Partnership as a whole.
The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board . 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 federal Safe Drinking Water Act 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.

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.
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.


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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 of 8.25% Series A Cumulative Redeemable Perpetual Preferred Units. In April 2015, we issued 46.7 million of 8.0% Series B Perpetual Convertible Preferred Units (“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 amount of cash distributed on each Common Unit may decrease;
the relative voting strength of each previously outstanding Common Unit may be diminished;
the market price of the Common Units may decline; and
the ratio of taxable income to distributions may increase.
 
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;

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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.
 
Certain of the directors and officers of our General Partner, including the Vice Chairman of the Board, our Chief Executive Officer, our President and other members of our senior management, own interests in PCEC, which is managed by our subsidiary, Breitburn Management. Conflicts of interest may arise between PCEC, on the one hand, and us and our unitholders, on the other hand. Our partnership agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.
 
Certain of the directors and officers of our General Partner, including the Vice Chairman of the Board, our Chief Executive Officer, our President and other members of our senior management, own interests in PCEC, which is managed by our subsidiary, Breitburn Management. Conflicts of interest may arise between PCEC, on the one hand, and us and our unitholders, on the other hand. We have entered into an Omnibus Agreement with PCEC to address certain of these conflicts. However, these persons may face other conflicts between their interests in PCEC and their positions with us. These potential conflicts include, among others, the following situations:
 
Our General Partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayments of indebtedness, issuances of additional partnership securities, cash reserves and expenses. Although we have entered into an Omnibus Agreement with PCEC, which addresses the rights of the parties relating to potential business opportunities, conflicts of interest may still arise with respect to the pursuit of such business opportunities. We have agreed in the Omnibus Agreement that PCEC and its affiliates will have a preferential right to acquire any third party upstream oil and natural gas properties that are estimated to contain less than 70% proved developed reserves.

Currently and historically some officers of our General Partner and many employees of Breitburn Management have also devoted time to the management of PCEC. This arrangement will continue under the Third Amended and Restated Administrative Services Agreement (as amended, the “Administrative Services Agreement”) and this will continue to result in material competition for the time and effort of the officers of our General Partner and employees of Breitburn Management who provide services to PCEC and who are officers and directors of the sole member of the general partner of PCEC. If the officers of our General Partner and the employees of Breitburn Management do not devote sufficient attention to the management and operation of our business, our financial results could suffer and our ability to make distributions to our unitholders could be reduced.


44



On February 5, 2016, PCEC provided written notice to Breitburn Management of its intention to terminate the Administrative Services Agreement effective as of June 30, 2016.

See “Breitburn Management” in Part II—Item 7 “—Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report for a discussion of PCEC.
 
Our partnership agreement limits the liability and reduces the fiduciary duties of our General Partner and its directors and officers, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing Common Units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law.
 
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 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.

45



 
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.
 
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.
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.
 

46



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, which is currently a maximum of 35% 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. For example, the Obama Administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships’ earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. 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. If successful, the Obama Administration’s proposal or other similar proposals could eliminate 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, the IRS, on May 5, 2015, issued proposed regulations concerning the activities that give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.

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. Recently enacted legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could 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.

Recently enacted legislation applicable to us for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as the result of audit adjustments, the value of our units may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.

47



Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction.
Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal and state income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact the value of an investment in our units. Additionally, legislation could be enacted that increases the taxes states impose on oil and natural gas extraction. Moreover, President Obama has proposed, as part of the Budget of the United States Government for Fiscal Year 2017, to impose an “oil fee” of $10.25 on a per barrel equivalent of crude oil. This fee would be collected on domestically produced and imported petroleum products. The fee would be phased in evenly over five years, beginning October 1, 2016. The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil.

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.

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 response to current market conditions, 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, we anticipate pursuing opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications and extinguishment of our existing debt that would 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 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. Unitholders are encouraged to consult their tax advisors with respect to the consequences to them of COD income.

48



 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 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 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. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The U.S. Treasury Department recently adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize the use of the proration method we have adopted for our 2015 taxable year and may not specifically authorize all aspects of our proration method thereafter. 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 unitholders.
 

49



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 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.

For example, in 2015 as a result of normal trading activity by our unitholders, greater than 50% of our Common Units traded within a twelve month period and caused a technical termination of the Partnership for federal income tax purposes. This technical termination required the closing of our taxable year for all unitholders on March 31, 2015 and brought about two taxable periods for 2015: January 1, 2015 to March 31, 2015 and March 31, 2015 to December 31, 2015. We were required to file two federal tax returns for the two short periods during the 2015 tax year.
 
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 California, Colorado, Florida, Indiana, Kentucky, Michigan, Texas, Utah and Wyoming. 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.



50



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.

Item 4. Mine Safety Disclosures.

Not applicable.


51



PART II

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

Our Common Units trade on the NASDAQ Global Select Market under the symbol “BBEP.” As of December 31, 2015, based upon information received from our transfer agent and brokers and nominees, we had approximately 96,927 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 February 25, 2016 was $0.53 per unit.
 
 
Unit Price Range
Quarter
 
High
 
Low
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

 
 
 
 
 
2014
 
 
 
 
Fourth Quarter
 
$
20.73

 
$
6.46

Third Quarter
 
$
23.15

 
$
19.83

Second Quarter
 
$
22.30

 
$
19.65

First Quarter
 
$
21.36

 
$
19.1


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 impact that low commodity prices has had on our cash flows and operations, we do not expect to reinstate distributions in 2016. Our credit agreement restricts us from making cash distributions unless, after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility. The indenture governing our Senior Secured Notes also restricts our ability to make distributions to unitholders. We are not currently restricted from paying distributions under our credit facility or the terms governing the Senior Secured Notes. See Item 7 “—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility” and Note 9 to the consolidated financial statements in this report.

In October 2013, we changed our distribution payment policy from a quarterly payment schedule to a monthly payment schedule beginning with the distributions relating to the fourth quarter of 2013. For the quarters for which we declare a distribution, we expect that the distribution for the quarter will be made in three equal monthly payments within 17, 45 and 75 days following the end of each quarter to unitholders of record on the applicable record date. Prior to the distribution policy change, for the quarters for which we declared a distribution, distributions of available cash were made within 45 days after the end of the quarter to unitholders of record on the applicable record date.

Available cash, as defined in our partnership agreement, generally is all cash on hand, including cash from borrowings, at the end of the quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs.


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The following table provides a summary of Common Unit distributions related to and declared during the years ended December 31, 2015 and 2014:
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

September 2014
 
$
36,447

 
$
0.1733

 
11/24/2014

 
12/12/2014

August 2014
 
$
23,245

 
$
0.1675

 
10/29/2014

 
11/14/2014

July 2014
 
$
22,524

 
$
0.1675

 
10/1/2014

 
10/16/2014

June 2014
 
$
20,179

 
$
0.1675

 
8/25/2014

 
9/11/2014

May 2014
 
$
20,179

 
$
0.1675

 
7/30/2014

 
8/14/2014

April 2014
 
$
20,179

 
$
0.1675

 
7/1/2014

 
7/16/2014

March 2014
 
$
19,836

 
$
0.1658

 
5/27/2014

 
6/12/2014

February 2014
 
$
19,836

 
$
0.1658

 
4/24/2014

 
5/14/2014

January 2014
 
$
19,815

 
$
0.1658

 
4/1/2014

 
4/16/2014

2013
 
 
 
 
 
 
 
 
December 2013
 
$
19,573

 
$
0.1642

 
2/26/2014

 
3/14/2014

November 2013
 
$
19,573

 
$
0.1642

 
1/30/2014

 
2/14/2014

October 2013
 
$
19,573

 
$
0.1642

 
1/2/2014

 
1/16/2014

 
 
 
 
 
 
 
 
 
(a) Does not include distribution equivalents paid under our long-term incentive plans.
(b) Effective November 30, 2015, distributions on Common units were suspended by the Board of Directors, thus there were no Common unit distributions attributable to the fourth quarter 2015 including the third monthly payment of the distribution attributable to the third quarter.


53



Distributions on Preferred Units

On April 8, 2015, we issued in a private offering $350 million of 8.0% Series B Perpetual Convertible Preferred Units (“Series B Preferred Units”) to EIG Redwood Equity Aggregator, LP (“EIG Equity”), ACMO BBEP Corp. (“ACMO”) and certain other purchasers at an issue price of $7.50 per unit. The Series B Preferred Units rank senior to the Common Units and on parity with the Series A Preferred Units (as defined below) with respect to the payment of current distributions. We have the election through April 2018 to pay our Series B Preferred Unit distribution in kind by issuing additional Series B Preferred units (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred units) in lieu of cash and we have paid the distributions in kind since the Series B Preferred Units were issued. In 2015, we declared distributions on our Series B Preferred Units of 0.054883 paid in kind units per Series B Preferred Unit, 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 8.25% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”) in a public offering at a price of $25.00 per Series A Preferred Unit. The Series A Preferred Units rank senior to our Common Units with respect to the payment of current distributions. Distributions on Series A Preferred Units are cumulative from the date of original issue and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our Board out of legally available funds for such purpose. We pay cumulative distributions in cash on the Series A Preferred Units on a monthly basis at a monthly rate of $0.171875 per Series A Preferred Unit.

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 2015.

Common Unit Performance Graph

The graph below compares our cumulative total unitholder return on our Common Units over the five years ended December 31, 2015 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, 2010. Cumulative return is computed assuming reinvestment of dividends.


54



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

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

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, 2015, 2014 and 2013, with the exception of consolidated balance sheet data for the year ended December 31, 2013, from our audited consolidated financial statements appearing elsewhere in this report. We derived the financial data for the years ended December 31, 2012 and 2011, as well as consolidated balance sheet data for the year ended December 31, 2013, from our prior year audited consolidated financial statements, which are not included in this report.

In 2015, we completed the acquisition on March 31, 2015 of certain CO2 producing properties located in Harding County, New Mexico for a purchase price of $70.5 million.

On October 24, 2014, we completed the Antares Acquisition for 4.3 million Common Units and $50.0 million in cash. On November 19, 2014 we closed the QRE Merger 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.

On July 15, 2013, we completed the Whiting Acquisition for approximately $845 million. We also completed the acquisition of additional interests in the Oklahoma Panhandle for an additional $30 million on July 15, 2013. On December 30, 2013, we completed the 2013 Permian Basin Acquisitions from CrownRock, L.P. for approximately $282 million. We also completed the acquisition of additional interests in certain of the acquired assets in the Permian Basin from other sellers for an additional $20 million in December 2013.


55



In 2012, we completed the NiMin Acquisition on June 28, 2012 for approximately $95 million. On July 2, 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. On November 30, 2012, we completed the AEO Acquisition for approximately $38 million in cash and approximately 3 million Common Units. On December 28, 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%. We completed the Greasewood Acquisition on July 28, 2011 for approximately $57 million and the Cabot Acquisition on October 6, 2011 for approximately $281 million.

See Note 3 to the consolidated financial statements in this report for further details about our acquisitions in 2015, 2014 and 2013.


56



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 
 
2015
 
2014
 
2013
 
2012
 
2011
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and NGL sales
 
$
645,272

 
$
855,820

 
$
660,665

 
$
413,867

 
$
394,393

Gain (loss) on commodity derivative instruments, net
 
438,614

 
566,533

 
(29,182
)
 
5,580

 
81,667

Other revenue, net
 
24,829

 
7,616

 
3,175

 
3,548

 
4,310

Total revenue
 
1,108,715

 
1,429,969

 
634,658

 
422,995

 
480,370

Impairment of oil and natural gas properties
 
2,377,615

 
149,000

 
54,373

 
12,313

 
648

Impairment of goodwill
 
95,947

 

 

 

 

Operating (loss) income
 
(2,376,582
)
 
545,967

 
44,276

 
21,700

 
153,809

Net (loss) income
 
(2,583,013
)
 
421,316

 
(43,671
)
 
(40,739
)
 
110,698

Less: Net income (loss) attributable to noncontrolling interest
 
326

 
(17
)
 

 
62

 
201

Net (loss) income attributable to the partnership
 
$
(2,583,339
)
 
$
421,333

 
$
(43,671
)
 
$
(40,801
)
 
$
110,497

Basic net (loss) income per unit
 
$
(12.39
)
 
$
3.04

 
$
(0.43
)
 
$
(0.56
)
 
$
1.80

Diluted net (loss) income per unit
 
$
(12.39
)
 
$
3.02

 
$
(0.43
)
 
$
(0.56
)
 
$
1.79

 
 
 
 
 
 
 
 
 
 
 
Cash Flow Data:
 
 

 
 

 
 

 
 

 
 

Net cash provided by operating activities
 
$
436,705

 
$
360,173

 
$
257,166

 
$
191,782

 
$
128,543

Net cash used in investing activities
 
(274,003
)
 
(837,004
)
 
(1,465,805
)
 
(697,159
)
 
(414,573
)
Net cash (used in) provided by financing activities
 
(164,866
)
 
487,001

 
1,206,590

 
504,556

 
287,728

 
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (at period end):
 
 

 
 

 
 

 
 

 
 

Cash
 
$
10,464

 
$
12,628

 
$
2,458

 
$
4,507

 
$
5,328

Other current assets
 
577,863

 
588,080

 
114,604

 
109,158

 
167,492

Net property, plant and equipment
 
3,932,882

 
6,454,201

 
3,915,376

 
2,711,893

 
2,072,759

Other assets
 
351,203

 
583,425

 
163,844

 
89,936

 
85,270

Total assets
 
$
4,872,412

 
$
7,638,334

 
$
4,196,282

 
$
2,915,494

 
$
2,330,849

Current liabilities
 
$
318,006

 
$
361,556

 
$
182,889

 
$
115,240

 
$
89,889

Long-term debt
 
2,867,157

 
3,247,160

 
1,889,675

 
1,100,696

 
820,613

Other long-term liabilities
 
281,354

 
263,442

 
133,898

 
110,022

 
93,133

Partners' equity
 
1,398,571

 
3,759,291

 
1,989,820

 
1,589,536

 
1,326,764

Noncontrolling interest
 
7,324

 
6,885

 

 

 
450

Total liabilities and partners' equity
 
$
4,872,412

 
$
7,638,334

 
$
4,196,282

 
$
2,915,494

 
$
2,330,849

 
 
 
 
 
 
 
 
 
 
 
Cash distributions declared per unit outstanding:
 
$
0.3333

 
$
1.7581

 
$
1.9125

 
$
1.8300

 
$
1.6875


57



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

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

We use Adjusted EBITDA to assess:

the financial performance of our assets, without regard to financing methods, capital structure or historical cost basis;
our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure;
the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities; and
the ability of our assets to generate cash sufficient to pay interest costs, pay distributions and support our indebtedness.

The following table presents a reconciliation of Adjusted EBITDA to net income (loss) attributable to the partnership and cash flows provided by operating activities, our most directly comparable US GAAP financial performance measures, for each of the periods indicated.
  
 
Year Ended December 31,
Thousands of dollars
 
2015
 
2014
 
2013
 
2012
 
2011
Reconciliation of consolidated net income (loss) to Adjusted EBITDA:
 
 
 
 
 
 
 
 
 
 
Net (loss) income attributable to the partnership
 
$
(2,583,339
)
 
$
421,333

 
$
(43,671
)
 
$
(40,801