10-K 1 bbep12311310k.htm 10-K BBEP 12.31.13 10K


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, 2013
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 L.P.
(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.)
 
 
515 South Flower Street, Suite 4800
 
Los Angeles, California
90071
(Address of Principal Executive Offices)
(Zip Code)

Registrant’s telephone number, including area code: (213) 225-5900
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 x No o
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 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 $1.8 billion on June 28, 2013, the last business day of the registrant’s most recently completed second fiscal quarter, based on $18.25 per unit, the last reported sales price on The NASDAQ Global Select Market on such date.
As of February 27, 2014, there were 119,201,681 Common Units outstanding.
Documents Incorporated By Reference: Certain information called for in Items 10, 11, 12, 13 and 14 of Part III are incorporated by reference from the registrant’s definitive proxy statement for the 2014 annual meeting of unitholders to be held on June 19, 2014.





BREITBURN ENERGY PARTNERS L.P. AND SUBSIDIARIES
TABLE OF CONTENTS

 
 
Page
 
 
No.
 
 
 
 
 
PART I
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
PART III
 
 
 
 
 
 
 
 
PART IV
 
 
 
 
 
 
 







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.
 

1



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 and operating methods or in which the cost of the required equipment is relatively minor compared to

2



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 and operating conditions 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.
 
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.
 _____________________________________
 

3



References in this report to “the Partnership,” “we,” “our,” “us” or like terms refer to BreitBurn Energy Partners L.P. and its subsidiaries. References in this filing to “PCEC” or the “Predecessor” refer to Pacific Coast Energy Company LP, formerly named BreitBurn Energy Company L.P., our predecessor, and its predecessors and subsidiaries. References in this filing to “BreitBurn GP” or the “General Partner” refer to BreitBurn GP, LLC, our general partner and our wholly-owned subsidiary. References in this filing to “BreitBurn Corporation” refer to Strand Energy Company, 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 L.P., 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 “BEPI” refer to BreitBurn Energy Partners I, L.P. References in this filing to “Utica” refer to BreitBurn Collingwood Utica LLC, our wholly-owned subsidiary formed September 17, 2010. References in this filing to “Quicksilver” refer to Quicksilver Resources Inc., from whom we acquired oil and gas properties and facilities in Michigan, Indiana and Kentucky on November 1, 2007.

4



PART I

Item 1. Business.

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.
 
Overview

We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil, NGL and gas properties in the United States. Our objective is to manage our oil, NGL and 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 primarily in:

the Antrim Shale and several non-Antrim formations in Michigan;
the Oklahoma Panhandle;
the Permian Basin in Texas;
the Evanston, Green River, Wind River, Big Horn and Powder River Basins in Wyoming;
the Los Angeles and San Joaquin Basins in California;
the Sunniland Trend in Florida; and
the New Albany Shale in Indiana and Kentucky.

Our assets are characterized by stable, long-lived production and proved reserve life indexes averaging greater than 15 years. We have high net revenue interests in our properties. As of December 31, 2013, our total estimated proved reserves were 214.3 MMBoe, of which approximately 53% was oil, 7% was NGLs and 40% was natural gas. Our production in 2013 was 11.0 MMBoe, of which approximately 51% was oil, 6% was NGLs and 43% 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.

In 2008, we acquired BreitBurn Management and its interest in the General Partner, resulting in BreitBurn Management and the 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.

5




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, 2013:


As of both December 31, 2013 and February 27, 2014, we had 119.2 million common units representing limited partner interests in us (“Common Units”) outstanding.

Long-Term Business Strategy

Our long-term goals are 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. In order to meet these objectives, we plan to continue to follow our core investment strategy, which includes the following principles:

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

Acquisitions

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 (together with the

6



Whiting Acquisition, the “Oklahoma Panhandle Acquisitions”). The properties acquired in Whiting Acquisitions were comprised of approximately 84% oil, 11% NGLs and 5% natural gas.

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”). The assets acquired in the CrownRock III Acquisition and 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”). The properties acquired in the 2013 Permian Basin Acquisitions were comprised of approximately 63% oil, 20% NGLs and 17% natural gas.

2012 Acquisitions

NiMin Acquisition. In June 2012, we completed the acquisition of oil properties located in Park County in the Big Horn Basin of Wyoming from Legacy Energy, Inc., a wholly-owned subsidiary of NiMin Energy Corp. (the “NiMin Acquisition”), for approximately $95 million in cash.

2012 Permian Basin Acquisitions. In July 2012, we completed acquisitions of oil and natural gas properties located in the Permian Basin in Texas from Element Petroleum, LP and CrownRock, L.P. for approximately $148 million and $70 million in cash, respectively, (the “CrownRock I Acquisition”). On December 28, 2012, we completed the acquisition of oil and natural gas properties 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 in cash, respectively (together with the CrownRock I Acquisition, the “2012 Permian Basin Acquisitions”). The properties acquired in the 2012 Permian Basin Acquisitions were comprised of approximately 59% oil, 20% NGLs and 21% natural gas.

AEO Acquisition. In November 2012, we completed the acquisition of principally oil properties from American Energy Operations, Inc. (“AEO”) located in the Belridge Field in the San Joaquin Basin in Kern County, California (the “AEO Acquisition”) for approximately $38 million in cash and approximately 3.01 million of our Common Units valued at $56 million.

2011 Acquisitions

Greasewood Acquisition. In July 2011, we completed the acquisition of oil properties in the Powder River Basin in eastern Wyoming (the “Greasewood Acquisition”) for approximately $57 million in cash.

Cabot Acquisition. In October 2011, we completed the acquisition of principally natural gas properties located primarily in the Evanston and Green River Basins in southwestern Wyoming (the “Cabot Acquisition”) for approximately $281 million in cash. The properties acquired in the Cabot Acquisition were comprised of approximately 95% natural gas.

2014 Outlook

We expect our full year 2014 oil and gas capital spending program to be between $325 million and $345 million, including capitalized engineering costs and excluding potential acquisitions, compared with approximately $295 million in 2013. In 2014, we anticipate spending approximately 92% principally on oil projects in Texas, California and Oklahoma and approximately 8% principally on oil projects in Florida, Wyoming and Michigan. We anticipate 85% of our total capital spending will be focused on drilling and rate-generating projects that are designed to increase or add to production or reserves. We plan to drill 168 wells with 156 wells expected in Texas and California and 12 wells expected in Wyoming, Michigan and Florida. Without considering potential acquisitions, we expect our 2014 production to be between 13.6 MMBoe and 14.4 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 27, 2014, we had approximately 76% of our expected 2014 production hedged. For 2014, we have 20,114 Bbl/d of oil and 55,100 MMBtu/d of natural gas hedged at average prices of approximately $93.70 per Bbl and $4.95 per MMBtu, respectively. For 2015, we have 17,989 Bbl/d of oil and 56,700 MMBtu/d of natural gas hedged at average prices of approximately $93.54 per Bbl and $4.94 per MMBtu, respectively. For 2016, we have 15,011 Bbl/d of oil and 41,700 MMBtu/d of natural gas hedged at average prices of approximately $89.48 per Bbl and $4.32 per MMBtu, respectively. For 2017, we have 8,269 Bbl/d of oil and 18,571 MMBtu/d of natural gas hedged at average prices of approximately $84.71 per Bbl and $4.44 per MMBtu, respectively. For 2018, we have 493 Bbl/d of oil and 1,870 MMBtu/d of natural gas hedged at average prices of approximately $82.20 per Bbl and $4.15 per MMBtu, respectively.

7




Consistent with our long-term business strategy, we intend to continue to actively pursue oil and natural gas acquisition opportunities in 2014.

Properties

Our properties include oil, natural gas and midstream assets in Michigan, Indiana and Kentucky, including fields in the Antrim Shale in Michigan and the New Albany Shale in Indiana and Kentucky, transmission and gathering pipelines, two gas processing plants and four NGL recovery plants. Our properties also include oil and natural gas and midstream assets located in Oklahoma, New Mexico and Texas, including the Postle Field, the Northeast Hardesty Unit and the Dry Trails gas plant, all of which are located in Texas County, Oklahoma. We own a 51-mile oil pipeline in Oklahoma that connects with Texas that is a common carrier and the 120-mile Transpetco Pipeline, a CO2 transportation pipeline delivering product from New Mexico to the Postle Field in Oklahoma. Our properties also include fields in the Permian Basin in Texas, the Evanston and Green River Basins in southwestern Wyoming, the Wind River and Big Horn Basins in central Wyoming, the Powder River Basin in eastern Wyoming, the Los Angeles Basin in California, the Belridge Field in the San Joaquin Basin in California and in Florida’s Sunniland Trend.

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 86% of our production in 2013. 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.

Reserves and Production

As of December 31, 2013, our total estimated proved reserves were 214.3 MMBoe, of which approximately 53% was oil, 7% was NGLs and 40% was natural gas. As of December 31, 2012, our total estimated proved reserves were 149.4 MMBoe, of which approximately 49% was oil, 4% was NGLs, and 47% was natural gas. The net increase in our total estimated proved reserves of 64.9 MMBoe from December 31, 2012 to December 31, 2013 included additions from acquisitions in 2013 of 60.9 MMBoe, positive reserve revisions of 13.7 MMBoe and 1.3 MMBoe in extensions and discoveries offset by 11.0 MMBoe of production. The reserve revisions in 2013 were primarily the result of an 86.0 Bcf increase in natural gas reserves and 2.7 MMBoe increase in NGL reserves driven primarily by an increase in commodity prices and additional drilling, recompletions and workovers, offset by a 3.3 MMBbl decrease in oil reserves due to lower performance. 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, 2013 were $96.94 per Bbl of oil for WTI spot price, $108.32 per Bbl of oil for ICE Brent and $3.67 per MMBtu of natural gas for Henry Hub spot price, compared to $94.71 per Bbl of oil for WTI spot price, $111.77 per Bbl of oil for ICE Brent and $2.76 per MMBtu of natural gas for Henry Hub spot price in 2012.

8




The following table summarizes our estimated proved reserves and production by state as of December 31, 2013:
 
 
As of December 31, 2013
 
Year Ended
 
 
Proved Reserves
 
December 31, 2013
 
 
Total
 
Oil
 
NGLs
 
Natural
Gas
 
 
 
 
 
 
 
Average
Daily
 
 
(MMBoe) (a)
 
(MMBbl)
 
(MMBbl)
 
(Bcf)
 
% Proved Developed
 
% Total
 
Production
(MBoe) (b)
 
Production
(Boe/d) (b)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Michigan
 
58.2

 
3.7

 
1.0

 
320.7

 
98
%
 
27
%
 
3,212

 
8,801

Oklahoma
 
43.6

 
36.7

 
4.9

 
12.1

 
69
%
 
20
%
 
1,217

 
7,204

Texas
 
40.9

 
23.2

 
9.7

 
47.9

 
56
%
 
19
%
 
1,423

 
3,899

Wyoming
 
36.6

 
17.9

 

 
112.3

 
80
%
 
17
%
 
2,561

 
7,014

California
 
23.3

 
22.1

 

 
7.0

 
89
%
 
11
%
 
1,690

 
4,645

Florida
 
9.7

 
9.7

 

 

 
100
%
 
5
%
 
664

 
1,818

Indiana/Kentucky
 
2.0

 

 

 
12.2

 
100
%
 
1
%
 
216

 
591

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
214.3

 
113.3

 
15.6

 
512.2

 
81
%
 
100
%
 
10,983

 
33,972

(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) For properties acquired during 2013, production and average daily production figures are based on activities from acquisition date to December 31, 2013.

The following table summarizes our estimated reserves and production by major field as of December 31, 2013:

 
 
As of December 31, 2013
 
Year Ended
 
 
Proved Reserves
 
December 31, 2013
 
 
Total
 
Oil
 
NGLs
 
Natural
Gas
 
 
 
 
 
 
 
Average
Daily
 
 
(MMBoe) (a)
 
(MMBbl)
 
(MMBbl)
 
(Bcf)
 
% Proved Developed
 
% Total
 
Production
(MBoe) (b)
 
Production
(Boe/d) (b)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Antrim Shale
 
49.6

 

 

 
297.7

 
95
%
 
23
%
 
2,411

 
6,606

Postle Field
 
40.3

 
33.4

 
4.9

 
12.1

 
69
%
 
19
%
 
1,141

 
6,751

Spraberry Trend
 
40.9

 
23.2

 
9.7

 
47.9

 
56
%
 
19
%
 
1,423

 
3,899

All others
 
83.5

 
56.7

 
1.0

 
154.5

 
91
%
 
39
%
 
6,008

 
16,716

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
214.3

 
113.3

 
15.6

 
512.2

 
81
%
 
100
%
 
10,983

 
33,972

(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) For properties acquired during 2013, production and average daily production figures are based on activities from acquisition date to December 31, 2013.

As of December 31, 2013, proved undeveloped reserves were 40.9 MMBoe compared to 29.7 MMBoe as of December 31, 2012. The Oklahoma Panhandle Acquisitions and the 2013 Permian Basin Acquisitions added 13.7 MMBoe and 9.5 MMBoe, respectively, of proved undeveloped reserves. During 2013, we incurred $160.1 million in capital expenditures and drilled 122 wells related to the conversion of estimated proved undeveloped reserves to estimated proved developed reserves. During 2013, we converted 7.1 MMBbl of oil, 1.0 MMBbl of NGLs and 9.6 Bcf of natural gas from estimated proved undeveloped reserves to estimated proved developed reserves. As of December 31, 2013, we had no estimated proved undeveloped reserves that have remained undeveloped for more than five years, and we expect to develop all estimated proved undeveloped reserves within the next five years.

9




As of December 31, 2013, the total standardized measure of discounted future net cash flows was $3.2 billion. During 2013, we filed estimates of oil and gas reserves as of December 31, 2012 with the U.S. Department of Energy, which were consistent with the reserve data as of December 31, 2012 as reported in Note A in the supplemental information to the consolidated financial statements in this report.

Uncertainties are inherent in estimating quantities of proved reserves, including many factors 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, 2013. Estimates of our proved reserves were prepared by Cawley, Gillespie & Associates, Inc. (“CGA”), Netherland, Sewell & Associates, Inc. (“NSAI”) and Schlumberger PetroTechnical Services (“SLB”), independent petroleum engineering firms. CGA prepares reserve data for our Oklahoma properties, NSAI prepares reserve data for our California, Wyoming, Texas and Florida properties, and SLB prepares reserve data for our Michigan, Indiana and Kentucky properties. The reserve estimates are reviewed and approved by members of our senior engineering staff and management. The process performed by CGA, NSAI and SLB 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. CGA, NSAI and SLB 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, CGA, NSAI and SLB 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 which 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 CGA, NSAI and SLB during the reserve estimation process to review properties, assumptions and relevant data.

See exhibits 99.1 to this report for the estimates of proved reserves provided by NSAI, exhibit 99.2 to this report for the estimates of proved reserves provided by SLB and exhibit 99.3 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 CGA, NSAI and SLB primarily responsible for preparing the reserves estimates.

Michigan

For the year ended December 31, 2013, our average production from our Michigan properties was approximately 8.8 MBoe/d or 52.8 MMcfe/d. As of December 31, 2013, our estimated proved reserves attributable to our Michigan properties were 58.2 MMBoe, or approximately 27% of our total estimated proved reserves. As of December 31, 2013, approximately 92% of our Michigan total estimated proved reserves were natural gas. Our integrated midstream assets enhance the value of our Michigan properties as gas is sold at MichCon City-Gate prices, and we have no significant reliance on third party transportation. We have interests in 3,396 productive wells in Michigan, and we operated approximately 56% of those wells.

In 2013, we drilled four wells, re-drilled one well and completed 15 recompletions in Michigan. Our capital spending in Michigan for the year ended December 31, 2013 was approximately $9.3 million.

10




The Antrim Shale underlies a large percentage of our Michigan acreage; wells tend to produce relatively predictable amounts of natural gas in this reservoir. On average, our Antrim Shale wells have a proved reserve life of greater than 21 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 through a sizable well-engineered drilling program are the keys to profitable Antrim Shale development. Growth opportunities include infill drilling and recompletions, horizontal drilling and bolt-on acquisitions.

Our non-Antrim interests are located in several reservoirs including the Prairie du Chien, Richfield, Detroit River Zone III and Niagaran pinnacle reefs.

Oklahoma

On July 15, 2013, we completed the Whiting Acquisition to acquire oil properties in the Oklahoma Panhandle in the western region of Oklahoma. For the year ended December 31, 2013, the properties produced approximately 7.2 MBoe/d since the acquisition. As of December 31, 2013, estimated proved reserves attributable to our Oklahoma properties were 43.6 MMBoe, or approximately 20% of our total estimated proved reserves. Approximately 84% of our Oklahoma total estimated proved reserves were oil, 11% were NGLs and 5% were natural gas. In 2013, we drilled four new productive development wells in Oklahoma. Our capital spending in Oklahoma for the year ended December 31, 2013 was approximately $43.9 million. In total, we have interests in 242 productive wells in Oklahoma, and we operated approximately 98% of those wells.

The Whiting Acquisition included the Postle Field, which currently has active CO2 flooding projects, and the Northeast Hardesty Unit, both of which are located in Texas County, Oklahoma. We have a contracted supply of CO2 in the Bravo Dome Field in New Mexico, with step-in rights, for 143 Bcf over the next 10 to 15 years, which when coupled with recycled CO2 , we expect will provide the volumes required to produce our estimated proved reserves. As part of the acquisition and the purchase of additional interests, we are also the sole owner of the Dry Trails gas plant located in Texas County, Oklahoma. This plant is comprised of two trains, each with a processing capacity of approximately 40 MMcf/d. One of the trains utilizes a membrane technology to extract CO2 from the produced wellhead mixtures of hydrocarbon and CO2 gas, so that it can be used for re-injection or sales. In addition, we own 100% in a CO2 transportation pipeline delivering product from New Mexico to the Postle Field in Oklahoma.
    
Texas

Our Texas properties are primarily located in the Spraberry Trend located in Howard, Martin and Midland counties in Texas. For the year ended December 31, 2013, our average production from our Texas properties in the Permian Basin was approximately 3.9 MBoe/d. As of December 31, 2013, estimated proved reserves attributable to our Texas properties were 40.9 MMBoe, or approximately 19% of our total estimated proved reserves. As of December 31, 2013, approximately 57% of our Texas total estimated proved reserves were oil, 24% were NGLs and 19% were natural gas. In 2013, we drilled 53 new productive development wells in Texas. Our capital spending in Texas for the year ended December 31, 2013 was approximately $104.3 million. In total, we have interests in 230 productive wells in Texas, and we operated approximately 92% of those wells.

Wyoming

For the year ended December 31, 2013, our average production from our Wyoming fields was approximately 7.0 MBoe/d. As of December 31, 2013, estimated proved reserves attributable to our Wyoming properties were 36.6 MMBoe, or approximately 17% of our total estimated proved reserves. As of December 31, 2013, approximately 51% of our Wyoming total estimated proved reserves were natural gas and were 49% oil. In 2013, we drilled 21 new productive development wells, 19 recompletions of existing productive wells and 2 workovers in Wyoming. Our capital spending in Wyoming for the year ended December 31, 2013 was approximately $26.4 million. In total, we have interests in 982 productive wells in Wyoming, and we operated approximately 66% of those wells.

Our Wyoming properties consist primarily of oil properties in the Powder River Basin in eastern Wyoming, principally natural gas properties in the Evanston and Green River Basins in southwestern Wyoming and principally oil fields in the Wind River and Big Horn Basins in central Wyoming, including Gebo, North Sunshine, Black Mountain, Hidden Dome, Sheldon Dome, Rolff Lake in Fremont County, West Oregon Basin and Half Moon.



11



California

For the year ended December 31, 2013, our average California production was approximately 4.6 MBoe/d. As of December 31, 2013, estimated proved reserves attributable to our California properties were 23.3 MMBoe, or approximately 11% of our total estimated proved reserves. As of December 31, 2013, approximately 95% of our California total estimated proved reserves were oil. In 2013, we drilled 34 productive wells, six recompletions and 12 workovers in California. Our capital spending in California for the year ended December 31, 2013 was approximately $81.1 million. In total, we have interests in 441 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, including the Santa Fe Springs, East Coyote, Sawtelle, Rosecrans and Brea Olinda fields, the Alamitos lease of the Seal Beach Field and the Recreation Park lease of the Long Beach Field. We also operate oil properties in the Belridge Field in the San Joaquin Basin in Kern County, California.

Florida

For the year ended December 31, 2013, our average Florida production was approximately 1.8 MBoe/d. As of December 31, 2013, estimated proved reserves attributable to our Florida properties were 9.7 MMBbls, or approximately 5% of our total estimated proved reserves. Production is from the Cretaceous Sunniland Trend of the South Florida Basin. Each of our Florida fields is 100% oil. Production from the Raccoon Point field currently accounts for more than half of our Florida production. In 2013, we drilled three productive wells in Florida. Our capital spending in Florida for the year ended December 31, 2013 was approximately $29.5 million. In total, we have interests in 27 productive wells in Florida, and we operated 100% of those wells.

Indiana/Kentucky

For the year ended December 31, 2013, our average Indiana and Kentucky production was approximately 0.6 MBoe/d or 4.7 MMcf/d. As of December 31, 2013, estimated proved reserves attributable to our Indiana and Kentucky properties were 2.0 MMBoe, or 1% of our total estimated proved reserves. Our capital spending in Indiana and Kentucky for the year ended December 31, 2013 was less than $0.1 million. In total, we have interests in 241 productive wells in Indiana and Kentucky, and we operated 100% of those wells.

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. The New Albany Shale has over 100 years of production history.


12



Production and Price History

The following table summarizes our production and sales prices of oil, NGLs and natural gas for the years ended December 31, 2013, 2012, and 2011.

 
 
 
For Year Ended December 31,
 
 
 
2013
 
2012
 
2011
Net Production
 
 
 
 
 
 
 
Oil (MBbl)
 
5,651

 
3,514

 
3,079

 
NGL (MBbl)
 
640

 
138

 
175

 
Natural gas (MMcf)
 
28,156

 
27,997

 
22,697

 
Total (MBoe)
 
10,983

 
8,318

 
7,037

 
Average daily production (Boe/d)
 
30,091

 
22,726

 
19,281

Average Realized Sales Price (a)
 
 
 
 
 
 
 
Oil price per Bbl
 
$
93.67

 
$
92.18

 
$
92.58

 
NGL price per Bbl
 
$
35.25

 
$
27.96

 
$
42.00

 
Natural gas price per Mcf
 
$
3.82

 
$
3.00

 
$
4.18

 
Total price per Boe
 
$
60.05

 
$
49.57

 
$
55.41

Average Unit Cost per Boe
 
 
 
 
 
 
 
Lease operating expense
 
$
19.69

 
$
19.15

 
$
19.39

 
Production taxes
 
$
4.21

 
$
4.04

 
$
3.78

 
Total lease operating expense
 
$
23.90

 
$
23.19

 
$
23.17

(a) Excludes the effect of derivatives.


13



The following table summarizes our production and sales prices of oil, NGLs and natural gas for our Antrim Shale, Spraberry Trend and Postle Field, as they each represent more than 15% of our total proved reserves.

 
 
 
Antrim Shale (a)
 
Spraberry Trend (b)
 
Postle Field (c)
 
 
 
2013
2012
2011
 
2013
2012
 
2013
Net Production
 
 
 
 
 
 
 
 
 
 
Oil production (MBbl)
 



 
778

178

 
996

 
Natural gas production (MMcf)
 
14,468

15,135

15,942

 
1,739

821

 
344

 
NGL production (MBbl)
 



 
356


 
88

 
Total production (MBoe)
 
2,411

2,523

2,657

 
1,423

315

 
1,141

Average Realized Sales Price
 
 
 
 
 
 
 
 
 
 
Oil price per Bbl
 
$

$

$

 
$
93.27

$
84.82

 
$
93.60

 
Natural gas price per Mcf
 
$
3.90

$
2.95

$
4.21

 
$
3.27

$
4.94

 
$
3.77

 
NGL price per Bbl
 
$

$

$

 
$
27.72

$

 
$
60.90

 
Total price per Boe
 
$
23.40

$
17.70

$
25.26

 
$
61.89

$
60.83

 
$
87.54

Average Unit Cost per Boe
 
 
 
 
 
 
 
 
 
 
Lease operating expense per Boe
 
$
11.68

$
11.51

$
11.61

 
$
8.91

$
5.58

 
$
21.36

 
Production taxes
 
$
1.51

$
1.26

$
1.65

 
$
4.43

$
6.42

 
$
6.36

 
Total lease operating expense
 
$
13.19

$
12.77

$
13.26

 
$
13.34

$
12.00

 
$
27.72

(a) There were no NGL sales from our Antrim Shale properties.
(b) The Spraberry Trend properties were acquired in separate transactions that closed on July 2, 2012, December 28, 2012 and December 30, 2013. Production data corresponds to operating results from the acquisition dates through December 31, 2012 and December 31, 2013. During 2012, the Partnership sold its natural gas production from the Spraberry Trend on a wet gas basis under contracts we assumed in the acquisitions.
(c) Postle field was acquired through the Whiting Acquisition in July 2013. Production data corresponds to operating results from the acquisition date through December 31, 2013.

The Antrim Shale, which accounted for 23% of our total estimated proved reserves at December 31, 2013, accounted for 22%, 30% and 38% of our total production and 51%, 54% and 70% of our natural gas production for 2013, 2012 and 2011, respectively. The average realized prices per Mcfe for our Antrim Shale production were $3.90, $2.95 and $4.21 for 2013, 2012 and 2011, respectively. Lease operating expenses per Mcfe for our Antrim Shale production were $1.95, $1.92 and $1.94 for 2013, 2012 and 2011, respectively.

The Spraberry Trend, which accounted for 19% of our total estimated proved reserves at December 31, 2013, accounted for 13% and 4% of our total production for 2013 and 2012, respectively. For the year ended December 31, 2013, the Spraberry Trend’s production accounted for 14% of our total oil, 56% of total NGL and 6% of our total natural gas production. For the year ended December 31, 2012, the Spraberry Trend’s production accounted for 5% of our total oil and 3% of our total natural gas production. The average realized prices per Boe for our Spraberry Trend production were $61.89 and $60.83 for 2013 and 2012. Lease operating expenses per Boe for our Spraberry Trend production were $8.91 and $5.58 for 2013 and 2012.

The Postle Field, which accounted for 19% of our total estimated proved reserves at December 31, 2013, accounted for approximately 10% of our total production since the acquisition date on July 15, 2013. During the year ended December 31, 2013, the Postle Field produced 18% of our total oil, 14% of our total NGL and 1% of our total natural gas production. The average realized price per Boe for our Postle Field production was $87.54. Lease operating expenses per Boe for our Postle Field production was $21.36 per Boe.

Productive Wells

The following table sets forth information for our properties as of December 31, 2013 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. None of our productive wells have multiple completions.

14




 
 
Oil Wells
 
Gas Wells
 
 
Gross
 
Net
 
Gross
 
Net
Operated
 
1,466

 
1,423

 
2,243

 
1,689

Non-operated
 
52

 
14

 
1,798

 
653

 
 
1,518

 
1,437

 
4,041

 
2,342

 
Developed and Undeveloped Acreage

The following table sets forth information for our properties as of December 31, 2013 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
Michigan
 
462,171

 
218,153

 
41,336

 
37,197

 
503,507

 
255,350

Wyoming
 
161,960

 
88,013

 
36,162

 
13,652

 
198,122

 
101,665

Indiana
 
44,240

 
43,500

 
3,568

 
3,534

 
47,808

 
47,034

Florida
 
34,402

 
33,322

 
8,020

 
3,268

 
42,422

 
36,590

Oklahoma
 
30,097

 
29,206

 
160

 
151

 
30,257

 
29,357

Colorado
 
14,292

 
13,198

 

 

 
14,292

 
13,198

Texas
 
10,160

 
8,316

 
7,853

 
6,549

 
18,013

 
14,865

California
 
3,984

 
3,154

 

 

 
3,984

 
3,154

Kentucky
 
3,148

 
3,148

 
697

 
397

 
3,845

 
3,545

Utah
 
1,740

 
529

 

 

 
1,740

 
529

 
 
766,194

 
440,539

 
97,796

 
64,748

 
863,990

 
505,287


The following table lists the net undeveloped acres as of December 31, 2013, the net acres expiring in the years ending December 31, 2014, 2015 and 2016, and, where applicable, the net acres expiring that are subject to extension options.
 
 
 
 
 
2014 Expirations
 
2015 Expirations
 
2016 Expirations
  
 
Net Undeveloped Acreage
 
Net Acreage without Ext. Opt.
 
Net Acreage with Ext. Opt.
 
Net Acreage without Ext. Opt.
 
Net Acreage with Ext. Opt.
 
Net Acreage without Ext. Opt.
 
Net Acreage with Ext. Opt.
Michigan
 
37,197

 
332

 
538

 
2,063

 
4,166

 
516

 
4

Wyoming
 
13,652

 
1,944

 

 
2,621

 

 
120

 

Texas
 
6,549

 
250

 

 
369

 

 
20

 

Indiana
 
3,534

 
1,681

 

 
136

 

 
209

 

Florida
 
3,268

 

 

 

 

 
2,273

 

Kentucky
 
397

 
175

 

 

 

 
150

 

Oklahoma
 
151

 

 

 

 

 

 

 
 
64,748

 
4,382

 
538

 
5,189

 
4,166

 
3,288

 
4

 
As of December 31, 2013, we held more than 130,000 net acres in the developing Utica-Collingwood shale play in Michigan. Approximately 85% of this acreage is held by production. As of December 31, 2013, we also held more than 75,000 net acres in the developing A1-Carbonate play in Michigan, approximately 80% of which is held by production.


15



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, 2013, 2012 and 2011. 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,
 
 
2013
 
2012
 
2011
Gross development wells:
 
 
 
 
 
 
Productive
 
119

 
107

 
79

Dry
 
3

 
3

 
2

 
 
122

 
110

 
81

Net development wells:
 
 
 
 

 
 

Productive
 
105

 
92

 
69

Dry
 
3

 
3

 
2

 
 
108

 
95

 
71

 
As of December 31, 2013, we had the following wells in progress: 13 (gross and net) wells in Texas, two (gross and net) wells in California and one (gross and net) well in Florida.

Delivery Commitments

As of December 31, 2013, 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 2013, our largest purchasers were Phillips 66, which accounted for approximately 15% of our net sales revenues; Shell Trading, which accounted for approximately 15% of our net sales revenues; and Marathon Oil Corporation, which accounted for approximately 10% of our net sales revenues. For the significant customer information for the years ended December 31, 2012 and 2011, see Note 19 to the consolidated financial statements in this report.
 
Commodity Prices

We analyze the prices we realize from sales of our oil, NGL and natural gas production 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 on regional pricing. The WTI spot price of oil is a widely used benchmark in the pricing of domestic and imported oil in the United States. The relative value of oil is mainly determined by its quality and location. In the case of WTI spot pricing, the oil is light and sweet, meaning that it has a lower specific gravity (lightness) and low sulfur content, and is priced for delivery at Cushing, Oklahoma. In general, higher quality oils (lighter and sweeter) with fewer transportation requirements result in higher realized pricing for producers. Historically there has been a strong relationship between changes in NGL and oil prices. NGL prices are correlated to North American supply and petrochemical demands.

Our Oklahoma oil traded at a discount to WTI spot prices primarily due to transportation and quality and our Oklahoma NGLs traded at a discount due to regional market demand and transportation. Our Texas oil traded at a discount to WTI spot prices due to the deduction of transportation costs and our Texas NGLs traded at a discount due to processing fees, profit sharing and transportation. Our California oil is generally medium gravity crude. Because of its proximity to the extensive Los Angeles refining market, it has traded at only a minor discount to WTI spot price in the past. Historically, WTI spot prices for oil and ICE Brent oil prices have traded with only a narrow margin. Increasing supply into Cushing starting in early 2011 resulted in transportation bottlenecks which have led to divergence in the two major world oil benchmarks that has continued to the present. With the California market largely isolated from Cushing, management believes that ICE Brent pricing will better correlate with local California prices we receive until such time as the transportation infrastructure issues

16



at Cushing are resolved. In 2013, ICE Brent prices were higher than WTI spot prices, and our California production traded at a premium to WTI spot prices. Our Wyoming oil, while generally of similar quality to our Los Angeles Basin oil trades at a significant discount to WTI spot price 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 eastern Wyoming production is priced relative to Flint Hills Resources Wyoming Sweet posting, both of which have historically traded at a significant discount to WTI spot price. Our Florida oil also traded at a discount to WTI spot price primarily because the oil is transported via barge.

In 2013, the WTI spot price averaged approximately $98 per Bbl, compared with about $94 a year earlier. Monthly average WTI spot prices during 2013 ranged from a low of $92 per Bbl in April to a high of $107 per Bbl in August. During 2013, the average differentials per barrel to WTI spot prices were a $8.03 discount for our Oklahoma based production, a $4.70 discount for our Texas-based production, a $19.67 discount for our Wyoming-based production, a $7.41 premium for our California-based production and a $2.38 discount for our Florida-based production. In 2013, our average NGL realized price was $35.25 per Boe.

Our Michigan properties have favorable natural gas supply and demand characteristics as the state has been importing an increasing percentage of its natural gas. This supply and demand situation has allowed us to sell our natural gas production at a slight premium to Henry Hub spot prices. Our Wyoming natural gas generally trades at a discount to Henry Hub due to its relative location and the regional supply and demand market balances. Prices for natural gas have historically fluctuated widely and in many regional markets are aligned with supply and demand conditions in regional markets and 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 2013, the monthly average Henry Hub spot price ranged from a low of $3.33 per MMBtu in February to a high of $4.23 per MMBtu in December. During 2013, the Henry Hub spot price averaged approximately $3.73 per MMBtu and the differentials per Mcf to the Henry Hub spot price were a $0.19 premium for our Michigan-based production, a $0.09 premium for our Wyoming-based production and a $0.45 discount for our Texas-based production. See Part I—Item 1A “—Risk Factors” — “Risks Related to Our Business — Oil, NGL and natural gas prices and differentials are highly volatile. In the past, declines in commodity prices have adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flow, access to the capital markets and ability to grow. A decline in our cash flow could force us to reduce our distributions or cease paying distributions altogether in the future. — Natural gas prices have declined substantially since 2008 and are expected to remain depressed for the foreseeable future. Approximately 43% of our 2013 production, on an MBoe basis, was natural gas. Sustained depressed prices of natural gas will adversely affect our assets, development plans, results of operations and financial position, perhaps materially. — Low natural gas prices, a future decline in oil prices and concern about the global financial markets could limit our ability to obtain funding in the capital and credit markets on terms we find acceptable, 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 and ICE Brent 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 and distributions, 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.




17



Competition

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

In regards to the competition we face for drilling rigs and the availability of related equipment, the oil and gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel in the past, which 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. 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 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.

18




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

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

Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the U.S. Environmental Protection Agency (“EPA”), the individual states 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.

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 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. In fact, there is 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 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.


19



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.

Underground Injection Control (UIC). The Safe Drinking Water Act and comparable state laws regulate the injection of produced water, steam, or carbon dioxide into underground reservoirs for enhanced oil recovery or disposal. Under the 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.

Air Emissions. The 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 August 2012, the EPA adopted new rules that establish new air emission control requirements for oil and natural gas production and natural gas processing operations. The new rules include New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The new regulations require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover or treat rather than vent the gas and NGLs that come to the surface during completion of the fracturing process. The rules also establish specific requirements regarding emissions from new or modified compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules establish new 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. 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 Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel, and in April 2012, the EPA adopted regulations requiring the reduction of volatile organic compound emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing activities, which requires the operator to recover rather than vent gas and NGLs that return to the surface during well completion operations. At the state level, several states, including California, 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.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and disposal. EPA has indicated that it expects to issue its study report in late 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. 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 ongoing or proposed studies, depending on their findings, 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

20



requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Global Warming and Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis.

In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories 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 California’s cap and trade program’s first compliance period began in 2012. 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 cap and trade program due to the levels of greenhouse gases that are emitted. 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 will decline annually from 2013 through 2020. We will be required to obtain compliance instruments for each metric ton of greenhouse gases that we emit 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. 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

21



as locations containing sole-source drinking water aquifers, endangered species or other protected ecological resources. 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.

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 we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued 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, 2013. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2014. However, accidental spills or releases may occur in the course of our operations, and we cannot assure you that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. In addition, we expect to be required to incur remediation costs for property, wells and facilities at the end of their useful lives. Moreover, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our business, financial condition and results of operations or ability to make distributions to our unitholders.

Other Regulation of the Oil and Gas Industry

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

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

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. Wyoming currently imposes a severance tax on oil and gas producers at the rate of 6% of the value of the gross product extracted. Wyoming wells that reside on Native American or federal land are subject to an additional tax of 8.5%. Florida currently imposes a severance tax on oil producers of up to 8%, and Michigan currently imposes a severance tax on oil producers at the rate of 7.4% and on gas producers at the rate of 5.8%. 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

22



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.

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. 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. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. 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.

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.

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. That pipeline is subject to a limited jurisdiction FERC certificate, and we are not currently required to maintain a tariff at FERC. Our intrastate natural gas transportation pipelines are subject to regulation by applicable state regulatory commissions. 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.

We also own a 51 mile oil pipeline in Oklahoma that connects with Texas that is a common carrier 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. However, 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

23



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. 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 now 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.

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, 2013, BreitBurn Management had 563 full time employees. BreitBurn Management provides services to us as well as to our Predecessor. None of our

24



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 515 South Flower Street, Suite 4800, Los Angeles, California 90071. BreitBurn Management leases office space in the 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.


25



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, we might not be able to pay the distributions on our Common Units, the trading price of our Common Units could decline 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. In the past, declines in commodity prices have adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flow, access to the capital markets and ability to grow. A decline in our cash flow could force us to reduce our distributions or cease paying distributions altogether in the future.
 
The oil, NGL and natural gas markets are highly volatile, and we cannot predict future oil 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;
weather conditions;
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;
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 prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because natural gas accounted for approximately 40% of our estimated proved reserves as of December 31, 2013 and approximately 43% of our 2013 production on an MBoe basis, our financial results will be sensitive to movements in 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, 2013, the monthly average WTI spot price ranged from a low of $92 per Bbl in April to a high of $107 per Bbl in August while the monthly average Henry Hub natural gas price ranged from a low of $3.33 per MMBtu in February to a high of $4.23 per MMBtu in December.

Price discounts or differentials between WTI spot prices and what we actually receive are also historically very volatile. For instance, during calendar year 2013, the average quarterly premium to WTI spot prices for our California production varied from $0.91 to $16.50 per Bbl, with the differential percentage of the total price per Bbl ranging from 1% to 18%. For Wyoming oil, our average quarterly price discount from WTI spot varied from $13.31 to $26.42, with the discount percentage ranging from 13% to 27% of the total price per Bbl. For Florida oil, our average quarterly differential to WTI spot prices varied from a $8.20 discount to a $6.39 premium, excluding transportation expenses, with the differential percentage ranging from a 8% discount to a 7% premium of the total price per Bbl.


26



Our revenue, profitability and cash flow depend upon the prices and demand for oil, NGLs and natural gas, and a drop in prices could significantly affect our financial results and impede our growth. In particular, continuance of the current low natural gas price environment, further declines in natural gas prices, lack of natural gas storage or a significant decline in oil prices will negatively impact:
 
our ability to pay 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 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. Accordingly, continued high costs 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 were not 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. Although distributions were reinstated in 2010, a decline in our cash flow may force us to reduce our distributions or cease paying distributions again altogether in the future.
Natural gas prices have declined substantially since 2008 and are expected to remain depressed for the foreseeable future. Approximately 43% of our 2013 production, on an MBoe basis, was natural gas. Sustained depressed prices of natural gas will adversely affect our assets, development plans, results of operations and financial position, perhaps materially.
Natural gas prices have declined from an average price at Henry Hub of $8.86 per MMBtu in 2008 to $3.73 per MMBtu in 2013. The reduction in prices has been caused by many factors, including increases in gas production from non-conventional (shale) reserves, warmer than normal weather and high levels of natural gas in storage. As of December 31, 2013, we had hedged more than 72% of our expected natural gas production in 2014 at prices higher than those currently prevailing. However, if prices for natural gas continue to remain depressed for lengthy periods, we will be required to write down the value of our oil and natural gas properties and/or revise our development plans which may cause certain of our undeveloped well locations to no longer be deemed proved. In addition, sustained low prices for natural gas will reduce the amounts we would otherwise have available to pay expenses, make distributions to our unitholders and service our indebtedness.

Low natural gas prices, a future decline in oil prices and concern about the global financial markets could limit our ability to obtain funding in the capital and credit markets on terms we find acceptable, obtain additional or continued funding under our credit facility or obtain funding at all.
 
Low natural gas prices, a future decline in oil prices and concern about the global financial markets could make it challenging to obtain funding in the capital and credit markets in the future. During 2012 and 2013, we were able to access the debt and equity capital markets. However, future decline in oil or natural gas prices could significantly increase the cost of obtaining money in the capital and credit markets and limit our ability to access those markets as a source of funding in the future. 

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. Any future decline in oil prices could ultimately decrease our net revenue and profitability. Lower natural gas prices could negatively impact our revenues and cash flows.
 
These events affect our ability to access capital in a number of ways, which include the following:

27



 
Our ability to access new debt or credit markets on acceptable terms may be 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 in their sole discretion based on their valuation of our estimated 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 to meet their funding obligations.
The operating and financial restrictions and covenants in our credit facility 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 pay 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 pay distributions. Moreover, if we are unable to obtain funding to make acquisitions of additional properties containing proved oil or natural gas 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 maintain our level of cash distributions.

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.

Even if we are able to pay distributions on our Common Units under the terms of our credit facility, 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, 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. While we currently are not restricted by our credit facility from declaring a distribution, we 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, 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. 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.
 
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:

28



 
the amount of oil and natural gas we produce;
demand for and prices at which we sell our oil and natural gas;
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 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”);
cash settlement of hedging positions;
timing and collectability of receivables; and
the amount of cash reserves established for the proper conduct of our business.
 
For a description of additional restrictions and factors that may affect our ability to make 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.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.
 
Our ability to grow and to increase 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 identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
we cannot obtain financing for these acquisitions on economically acceptable terms;
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 increase or maintain our level of cash distributions.
 
Any acquisitions that we complete are subject to substantial risks that could reduce our ability to make 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:

29



 
the validity of our assumptions about reserves, future production, revenues and costs, including synergies;
an inability to integrate successfully the businesses we acquire;
a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
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.
 
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 pay 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;
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;

30



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 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.

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

As of February 27, 2014, we had approximately $747.0 million in borrowings outstanding under our credit facility. Our credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. The borrowing base is redetermined semi-annually, and the available borrowing amount could be further decreased as a result of such redeterminations. 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. Currently, our borrowing base for our credit facility is $1.5 billion, and the aggregate commitment of all lenders is $1.4 billion with the ability to increase our total commitments up to the $1.5 billion borrowing base upon lender approval. Our next borrowing base redetermination is scheduled for April 2014. In the event of a substantial decline in commodity prices, our borrowing base could be decreased by the lenders under our credit facility. A future decrease in our borrowing base could be substantial and could be to a level below our outstanding borrowings at that time. Outstanding borrowings in excess of the borrowing base are required to be repaid in five equal monthly payments, or we are required to pledge other oil and natural gas properties as additional collateral, within 30 days following notice from the administrative agent of the new or adjusted borrowing base. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our credit facility or sell assets, debt or Common Units. We may not be able to obtain such financing or complete such transactions on terms acceptable to us or at all. Failure to make the required repayment could result in a default under our credit facility, which could adversely affect our business, financial condition and results of operations.
 
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 pay distributions. Our credit facility restricts, and any future credit facility likely will restrict, our ability to:
 
incur indebtedness;

31



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. 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 and covenants 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 low natural gas prices, our ability to comply with these covenants may be impaired. 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 inhibited 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.
 
Restrictive covenants under our indenture governing our senior notes may adversely affect our operations.
 
The indentures governing our $305 million unsecured 8.625% senior notes maturing October 15, 2020 (the “2020 Senior Notes”) and $850 million unsecured 7.875% senior notes maturing April 15, 2022 (the “2022 Senior Notes”) (together, 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;
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 indenture governing our senior notes or any future indebtedness could result in an event of default under the indenture 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.

32



Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

As of February 27, 2014, our long-term debt totaled $1.9 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 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. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.
 
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 2014, our oil and gas capital spending program is expected to be between $325 million and $345 million, compared to approximately $295 million in 2013 and approximately $153 million in 2012. We expect to use cash generated from operations to partially 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 limit our ability to pay 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, thereby increasing the aggregate amount of cash required to maintain the then-current distribution rate, which could have a material adverse effect on our ability to pay distributions at the then-current distribution rate.
 
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 sustain or increase distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base.
 
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, 2013 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

33



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 sustain or increase 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.
 
Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions. If we do not make sufficient growth capital expenditures, we will be unable to sustain our business operations and therefore will be unable to maintain our current level of distributions. With our reserves decreasing, if we do not reduce our distributions, then a portion of the distributions may be considered a return of part of your investment in us as opposed to a return on your investment. Also, if we do not make sufficient growth capital expenditures, we will be unable to expand our business operations and will therefore be unable to raise the level of future distributions.
 
Future oil and natural gas price declines may result in a write-down of our asset carrying values.
 
Accounting rules require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties in the event we have 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, 2013, we recorded non-cash impairment charges of approximately $54.4 million. The impairment charges during 2013 were primarily due to $28.3 million of impairment charges to our Michigan non-Antrim oil and gas properties due to negative reserve adjustments due to lower performance and a decrease in expected future commodity prices, and $25.3 million of impairments to an oil property in our Bighorn Basin in Northern Wyoming due to a negative reserve adjustment due to lower performance and a decrease in expected future oil prices. Decreased drilling activity in Michigan was also a factor as the Partnership continues to allocate its capital expenditures more towards liquids-rich areas. Continuing to focus our drilling efforts on liquids could lead to further impairments in our natural gas properties in the future. During the year ended December 31, 2012, we recorded impairments of approximately $12.3 million primarily related to uneconomic proved properties in Michigan, Indiana and Kentucky due to a decrease in expected future natural gas prices. During the year ended December 31, 2011, we recorded impairments of approximately $0.6 million related to uneconomic proved properties in Michigan primarily due to a decrease in expected future natural gas prices.
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.
Our derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay 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 27, 2014, we had hedged, through swaps, options (including collar instruments) and physical contracts, approximately 76% of our expected 2014 production.


34



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 27, 2014, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, U.S. Bank National Association, Toronto-Dominion Bank and Royal Bank of Canada. We periodically obtain credit default swap information on our counterparties. As of December 31, 2013 and February 27, 2014, 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, 2013, our largest derivative asset balances were with Wells Fargo Bank National Association, Credit Suisse Energy LLC and Citibank, N.A., which accounted for approximately 30%, 26% and 13% of our derivative asset balances, respectively.

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 October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents.  The initial position limits rule was vacated by the United States District Court for the District of Colombia in September of 2012. Certain bona fide hedging transactions would be exempt from these position limits.  However, 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.


35



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, Dodd-Frank requires that regulators establish margin rules for uncleared swaps. Rules that require end-users to post initial or variation margin could impact our liquidity and reduce cash available for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules for uncleared swaps are not yet final and their impact on us is not yet clear.

Dodd-Frank may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as credit worthy as the current counterparty.  In addition, Dodd-Frank was intended, in part, to reduce the volatility of oil and gas prices. To the extent they 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, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less credit worthy counterparties. 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.
 
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, 2013 reserve report had been $10.00 less per Bbl and $1.00 less per MMBtu, respectively, then the standardized measure of our estimated proved reserves as of December 31, 2013 would have decreased by $1.7 billion, from $3.2 billion, to $1.5 billion.


36



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 estimated discounted future net cash flows from our 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.

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 2013, we depended on three 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 2013, three customers accounted for approximately 40% 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 2013, Phillips 66 accounted for approximately 15% of our net sales revenues, Shell Trading accounted for approximately 15% of our net sales revenues and Marathon Oil Corporation accounted for approximately 10% 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.


37



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

On a net production basis, we operated approximately 86% of our production in 2013.  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 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.


38



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, and currently, there is a legislative proposal to impose a 9.5% severance tax on oil. 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. There also is currently proposed federal legislation in three areas (tax legislation, climate change and hydraulic fracturing) that if adopted could significantly affect our operations. The following are brief descriptions of the proposed laws:
 
Tax Legislation. The Obama Administration's budget proposal for fiscal year 2014 includes proposals that would, among other things, eliminate or reduce 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 gas properties, (ii) the elimination of current deductions for intangible drilling and development costs and certain environmental clean-up costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) the extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these proposals will be introduced into law and, if so, how soon any resulting changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our Common Units.
 
Climate Change Legislation and Regulation. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis.
 
In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories 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 California’s cap and trade program’s first compliance period began in 2012. California's cap and trade program

39



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 cap and trade program due to the levels of greenhouse gases that are emitted. 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 will decline annually from 2013 through 2020. We will be required to obtain compliance instruments for each metric ton of greenhouse gases that we emit, 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. Although we do not expect the cost to be material to our operations, we cannot predict the future costs of allowances, and such costs could become material to our operations and impose significant costs on our business.

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. 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. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
 
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 Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel, and in April 2012, the EPA adopted regulations requiring the reduction of volatile organic compound emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing activities, which requires the operator to recover rather than vent gas and NGLs that return to the surface during well completion operations. At the state level, several states, including California, 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.
In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water and wastewater treatment and disposal. EPA has indicated that it expects to issue its study report in late 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. 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 ongoing or proposed studies, depending on their findings, 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.

40



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 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.
  

Risks Related to Our Structure
 
We may issue additional Common 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, 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 February 2012, we issued 9.2 million Common Units (or approximately 15% of our outstanding Common Units at issuance). In September 2012, we issued 11.5 million Common Units (or approximately 17% of our outstanding Common Units at issuance). In December 2012 we issued 3.0 million Common Units (or approximately 4% of our outstanding Common Units at issuance) in connection with the acquisition of oil and natural gas properties. In February 2013, we issued 14.95 million Common Units (or approximately 18% of our outstanding Common Units at issuance). In November 2013, we issued approximately 18.98 million Common Units (or approximately 16% of our outstanding Common Units at issuance).
 
The issuance of additional Common 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.

41



 
Our partnership agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
 
provides that our General Partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were in the best interests of the Partnership;
generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the Board and not involving a vote of unitholders will not constitute a breach of our partnership agreement or of any fiduciary duty if they are on terms no less favorable to us than those generally provided to or available from unrelated third parties or are “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
provides that in resolving conflicts of interest where approval of the conflicts committee of the Board is not sought, it will be presumed that in making its decision the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and
provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the 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 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.


42



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 Pacific Coast Oil Trust.
 
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.
 

43



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 (the “Delaware 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 our cash available for distribution would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in our Common Units depends largely on us being treated as a partnership for federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations we believe that we satisfy the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying

44



rates. 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 cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders likely causing 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 will reduce the cash available for distribution to our unitholders.
The tax treatment of publicly traded partnerships or an investment in our Common 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 Common Units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would 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. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Common Units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.
 

If the IRS contests the federal income tax positions we take, the market for our Common Units may be adversely impacted, and the cost of any IRS contest will reduce our cash available for distribution.
 
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 Common 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 will reduce our cash available for distribution.
 
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.
 
Tax gain or loss on the disposition of our Common Units could be more or less than expected.
 
If you sell your Common Units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those Common Units. Because distributions to you in excess of your allocable share of our net taxable income decrease your tax basis in your Common 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. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you due to potential recapture items,

45



including depreciation recapture. 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. 
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our Common Units that may result in adverse tax consequences to them.
 
Investment in Common 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 Common 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 use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. The proposed regulations do not, however, specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among unitholders.
 
A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
 
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and 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. 


46



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 2011 as a result of Quicksilver selling approximately 15.7 million of our Common Units together with normal trading activity by other 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 November 30, 2011 and brought about two taxable periods for 2011: January 1, 2011, to November 30, 2011 and December 1, 2011, to December 31, 2011. We were required to file two federal tax returns for the two short periods during the 2011 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 common 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.


47



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.

48



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, 2013, based upon information received from our transfer agent and brokers and nominees, we had approximately 87,239 common unitholders of record.

The following table sets forth high and low sales prices per Common Unit for the periods indicated. The last reported sales price for our Common Units on February 27, 2014 was $19.87 per unit.

 
 
Price Range
 
 
High
 
Low
2013
 

 

Fourth Quarter
 
$
20.41

 
$
17.80

Third Quarter
 
$
18.71

 
$
15.24

Second Quarter
 
$
20.76

 
$
17.36

First Quarter
 
$
21.75

 
$
19.03

2012
 

 

Fourth Quarter
 
$
20.47

 
$
16.90

Third Quarter
 
$
19.85

 
$
16.51

Second Quarter
 
$
19.20

 
$
16.06

First Quarter
 
$
20.19

 
$
18.65


Distributions

We intend to make cash distributions of available cash to unitholders on a monthly basis, although there is no assurance as to future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. 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. See Item 7 “—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility” and Note 10 to the consolidated financial statements in this report.

On October 30, 2013, the Partnership changed its 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.




49



The following table provides a summary of distributions paid for the years ended December 31, 2013 and 2012:
 
 
Cash Distributions
Thousands of dollars, except per unit amounts
 
Total
 
Per Common Unit
 
Payment Date
2014 (a)
 
 
 
 
 
 
February 2014
 
$
20,037

 
$
0.1642

 
2/14/2014
January 2014
 
$
19,573

 
$
0.1642

 
1/16/2014
2013
 
 
 
 
 
 
Third Quarter
 
$
48,594

 
$
0.4875

 
11/14/2013
Second Quarter
 
$
47,846

 
$
0.4800

 
8/14/2013
First Quarter
 
$
47,348

 
$
0.4750

 
5/14/2013
2012
 
 
 
 
 
 
Fourth Quarter
 
$
39,823

 
$
0.4700

 
2/14/2013
Third Quarter
 
$
37,499

 
$
0.4650

 
11/14/2012
Second Quarter
 
$
31,806

 
$
0.4600

 
8/14/2012
First Quarter
 
$
31,461

 
$
0.4550

 
5/14/2012
(a) Reflects the change in our distribution policy where distributions attributable to the fourth quarter of 2013 were paid out in equal monthly payments in January and February. The March distribution was declared on February 27, 2014 and will be payable on March 14, 2014.

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

There were no sales of unregistered equity securities during the period covered by this report.

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 2013.


50



Common Unit Performance Graph

The graph below compares our cumulative total unitholder return on our Common Units over the past five years 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, 2008. Cumulative return is computed assuming reinvestment of dividends.

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


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



51



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, 2013, 2012 and 2011, with the exception of consolidated balance sheet data for the year ended December 31, 2011, from our audited consolidated financial statements appearing elsewhere in this report. We derived the financial data for the years ended December 31, 2010 and 2009, as well as consolidated balance sheet data for the year ended December 31, 2011, from our prior year audited consolidated financial statements, which are not included in this report.

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. 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 on for approximately $38 million in cash and approximately 3.01 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%. See Note 16 to the consolidated financial statements in this report. In 2011, 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 4 to the consolidated financial statements in this report for further details about our acquisitions in 2013, 2012 and 2011.

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.



52




  
 
Year Ended December 31,
Thousands of dollars, except per unit amounts 
 
2013
 
2012
 
2011
 
2010
 
2009
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and NGLs sale
 
$
660,665

 
$
413,867

 
$
394,393

 
$
317,738

 
$
254,917

Gain (loss) on commodity derivative instruments, net
 
(29,182
)
 
5,580

 
81,667

 
35,112

 
(51,437
)
Other revenue, net
 
3,175

 
3,548

 
4,310

 
2,498

 
1,382

Total revenue
 
634,658

 
422,995

 
480,370

 
355,348

 
204,862

 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
 
44,276

 
21,700

 
153,809

 
63,743

 
(82,811
)
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
 
(43,671
)
 
(40,739
)
 
110,698

 
34,913

 
(107,257
)
Less: Net income attributable to noncontrolling interest
 

 
(62
)
 
(201
)
 
(162
)
 
(33
)
Net income (loss) attributable to the partnership
 
$
(43,671
)
 
$
(40,801
)
 
$
110,497

 
$
34,751

 
$
(107,290
)
Basic net income (loss) per unit
 
$
(0.43
)
 
$
(0.56
)
 
$
1.80

 
$
0.61

 
$
(2.03
)
Diluted net income (loss) per unit
 
$
(0.43
)
 
$
(0.56
)
 
$
1.79

 
$
0.61

 
$
(2.03
)
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Data:
 
 

 
 

 
 

 
 

 
 

Net cash provided by operating activities
 
$
257,166

 
$
191,782

 
$
128,543

 
$
182,022

 
$
224,358

Net cash used in investing activities
 
$
(1,465,805
)
 
$
(697,159
)
 
$
(414,573
)
 
$
(68,286
)
 
$
(6,229
)
Net cash provided by (used in) financing activities
 
$
1,206,590

 
$
504,556

 
$
287,728

 
$
(115,872
)
 
$
(214,909
)
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (at period end):
 
 

 
 

 
 

 
 

 
 

Cash
 
$
2,458

 
$
4,507

 
$
5,328

 
$
3,630

 
$
5,766

Other current assets
 
114,604

 
109,158

 
167,492

 
121,674

 
136,675

Net property, plant and equipment
 
3,915,376

 
2,711,893

 
2,072,759

 
1,722,295

 
1,741,089

Other assets
 
163,844

 
89,936

 
85,270

 
82,568

 
87,499

Total assets
 
$
4,196,282

 
$
2,915,494

 
$
2,330,849

 
$
1,930,167

 
$
1,971,029

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
$
182,889

 
$
115,240

 
$
89,889

 
$
101,317

 
$
91,890

Long-term debt
 
1,889,675

 
1,100,696

 
820,613

 
528,116

 
559,000

Other long-term liabilities
 
133,898

 
110,022

 
93,133

 
91,477

 
91,338

Partners' equity
 
1,989,820

 
1,589,536

 
1,326,764

 
1,208,803

 
1,228,373

Noncontrolling interest
 

 

 
450