10-K 1 a2014form10-k.htm 10-K 2014 Form 10-K
 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 2014
 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 No. 001-33016
 
EAGLE ROCK ENERGY PARTNERS, L.P.
(Exact Name of Registrant as Specified in Its Charter)
Delaware
 
68-0629883
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification Number)
 1415 Louisiana Street, Suite 2700
Houston, Texas 77002
(Address of principal executive offices, including zip code)

(281) 408-1200
(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange on Which Registered
Common Units of Limited Partner Interests
 
NASDAQ Global Select Market
 Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes  o    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.    Yes  o    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 13(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants 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 website, 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) 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.  x

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. (Check one):
Large accelerated Filer  x
Accelerated Filer  o
Non-accelerated Filer  o
Smaller reporting company  o
 (Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  o    No  x

As of June 30, 2014, the aggregate market value of the registrant's common units held by non-affiliates of the registrant was $514,751,744 based on the closing sale price as reported on NASDAQ Global Select Market.

The issuer had 151,223,977 common units outstanding as of February 26, 2015.

 DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant's definitive proxy statement for its 2014 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2014, are incorporated by reference into Part III of this report.

1


TABLE OF CONTENTS
 
 
 
Page 
PART I
Item 1.
Business
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Item 2.
Properties
Item 3.
Legal Proceedings
Item 4.
Mine Safety Disclosures
PART II
Item 5.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Item 6.
Selected Financial Data
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Financial Statements and Supplementary Data
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A.
Controls and Procedures
Item 9B.
Other Information
PART III
Item 10.
Directors, Executive Officers and Corporate Governance
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accounting Fees and Services
PART IV
Item 15.
Exhibits and Financial Statement Schedules


1


CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This report includes “forward-looking statements” as defined by federal securities laws. All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control, which may cause our actual results to differ materially from those implied or expressed by the forward-looking statements. We do not assume any obligation to update such forward-looking statements following the date of this report. For a complete description of known material risks, please read our risk factors set forth under Item 1A of this report. These factors include but are not limited to:

Drilling and geological / exploration risks;
Assumptions regarding oil and natural gas reserve levels and costs to exploit and timing of development;
Volatility or declines (including sustained declines) in commodity prices;
Ability to make favorable acquisitions and integrate operations from such acquisitions;
Our existing indebtedness;
Hedging activities;
Ability to obtain credit and access capital markets;
Ability to remain in compliance with the covenants set forth in our revolving credit facility;
Conditions in the securities and/or capital markets;
Availability and cost of processing and transportation of natural gas liquids ("NGLs");
Competition in the oil and natural gas industry;
Relevant legislative or regulatory changes, including retroactive royalty or production tax regimes, changes in environmental, health and safety regulation, hydraulic fracturing regulation, environmental risks and liability under federal, state, local and foreign environmental laws and regulations;
Shortages of personnel and equipment;
Increases in interest rates;
Creditworthiness of our counterparties;
Weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business;
Any other factors that impact or could impact the exploration of oil or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operations factors relating to the extraction of oil and natural gas;
Tax risk associated with pass-through investment, including potential reduction in tax shield or creation of phantom income in the event distributions are not enough to support the tax burden; and
Impact of cyber-security threats and related disruptions.


i


GLOSSARY OF OIL AND GAS TERMS
 
The following is a description of the meanings of some of the oil and gas industry terms that may be used in this report. The definitions of proved reserves, proved developed reserves, and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a) (2-4) of Regulation S-X.
 
Bbl:    One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.
 
Bbl/d:    One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons per day.
 
Bcf:    One billion cubic feet of natural gas.
 
Bcfe: One billion cubic feet of natural gas equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil and NGLs.
 
Boe:    One barrel of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil.

contingent resources:    These are resources that are potentially recoverable but not currently planned for commercial development due to technological, market, pricing or other factors.
 
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.
 
exploitation:    A drilling, recompletion, workover or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than 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 natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

extension well:    A well drilled to extend the limits of a known reservoir.
 
fee mineral:    A perpetual ownership of all or a portion of the oil, natural gas and other naturally-occurring substances that lie beneath the surface of the earth in a specific area.
 
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:    The total acres or wells, as the case may be, in which a working interest is owned.
 
MBbls:    One thousand barrels of crude oil or other liquid hydrocarbons.
 
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 a ratio of six Mcf of natural gas to one Bbl of crude oil and NGLs.
 
MMBbls:    One million barrels of crude oil or other liquid hydrocarbons.
 
MMBtu:    One million British thermal units.
 
MMcf:    One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil and NGLs.
 
MMcfe/d:    One million cubic feet of natural gas equivalent per day.
 
natural gas liquids or NGLs:    The combination of ethane, propane, isobutane, normal butane and natural gasoline that may be removed from natural gas as a liquid under certain levels of pressure and temperature. Most NGLs are gases at room temperature and pressure.
 
net acres:    The sum of the fractional working interests owned in gross acres or wells, as the case may be.
 
NYMEX:    New York Mercantile Exchange.
 
oil:    Crude oil and condensate.
  

ii


play: A geographic area with hydrocarbon potential.

productive well:    A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.
 
proved developed reserves:    Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
 
proved reserves:    The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.  Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.
 
proved undeveloped reserves:    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.
 
recompletion:    The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.
 
reserve life index:    The number of years required to produce the proved reserves at the current annual production rate.
 
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 reserves.
 
royalty or royalty interest:    A non-cost bearing interest in the production from a well that is created from a mineral interest when the minerals are leased to an operator. The royalty interest generally is retained by the mineral interest owner as part of the compensation for leasing the minerals.
 
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.
 
unit development cost:  The capital expenditures required to develop proved or unproved reserves per unit of reserves added or transferred from undeveloped or non-producing acreage to proved developed reserves, expressed in $/Mcfe or $/Boe.

West Texas Intermediate or WTI:    Light, sweet crude oil with high API gravity and low sulfur content used as the benchmark for U.S. crude oil refining and trading. NYMEX futures contracts for light, sweet crude oil specify the delivery of WTI at Cushing, Oklahoma.
 
working interest:    The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property/lease and to receive a share of production.
 
workover:    Operations on a producing well to restore or increase production.


iii


In this Annual Report on Form 10-K (this "report"), as the context requires, references to “Eagle Rock Energy Partners, L.P.,” “Eagle Rock,” the “Partnership,” “we,” “our,” “us,” or like terms, refer to Eagle Rock Energy Partners, L.P. and/or one or more of its subsidiaries. References to our “general partner” refer to Eagle Rock Energy GP, L.P., and the general partner of Eagle Rock Energy GP, L.P., Eagle Rock Energy G&P, LLC, both wholly-owned subsidiaries of the Partnership. References to “Natural Gas Partners” or “NGP” refers collectively to Natural Gas Partners VII, L.P.; Natural Gas Partners VIII, L.P.; and such other entities as set forth on that certain Schedule 13D/A filed with the Securities and Exchange Commission on September 22, 2014 including, without limitation, Montierra Minerals & Production, L.P. and Montierra Management LLC (collectively the "Montierra Entities") in the context of any description of our investors, and in other contexts refer to NGP Energy Capital Management, which manages a series of energy investment funds, including Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. References to the “NGP Investors” refer to Natural Gas Partners and some of our directors and current and former members of our management team. References to our “Board of Directors” or "Board" refer to the board of directors of Eagle Rock Energy G&P, LLC.
 
PART I


Item 1.
Business.


Overview and Recent Events

We are a domestically-focused, growth-oriented, publicly-traded Delaware limited partnership engaged in developing and producing oil and natural gas properties. Our interests include operated and non-operated wells located in four significant oil and gas producing regions: (i) Mid-Continent (which includes areas in Oklahoma, Arkansas and the Texas Panhandle); (ii) Alabama (which includes one treating facility and one natural gas processing plant and related gathering system); (iii) Permian (which includes areas in West Texas); and (iv) East Texas/South Texas/Mississippi.

Our objective is to grow our business in a manner that enhances our ability to maintain and increase cash distributions to our unitholders. To do so, we focus on achieving operational excellence, executing accretive low-risk acquisitions, pursuing organic growth opportunities, and allocating a portion of our cash flows to fund growth-related capital expenditures.

On July 1, 2014, we contributed our midstream business to Regency Energy Partners LP ("Regency") (such contribution, the "Midstream Business Contribution"). Our "Midstream Business" consisted of gathering, compressing, treating, processing, transporting, marketing and trading natural gas, fractionating, transporting and marketing natural gas liquids ("NGLs") and crude oil and condensate logistics and marketing (collectively, the "Midstream Business") The consideration we received for the Midstream Business Contribution included: (i) $576.2 million in cash; (ii) 8,245,859 Regency common units (valued at approximately $265.6 million based on the closing price of Regency common units on June 30, 2014) and (iii) the exchange of $498.9 million face amount of our outstanding unsecured senior notes ("Senior Notes") for an equivalent amount of Regency unsecured senior notes. Following the Midstream Business Contribution, $51.1 million of our Senior Notes remained outstanding under an amended indenture with substantially all of the restrictive covenants and certain events of default eliminated.

Accordingly, we have retrospectively adjusted prior periods as reflected in our consolidated financial statements to reflect the Midstream Business's assets and liabilities as held for sale and operations as discontinued. As a result of this transaction, we report our business as one segment. See our consolidated financial statements, and the notes thereto, included elsewhere in this report, for financial information on our operations and assets; such information is incorporated herein by reference.




Ownership Structure
   
The diagram below depicts our ownership structure as of February 26, 2015.

_________53,340,601 of such common units are beneficially held by NGP. "NGP" refers collectively to Natural Gas Partners VII, L.P.; Natural Gas Partners VIII, L.P.; and such other entities as set forth on that certain Schedule 13D/A filed with the Securities and Exchange Commission on September 22, 2014 including, without limitation, Montierra Minerals & Production, L.P. and Montierra Management LLC (collectively the "Montierra Entities"). For a discussion of beneficial ownership in the Montierra Entities by certain current and former members of management, see Part III, Item 12 -Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters, incorporating by reference our to-be-filed proxy statement for our 2015 Annual Meeting of Unitholders. 





2


History 

Our Partnership, formed in May 2006, is the successor to Eagle Rock Pipeline, L.P. as a result of our initial public offering in October 2006. We have historically grown through acquisitions and organic growth projects.
        
The following is a table that depicts our significant acquisitions/dispositions by date, transaction type, cost, financing sources and business over the past five years.

Table of Significant Acquisitions/Dispositions in the Past Five Years

Closing
Date
 
Transactions
 
Amount  ($ in Millions)
 
Financing/Consideration Sources ($ in Millions)
 
Segment
 
 
 
Cash
 
Debt
 
Equity
 
Cash from equity offerings
 
Acquisitions:
 
 
 
 
 
 
 
 
 
 
 
 
5/3/2011
 
Mid-Continent Acquisition
 
$
563.7

 
$
15.0

 
$
212.6

 
$
336.1

 
$

 
Upstream
10/1/2012
 
Panhandle Acquisition (a)
 
$
230.6

 
$

 
$
146.3

 
$

 
$
84.3

 
Midstream
Dispositions:
 
 
 
 
 
 
 
 
 
 
 
 
5/24/2010
 
Minerals Business Disposition (b)
 
$
174.5

 
$
174.5

 
$

 
$

 
$

 
Minerals
7/1/2014
 
Contribution of Midstream Business (a)
 
$
1,340.7

 
$
576.2

 
$
498.9

 
$
265.6

 
$

 
Midstream
_______________________________

(a)
Midstream acquisitions and divestiture are included within discontinued operations.
(b)
Amount includes approximately $2.9 million of cash received from the Minerals Business after the effective date of the sale.


Contribution of Midstream Business

As discussed above in the "Overview and Recent Events" section, on July 1, 2014, we contributed our Midstream Business to Regency for total consideration of approximately $1.3 billion.


Recapitalization and Related Transactions

In 2010, we completed a series of transactions (the "Recapitalization and Related Transactions") which simplified our capital structure and provided us with added financial liquidity. This series of transactions included:

the contribution, and resulting cancellation, of our incentive distribution rights and 20,691,495 subordinated units held by Eagle Rock Holdings, L.P. ("Holdings") which occurred on May 24, 2010;
the sale of all of our fee mineral and royalty interests, as well as our equity investment in Ivory Working Interests, L.P., (collectively "the Minerals Business") to Black Stone Minerals Company, L.P. for total consideration of $174.5 million which sale was completed on May 24, 2010;
a rights offering, which was launched on June 1, 2010 and expired on June 30, 2010, and for which we received gross proceeds of $53.9 million and issued 21,557,164 common units and 21,557,164 warrants and;
an option, which was exercised on July 30, 2010 by the issuance to Holdings of 1,000,000 newly-issued common units, to capture the value of the controlling interest in us through (a) acquiring our general partner entities from Holdings and immediately thereafter eliminating our 844,551 outstanding general partner units owned by Holdings and (b) reconstituting our Board to allow our common unitholders not affiliated with NGP to elect the majority of our directors.





3


Business Overview
 
Our business consists of long-lived, high working interest properties with extensive production histories and development opportunities located in four regions within the United States:

Mid-Continent, which includes areas in Oklahoma, Arkansas and the Texas Panhandle;
Alabama, which includes associated gathering and processing assets;
Permian, which includes areas in West Texas; and
East Texas/South Texas/Mississippi/Louisiana.

As of December 31, 2014, these working interest properties included 561 gross operated productive wells and 1,217 gross non-operated wells with net production of approximately 73.5 MMcfe/d and proved reserves of approximately 169.1 Bcf of natural gas, 11.0 MMBbls of crude oil, and 13.8 MMBbls of natural gas liquids, of which 78.5% were proved developed. The reserve life index is approximately 11.8 years based on our average daily production for the year ended 2014.

The Golden Trend field in Oklahoma (including the portion of the South Central Oklahoma Oil Province ("SCOOP") play that is designated as part of the Golden Trend field) contains 38% of our proved reserves. As of December 31, 2013, the Golden Trend field accounted for 41% of our reserves, but the percentage decreased in 2014 due to downward revisions in wells completed in the vertical Big Four and Bromide reservoirs related to lower performance, combined with higher operating costs. The next largest field is the Big Escambia Creek field (located in Alabama) which contains 14% of our proved reserves; no other field exceeds 10% of our proved reserves.


4


The following table summarizes our producing properties by region:
 
Region
 
Average net daily
production
 
Gross productive
wells
 
Oil,
Bbl/d
 
Natural
gas,
Mcf/d
 
Natural
gas
liquids,
Bbl/d
 
Operated
 
Non-
Operated
December 31, 2014
 
 
 
 
 
 
 
 
 
 
Mid-Continent Region
 
 
 
 
 
 
 
 
 
 
Golden Trend (a)
 
1,461

 
10,470

 
1,560

 
96

 
95

All other Mid-Continent Region
 
208

 
15,577

 
398

 
211

 
964

Alabama Region
 
1,267

 
2,654

 
625

 
22

 
3

Permian Region
 
481

 
1,576

 
196

 
191

 
53

East Texas/South Texas/Mississippi/Louisiana Region
 
179

 
2,587

 
394

 
41

 
102

Total
 
3,596

 
32,864

 
3,173

 
561

 
1,217

 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
 
 
 
 
Mid-Continent Region
 
 
 
 
 
 
 
 
 
 
Golden Trend (a)
 
1,128

 
10,623

 
1,492

 
90

 
94

All other Mid-Continent Region
 
196

 
17,275

 
347

 
209

 
950

Alabama Region
 
1,342

 
2,635

 
652

 
27

 
3

Permian Region
 
469

 
1,471

 
198

 
192

 
53

East Texas/South Texas/Mississippi Region
 
214

 
3,076

 
477

 
44

 
102

Total
 
3,349

 
35,080

 
3,166

 
562

 
1,202

 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
 
 
 
 
 
 
 
 
 
 
Mid-Continent Region
 
 
 
 
 
 
 
 
 
 
Golden Trend (a)
 
774

 
8,107

 
1,113

 
78

 
95

All other Mid-Continent Region
 
313

 
27,430

 
602

 
208

 
983

Alabama Region
 
1,406

 
3,651

 
644

 
26

 
3

Permian Region
 
472

 
1,450

 
190

 
207

 
55

East Texas/South Texas/Mississippi Region
 
272

 
4,299

 
515

 
40

 
113

Total
 
3,237

 
44,937

 
3,064

 
559

 
1,249

 ____________________________
(a)
Individual field representing greater than 15% of our total proved reserves.


 Mid-Continent Region. The Mid-Continent region consists of operated and non-operated properties in the Golden Trend field, Cana (Woodford) shale play, Verden field, and other fields located in the Anadarko Basin of western Oklahoma; the Mansfield field and other fields in the Arkoma Basin of Arkansas and Oklahoma; and various fields in the Texas Panhandle. Within the Mid-Continent region, our assets can generally be characterized as mature fields that produce from multiple reservoirs. Productive depths range from approximately 2,500 feet in the Arkoma fields of western Arkansas to greater than 18,000 feet in the Springer formation in certain western Oklahoma fields.

Our largest producing field in the region is the Golden Trend field, which extends across Grady, McClain and Garvin Counties in Oklahoma. The field is a large structural trap, discovered in 1947, that produces from the shallow Pennsylvanian Deese formation to the deep Ordovician Arbuckle formation. Most of our current production is from the Bromide formation and the "Big Four" interval consisting of the Viola, Hunton, Woodford and Sycamore formations. We typically drill through all these formations and perform multi-stage fracture stimulation completions in the Bromides and "Big Four" interval.

We have a significant ownership position in the expanding Cana (Woodford) shale, Springer shale and Southeast Cana shale plays in western Oklahoma. We have approximately 22,846 net acres in these plays extending across Canadian, Blaine, Dewey, Grady, Garvin, McClain and Stephens Counties in Oklahoma. The Cana and Southeast Cana Shale produce from

5


horizontal wells drilled to vertical depths of 11,000 to 16,000 feet and extended with horizontal lateral lengths of approximately 5,000 to 10,000 feet. The horizontal laterals are fracture stimulated in multiple stages to optimize production from the shale reservoir.

In the Mid-Continent region, we operate 307 productive wells and own a working interest in an additional 1,059 non-operated productive wells. The average working interest in these productive operated and non-operated wells is 84% and 8%, respectively. The net production averaged approximately 48.6 MMcfe/d in the year ended 2014, of which approximately 62% was produced from wells we operated. Most of the non-operated production comes from the properties within the Cana Shale and Southeast Cana shale plays, Verden field, and various other fields located in the Arkoma and Anadarko Basin. The majority of the interests in the Cana shale and Southeast Cana shale plays are operated by large upstream companies with significant experience and expertise in developing shale gas reserves.

Alabama Region. The Alabama region includes the Big Escambia Creek, Flomaton and Fanny Church fields located in Escambia County, Alabama. These fields produce from either the Smackover or Norphlet formations at depths ranging from approximately 15,000 to 16,000 feet.  The Big Escambia Creek field was discovered in 1971 and encompasses approximately 10,278 gross (7,687 net) Eagle Rock operated acres.  We operate sixteen productive wells with an average ownership of 75% working interest and 62% net revenue interest in the Big Escambia Creek field.  

The Fanny Church field is located two miles east of Big Escambia Creek. Our ownership includes approximately 1,123 gross (839 net) operated acres that include three productive operated wells with an ownership of 80% working interest and 62% net revenue interest.  

The Flomaton field is adjacent to and partially underlies the Big Escambia Creek field.   The field encompasses approximately 2,570 gross (2,215 net) acres and produces from the Norphlet formation at depths from approximately 15,000 to 16,000 feet.  We participate in one non-operated well with a 30% working interest and a 26% net revenue interest. We will be concluding a completion and a recompletion operation on two wells in 2015 with an average 97% working interest and 83% net revenue interest.

The Smackover and Norphlet reservoirs are sour gas condensate reservoirs which produce gas and fluids containing a high percentage of hydrogen sulfide and carbon dioxide. These impurities are extracted at the Eagle Rock-operated Big Escambia Creek Treating Facility and the effluent gas is further processed for the removal of natural gas liquids in the Big Escambia Creek Gas Processing Facility. During the fourth quarter of 2014, the Flomaton facility sulfur recovery unit was shut down and full well stream Flomaton facility gas was re-routed to the Big Escambia Creek facility for treating and processing. The operation of the wells and the facility is closely connected, and we are the largest owner and operator of the combined assets. In addition to selling condensate, natural gas, and NGLs, we also market elemental sulfur.

Permian Region. The Permian region contains numerous fields, including Ward South and Ward-Estes North located mainly in Ward, Pecos, and Crane Counties, Texas.  These fields are located on the Central Basin Platform, which extends from central Lea County in New Mexico to central Pecos County in Texas and encompasses hundreds of fields with multiple productive intervals from the Yates-Seven Rivers-Queen group through the Ellenburger formations. In Ward County, we have approximately 10,285 gross (10,215 net) acres of leasehold, and we operate fields with multiple productive horizons, which produce from depths of 2,300 feet (Yates) to 9,100 feet (Pennsylvanian).   Two of our major properties in the region, the Louis Richter lease and the American National Life lease, are located in Ward County. In Crane County, the Southern Unit is located in the Running “W” Waddell field, which was discovered in the mid-1930s and produces predominantly oil at depths from approximately 5,750 to 5,900 feet.  We operate 191 productive wells and own an interest in another 53 non-operated productive wells across approximately 22,666 net acres in the Permian region.   Our ownership in the Permian region operated wells averages 95% net working interest and 76% net revenue interest. 

East Texas/South Texas/Mississippi/Louisiana Region. In East Texas, Mississippi and Louisiana, we operate 41 productive wells and own a non-operated interest in an additional 102 wells. The average working interest in these productive operated and non-operated wells is 87% and 2%, respectively. The East Texas fields produce primarily from the Smackover Trend at depths from 12,000 to 12,700 feet and encompass approximately 18,991 gross (15,872 net) Eagle Rock acres. In East Texas, we operate 32 productive wells which produce gas that contains between approximately 25% to 65% of impurities (hydrogen sulfide, nitrogen, and carbon dioxide). The Edgewood field in East Texas contains two productive gas wells in the Cotton Valley at depths of 11,500 to 11,600 feet which produce "sweet" natural gas. The East Texas production, with the exception of a single well, is gathered by Tristream Energy, LLC and processed at its Eustace Plant for separation of condensate, removal of impurities, and extraction of natural gas liquids and sulfur.    


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In South Texas, we operate seven productive wells with 100% working interest and 88% net revenue interest in the Jourdanton field in Atascosa County, Texas, which was discovered in 1945 by Humble Oil Company.  Our net leasehold ownership in the field is 544 acres.  Our production from the field is primarily from the Edwards carbonates (7,300 to 7,400 feet); however, production has been established in multiple reservoirs above the Edwards interval, predominately the Georgetown, Austin Chalk, and Buda formations.  In addition, the Eagle Ford shale is productive in the southern portion of Atascosa County, but it has not been widely tested in the immediate vicinity of our wells.

Our Mississippi properties produce from the Smackover formation at depths of 16,500 feet to 17,200 feet, and our interests encompass approximately 800 gross and 790 net acres. We operate one productive oil well and one productive gas well in Mississippi.

Customers

For the year ended December 31, 2014, NGL Energy Partners LP, CVR Refining, LP and Oneok Partners, LP, our largest customers, represented 15%, 12% and 11%, respectively, of our total sales revenue (excluding gains and losses on commodity derivatives).

Seasonality

Generally, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or abnormally hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other natural gas and oil operations in certain areas.

Productive Wells
 
On December 31, 2014, we had under operation 287 gross (260 net) productive oil wells and 274 gross (229 net) productive natural gas wells. On December 31, 2014, we owned non-operated interests in an additional 186 gross (28 net) productive oil wells and 1,031 gross (72 net) productive natural gas wells.

Developed and Undeveloped Acreage
 
The following table describes the leasehold acreage we owned as of December 31, 2014:
 
Developed
Acreage(a)
 
Undeveloped
Acreage(b)
 
Total
Acreage
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Total
505,091

 
196,672

 
14,058

 
5,960

 
519,149

 
202,632

____________________________
(a)
Developed acres are acres pooled or assigned to productive wells.
(b)
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 natural gas or oil, regardless of whether such acreage contains proved reserves.

Drilling and Recompletion Activity

The following table describes our drilling activities for the years ended December 31, 2014, 2013 and 2012:
 
 
 
Year ended December 31, 2014
 
Year ended December 31, 2013
 
Year ended December 31, 2012
 
 
Gross
Net
 
Gross
Net
 
Gross
Net
Development wells (a):
 
 
 
 
 
 
 
 
 
Productive
 
26

11

 
44

13

 
33

15

Dry
 
1

1

 
1

1

 


Total
 
27

12

 
45

14

 
33

15

____________________________
(a)
Includes extension wells.

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During 2014, we drilled and completed twelve operated wells, which included two horizontal wells in the Southeast Cana shale play, eight vertical wells in the Golden Trend field and two vertical wells, one of which was a dry hole, in Big Escambia Creek field. In addition, we participated with a working interest in 15 non-operated wells drilled and completed in the Mid-Continent region. Our average working interest in these operated and non-operated drilling programs are 82% and 11% respectively. During 2014, seven recompletions and 15 capital work-over projects were conducted. Overall, the capital program achieved a unit development cost of $20.30/Boe. As of December 31, 2014, one operated well (31% net) was being completed and one (69% net) was in the process of being drilled.

During 2013, we drilled fourteen operated wells, which included two horizontal wells in the Southeast Cana shale play, eleven vertical wells in the Golden Trend field and one well in Big Escambia Creek field. In addition, we participated with a working interest in thirty-one non-operated wells drilled and completed in the Mid-Continent region. Our average working interest in these operated and non-operated drilling programs are 92% and 3.5%, respectively. During 2013, ten recompletions and thirty-two workover projects were conducted. Overall, the capital program achieved a unit development cost of $20.34/Boe.

During 2012, we drilled and completed eleven operated wells in our Mid-Continent region, which included four wells in the Cana and Cana Southeast Shale plays and seven wells in the Golden Trend field. In addition, we participated with a working interest in twenty non-operated wells drilled and completed in the region. In our remaining operated regions, we drilled and completed one operated well in the Permian Basin and one non-operated well in East Texas. During 2012, recompletion and workover projects were conducted on thirty-one operated wells and one non-operated well. Overall, the capital program generated a unit development cost of $22.08/Boe.
    
During the years ended December 31, 2014, 2013 and 2012, we did not drill or participate in the drilling of any exploratory wells.


Oil and Natural Gas Reserves
     
Estimates of proved reserves as of December 31, 2014 were based on estimates made by our independent engineers, Cawley, Gillespie & Associates, Inc (“CGA”). CGA has conducted the annual estimate of proved reserves for us since 2007. In 2014, CGA was engaged by and provided its reports to our senior management team.  The Audit Committee has the authority to engage and terminate the independent reserve engineer.  Management continues, however, to have direct oversight of the independent reserve engineer's activities.  
 
We make representations to CGA that we have provided all relevant operating data and documents, and in turn, we review the reserve reports provided by CGA to ensure completeness and accuracy. Our review entails a comparison of the forecasts and other parameters in the reserve report to our internal estimates and our historical results.  If discrepancies are identified, we discuss these issues with CGA and provide them with additional information.  This process may or may not result in changes to their estimates, but the final report will represent their estimates, based on the data we provided and their engineering judgment.  

Qualifications of Reserve Estimators
   
Our reserves estimation process involves two major steps: (i) the population of a reserves database by our Technical Evaluations staff, and (ii) the preparation of an independent reserves report which uses the database as its starting point.  The independent reserves report is prepared by CGA, which is a Texas Registered Engineering Firm (F-693).  The primary engineer on our account is Ms. Kellie Jordan who works under the supervision of Mr. Robert Ravnaas, President.  Mr. Ravnaas is a State of Texas Licensed Professional Engineer (License #61304). CGA's report is attached as Exhibit 99.1 to this report.
 
In the preparation of its report, CGA relies on engineering, financial and other data provided by our staff and is overseen by our Director - A&D and Reserves, Mr. Kevin D. Neeley.  Mr. Neeley has over 26 years of experience in petroleum engineering, economics, field operations, finance and acquisitions.  He earned a Bachelor's of Science degree in Petroleum Engineering Technology from Oklahoma State University and an MBA degree in finance from the University of St. Thomas.  He is a member of the Society of Petroleum Engineers.
 

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Internal Controls Over Reserve Estimation
 
One of our primary controls with respect to reserve reporting is the independent reserve report; however, we also have various internal controls to ensure that the data we supply to CGA is accurate.  Among other things, our internal controls include the following items:

A process to identify all of the drilled producing wells and add them to our database.
A process to retrieve production data from the IHS software application we use, to use as the basis of our decline curve forecasts.
A process to estimate various economic parameters, such as operating costs; price differentials; gas shrinkages; and condensate and NGL yields.  This process relies on historical data provided by our accounting department and our operations engineers.
A process to check the working and net revenue interests in our reserves database to ensure they are consistent with our land and revenue accounting records.
A process to identify and document the engineering and geological support for our developed non-producing and undeveloped reserves.
Processes to estimate future capital expenditures and abandonment costs that are based on our prior experiences and engineering judgment.
 
We use the data gathered and estimated in the processes above to populate our reserves database.  Our Technical Evaluations staff prepares a reserves estimate for each well in which we own an interest (including non-producing and undeveloped locations).  This database is then provided to CGA, along with any additional supporting information they request, and forms the primary basis for their reserve estimates.
 
After CGA has made their preliminary reserves estimate, the Director - A&D and Reserves reviews their results and compares them to our historic production rates, operating costs, price differentials, severance tax rates and ad valorem tax rates.  If they are not consistent with our historical results, the database is scrutinized to identify and correct possible sources of error.  The Director - A&D and Reserves and his staff also review the production forecasts prepared by CGA for possible errors, omissions or significant differences in engineering judgment.  In those instances, the issue is discussed with CGA and additional supporting data is provided, if needed.  Capital costs and investment timing are also reviewed to ensure that they are consistent with our five year development plan and our approved budget.
 
After CGA has completed its report, our Technical Evaluations group prepares the reserves reconciliation.  During this process, we occasionally identify small discrepancies that we believe should be corrected and these discrepancies  are discussed and resolved with CGA.
 
General Reserve Estimation Methods
   
Because the majority of our proved reserves are classified as proved developed producing reserves, we extensively use production performance methods (primarily decline curve analysis) in the preparation of our proved reserves estimates.  Our estimates of proved undeveloped and proved developed non-producing reserves are based on volumetric methods and analogy to offset producers.  Where applicable, we occasionally use material balance methods to estimate reserve quantities.  We have not used reservoir simulation or proprietary methods to prepare our reserves estimates.
   
Proved Reserves
 
The following table presents our estimated net proved natural gas and oil reserves on December 31, 2014. These values are based on independent reserve reports prepared by CGA.
 
Oil and natural gas liquids prices applied for 2014 are based on an average of the prior twelve months first-of-month spot prices of West Texas Intermediate ($94.99 per barrel) and are adjusted for quality, transportation fees, and price differentials. Likewise, natural gas prices applied for 2014 are based on an average of the prior twelve months first-of-month spot prices of Henry Hub natural gas ($4.35 per MMBtu) and are adjusted for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines. Such prices, calculated in accordance with SEC guidelines, were higher than market prices as of December 31, 2014.

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As of
December 31, 2014
Reserve Data:
 
Estimated net proved reserves:
 
Natural gas (Bcf)
169.1

Oil (MMBbls)
11.0

Natural Gas Liquids (MMBbls)
13.8

Total (Bcfe)
318.2

Proved developed (Bcfe)
249.7

Proved developed reserves as % of total proved reserves
78.5
%
 
 

Estimated net undeveloped reserves:
 

Natural gas (Bcf)
42.3

Oil (MMBbls)
1.4

Natural Gas Liquids (MMBbls)
2.9

Total (Bcfe)
68.5

Proved undeveloped (Bcfe)
68.5

 

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Proved Undeveloped Reserves

As of December 31, 2014, our proved undeveloped reserves totaled 42.3 Bcf of natural gas, 1.4 MMBbls of oil and 2.9 MMBbls of natural gas liquids. The total proved undeveloped reserves of 68.5 Bcfe results from a decrease of approximately 25.3 Bcfe, or 27.0%, from total proved undeveloped reserves of approximately 93.8 Bcfe as of December 31, 2013. The changes in our proved undeveloped reserves during 2014 were attributable to:

An increase of 26.5 Bcfe due to extensions and discoveries, primarily in our Golden Trend area and Southeast Cana Woodford play;

A decrease of approximately 19.1 Bcfe resulting from transfers to the proved developed producing category as a result of development drilling;

A decrease of approximately 32.7 Bcfe due to revisions to previous estimates, composed of 3.0 Bcfe due to recategorizing proved undeveloped locations from proved to probable reserves due to poor economic expectations and 0.2 Bcfe due to recategorizing proved undeveloped locations to contingent resources because they were non-commercial at the time, a decrease of 29.5 Bcfe due to other changes including increased costs, negative changes to forecast performance expectations and widening product price differentials; and

No changes to proved undeveloped reserves related to purchase and sales or improved recovery.

We spent approximately $49.4 million of capital expenditures in 2014 to drill wells classified as proved undeveloped as of December 31, 2013. Our working interest in these wells at the time they were drilled was often significantly greater than our working interest as of December 31, 2013 because other working interest owners elected to not participate in the wells. As a result, the amount of reserves transferred into the proved developed producing category on account of wells drilled in 2014 was often significantly greater than the wells’ estimated proved undeveloped reserves as of December 31, 2013. In addition, the amount of reserves transferred into the proved developed producing category on account of wells drilled in 2014 was often different from the wells’ estimated proved undeveloped reserves as of December 31, 2013 because the performance of the wells differed from our original expectations.

As a master limited partnership, we grow primarily through acquisitions of producing properties and subsequently conduct development activities on those properties to maintain or grow our production rates.  The acquisition candidates that meet our investment criteria often have a high ratio of developed to undeveloped reserves, and we conduct limited exploration activities. As of December 31, 2014, we had 97 drilling locations associated with proved undeveloped reserves.
 
We approach the development of our undeveloped reserves at a measured pace, in order to hold our production rate fairly constant or slightly inclining.  The development plan in our proved reserves report contemplates the drilling of all of our undeveloped locations within five years of initial booking.
 
Our undeveloped drilling locations are concentrated in the Mid-Continent region, primarily in the Golden Trend field of Grady and Stephens Counties, Oklahoma and the Cana Shale and Southeast Cana Shale plays in western Oklahoma.

Of the 27 wells drilled during the year ended December 31, 2014, six were proved undeveloped locations and of these six, all were operated. In 2013, of the 45 wells drilled, seven of the operated wells and four of the non-operated wells were proved undeveloped locations. In 2012, of the 33 wells drilled, eight of the operated wells and three of the non-operated wells were proved undeveloped locations.

Oil and Natural Gas Production

For details and a discussion of our net production, realized prices by product and production costs for the years ended December 31, 2014, 2013 and 2012, see our discussion of the results of operations within Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Year Ended December 31, 2014 Compared with Year Ended December 31, 2013 and Year Ended December 31, 2013 Compared with Year Ended December 31, 2012.  Production costs, excluding ad valorem and severance taxes for the years ended December 31, 2014, 2013 and 2012 were $8.07/Boe, $8.16/Boe and $7.14/Boe, respectively.  


Regulation of Our Operations
 

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Safety and Maintenance Regulation
 
The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil industry is constantly evolving, frequently increasing the regulatory burden. Numerous departments and agencies, both federal and state, are authorized by statute to issue new and revised rules and regulations, some of which carry substantial penalties for failure to comply, which could be applicable to our business. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us differently or to a greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Our business, among other things, is subject to the Occupational Safety and Health Act of 1970, as amended (“OSHA”), the EPA’s Risk Management Plan (“RMP”), the U.S. Department of Transportation ("DOT") standards, and rules and regulations promulgated by other federal and state agencies. While these agencies have established some regulations designed to protect worker and community health and safety, their primary focus is on environmentally sound drilling, servicing, and production operations. See Item 1A. Risk Factors - We may incur significant costs and liabilities resulting from safety and compliance-related regulations.

  Drilling and Production. The activities conducted by us and by the operators on our properties are subject to significant regulation at the federal, state and local levels. These regulations include requiring permits for the drilling of wells, posting of drilling bonds and filing 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 methods of drilling, casing and cementing wells; 
the surface use and restoration of properties upon which wells are drilled; 
the disposal of fluids and solids used in connection with our operations; 
air emissions associated with our operations; 
the plugging and abandoning of wells; and 
notice to surface owners and other third parties.
 
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally restrict or prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. Additionally, some municipalities also impose property taxes on oil and natural gas interests, production equipment, and our production revenues. For more information regarding the regulations that govern us, see "Item 1A.Risk Factors - We may incur significant costs and liabilities resulting from safety and compliance-related regulations." and "Item 1A.Risk Factors - Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays."

Federal Regulation. Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas prices or market participants might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.
 
State Regulation. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural 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. For more information regarding the impact of state regulation on us and our operations, see "Item 1A.Risk Factors - We are subject to compliance with stringent environmental and safety laws and regulations that may expose us to significant costs and liabilities, and future regulations may be more stringent" and "Item 1A. Risk Factors - We may incur significant costs and liabilities resulting from safety and compliance-related regulations."

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The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity.



Environmental Matters

Our business involves acquiring, developing and producing oil and natural gas working interests, and certain associated gathering and processing in Alabama.  
 
Our operations and those of our lease operators are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection or safety. Our business could be impacted by any legislation or regulations that are adopted to address criteria pollutant and/or greenhouse gas emissions in the United States. For further discussion of these environmental laws and regulations, see “Item 1A. Risk Factors-We are subject to compliance with stringent environmental laws and regulations that may expose us to significant costs and liabilities, and future regulations may be more stringent.”

On our working interest properties, and particularly our operated properties, as well as our processing facility in Alabama, we are responsible for conducting operations in a manner that complies with applicable environmental laws and regulations.  These laws and regulations can adversely affect our capital expenditures, earnings and competitive position in many ways, such as:
requiring the acquisition of various permits before drilling commences;
requiring the installation of pollution control equipment;
restricting the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;
limiting or prohibiting drilling activities on lands lying within wilderness, wetlands and other protected areas;
siting, construction and operating restrictions on or near endangered species habitats;
requiring remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;
imposing substantial liabilities for pollution resulting from our operations;
requiring the preparation of plans to evaluate and mitigate the potential for offsite impacts;
with respect to operations affecting federal lands or leases, requiring preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement; and
restricting the rate of natural gas and oil production below the rate that would otherwise be possible.

Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite.  We have recorded liabilities for these asset retirement obligations in accordance with authoritative guidance which applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. The guidance requires that we record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset.

Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly from tight formations. For additional information about hydraulic fracturing and related environmental matters, see “Item 1A. Risk Factors-Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”

Environmental Laws and Regulations
The following is a summary of the more significant existing environmental laws and regulations to which our business operations are subject:
 The Federal Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including our processing plants and compressor stations. These laws and regulations require us to obtain pre-approval

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for the construction or modification of certain projects or facilities expected to emit new pollutants or increase emissions, obtain and comply with air permits containing various emission and operational limitations, and utilize specific equipment or technologies to control emissions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. For instance, the United States Environmental Protection Agency (“EPA”) periodically reviews and may lower the National Ambient Air Quality Standards (“NAAQS”) for various pollutants in the future, which could require us to install more stringent controls at our facilities, resulting in increased capital expenditures.
    
We could also be impacted by federal regulations limiting greenhouse gas emissions or imposing reporting obligations with respect to such emissions which have been proposed or finalized.  For a discussion of the effects of greenhouse gas regulation, see “Item 1A. Risk Factors- Climate change laws or regulations restricting emissions of 'greenhouse gases' could result in increased operating costs and a decreased demand for oil and natural gas that we produce or process.”

The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for certain wastewater and stormwater discharges and discharges of dredged or fill material in wetlands and other waters of the United States, as well as develop and to implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of greater than threshold quantities of oil.
 
The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which addresses three principal areas of oil pollution—(a) prevention, (b) containment and cleanup, and (c) liability. OPA applies to vessels, offshore platforms and onshore facilities, including terminals, pipelines and transfer facilities, and subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages and certain other consequences of an oil spill, where such spill is into waters of the U.S. Any unpermitted release of petroleum or other pollutants from our operations could result in potential liability. Some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.  These programs may also require remedial activities or capital expenditures to mitigate groundwater contamination along our pipeline systems as a result of past or current operations.  Contamination of groundwater resulting from spills or releases of oil or gas is an inherent risk within our industry.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Under CERCLA, these “responsible persons” may be subject to joint and several, strict 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. We also generate materials in the course of our operations that may be regulated as hazardous substances and we may incur liability under the Resource Conservation and Recovery Act, as amended, also known as “RCRA,” which imposes requirements related to the handling and disposal of solid and hazardous wastes, as well as similar state laws. In the course of our operations we may generate petroleum product wastes and ordinary industrial wastes that may be regulated as solid and hazardous wastes under RCRA.

We currently own or lease, and have in the past owned or leased, properties that for many years have been used for oil and gas operations. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes were not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of by prior owners or operators) or contaminated property (including ground water contamination), or to perform activities to prevent future contamination.

The federal Endangered Species Act, as amended, or “ESA,” restricts activities that may affect endangered or threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA.
In addition to claims arising under state and federal statutes, where a release or spill of hazardous substances, oil and gas, or oil and gas wastes have occurred, private parties or landowners may bring lawsuits under state law. The plaintiffs in such lawsuits may seek property damages, personal injury damages, remediation costs or injunctions to require remediation or restoration of contaminated environmental media, including soil, sediment, groundwater or surface water. Some of our oil and

14


gas operations are located near populated areas and routine emissions or accidental releases could affect the surrounding properties and population.


Title to Properties and Rights-of-Way
 
As is customary in the natural gas and oil industry, we initially conduct only a cursory review of the title to our properties on which we do not have producing reserves. Prior to completing an acquisition of producing natural gas and/or oil properties, we perform title reviews on the most significant leases and, depending on the materiality of properties or irregularities we may observe in the title chain, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained or reviewed title opinions on a significant portion of our natural gas and oil properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the natural gas and oil industry. Our natural gas and oil properties are 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.  We own and operate certain gathering and processing assets associated with our South Alabama assets. The portion of land on which the processing facility is located is owned by us in fee title, and we believe that we have satisfactory title to this land. We also possess rights-of-way relating to our associated gathering assets, and we have no knowledge of any challenge to the underlying rights-of-way.


Employees
 
To carry out our operations, as of December 31, 2014, Eagle Rock Energy G&P, LLC or its affiliates employed 159 people who provide direct support for our operations. None of these employees are covered by collective bargaining agreements. Eagle Rock Energy G&P, LLC considers its employee relations to be good.

Available Information
 
We provide access free of charge to all of our Securities and Exchange Commission ("SEC") filings, as soon as reasonably practicable after filing or furnishing it, on our internet site located at www.eaglerockenergy.com. We will also make available to any unitholder, without charge, copies of our Annual Report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Eagle Rock Energy Partners, L.P., General Counsel or Chief Financial Officer, 1415 Louisiana Street, Suite 2700, Houston, TX 77002, or call 281-408-1200. The information on our website is not incorporated by reference into this report.
 
In addition, the public may read and copy any materials Eagle Rock files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.


Item 1A.
Risk Factors.

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses.
   
If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay a distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.



Risks Related to Our Business
 
Natural gas, NGLs, crude oil and other commodity prices are volatile, and an adverse movement in these prices, such as the one recently experienced, could adversely affect our cash flow and our ability to make distributions.
 
We are subject to risks related to frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas, NGLs and crude oil have been extremely volatile, and we expect this volatility to continue. A drop in prices can significantly affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms, all of which can affect our ability to pay distributions. Average oil and natural gas prices decreased substantially during the year ended December 31, 2014. Any additional actual or anticipated reduction in crude oil and natural gas prices may further depress our level of exploration, drilling and production activity.
 
Changes in natural gas, NGL and crude oil prices have a significant impact on the value of our reserves and on our cash flows. In 2014, the settlement price of the prompt month NYMEX natural gas contract ranged from $2.89 per MMBtu to

15


$6.15 per MMBtu, and the settlement price of the prompt month NYMEX crude oil contract ranged from $53.45 per barrel to $107.95 per barrel. As of December 31, 2014, the settlement price of the prompt month NYMEX natural gas contracts and NYMEX crude oil contracts was $2.89 per MMBtu and $53.45 per barrel, respectively.
 
The prices for natural gas, NGLs and crude oil depend upon the supply and demand for these products, which in turn depend on a large number of complex, interrelated factors that are beyond our control. These factors include:
 
the overall level of economic activity in the United States and the world; 
the actions of the Organization of Petroleum Exporting Countries;
the price and quantity of imports of foreign oil, natural gas and NGLs;
the impact of weather or other force majeure events; 
political and economic conditions and events in, as well as actions taken by, foreign oil and natural gas producing nations, including the Middle East, Africa, South America and Russia; 
significant crude oil or natural gas discoveries;
application of new technologies that make the development of large resource plays economically attractive; 
the availability of local, intrastate and interstate transportation systems for natural gas, NGLs and crude oil; 
the availability and marketing of competitive fuels; 
delays or cancellations of crude oil and natural gas drilling and production activities; 
the impact of energy conservation efforts, including technological advances affecting energy consumption; and 
the extent of governmental regulation and taxation.
 
Lower natural gas, NGL or crude oil prices may not only decrease our revenues and net proceeds, but may also reduce the amount of natural gas, NGLs or crude oil that we can economically produce. As a result, especially during periods of low commodity prices, we may decide to shut in or curtail production, or to plug and abandon marginal wells, which could have a material adverse effect on our future cash flows.

We may not have sufficient cash from operations following the establishment of cash reserves to enable us to make cash distributions at any particular level or at all.
 
The amount of cash available to us to distribute on our units may fluctuate from quarter to quarter based on, among other things:

the level of oil, natural gas, NGLs and condensate that we produce;
volatility in the realized prices for oil, natural gas, NGLs and condensate that we and others produce;
the effectiveness of our hedging program and the creditworthiness of our hedging counterparties;
our level of indebtedness, debt service requirements and need to reduce outstanding indebtedness;
our ability to borrow funds and access capital markets; 
the level of our operating and general and administrative costs;
our decisions regarding the level and use of available cash for growth versus maintenance capital expenditures;
our and other operators’ drilling activities and success of such programs;
results of litigation or changes in methods of royalty calculations; and
the level of competition from other upstream energy companies.

As a result of these factors, the amount of cash we distribute to our unitholders may be significantly less than the current distribution level, or the distribution may be suspended. In addition, under our partnership agreement, our General Partner may determine to establish any cash reserve necessary for the proper conduct of our business including reserves for future capital expenditures, future credit needs and to better ensure continued compliance with our credit facility before making distributions to our unitholders.

Our general partner also determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, and issuances of additional partnership securities, which, together with establishing reserves, can affect the amount of cash available for distribution to our unitholders. As a result, we may make distributions during periods when we record losses and may not make distributions during periods when we record net income.
 
If commodity prices remain at their current level for an extended period of time or continue to decline, we may be required to take additional write-downs of our asset carrying values.
 
Low oil and natural gas prices may result in substantial downward adjustments to our estimated proved reserves.  Additionally, if our estimates of development costs increase, production data factors change or drilling results

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deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Furthermore, our proved reserves are calculated using average prices observed in the previous twelve months, which are higher than the market prices on December 31, 2014.  

We are required to perform impairment tests on our assets quarterly and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated future cash flows of our assets, the carrying value may not be recoverable and therefore may require a write-down. To calculate the estimated cash flows used in our impairment tests, we use the forward strip prices as of the date we are performing the test. During the year ended December 31, 2014, we incurred total impairment charges of $395.9 million, related to certain proved properties in all of our regions, but primarily Golden Trend, Anadarko and Big Escambia Creek. These impairment charges were due primarily to lower commodity prices, higher operating costs and lower well performance. See Note 5 and Note 12 to our consolidated financial statements for further discussion. During the year ended December 31, 2013, we incurred total impairment and other charges of $214.3 million, primarily related to certain proved properties in the Cana Shale in the Mid-Continent region and Permian region due to lower reserve forecasts and certain leaseholds in our Mid-Continent region unproved properties that we expect to expire undrilled in 2014.  Continued declines in oil and natural gas prices from the December 31, 2014 prices may cause us to incur additional impairment charges in the future, which could have a material adverse effect on our results of operations and financial position in the periods in which such charges are taken.

Our hedging activities may have a material adverse effect on our earnings, profitability, cash flows and financial condition.
 
Because we are exposed to risks associated with fluctuating commodity prices, we utilize various financial instruments (swaps, collars, and puts) to mitigate these risks within our overall hedge portfolio. It is possible that our various hedging activities may not be effective in reducing our exposure to commodity price risk. For instance, we may not produce or process sufficient volumes to cover our hedges, we may fail to hedge a sufficient portion of our future production or the instruments we use may not adequately correlate with changes in the prices we receive. Our current hedging portfolio is presented in Part II, Item 7A. Qualitative and Quantitative Disclosure About Market Risk.
 
To the extent we hedge our commodity price and interest rate risk, we may forego the benefits we would otherwise experience when commodity prices or interest rates improve. Furthermore, because we have entered into derivative transactions related to only a portion of the commodity volumes and outstanding debt to which we have price and interest rate exposure, we will continue to have direct commodity price and interest rate risk on the unhedged portion. Our actual future production may be significantly higher or lower than we estimated at the time we entered into the commodity derivative transactions for that period. If the actual amount is higher than we estimated, we will have more commodity price risk than we intended. If the actual amount is lower than the 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 a corresponding settlement of the underlying physical commodity, which could, in certain circumstances, result in a reduction of our liquidity.
 
As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances might actually increase the volatility of our cash flows. In addition, hedging activities may result in substantial losses. Such losses could occur under various circumstances, such as when a counterparty fails to perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or our hedging policies and procedures are not properly followed or otherwise do not work as planned. The steps we take to monitor our hedging activities may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
 
Due to the enactment of the Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank"), the hedges we execute are undertaken in a highly regulated market. While many of the rules implementing the Dodd-Frank statute are in place at this time, some significant components of the Dodd-Frank regulatory regime remain subject to rulemaking by the Commodity Futures Trading Commission (the "CFTC") and other regulators. For related discussion, see the risk factor below entitled - The adoption of derivatives legislation by the United States Congress and its implementation by the Commodity Futures Trading Commission and SEC 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.
 

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We have indebtedness under our revolving credit facility and our senior notes, which may limit our flexibility in obtaining additional financing and in pursuing other business opportunities. In addition, we may incur substantial debt in the future to enable us to maintain or increase our reserve and production levels and to otherwise pursue our business plan. This debt may restrict our ability to make distributions.
 
As of December 31, 2014, we had $212.6 million outstanding under our senior secured credit facility, leaving approximately $107.4 million of available borrowing capacity as of that date,  and $50.7 million outstanding under our senior notes, net of unamortized discount. Our level of outstanding debt could have important consequences to us, including the following:
 
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 favorable terms; 
we will need a portion of our cash flow to make interest payments on our debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; 
our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and 
our debt level may limit our flexibility in responding to changing business and economic conditions.
 
Our ability to service our debt 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. In addition, our ability to service debt under our credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness or comply with our financial covenants under our existing credit facility, we will be forced to take actions such as eliminating, reducing or further reducing distributions, reducing or delaying our business activities and expenses, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms, or at all.
  
Decreases in commodity prices could result in decreases in the borrowing base under our revolving credit facility, which could materially and adversely affect our operations and financial condition.
Availability under our revolving credit facility is subject to a borrowing base that is typically determined semi-annually as an amount equal to the loan value of our proved oil and gas reserves. As a result, a reduction in commodity prices could lead to a reduction in the value of our proved oil and gas reserves and the corresponding borrowing base, which would negatively impact our borrowing ability. The decline in oil and natural gas prices in the fourth quarter of 2014 has impacted the value of our estimated proved reserves and, in turn, the market value used by our lenders to determine our borrowing base. Accordingly, at the next redetermination we anticipate that our borrowing base will be lower than our current $320 million borrowing base due to declines in commodity prices. If the amount outstanding under our revolving credit facility at any time exceeds the borrowing base, we may be required to repay a portion of our outstanding borrowings, and if such an event were to occur, it could materially and adversely affect our operations and financial condition. For a further discussion of our Amended and Restated Credit Agreement (as amended, the "Credit Agreement"), see Note 8 to our consolidated financial statements.
Covenants in our credit facility limit our ability to make distributions, enter into certain types of acquisitions or engage in other business transactions.
 
Our credit facility contains covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates. Furthermore, our credit facility contains covenants requiring us to maintain certain financial ratios and tests. Any subsequent replacement, restatement or amendment of our credit facility or any new indebtedness could impose similar or greater restrictions.
 
We may not be able to execute our business strategy if we encounter illiquid capital and commercial credit markets.
 
One component of our business strategy contemplates pursuing opportunities to acquire assets where we believe growth opportunities are attractive and our business strategies could be applied. We regularly consider and enter into discussions regarding strategic transactions that we believe will present opportunities to pursue our growth strategy.
 
We will require substantial new capital to finance strategic acquisitions. Any limitations on our access to capital or commercial credit will impair our ability to execute this component of our growth strategy. If the cost of such capital or credit becomes too expensive, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the

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necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of capital include our units’ market performance, conditions in the commercial credit, debt and equity markets and offering or borrowing costs such as interest rates or underwriting discounts.

Our operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a decline in our cash flows.
 
The oil and natural gas industry is capital intensive. We expect to continue to make substantial capital expenditures in our business for the maintenance, growth, construction and acquisition of assets and oil and natural gas production and reserves. In 2015, our capital expenditure budget is expected to be approximately $72.4 million, excluding acquisitions, of which $71.4 million relates to upstream capital expenditures and $1.0 million relates to corporate capital expenditures. We intend to fund our future capital expenditures with cash flows from operations, borrowings under our credit facility and the issuance of debt and equity securities, when market conditions allow. In the event of continued declines in commodity prices we will additionally reconsider our capital budget. The incurrence of debt will require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:

the estimated quantities of our proved reserves; 
the amount of oil and natural gas produced from existing wells; 
the prices at which we sell our production; 
the strike prices of our hedges; 
our operating and general and administrative expenses; and 
our ability to acquire, locate and produce new reserves.
 
If our revenues or the borrowing base under our credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, our ability to obtain the capital needed to sustain our operations at current levels, or to pursue our growth strategy, may be limited. Our credit facility may restrict our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations, which in turn could lead to a possible decline in our natural gas and crude oil reserves and production. Even if we are successful in obtaining additional financing, the terms of such financing could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage. Issuing additional partnership interests may result in significant unitholder dilution which could have a material adverse effect on our ability to pay distributions at the then-current distribution rate. Further, we may lose opportunities to acquire oil and natural gas properties and businesses.
 
Our industry is highly competitive, and increased competitive pressure or loss of key customers could adversely affect our business and operating results.
 
We compete with similar enterprises in our areas of operation. Some of our competitors are large oil and natural gas companies that have greater financial resources and access to supplies of oil, natural gas and NGLs than we do.

Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas, but also conduct 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 natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil and natural gas prices, to contract for drilling equipment, to secure trained personnel and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. If a significant customer of ours reduces the volume it purchases from us, we could experience a temporary interruption in sales of, or lower prices for, our production.  As a result our revenues and cash available for distribution could decline which may adversely affect our ability to make cash distributions to our unitholders.
 
In our industry there is significant competition for experienced personnel, particularly in the engineering, accounting and financial reporting, tax and land departments. In addition, competition is strong for oil and natural gas producing properties, oil and natural gas companies and undeveloped leases and drilling rights. We may often be outbid by competitors in

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our attempts to acquire personnel, assets, properties or companies. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

If we are unable to make acquisitions on economically acceptable terms, our future growth will be limited.
 
Our ability to grow our business depends, in part, on our ability to make acquisitions that are accretive to our cash available for distributions on a per unit basis. If we are unable to make these accretive acquisitions because we are: (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them; (ii) unable to obtain financing for these acquisitions on economically acceptable terms; or (iii) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit because of unforeseen circumstances.
 
All acquisitions involve potential risks, including, among other things:
 
mistaken assumptions about future prices, volumes, revenues and costs of oil and natural gas, including synergies and estimates of the oil and natural gas reserves attributable to a property we acquire; 
inefficiencies and complexities that can arise because of unfamiliarity with new assets, operations and the businesses associated with them, including their markets and geographic service areas; 
the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate; 
mistaken assumptions about the overall costs of equity or debt; 
decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition; 
increases in our interest expense or financial leverage if we incur additional debt to finance the acquisition; and 
customer or key employee losses at the acquired businesses.
 
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our limited partners will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider.
 
Our ability to derive benefits from our acquisitions will depend on our ability to successfully integrate the acquired operations.
 
Achieving the anticipated benefits from acquisitions depends in part upon whether we are able to successfully integrate the assets or businesses of these acquisitions, in an efficient and effective manner. The difficulties combining businesses or assets potentially will include, among other things:
 
geographically separated organizations and possible differences in corporate cultures and management philosophies; 
significant demands on management resources, which may distract management's attention from day-to-day business; and 
differences in the disclosure systems, accounting systems, and internal controls and procedures (including accounting controls and internal controls and procedures we are required to maintain under the Sarbanes-Oxley Act of 2002) of the two companies, which may interfere with our ability to make timely and accurate public disclosure.
  
Any inability to realize the potential benefits of the acquisition, as well as any delays in integration, could have an adverse effect upon the revenues, level of expenses and operating results of the company, after the acquisitions, which may affect the value of our common units after the acquisition.

Inclement weather, unforeseen events or events of force majeure may limit our ability to operate our business and could adversely affect our operating results.

The weather, (such as unseasonably wet or dry weather, extended periods of below freezing weather, hurricanes, lightning strikes, tornadoes) unforeseen events (such as electrical outages), or events of force majeure (such as acts of nature or acts of terrorism) in the areas in which we operate could cause disruptions and, in some cases, suspension of our operations (whether directly or by virtue of disrupting or suspending operations of those upon whom we rely in our operations), which could in turn result in our inability to cause physical delivery of commodities guaranteed under contract or require us to purchase third-party volumes at significantly higher prices to satisfy our delivery obligations.


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Our business involves many hazards and operational risks, some of which may not be partially or fully insured or insurable. If a significant accident or event occurs that is not fully insured or interrupts normal operations, our operations and financial results could be adversely affected.

Our operations are subject to many hazards inherent in drilling and producing oil, natural gas and NGLs, including:
 
damage to production equipment, gathering equipment, pipelines and treating or processing plants, compression and related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism; 
inadvertent damage from construction, farm and utility equipment or acts of vandalism; 
leaks of natural gas, poisonous hydrogen sulfide gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of pipeline, equipment or facilities;
mishandling of fluids, including chemical additives that may be toxic;
surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids; 
fires and explosions; and 
other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
 
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage, and may result in curtailment or suspension of our related operations. We could incur substantial expenses in the prosecution or defense of litigation. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations and ability to pay distributions to our unitholders.
 
As is customary in the industry, we maintain insurance against some but not all of these risks. 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. We are not fully insured against all risks inherent to our business.  For example, we are not fully insured against all environmental accidents which may include toxic tort claims. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential liabilities. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition, results of operations and ability to pay distributions to our unitholders.
 
Increases in interest rates could adversely impact our unit price and our ability to issue additional equity, to incur debt to make acquisitions or for other purposes or to make cash distributions at our intended levels.

Credit markets have experienced a prolonged period of low interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, to incur debt to make acquisitions or for other purposes or to make cash distributions at our intended levels.

Due to the limited industry and geographic diversification of our properties, adverse developments in our operations or operating areas would reduce our ability to make distributions to our unitholders.

All of our properties are located in Texas, Oklahoma, Alabama, Arkansas, and Mississippi. Due to our limited diversification in industry type and location, an adverse development in one of these areas would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.


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Our ability to manage and grow our business effectively may be adversely affected if we lose key management or operational personnel.

We depend on the continuing efforts of our key management and operational personnel. The departure of any of our key management or operational personnel could have a significant negative effect on our business, operating results, financial condition, and on our ability to compete effectively in the marketplace. Additionally, our ability to hire, train, and retain qualified personnel will continue to be important and will become more challenging as we grow and face more significant competition in the marketplace. Our ability to grow may be adversely impacted if we are unable to successfully hire, train and retain these important personnel.

We are exposed to the credit risk of our customers and other counterparties, and a general increase in the nonperformance by counterparties could have an adverse impact on our cash flows, results of operations and financial condition.

We are subject to risks of loss resulting from nonperformance by our counterparties, such as our lenders and other hedge counterparties. Any deterioration in the financial health of our counterparties or any factors causing reduced access to capital for them may result in the reduction in their ability to pay or otherwise perform on their obligations to us. Any increase in the nonperformance by our counterparties, either as a result of recent changes in financial and economic conditions or otherwise, could have an adverse impact on our operating results and could adversely affect our liquidity.

Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of production and develop our undeveloped reserves. These activities are dependent on certain factors, many of which are beyond our control. A decrease in production or reserves could adversely affect our business and operating results.

The volume of hydrocarbons that we sell from our producing wells will naturally decline over time, and so may our revenues. In order to maintain or increase the throughput levels of our assets we must continually obtain new supplies of natural gas and oil to offset these declines.

Our producing reservoirs experience production rate declines that vary depending upon reservoir characteristics and other factors. The overall production decline rate may change when additional wells are drilled, when we make acquisitions and under other circumstances. Our future cash flows and income, and our ability to maintain and to increase distributions to unitholders, are partly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. 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. Factors that may hinder our ability to acquire additional reserves or develop current reserves include competition, access to capital, prevailing oil and natural gas prices, the costs incurred by us to develop and exploit current and future oil and natural gas reserves, the availability of drilling and other equipment, and the number and attractiveness of properties for sale. 

Our business depends in part on gathering, transportation and processing facilities. Any limitation in the availability of, or our access to, those facilities would interfere with our ability to produce and market oil, natural gas and NGLs and could reduce our cash available for distribution and adversely impact expected increases in oil, natural gas and NGL production from our drilling program.
 
The marketability of our oil, gas and NGL production depends in part on the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems. The amount of oil, natural gas and NGLs that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, processing or transportation system, weather, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our oil wells may be drilled in locations that are not serviced by gathering, processing and transportation facilities, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport additional production. As a result, we may not be able to sell the oil production from these wells until the necessary gathering, processing and transportation facilities are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering, processing and transportation facilities, would interfere with our ability to market the oil, gas and NGLs we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil and gas production from our drilling program.  Our access to transportation options can also be affected by U.S. federal and state regulations of oil and natural gas production and transportation and other general economic conditions beyond our control.


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In addition, sulfur is a by-product associated with substantially all of the natural gas production in our operations in Alabama.   If we were unable to sell the sulfur we produce, we may be forced to store it or curtail our oil and gas production.

Our and other operators’ drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors.

Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Our and other operators’ drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

unexpected drilling conditions; 
drilling, production or transportation facility or equipment failure or accidents;
mechanical difficulties, such as lost or stuck drilling or service tools;
abnormally pressured formations or rock compaction;  
increasing costs for or shortages or delays in the availability of drilling rigs, experienced personnel and other services and equipment; 
adverse weather conditions; 
compliance with environmental and governmental requirements; 
title problems or royalty disputes;
unusual or unexpected geological formations; 
pipeline ruptures; 
fires, blowouts, craterings and explosions; 
mishandling of fluids, including chemical additives that may be toxic; and 
surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids.
 
Any curtailment to the gathering and pipeline systems used to deliver our oil and gas production for processing, storage or further delivery to end markets could require us to find alternative means to transport the oil and natural gas production from the underlying properties, which alternative means could require us to incur additional costs. Additionally, any delay in the drilling of new wells could reduce our revenues. Any such curtailment, delay, cancellation, cost increase or revenue reduction may limit our ability to make cash distributions to our unitholders.

Our estimated oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves.  The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. Reserve reports rely upon many assumptions, including future oil and natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the estimated timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates that reflect the actual results of drilling and production. Any significant change in our assumptions or actual performance of our wells could affect our estimates of reserves, the classifications of the reserves and our estimates of the future net cash flows associated with the reserves. In addition, since many of our wells are mature and have low production rates, changes in future production costs assumptions could have a significant effect on our proved reserve estimates.

The standardized measure of discounted future net cash flows of our estimated net proved reserves is not the same as the current market value of our estimated net proved reserves. We base the discounted future net cash flows from our estimated net proved reserves on average prices observed in the previous twelve months and on cost estimates we believe reflect the costs at the end of the period. Actual prices received for production and actual costs of such production will be different than these assumptions, perhaps materially. In particular, commodity prices declined in 2014, causing the average of the prices observed in the previous twelve months to be higher than the market prices on December 31, 2014.

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on actual interest rates and the risks associated with our firm in particular or the natural gas and oil industry in general. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the

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quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

We have limited control over the activities on properties we do not operate, which includes a substantial amount of the properties we acquired in the Mid-Continent Acquisition.

Continental Resources, Inc., Newfield Exploration Mid-Continent Inc., Devon Energy Production Co LP, and others operate some of the properties in which we have an interest, including the properties we acquired in the Mid-Continent Acquisition. We have less ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them versus those fields in which we are the operator. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside our control, including:

the operator's expertise and financial resources;
the timing and amount of their capital expenditures;
current commodity prices;
the rate of production of the reserves;
approval of other participants to drill wells and implement other work programs;
the availability of suitable drilling rigs, drilling equipment, production and transportation infrastructure and qualified operating personnel; and
selection of technology.

Our dependence on the operator and other working interest owners for these projects and our reduced influence or ability to control the operation and future development of these properties could materially adversely affect our business, results of operations, financial condition and ability to pay distributions to our unitholders.

We cannot control the value of the Regency common units we received as part of the consideration for the Midstream Business Contribution, and a significant reduction in the value of the common units could have a material adverse effect on our liquidity.

As part of the consideration for the Midstream Business Contribution, we received approximately 8.2 million Regency common units and continue to hold 4.0 million of such units as of February 26, 2015. These common units represent a significant source of potential liquidity for us. The value of the Regency common units, however, is based on a fluctuating market price and is thus outside of our control. If the market price of the Regency common units that we hold were to decline significantly, it could have a material adverse effect on our liquidity.

Our business could be negatively impacted by cyber-security threats and related disruptions.

We rely heavily on our information technology ("IT") infrastructure to process, store and transmit large amounts of information. The availability and integrity of this information is essential for us to conduct business activities, such as maintaining safe and efficient operation of our assets, analyzing of the performance of our assets, making timely royalty payments, complying with regulatory requirements and providing timely disclosures to our investors, among others.  

Cyber-security threats could include, among others, unlawful attempts to gain access to our IT infrastructure by directed attacks from hackers; infiltration by computer viruses and other malware; attempts to gain unauthorized access to our IT infrastructure by acts of deception against individuals with legitimate access; and deliberate acts of sabotage by persons with legitimate access. Furthermore, third-party systems on which we rely could also suffer operational system failure or cyber-security breaches. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cyber-security threats. Any future cyber-security attacks that negatively affect our IT infrastructure could have a material adverse effect on our businesses.




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Risks Inherent in an Investment in Us
 
The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flow and not solely on profitability.
 
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

NGP controls a substantial portion of our common units and is entitled to appoint three of our directors, and thus it could exert certain significant influence over us.
As of February 26, 2015, NGP beneficially owned 53,340,601 common units, representing over 35% of our outstanding common units. In addition, pursuant to our partnership agreement, NGP is entitled to appoint three of the nine members of our board of directors. As a result, NGP could exert certain significant influence over us. NGP may have interests that do not align with our interests and with the interests of our unitholders, which could have an adverse impact on our results of operations or cash available for distribution to unitholders. In addition, NGP's level of control may make any potential takeover bids more costly or difficult in the future.

Unitholders have less ability to influence management's decisions than holders of common stock in a corporation.
Unlike the holders of common stock in a corporation, unitholders have more limited voting rights on matters affecting our business, and therefore a more limited ability to influence management's decisions regarding our business. Our partnership agreement provides that our general partner may not withdraw and may not be removed at any time for any reason whatsoever. In addition, if unitholders are dissatisfied with the performance of our general partner, they only have the right to elect five of the nine directors.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
 
Unitholders’ voting rights are further restricted by the partnership agreement provision 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 of directors of our general partner, cannot vote on any matter. 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 the unitholders’ ability to influence the manner or direction of management.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
 
We expect that we will distribute all of our available cash, as defined in our partnership agreement, to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
 
In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, our credit facility or the indenture governing our senior notes on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.


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If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
 
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

Our partnership agreement contains provisions that modify and limit our general partner's fiduciary duties to our unitholders.
 
Our partnership agreement contains provisions that modify and limit our general partner's fiduciary duties to our unitholders. Our partnership agreement also contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:
 
provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action in good faith, and our general partner will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation or at equity;
 
provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, and our partnership agreement specifies that the satisfaction of this standard requires that our general partner must believe that the decision is in the best interests of our partnership;
 
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 or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
 
provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if the resolution of a conflict is:
 
approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval; 
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates; 
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or 
fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
 
In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.


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We have the right to borrow to make distributions. Covenants in our credit facility may restrict our ability to make distributions.
 
Our partnership agreement allows us to borrow to make distributions. We may borrow under our credit facility to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short term fluctuation in our cash flow that would otherwise cause volatility in our quarter to quarter distributions.
 
The terms of our credit facility may restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.
 
We may issue additional units without limited partner approval, which would dilute ownership interests.
 
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
 
our unitholders’ proportionate ownership interest in us will decrease; 
the amount of cash available for distribution on each unit may decrease; 
the ratio of taxable income to distributions may increase; 
the relative voting strength of each previously outstanding unit may be diminished; and 
the market price of the common units may decline.
 
Our management team, directors and NGP may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.
 
As of February 26, 2015, our management team, directors and NGP (including through their interests in the Montierra Entities) beneficially owned an aggregate of 55,728,280 common units, including 1,103,358 common units which are still subject to a vesting requirement. The resale of any of these common units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop. 53,340,601 of the units beneficially owned by NGP (including through their interests in the Montierra Entities) are registered for resale under an effective Form S-3, filed with the Securities and Exchange Commission on September 18, 2014.
 
Liability of a limited partner may not be limited if a court finds that unitholder action constitutes control of our business.
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. 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 other states in which we do business. Limited partners could be liable for any and all of our obligations as a general partner 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
 
the right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
 
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
 
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the 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. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.


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Our simplified capital structure (i.e. only one common class of equity outstanding) could result in slower distribution growth and less certainty of minimum distributions.

Unlike many publicly-traded partnerships, we do not have incentive distribution rights. Incentive distribution rights generally entitle the general partner of a publicly-traded partnership to increasing percentages of the cash distributed by the partnership in excess of a specified level and are designed to encourage the general partner and its affiliates to grow distributions of the partnership through, among other things, the sale or contribution of additional assets to the partnership on an accretive basis. Since we no longer have an independently-controlled general partner with incentive distribution rights in us, we could have difficulty consummating accretive transactions at the same rate as, and see slower distribution growth than, other publicly-traded partnerships.

Unlike many publicly-traded partnerships, we also do not have subordinated units. Subordinated units generally are not entitled to receive any distributions until the common units have received a specified minimum quarterly distribution plus any arrearages from prior quarters. The practical effect of the existence of subordinated units in lieu of common units is to increase the likelihood that a specified minimum quarterly distribution will be distributed on the outstanding common units. Accordingly, there may be more risk that we will not distribute a specified minimum amount each quarter (either present or in arrears) on our common units than there would exist if a portion of our outstanding units were subordinated units rather than common units.


Risks Related to Governmental Regulation

We are subject to compliance with stringent environmental laws and regulations that may expose us to significant costs and liabilities, and future regulations may be more stringent. 

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations may impose numerous obligations on our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our wells, pipelines and facilities, and the imposition of substantial liabilities for pollution resulting from our operations. Failure or delay in obtaining regulatory approvals or drilling permits by us or our operators could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the spacing, and density of wellbores may limit the quantity of oil and natural gas that may be produced and sold.
 
Numerous governmental authorities, such as the federal Environmental Protection Agency ("EPA") and analogous state agencies in which states we operate have the power to enforce compliance with these laws and regulations, often requiring difficult and costly actions. Failure to comply may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, assessment of monetary penalties and the issuance of injunctions limiting or preventing some or all of our operations. Certain environmental statutes and analogous state laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.
 
There is risk of incurring significant environmental costs and liabilities in connection with our operations as a result of our handling of petroleum hydrocarbons and wastes; operation of our wells, gathering systems and other facilities; air emissions and water discharges related to our operations and historical industry operations and waste disposal practices. See Part I, Item 1. Business—Regulation of Our Operations.

Changes in environmental laws and regulations occur frequently and such laws and regulations tend to become more stringent over time. Stricter laws, regulations or enforcement policies could significantly increase our compliance costs and have a material adverse effect on our operations or financial position. For example, on August 16, 2012, the EPA published final rules that establish new air emission control requirements for natural gas and NGL production, processing and transportation activities, including New Source Performance Standards (NSPS) to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants (NESHAPS) to address hazardous air pollutants frequently associated with gas production and processing activities. Among other things, these final rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. On August 5, 2013, the EPA released a final rule amending the NSPS rule’s provisions for storage tanks, adjusting the compliance date and establishing an alternative emissions limit to account for the decline in emissions that occurs over time. Compliance with these

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requirements may require modifications to certain of our operations, including the installation of new equipment to control emissions at the well site that could increase our costs or reduce our production, which could have a material adverse effect on our results of operations and cash flows.

We may incur significant costs and liabilities resulting from safety and compliance-related regulations.

Our gathering operations may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such operations. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. For example, Louisiana's Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating gathering facilities in Louisiana, and has authority to review and authorize the construction, acquisition, abandonment and interconnection of physical pipeline facilities and may implement new regulations in the future. Historically, apart from pipeline safety, it has not acted to exercise this jurisdiction respecting gathering facilities. 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 gathering lines in Texas have been deemed non-utilities by the TRRC. Under Texas law, non-utilities are not subject to rate regulation by the TRRC. Should the status of these non-utility facilities change, they would become subject to rate regulation by the TRRC, which could adversely affect the rates that our facilities are allowed to charge their customers.  Texas also administers federal pipeline safety standards under the Pipeline Safety Act of 1968. The non-jurisdictional gathering exemption under the Natural Gas Pipeline Safety Act of 1968 presently exempts most of our gathering facilities from jurisdiction under that statute. The “rural gathering exemption,” however, may be restricted in the future. As a result of recent pipeline incidents in other parts of the country, Congress and the Department of Transportation have passed or are considering imposing more stringent pipeline safety requirements. Costs associated with complying with and qualifying our facilities under these and other regulations could be material and have an adverse effect on us, our financial condition, and our results of operations.

The adoption of derivatives legislation by the United States Congress and its implementation by the CFTC and the SEC 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.
In 2010, Congress adopted Dodd-Frank, which among other things, establishes a comprehensive framework for the regulation of derivatives, or swaps. The SEC, which has jurisdiction over security-based swaps, and the CFTC, which has jurisdiction over swaps, have issued regulations to implement this new statutory regime. 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 Columbia in September 2012. 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.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and exchange trading. To the extent the Company engages in such transactions or transactions that become subject to such rules in the future, the Company will be required to comply or to take steps to qualify for an exemption to such requirements. Although the Company expects to qualify for the end-user exception to the mandatory clearing requirements for swaps entered to hedge its 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 the Company uses for hedging. In addition, the Act requires that regulators establish margin rules for uncleared swaps. Rules that require end-users to post initial or variation margin could impact liquidity and reduce cash available to the Company for capital expenditures, therefore reducing its 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 the Company is not yet clear.
Finally, the Act was intended, in part, to reduce the volatility of oil and gas prices. To the extent they are unhedged, the Company's revenues could be adversely affected if a consequence of the Act and implementing regulations is to lower commodity prices.

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The full impact of the Act and related regulatory requirements upon the Company’s business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Act and any new regulations could significantly increase the cost of derivative transactions, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company's ability to monetize or restructure its existing derivative contracts or increase the Company's exposure to less creditworthy counterparties. If the Company reduces its use of derivatives as a result of the Act and related regulations, the Company's results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company's ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on the Company, its financial condition and its results of operations.
 
In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties subject to such foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.

Climate change laws or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and a decreased demand for oil and natural gas that we produce or process.

In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases, or “GHGs,” present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth's atmosphere and other climate changes, the EPA has adopted regulations under existing provisions of the federal Clean Air Act. To date, the EPA has issued (i) a “Mandatory Reporting of Greenhouse Gases” final rule, which establishes a new comprehensive scheme requiring operators of stationary sources (including certain oil and natural gas production systems) in the United States emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually; (ii) an “Endangerment Finding” final rule, effective January 14, 2010, which states that current and projected concentrations of six key GHGs in the atmosphere, as well as emissions from new motor vehicles and new motor vehicle engines, threaten public health and welfare, which allowed the EPA to finalize motor vehicle GHG standards (the effect of which could reduce demand for motor fuels refined from crude oil); and (iii) a final rule, effective August 2, 2010, to address permitting of GHG emissions from stationary sources under the CAA’s Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Where required for current operations, we have implemented GHG monitoring and reporting programs and amended our air permits to include GHG emissions. These and future EPA rulemakings could adversely affect our operations by limiting drilling opportunities, restricting or delaying our ability to obtain air permits for new or modified facilities, or imposing materially increased costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements.
In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for GHGs, became binding on the countries that had ratified it. International discussions are underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2020. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce or the oil, natural gas and NGLs we gather and process or fractionate. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in many of our oil and natural gas well drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic fracturing involving fluids that contain diesel fuel

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under the Safe Drinking Water Act's Underground Injection Control Program and has released draft permitting guidance for hydraulic fracturing operations that use diesel fuel in fracturing fluids in those states where EPA is the permitting authority. EPA accepted comments on the draft guidance in 2012, but has not yet finalized the permitting guidance. In addition, legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process. Moreover, on May 19, 2014 , the EPA published an Advanced Notice of Proposed Rulemaking to regulate chemicals used in hydraulic fracturing under the Toxic Substances Control Act. Further, on May 16, 2013, the Department of the Interior's Bureau of Land Management (“BLM”) issued a revised proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans.
Certain states where we operate, including Texas, have adopted, and other states are considering adopting, regulations and legislation that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Texas adopted new well integrity rules on May 24, 2013 addressing drilling, casing, cementing, blow-out preventers and fracture stimulation that took effect on January 1, 2014. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.
We use a significant amount of water in our hydraulic fracturing operations. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. For example, in October 2011, the EPA announced as part of its Clean Water Act planning process that the EPA will develop standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works (POTWs). The regulations will be developed under the EPA's Effluent Guidelines Program under the authority of the Clean Water Act. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial condition.
A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The Agency released a progress report outlining work currently underway on December 21, 2012, but has not yet issued a draft or final report or findings for peer review and public comment. These on-going or proposed studies, depending on their course and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substance Control Act, and/or other regulatory mechanisms. President Obama created the Interagency Working Group on Unconventional Natural Gas and Oil by Executive Order on April 13, 2012, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional natural gas and oil resources.
If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
Certain of our properties, including some of our operations in Oklahoma, are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which may increase our costs and delay or prevent our efforts to conduct planned operations.

Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management and the Office of Natural Resources Revenue, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations and approval requirements relate to such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and

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regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native American tribes were to deteriorate, we could face significant risks to our ability to continue the projected development of our leases on Native American tribal lands. One or more of these factors may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our natural gas or oil development and production operations on such lands.


Tax Risks to Common 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 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 the common units depends largely on our 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 or any other tax matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to the limited partners. Because a tax would be imposed upon us as a corporation, our cash available for distributions 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 the unitholders, likely causing a substantial reduction in the value of our common 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. We are, for example, subject to an entity level tax on the portion of our income that is generated in Texas. Imposition of such any such tax on us by any other state will reduce the cash available for distribution.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama administration's budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration's proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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 challenge will reduce our cash available for distribution.


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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 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 by the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.

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

We will be considered to have technically 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. A deferral of depreciation deductions would result in increased taxable income or reduced taxable loss to certain unitholders, although the exact increase or reduction for each unitholder cannot be estimated at this time. 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 his taxable income for the year of termination. Our termination currently would not affect our consolidated financial statements or our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for 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 unitholders for the tax year in which the technical termination occurs.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular 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 units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular 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. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not 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 our unitholders.

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

Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.


33


Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if no cash distributions were received from us. Although not anticipated, our taxable income for a taxable year may include income without a corresponding receipt of cash by us, such as accrual of future income, original issue discount or cancellation of indebtedness income. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that result from that income.

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

If a unitholder sells common units, they will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income allocated for a common unit, which decreased the unitholder’s tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than their tax basis in that common unit, even if the price received is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our non-recourse liabilities, if a unitholder sells units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale.

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

Investment in common units by tax-exempt entities, such as 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. Distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file U.S. federal tax returns and pay tax on its share of our taxable income. Tax-exempt entities or non-U.S. persons should consult a tax advisor before investing in our common units.

We will 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 have adopted 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 the unitholders. It also could affect the timing of these tax benefits or the amount of gain from sales of common units and could have a negative impact on the value of our common units or result in audit adjustments to tax returns of our unitholders.

Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.

In addition to federal income taxes, a unitholder will likely be subject to 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 the unitholder does not live in any of those jurisdictions. A unitholder will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, a unitholder may be subject to penalties for failure to comply with those return filing requirements. We own assets and conduct business in several states. Many of these states currently impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is a unitholder's responsibility to file all United States federal, state and local tax returns.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

The Obama administration's budget for the fiscal year 2016 recommends elimination of certain key U.S. tax incentives
currently available to oil and natural gas exploration and production companies. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the manufacturing tax deduction for oil and gas companies; and an increase in the

34


geological and geophysical amortization period for independent producers. It is unclear whether any such changes will be introduced into law and, if so, how soon any such changes would become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect the taxable income allocable to the unitholders.



Item 1B.
Unresolved Staff Comments.
 
Not applicable.


Item 2.
Properties.
 
For complete descriptions of our significant properties, see Item 1. Business, which descriptions are incorporated into this item by reference.


Item 3.
Legal Proceedings.
 
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we are and may, at any given time, be a party to various legal proceedings and litigation arising in the ordinary course of business. We maintain insurance policies in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, give assurance that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

In March and April 2014, alleged unitholders of the Partnership filed three class action lawsuits in the United States District Court for the Southern District of Texas on behalf of the Partnership's public unitholders.  Plaintiffs in each lawsuit alleged a variety of causes of action challenging the Midstream Business Contribution, including alleged breaches of fiduciary or contractual duties, alleged aiding and abetting these alleged breaches of duty, and alleged violations of the Securities Exchange Act of 1934 (the "Exchange Act"). The plaintiffs sought to have the sale rescinded and receive monetary damages and attorneys’ fees. In August 2014, the court consolidated the lawsuits into an action styled In re Eagle Rock Energy Partners, L.P. Securities Litigation and appointed a lead plaintiff and co-lead counsel. On November 19, 2014, the court dismissed the action without prejudice.



Item 4.
Mine Safety Disclosures.

Not applicable.


PART II

35




Item 5.
Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
 
Our common units are listed on the NASDAQ Global Select Market under the symbol “EROC.” The following table sets forth, for the periods indicated, the high and low sales prices of our common units as reported by the NASDAQ Global Select Market, as well as the amount of cash distributions declared per quarter.
Quarter Ended
 
High
 
Low
 
Distribution
per Unit
 
Record Date
 
Payment Date
March 31, 2013
 
$
9.84

 
$
8.73

 
$
0.22

 
May 7, 2013
 
May 15, 2013
June 30, 2013
 
$
10.52

 
$
7.46

 
$
0.22

 
August 7, 2013
 
August 14, 2013
September 30, 2013
 
$
8.25

 
$
6.01

 
$
0.15

 
November 7, 2013
 
November 14, 2013
December 31, 2013
 
$
7.88

 
$
5.01

 
$
0.15

 
February 7, 2014
 
February 14, 2014
 
 
 
 
 
 
 
 
 
 
 
March 31, 2014
 
$
6.30

 
$
4.68

 
$

 
N/A
 
N/A
June 30, 2014
 
$
5.33

 
$
3.97

 
$

 
N/A
 
N/A
September 30, 2014
 
$
5.14

 
$
3.42

 
$
0.07

 
November 7, 2014
 
November 14, 2014
December 31, 2014
 
$
3.63

 
$
1.78

 
$
0.07

 
February 6, 2015
 
February 13, 2015

The last reported sale price of our common units on the NASDAQ Global Select Market on February 26, 2015 was $2.63. As of that date, there were 107 holders of record and approximately 29,730 beneficial owners of our common units.

Distribution Policy

Our distribution policy is to distribute to our unitholders, on a quarterly basis, all of our available cash, if any, in the manner described below and as further described in our partnership agreement. Available cash generally means, for any quarter ending prior to liquidation, all cash and cash equivalents on hand at the end of that quarter (or, if the general partner chooses, on the date of determination) less the amount of cash reserves established by the general partner to:

provide for the proper conduct of our business, including for future capital expenditures and credit and other needs;
comply with applicable law or any Partnership debt instrument or other agreement; or
provide funds for distributions to unitholders in respect of any one or more of the next four quarters. 

In connection with making the distribution decision for the quarter ended March 31, 2014, the Board of Directors, upon management's recommendation, decided to suspend the quarterly distribution in order to preserve liquidity in advance of closing the contribution of the Midstream Business to Regency. For the quarter ended June 30, 2014, the Board of Directors, upon management's recommendation, decided to continue the suspension of the quarterly distribution. Upon management's recommendation, the Board of Directors approved the resumption of the quarterly distribution for the quarter ended September 30, 2014.

The actual distributions we will declare will be subject to our operating performance, prevailing market conditions (including forward oil, condensate, natural gas, natural gas liquid and sulfur prices), the impact of unforeseen events and the approval of our Board of Directors and will be done pursuant to our distribution policy.

Under the terms of the agreements governing our debt, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Requirements—Revolving Credit Facility.

Our Board of Directors will evaluate our distribution policy from time to time as conditions warrant in the future.


36


 Repurchases of Common Units

On October 27, 2014, we announced a common unit repurchase program of up to $100 million through which repurchases may be made from time to time at prevailing prices on the open market or in privately negotiated transactions. The program was authorized to commence following the filing of the Quarterly Report on Form 10-Q for the quarter ending September 30, 2014 and will conclude by March 31, 2016. The repurchase program does not obligate us to repurchase any, or any specific number of, units and may be discontinued at any time. We have cancelled all repurchased units and will continue to cancel any additional units repurchased under the repurchase program. We have funded repurchases, and intend to fund any future repurchases, from the proceeds of potential future sales of Regency Common Units. The use of these sales proceeds is expressly permitted under our Credit Agreement.
The following table sets forth certain information with respect to repurchases of common units during the three months ended December 31, 2014
Period
 
Total Number of Units Purchased
 
Average Price Paid Per Unit
 
Total Number of Units Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number (or Approximate Dollar Value) of Units that May Yet Be Purchased Under the Plan or Programs
October 1, 2014 to October 31, 2014
 

 
$

 

 
$
100,000,000

November 1, 2014 to November 30, 2014
 
1,520,297

 
$
3.09

 
1,460,987

 
$
95,512,225

December 1, 2014 to December 31, 2014
 
6,001,072

 
$
2.45

 
5,994,900

 
$
80,848,978

Total
 
7,521,369

 
$
2.58

 
7,455,887

 
$
80,848,978


The units not repurchased under the publicly announced program were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units. As a result, we are are including the units surrendered in the "Total Number of Units Purchased" column..

Sales of Unregistered Securities

We did not sell our equity securities in unregistered transactions during the twelve months ended December 31, 2014.

Common Unitholder Return Performance Presentation

The performance graph below compares the cumulative total unitholder return on our common units with the cumulative total returns on the Standard & Poor’s 500 Index (the “S&P 500 Index”) and our Peer Group Index (the "Peer Group") identified below. The Peer Group we used for this comparison included the following companies: Atlas Resource Partners, L.P., Breitburn Energy Partners, L.P., EV Energy Partners, L.P., Legacy Reserves LP, Linn Energy, LLC, LRR Energy, L.P., Mid-Con Energy Partners, LP, Memorial Production Partners LP, New Source Energy Partners L.P. and Vanguard Natural Resources, LLC. The graph assumes an investment of $100 in our common units, and in each of the S&P 500 Index and the Peer Group on December 31, 2009 and reinvestment of all dividends and distributions. The results shown in the graph are based on historical data and should not be considered indicative of future performance.


37


____________________________
Note: The above graph compares the cumulative total unitholder return on our common units assuming rights associated with Eagle Rock's Rights Offering were distributed effective May 27, 2010, the record date for the Rights Offering, and then immediately sold with the proceeds re-invested in Eagle Rock common units on the same day.

The information contained in the Performance Graph above will not be deemed to be "soliciting material" or to be "filed" with the SEC, nor will such information be incorporated by reference into any future filings of the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that we specifically incorporate it by reference into any such filing.

 Item 6.              Selected Financial Data.
 
The following table shows selected historical financial data from our audited consolidated financial statements for the five fiscal years from January 1, 2010 to December 31, 2014. The following financial data should be read in conjunction with our consolidated financial statements and the accompanying notes and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this report.
 
Our historical results of operations for the periods presented below may not be comparable either from period to period or going forward due to the following significant transactions:

On May 24, 2010, we completed the sale of all of our fee mineral and royalty interests, as well as our equity investment in Ivory Working Interests, L.P., (collectively "the Minerals Business") to Black Stone for approximately $171.6 million, and resulted in a pre-tax gain in the disposition of approximately $37.7 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility. Operations related to these assets for 2010 have been recorded as part of discontinued operations.

On June 30, 2010, we closed our rights offering, which was launched on June 1, 2010, for which we received gross proceeds of $53.9 million (the "Rights Offering"). We used these proceeds to pay down amounts outstanding under our senior secured credit facility.

On May 3, 2011, we completed the acquisition of all the outstanding membership interests of CC Energy II L.L.C. ("Crow Creek Energy") for total consideration of $563.7 million including 28.8 million common units valued at $336.1 million, debt assumed of $212.6 million and cash of approximately $15.0 million. As a result, financial results for the periods prior to May 3, 2011 do not include the financial results from these assets.

On May 27, 2011, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer, issued $300 million of 8 3/8% senior unsecured notes through a private placement. The Senior Notes will mature on June 1, 2019, and interest is payable on each June 1 and December 1, commencing December 1, 2011. These notes were exchanged for registered notes on February 15, 2012.


38


On May 31, 2012, we announced a program through which we may issue common units, from time to time, with an aggregate market value of $100 million. During 2012, we issued 834,327 common units under this program for net proceeds of approximately $7.3 million. During 2013, we issued 686,759 common units under this program for net proceeds of approximately $5.6 million. No sales were made under the program during 2014.

On July 13, 2012, the Partnership, along with Finance Corp, issued $250 million of Senior Notes through a private placement. This issuance supplemented our prior $300 million of Senior Notes issued in May 2011.

On August 17, 2012, we closed an underwritten public offering of 10,120,000 common units for net proceeds of approximately $84.3 million. The net proceeds were used to repay a portion of the outstanding borrowings under our revolving credit facility in advance of funding the Panhandle Acquisition.

On March 12, 2013, we closed an underwritten public offering of 10,350,000 common units for net proceeds of approximately $92.3 million.
On July 1, 2014, we contributed our Midstream Business to Regency. As a result of this transaction, the financial statements for all periods have been retrospectively restated to classify the operations of our Midstream Business as discontinued and the assets and liabilities related to our Midstream Business as held for sale.


39


 
Year Ended
December 31,
2014
 
Year Ended
December 31,
2013
 
Year Ended
December 31,
2012
 
Year Ended
December 31,
2011
 
Year Ended
December 31,
2010
 
($ in thousands, except distributions per unit)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Sales to external customers
$
203,773

 
$
201,309

 
$
203,205

 
$
204,310

 
$
94,735

Commodity risk management gains (losses), net
94,431

 
(3,937
)
 
28,110

 
37,269

 
(4,026
)
Total revenues
298,204

 
197,372

 
231,315

 
241,579

 
90,709

Operating and maintenance expense
43,670

 
41,426

 
41,391

 
32,287

 
24,007

Taxes other than income
12,925

 
12,928

 
15,343

 
15,436

 
8,764

General and administrative expense
47,193

 
53,131

 
50,990

 
42,525

 
34,512

Impairment expense
395,892

 
214,286

 
45,289

 
11,728

 
3,536

Depreciation, depletion and amortization
85,579

 
89,444

 
90,510

 
66,909

 
31,934

Operating (loss) income
(287,055
)
 
(213,843
)
 
(12,208
)
 
72,694

 
(12,044
)
Interest expense, net
16,981

 
19,893

 
21,003

 
22,246

 
31,861

Loss on short-term investments
62,028

 

 

 

 

Other expense (income)
(8,294
)
 
30

 
28

 
149

 
(453
)
(Loss) income from continuing operations before income taxes
(357,770
)
 
(233,766
)
 
(33,239
)
 
50,299

 
(43,452
)
Income tax benefit
(5,403
)
 
(5,595
)
 
(1,093
)
 
(3,350
)
 
(2,885
)
(Loss) income from continuing operations
(352,367
)
 
(228,171
)
 
(32,146
)
 
53,649

 
(40,567
)
Discontinued operations, net of tax
212,460

 
(49,808
)
 
(118,456
)
 
19,483

 
35,218

Net (loss) income
$
(139,907
)
 
$
(277,979
)
 
$
(150,602
)
 
$
73,132

 
$
(5,349
)
(Loss) income from continuing operations per common unit - diluted
$
(2.25
)
 
$
(1.50
)
 
$
(0.26
)
 
$
0.45

 
$
(0.49
)
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (at period end):
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
487,988

 
$
824,451

 
$
982,784

 
$
956,347

 
$
351,594

Total assets
$
794,275

 
$
2,127,550

 
$
2,294,216

 
$
2,045,688

 
$
1,349,397

Long-term debt
$
263,343

 
$
757,480

 
$
659,117

 
$
509,193

 
$
530,000

Net equity
$
388,470

 
$
573,879

 
$
868,374

 
$
1,007,347

 
$
579,113

 
 
 
 
 
 
 
 
 
 
Cash Flow Data:
 
 
 
 
 
 
 
 
 
Net cash flows provided by (used in):
 
 
 
 
 
 
 
 
 
Operating activities
$
78,126

 
$
114,243

 
$
75,336

 
$
60,419

 
$
6,716

Investing activities
$
(92,858
)
 
$
(149,868
)
 
$
(152,509
)
 
$
(297,264
)
 
$
141,310

Financing activities
$
(555,358
)
 
$
69,723

 
$
165,471

 
$
(9,834
)
 
$
(175,446
)
Discontinued operations
$
571,357

 
$
(34,047
)
 
$
(89,150
)
 
$
243,507

 
$
28,737

Other Financial Data:
 
 
 
 
 
 
 
 
 
Cash distributions per common unit (declared)
$
0.14

 
$
0.74

 
$
0.88

 
$
0.75

 
$
0.23

Adjusted EBITDA(a)
$
120,890

 
$
119,772

 
$
133,561

 
$
119,240

 
$
26,874

________________________
(a)
See Part II Item 6. Selected Financial Data – Non-GAAP Financial Measures for reconciliation of “Adjusted EBITDA” to net cash flows from operating activities and net income (loss).


40


Non-GAAP Financial Measures
 
We include in this report Adjusted EBITDA, a non-GAAP financial measure, which does not comply with accounting principles generally accepted in the United States ("GAAP"). We provide reconciliations of this non-GAAP financial measure to its most directly comparable financial measures as calculated and presented in accordance with GAAP.
 
We define Adjusted EBITDA as net income (loss) plus or (minus) income tax provision (benefit); interest-net, including gains and losses from interest rate risk management instruments that settled during the period and other expense; depreciation, depletion and amortization expense; impairment expense; other operating expense, non-recurring; other non-cash operating and general and administrative expenses, including non-cash compensation related to our equity-based compensation program; mark-to-market (gains) losses on commodity and interest rate risk management related instruments; gains (losses) on discontinued operations and other (income) expense.  

We use Adjusted EBITDA as a measure of our core profitability to assess the financial performance of our assets. Adjusted EBITDA is also used as a supplemental financial measure by external users of our financial statements such as investors, commercial banks and research analysts.  For example, the compliance covenant used by our lenders under our Credit Agreement which is designed to measure our viability and our ability to perform under the terms of our Credit Agreement uses a variant of our Adjusted EBITDA.  We believe that investors benefit from having access to the same financial measures that our management team uses in evaluating performance.  Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash, mark-to-market benefit (charge) which represents the change in fair market value of our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, we believe Adjusted EBITDA provides additional information of our ability to generate cash sufficient to pay interest costs, support our level of indebtedness, make cash distributions to our unitholders and general partner and finance our maintenance capital expenditures. We further believe that Adjusted EBITDA also provides additional information on the underlying performance of our operating assets by isolating the performance of our operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of our financial statements additional information on our current assets’ cash generation ability, independently from that of assets which are no longer a part of our operations. Our Adjusted EBITDA definition may not be comparable to Adjusted EBITDA or similarly titled measures as used by other entities, as other entities may not calculate Adjusted EBITDA in the same manner as us. For example, we include in Adjusted EBITDA the actual settlement revenue created from our commodity hedges by virtue of transactions occasionally undertaken by us to reset commodity hedges to higher prices or purchase puts or other similar floors, despite the fact that we exclude from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts. 

Adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate net income. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income (loss) and net cash flows provided by operating activities determined in accordance with GAAP, as well as Adjusted EBITDA, to evaluate our performance and liquidity.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows provided by operating activities or any other measure of financial performance presented in accordance with GAAP.


 

41


The following table provides a reconciliation of Adjusted EBITDA to net cash flows provided by operating activities and net income (loss):

 
Year Ended
December 31,
2014
 
Year Ended
December 31,
2013
 
Year Ended
December 31,
2012
 
Year Ended
December 31,
2011
 
Year Ended
December 31,
2010
 
($ in thousands)
Reconciliation of Adjusted EBITDA to net cash flows provided by (used in) operating activities and net (loss) income:
 
 
 
 
 
 
 
 
 
Net cash flows provided by (used in) operating activities
$
78,126

 
$
114,243

 
$
75,336

 
$
60,419

 
$
6,716

Add (deduct):
 
 
 
 
 
 
 
 
 
Discontinued operations, net of tax
212,460

 
(49,808
)
 
(118,456
)
 
19,483

 
35,218

Depreciation, depletion, amortization and impairment
(481,471
)
 
(303,730
)
 
(135,799
)
 
(78,637
)
 
(35,470
)
Amortization of debt issuance cost
(2,241
)
 
(2,151
)
 
(1,735
)
 
(1,621
)
 
(1,305
)
Gain (loss) from risk management activities, net
92,697

 
(5,041
)
 
23,383

 
25,868

 
(31,161
)
Derivative settlements - operating
(4,669
)
 
(7,478
)
 
(5,368
)
 
22,456

 
25,205

Other
(5,624
)
 
(9,119
)
 
(7,127
)
 
(1,954
)
 
(3,290
)
Loss on short-term investments
(62,028
)
 

 

 

 

Accounts receivable and other current assets
24,216

 
(16,118
)
 
24,655

 
(13,924
)
 
(5,039
)
Accounts payable and accrued liabilities
9,161

 
(774
)
 
(16,717
)
 
26,975

 
3,992

Risk management activities

 

 
6,607

 
15,773

 

Other assets and liabilities
(534
)
 
1,997

 
4,619

 
(1,706
)
 
(215
)
Net (loss) income
(139,907
)
 
(277,979
)
 
(150,602
)
 
73,132

 
(5,349
)
Add (deduct):
 
 
 
 
 
 
 
 
 
Interest expense, net
20,016

 
25,575

 
26,531

 
27,990

 
24,244

Depreciation, depletion, amortization and impairment
481,471

 
303,730

 
135,799

 
78,637

 
35,470

Income tax benefit
(5,403
)
 
(5,595
)
 
(1,093
)
 
(3,350
)
 
(2,885
)
EBITDA
356,177

 
45,731

 
10,635

 
176,409

 
51,480

Add (deduct):
 
 
 
 
 
 
 
 
 
(Gain) loss from risk management activities, net
(92,697
)
 
5,041

 
(23,383
)
 
(25,868
)
 
31,161

Total derivative settlements
(354
)
 
8,801

 
19,817

 
(16,189
)
 
(24,074
)
Restricted unit compensation expense
8,198

 
10,392

 
7,719

 
4,297

 
4,271

Non-cash mark-to-market imbalances
(2
)
 
(1
)
 
317

 
74

 
(746
)
Discontinued operations, net of tax
(212,460
)
 
49,808

 
118,456

 
(19,483
)
 
(35,218
)
Loss on short-term investments
62,028

 

 

 

 

ADJUSTED EBITDA(a)
$
120,890

 
$
119,772

 
$
133,561

 
$
119,240

 
$
26,874

________________________


(a)
Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the year ended December 31, 2010 of $2.2 million.  Including these amortization costs, our Adjusted EBITDA for the year ended December 31, 2010 would have been $24.7 million.
 

42


Quarterly Financial Data

The following table summarizes our quarterly financial data for 2014:

 
For the Quarters Ended
 
December 31, 2014
 
September 30, 2014
 
June 30, 2014
 
March 31, 2014
 
($ in thousands, except earnings per unit)
Sales of natural gas, NGLs, oil and condensate
$
43,115

 
$
53,626

 
$
51,967

 
$
55,084

Commodity risk management gains (losses), net
94,578

 
27,967

 
(18,081
)
 
(10,033
)
Other revenues
40

 
(369
)
 
158

 
152

Total revenues
137,733

 
81,224

 
34,044

 
45,203

Operating and maintenance expense
12,912

 
13,891

 
14,503

 
15,289

General and administrative expense
9,663

 
12,235

 
12,005

 
13,290

Depreciation, depletion, amortization and impairment expense
401,202

 
39,564

 
20,299

 
20,406

Interest expense, net
(2,357
)
 
(3,188
)
 
(4,948
)
 
(4,754
)
Interest rate risk management losses, net
(792
)
 
(81
)
 
(571
)
 
(290
)
Income tax benefit
(2,767
)
 
(886
)
 
(885
)
 
(865
)
Loss on short-term investments
(62,028
)
 

 

 

Other income (expense), net
4,211

 
4,080

 
2

 
1

Discontinued operations, net of tax
(348
)
 
249,057

 
(25,646
)
 
(10,603
)
Net (loss) income
$
(344,591
)
 
$
266,288

 
$
(43,041
)
 
$
(18,563
)
Net (loss) income per common unit - diluted
$
(2.21
)
 
$
1.67

 
$
(0.27
)
 
$
(0.12
)

During our fiscal year ended December 31, 2014, we recorded the following significant items:

During the quarter ended September 30, 2014, we completed the contribution of our Midstream Business to Regency. We classified the operations of our Midstream Business as discontinued and recorded a gain on the sale of $249.9 million.
During the quarters ended September 30, 2014 and December 31, 2014, we incurred impairment charges of $17.3 million and $378.6 million, respectively. See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview - Impairment for further discussion of our impairment charges during the year ended December 31, 2014.
A portion of the consideration received for the Midstream Business Contribution included Regency common units, which we have classified as short-term investments and available-for-sale. During the quarter ended December 31, 2014, we recorded a loss on short-term investments of $62.0 million, which consisted of $9.5 million of losses on sales of the common units and $52.5 million associated with the decrease in the fair value of Regency common units that was deemed to be other than temporary.
We experienced significant fluctuations in our mark-to-market commodity derivative gains and losses from quarter to quarter as a result of the volatility of commodity prices during 2014.  For example, we recorded mark-to-market gains of $26.7 million and $85.9 million during the quarters ended September 30, 2014 and December 31, 2014, respectively, while we recorded mark-to-market losses of $15.9 million and $6.9 million during the quarters ended June 30, 2014 and March 31, 2014, respectively. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – General Trends and Outlook – Natural Gas Supply and Demand and Crude Oil Supply, Demand and Outlook for further discussion regarding the volatility of commodity prices. 

43


The following table summarizes our quarterly financial data for 2013:
 
For the Quarters Ended
 
December 31, 2013
 
September 30, 2013
 
June 30, 2013
 
March 31, 2013
 
($ in thousands, except earnings per unit)
Sales of natural gas, NGLs, oil and condensate
$
51,233

 
$
53,318

 
$
49,252

 
$
46,805

Commodity risk management gains (losses), net
(3,561
)
 
(10,878
)
 
17,338

 
(6,836
)
Other revenues
83

 
45

 
76

 
497

Total revenues
47,755

 
42,485

 
66,666

 
40,466

Operating and maintenance expense
14,572

 
12,504

 
13,162

 
14,116

General and administrative expense
12,965

 
13,515

 
13,341

 
13,310

Depreciation, depletion, amortization and impairment expense
174,675

 
83,860

 
23,899

 
21,296

Interest expense, net
(4,578
)
 
(4,647
)
 
(4,499
)
 
(5,065
)
Interest rate risk management losses, net
(338
)
 
(459
)
 
(151
)
 
(156
)
Income tax benefit
(1,335
)
 
(2,155
)
 
(544
)
 
(1,561
)
Other income (expense), net
2

 
3

 
(27
)
 
(8
)
Discontinued operations, net of tax
(10,896
)
 
(21,223
)
 
3,901

 
(21,590
)
Net (loss) income
$
(168,932
)
 
$
(91,565
)
 
$
16,032

 
$
(33,514
)
(Loss) earnings per unit—diluted
$
(1.08
)
 
$
(0.59
)
 
$
0.10

 
$
(0.23
)

During our fiscal year ended December 31, 2013, we recorded the following significant items:.

During the quarters ended June 30, 2013, September 30, 2013 and December 31, 2013 we incurred impairment charges of $1.8 million, $61.4 million and $151.1 million, respectively. See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview - Impairment for further discussion of our impairment charges during the year ended December 31, 2013.

We experienced significant fluctuations in our mark-to-market commodity derivative gains and losses from quarter to quarter as a result of the volatility of commodity prices during 2013.  For example, we recorded mark-to-market gains of $13.5 million during the quarter ended June 30, 2013, while we recorded mark-to-market losses of $12.2 million, $13.7 million and $7.1 million during the quarters ended March 31, 2013, September 30, 2013 and December 31, 2013, respectively.  See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – General Trends and Outlook – Natural Gas Supply and Demand and Crude Oil Supply, Demand and Outlook for further discussion regarding the volatility of commodity prices. 

44


Item 7.                      Management's Discussion and Analysis of Financial Condition and Results of Operations.
 
The following discussion analyzes our financial condition and results of operations and should be read in conjunction with our historical consolidated financial statements and notes included elsewhere in this report.

OVERVIEW
 
Recent Developments

On July 1, 2014, we completed the contribution of our Midstream Business to Regency Energy Partners LP ("Regency"). The consideration received by us for the contribution of our Midstream Business included: (i) $576.2 million of cash; (ii) 8,245,859 Regency common units (valued at approximately $265.6 million based on the closing price of Regency common units on June 30, 2014) and (iii) the exchange of $498.9 million face amount of newly-issued Regency 8.375% Senior Notes due 2019 for $498.9 million face amount of our existing 8.375% Senior Notes. Accordingly, prior periods have been retrospectively adjusted to reflect the Midstream Business's assets and liabilities as held for sale and operations as discontinued (see Note 18) in the financial statements included in this report.

We used the cash received from Regency for the Midstream Business Contribution to paydown $570.4 million outstanding under the Credit Agreement. In addition, $51.1 million of our Senior Notes did not exchange in connection with the Midstream Business Contribution and remained outstanding following the contribution. However, having secured a sufficient number of consents as part of the exchange offer, we amended the indenture governing our Senior Notes to eliminate substantially all of the restrictive covenants and certain events of default pertaining to our Senior Notes. In October 2014 we amended the Credit Agreement to more of a traditional reserve-based facility with revised covenants and improved fee pricing.
Results Overview

As a result of the contribution of our Midstream Business, we are now a domestically-focused, growth-oriented, publicly traded Delaware master limited partnership engaged in developing and producing oil and natural gas property interests. Our interests include operated and non-operated wells located in the Mid-Continent (which includes areas in Oklahoma, Arkansas, and the Texas Panhandle); Permian (which includes areas in West Texas); East Texas; South Texas; Mississippi; and Alabama (which also includes one treating facility and one natural gas processing plant and related gathering system).   
 
Results for the year ended December 31, 2014, included the following:

revenues, excluding the impact of commodity risk management gains (losses) were $203.8 million for the year ended December 31, 2014, compared to $201.3 million for the year ended December 31, 2013;
commodity risk management gains were $94.4 million for the year ended December 31, 2014, compared to losses of $3.9 million for the year ended December 31, 2013;
impairment charges were $395.9 million for the year ended December 31, 2014, compared to $214.3 million for the year ended December 31, 2013;
operating losses were $287.1 million for the year ended December 31, 2014, compared to $213.8 million for the year ended December 31, 2013;
average daily production was 73 MMcfe/d for the year ended December 31, 2014 and 74 MMcfe/d for the year ended December 31, 2013; and
capital expenditures were $134.5 million for the year ended December 31, 2014, compared to $134.4 million for the year ended December 31, 2013.

Acquisitions

On December 9, 2014, we acquired certain additional interests in the Big Escambia Creek Field from LP 224 LLC. These interests are in wells in which we currently own significant interest and are nearly 100% operated by us.

On October 1, 2012, we completed the acquisition of BP America Production Company's ("BP") Texas Panhandle midstream assets (the "Panhandle Acquisition"), including the Sunray and Hemphill processing plants and associated 2,500

45


mile gathering system. The assets acquired and liabilities assumed as part of the Panhandle Acquisition have been classified as held for sale and the operations have been classified as discontinued.

Impairment
 
During the year ended December 31, 2014, we incurred impairment charges of $395.9 million primarily related to certain proved properties in all of our regions, but primarily our Golden Trend, Anadarko and Big Escambia Creek fields. The impairment charges were due primarily to lower commodity prices, higher operating costs and lower well performance. During the year ended December 31, 2013, we recorded an impairment in our Upstream Business of $207.1 million, primarily related to certain proved properties in the Cana Shale in the Mid-Continent region and Permian region due to lower reserve forecasts. We also incurred an impairment of $7.2 million for certain leaseholds in our Mid-Continent region unproved properties that we expected to expire undrilled in 2014. During the year ended December 31, 2014, we recorded an impairment charge of $2.1 million in our Midstream Business due to the loss of two customers on the North System. During the year ended December 31, 2013, we recorded no impairment charges in our Midstream Business. Impairment charges related to our Midstream Business have been recorded as part of discontinued operations within the statements of operations.  Continued declines in oil and natural gas prices from the December 31, 2014 prices may cause us to incur additional impairment charges in the future, which could have a material adverse effect on our results of operations and financial position in the periods in which such charges are taken.

Pursuant to GAAP, our impairment analysis does not take into account the value of our commodity derivative instruments, which generally increase as the estimates of future prices decline.  To calculate the estimated cash flows used in our impairment tests, we use the forward strip prices as of the date of the impairment.  Further declines in commodity prices and other factors could result in additional impairment charges and changes to the fair value of our derivative instruments.

General Trends and Outlook
 
We expect our business to be affected by the following key trends. This expectation is based on assumptions made by us and information currently available to us; however, our actual results may vary materially from our expectations.

Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and are expected to be volatile in the future. In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we have entered into commodity derivative contracts, and we intend to enter into commodity derivative contracts in the future, to reduce cash flow volatility.
 
Since 2006, the United States has experienced significant growth in natural gas production due to drilling for gas in shale plays and the production of associated gas from wells drilled in liquids-rich shale and other unconventional plays. We believe that continued increases in natural gas production due to ongoing development of domestic oil and gas shale resources will result in sustained low prices unless significant new sources of demand arise, such as additional fuel switching in the electrical power generation industry or the export of natural gas to other markets in the form of LNG. The U.S. Energy Information Administration ("EIA") expects the Henry Hub natural gas spot price to average $3.44/MMBtu in 2015 and $3.86/MMBtu in 2016, down from $4.39/MMBtu in 2014.

Since 2000, worldwide petroleum supply has grown at a modest pace, with almost all of the growth explained by production increases in Saudi Arabia, Russia, Kazakhstan, the United States and Canada. The dramatic growth in United States production is attributable to the development of vast oil and liquids-rich shale plays that require much higher prices to remain viable than do Middle Eastern reserves. In the fourth quarter of 2014, the Saudi Arabian Oil Minister announced his country's intention to no longer attempt to maintain the global oil supply/demand balance by reducing its production of oil, either alone or in concert with other OPEC members. This announcement resulted in an immediate and significant reduction in the price of West Texas Intermediate ("WTI"). If Saudi Arabia adheres to this policy, we believe that the current oversupply of crude oil will persist until drilling in high-cost areas slows and the production decline eliminates the imbalance. The EIA forecasts that West Texas Intermediate prices will average $54 - $55/Bbl in 2015 and $71 - $72/Bbl in 2016.
 
The high level of liquids-directed drilling in the United States has resulted in significant increases in the supply of NGLs while demand for the products has remained relatively stable. As a result, NGL prices were low by recent historical standards in 2014. Historically, natural gas liquids prices have tended to have a high correlation to crude oil prices, especially for propane and heavier NGLs. This correlation has weakened in the last few years, but is still somewhat present. Accordingly, the recent precipitous fall in the price of oil was accompanied by a somewhat larger decline in the prices of many NGLs. We believe that NGL prices are likely to stay low during 2015.

46


 
Much of the natural gas that we produce in the East Texas and Alabama regions contains high, naturally-occurring concentrations of hydrogen sulfide ("sulfur"). The primary use of sulfur is in the manufacture of phosphate fertilizers, therefore one of the major factors influencing the demand for sulfur is the demand for fertilizer. As with many commodities, developing economies are responsible for much of the global demand growth for fertilizer. We expect sulfur supply and demand to be in balance in 2015 and for prices to remain at or slightly below their current levels. Sulfur prices at Tampa in 2014 reached a high of almost $140 per long ton in the third quarter of 2014 and averaged $129 per long ton in the fourth quarter of 2014.
  

How We Evaluate Our Operations
 
Our management uses a variety of financial and operational measures to analyze our performance. We view these measures as important indicators of our profitability and review these measures on a monthly basis for consistency and trend analysis. These measures include volumes, net revenues, operating expenses and Adjusted EBITDA (defined in Part II, Item 6. Selected Financial Data) from our continuing operations.
 
Volumes
 
We continually monitor the production rates of operated wells and significant non-operated wells. This information is a critical indicator of the performance of our wells, and we evaluate and respond to any significant adverse changes. We employ an experienced team of engineering and operations professionals to monitor these rates on a well-by-well basis and to design and implement remediation activities when necessary. We also design and implement workover and drilling operations to increase production in order to offset the natural decline of our currently producing wells. Because our rates of return on new drilling activity are determined in part on commodity prices, we may elect to scale back or cancel such activity during periods of low commodity prices, such as the one we are currently experiencing. Furthermore, we may elect to shut-in existing production in extreme commodity downturns (i.e., when the realized prices we receive are below our operating costs on a per unit basis).

Net Revenues
 
Commodity Pricing.  Our revenues generally will correlate with changes in crude oil, natural gas, NGL and sulfur prices.
 
Risk Management.  We conduct risk management activities to mitigate the effect of commodity price and interest rate fluctuations on our cash flows. Our primary method of risk management in this respect is entering into derivative contracts. For a further discussion of our risk management activities, see Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
 
Operating Expenses
 
We monitor and evaluate our costs routinely, both on a total cost and unit cost basis. Many of the operating costs we incur are not directly related to the quantity of hydrocarbons that we produce, so we strive to maximize our production rates in order to improve our unit operating costs. The most significant portion of our operating costs is associated with the operation of the Big Escambia Creek treating and processing facilities. These facilities are overseen by members of our engineering and operations staff. The majority of the cost of operating these facilities is independent of their throughput. This includes items such as labor, chemicals, utilities and materials.