Annual Report (10-k)

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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



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.

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TABLE OF CONTENTS



		Page
PART I
Item 1.	Business	3
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	35
Item 4.	Mine Safety Disclosures	35
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	36
Item 6.	Selected Financial Data	38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	45
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	63
Item 8.	Financial Statements and Supplementary Data	66
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	66
Item 9A.	Controls and Procedures	66
Item 9B.	Other Information	68
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	69
Item 11.	Executive Compensation	69
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	69
Item 13.	Certain Relationships and Related Transactions, and Director Independence	69
Item 14.	Principal Accounting Fees and Services	69
PART IV
Item 15.	Exhibits and Financial Statement Schedules	69

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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.

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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.

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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

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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.

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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
Closing Date	Transactions	Amount ($ in Millions)		Cash		Debt		Equity		Cash from equity offerings		Segment
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.

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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.

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The following table summarizes our producing properties by region:



Region	Average net daily production			Gross productive wells
Region	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

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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

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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

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$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. 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.

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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

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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

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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.

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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.

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____________________________

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.

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•

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.

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	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

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(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).

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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.

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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.

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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.

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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.

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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

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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.

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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.

Adjusted EBITDA

See discussion of Adjusted EBITDA in Part II, Item 6. Selected Financial Data.

Critical Accounting Policies and Estimates

Conformity with GAAP requires management to make estimates and judgments that affect the amounts reported in the financial statements and notes. On an ongoing basis, we make and evaluate estimates and judgments based on management's best available knowledge of previous, current, and expected future events. We base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and estimates are subject to change due to modifications in the underlying conditions or assumptions. Currently, we do not foresee any reasonably likely changes to our current estimates and assumptions which would materially affect amounts

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reported in the financial statements and notes. Below are expanded discussions of our more significant accounting policies, estimates and judgments, i.e., those that reflect more significant estimates and assumptions used in the preparation of our financial statements. See Note 2 to our consolidated financial statements for details about additional accounting policies and estimates made by management.

Successful Efforts. We utilize the successful efforts method of accounting for our oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Unproved properties are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well as long as we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. GAAP authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves (developed and undeveloped) and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves. Since our units of production depletion and amortization rate are a function of our proved reserves, we experience a higher depletion and amortization rate than we would if we claimed undeveloped or non-producing reserves.

Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.

We assess proved oil and natural gas properties for possible impairment when events or circumstances indicate that the recorded carrying value of the properties may not be pre-tax recoverable. We recognize an impairment loss as a result of a triggering event and when the estimated undiscounted pre-tax future cash flows from a property are less than the carrying value. If impairment is indicated, the fair value is compared to the carrying value for determining the amount of the impairment loss to record. Estimated future cash flows are based on management's expectations for the future and include estimates of oil and natural gas reserves and future commodity prices and operating costs. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate property impairment.

Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience, drilling plans and average lease-term lives. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units of production basis. Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.

Our estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. Annually, and on other occasions, Cawley, Gillespie & Associates, Inc. prepares an estimate of the proved reserves on all our properties, based on information provided by us.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described herein adheres to the same guidelines when preparing their reserve reports. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas, natural gas liquids and oil eventually recovered.

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Risk Management Activities. We have structured our hedging activities in order to minimize our commodity pricing and interest rate risks and to help maintain compliance with certain financial covenants in our revolving credit facility. These hedging activities rely upon forecasts of our expected operations and financial structure over the next few years. If our operations or financial structure are significantly different from these forecasts, we could be subject to adverse financial results as a result of these hedging activities. We mitigate this potential exposure by retaining an operational cushion between our forecasted transactions and the level of hedging activity executed. Based on our current production estimates, we have hedged approximately 85% of our 2015 expected crude and condensate production, 75% of our expected natural gas and ethane production and 20% of our expected natural gas liquids (heavier than ethane) production.

From the inception of our hedging program, we used mark-to-market accounting for our commodity hedges and interest rate swaps. We record monthly gains and losses on hedge instruments based upon cash settlement information. The settlement amounts vary due to the volatility in the commodity market prices throughout each month. We also record mark-to-market gains and losses monthly based upon the future value through their expiration dates. The expiration dates vary but are currently no later than December 2019 for our interest rate hedges and December 2019 for our commodity hedges. We monitor and review hedging positions regularly.

Impairment of Long-Lived Assets. We assess our long-lived assets for impairment whenever events or changes in circumstances indicate its carrying amount may not be recoverable.

Examples of events or changes in circumstances include:


•	a significant decrease in the market price of a long-lived asset or asset group;


•	a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;


•	a significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;


•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset or asset group;


•	a current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and


•	a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

The carrying value of a long-lived asset is determined to not be recoverable when the carrying value of a long-lived asset exceeds our estimate of the undiscounted cash flows (calculated using the forward strip prices as of the date of the impairment test) expected to result from the use and eventual disposition of the long-lived asset. If the carrying value of a long-lived asset is determined not to be recoverable, the impairment loss is measured as the excess of the carrying value over its fair value.

Asset Retirement Obligations. The recognition of an asset retirement obligation requires that management make numerous estimates, assumptions and judgments regarding such factors as costs of remediation, timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. In periods subsequent to initial measurement of the asset retirement obligation, we must recognize period-to-period changes in the liability resulting from changes in the timing of settlement to changes in the estimate of the costs of remediation. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis and an adjustment in our depreciation, depletion and amortization expense in future periods.

Presentation of Financial Information

For a description of the presentation of our financial information in this report, please see Part II, Item 6. Selected Financial Data.

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Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the years ended December 31, 2014, 2013 and 2012.



		Year Ended December 31,
		2014			2013			2012
	($ in thousands)
Revenues:
Oil and condensate		$	105,122		$	106,752		$	101,424
Natural gas		51,252			45,222			42,444
Natural gas liquids		39,177			40,583			43,831
Sulfur		8,241			8,051			14,020
Commodity risk management gains (losses), net		94,431			(3,937		)	28,110
Other revenue		(19		)	701			1,486
Total revenues		298,204			197,372			231,315
Costs and expenses:
Operations and maintenance		43,670			41,426			41,391
Taxes other than income		12,925			12,928			15,343
General and administrative		47,193			53,131			50,990
Impairment		395,892			214,286			45,289
Depreciation, depletion and amortization		85,579			89,444			90,510
Total costs and expenses		585,259			411,215			243,523
Operating loss		(287,055		)	(213,843		)	(12,208		)
Other income (expense):
Interest expense, net		(15,247		)	(18,789		)	(16,276		)
Interest rate risk management losses, net		(1,734		)	(1,104		)	(4,727		)
Loss on short-term investments		(62,028		)	—			—
Other income (expense), net		8,294			(30		)	(28		)
Total other expense		(70,715		)	(19,923		)	(21,031		)
Loss from continuing operations before income taxes		(357,770		)	(233,766		)	(33,239		)
Income tax expense (benefit)		(5,403		)	(5,595		)	(1,093		)
Loss from continuing operations		(352,367		)	(228,171		)	(32,146		)
Discontinued operations, net of tax		212,460			(49,808		)	(118,456		)
Net loss		$	(139,907	)	$	(277,979	)	$	(150,602	)
Adjusted EBITDA(a)		$	120,890		$	119,772		$	133,561

________________________


(a)	See "Part II, Item 6. Selected Financial Data - Non-GAAP Financial Measures" for a definition and reconciliation to GAAP.

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	Year Ended December 31,
	2014		2013		2012

Realized average prices:
Oil and condensate (per Bbl)	$	80.07	$	87.34	$	85.65
Natural gas (per Mcf)	$	4.27	$	3.53	$	2.58
NGLs (per Bbl)	$	33.83	$	35.12	$	39.12
Sulfur (per Long ton)	$	84.94	$	76.38	$	137.46
Production volumes:
Oil and condensate (Bbl)	1,312,749		1,222,270		1,184,200
Natural gas (Mcf)	11,995,478		12,804,475		16,442,579
NGLs (Bbl)	1,158,158		1,155,639		1,120,522
Total (Mcfe)	26,820,920		27,071,929		30,270,911
Sulfur (Long ton)	97,033		105,394		102,002

Capital expenditures	$	134,510	$	134,435	$	163,975

Year Ended December 31, 2014 Compared with Year Ended December 31, 2013

Production Revenues. For the year ended December 31, 2014, our production revenues, which exclude commodity risk management gains (losses), increased by $2.5 million as compared to the year ended December 31, 2013. The increase in revenues was due to higher oil and condensate volumes and higher natural gas and sulfur prices, partially offset by lower natural gas, NGL and sulfur volumes and lower oil and condensate and NGL prices for the year ended December 31, 2014, compared to the year ended December 31, 2013.

Production volumes during the year ended December 31, 2014 were negatively impacted by performance on our Alabama wells due to increases in completion times as well as declines in production on our Mid-Continent wells due to offsetting fracing on other wells and delays in completions for both operated and non-operated wells.

Commodity Risk Management Gains (Losses), net. During the year ended December 31, 2014, our commodity risk management gains increased by $98.4 million, as compared to the year ended December 31, 2013. During the year ended December 31, 2014, our gains due to the change in the mark-to-market value of our derivative contracts increased by $109.3 million, as compared to the year ended December 31, 2013, due to decreases in the natural gas, NGL and crude oil forward curves, especially in the fourth quarter of 2014 when West Texas Intermediate oil prices fell 37% from September 30, 2014 to December 31, 2014. Our commodity risk management gains from derivative contracts that settled during the year ended December 31, 2014 decreased $10.9 million, as compared to the year ended December 31, 2013. This decrease was due to higher natural gas and crude oil index prices, primarily during the first half of 2014, in relation to the strike prices of our settled contracts, as compared to the same period in the prior year.

Given the uncertainty surrounding future commodity prices, and the general inability to predict future commodity prices as they relate to the strike prices at which we have hedged our exposure, it is difficult to predict the magnitude and impact that marking our hedges to market will have on our income from operations in future periods.

Operating Expenses (Including Taxes Other Than Income). Operating expenses, including taxes other than income, increased by $2.2 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013. The increase was primarily due to increased post-production costs, increased plant operating expense and higher lease operating costs due to additional wells drilled.

Taxes Other Than Income. Taxes other than income, which includes severance and ad valorem taxes, for the year ended December 31, 2014 was consistent with the amount for the the year ended December 31, 2013.

General and Administrative Expenses. General and administrative expenses decreased by $5.9 million for the year ended December 31, 2014 as compared to the same period in 2013. This decrease was primarily due to lower compensation and benefit expenses due to the reduction in headcount as a result of the Midstream Business Contribution and lower equity based compensation expense due to an increase made to the estimated forfeiture rate during the year ended December 31, 2014. The forfeiture rate is used to calculate the amount of equity based compensation expense.

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Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $3.9 million for the year ended December 31, 2014 as compared to the same period in 2013. The decrease was primarily a result of the impairment charges recorded during 2013 and overall decrease in production for the year ended December 31, 2014 as compared to the same period in 2013.

Impairment. During the year ended December 31, 2014, we recorded impairment charges of $395.9 million related to certain proved properties in all of our regions due primarily to lower commodity prices, higher operating costs and lower well performance. During the year ended December 31, 2013, we incurred impairment and other charges of $214.3 million 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 expected to expire undrilled in 2014.

Total Other Income (Expense). Total other income (expense) primarily consisted of distributions from Regency related to the units we hold as a short-term investment and gains and losses from our interest rate swaps and interest expense related to our senior secured credit facility and our senior notes. During the year ended December 31, 2014, we received total distributions of $8.0 million. During the year ended December 31, 2014, our interest rate risk management losses increased by $0.6 million as compared to the year ended December 31, 2013, due to decreases in the forward interest rate curve.

Interest Expense. Interest expense decreased by $3.5 million during the year ended December 31, 2014, as compared to the year ended December 31, 2013. Interest expense is shown before the impact of our interest rate derivatives, which convert a portion of our outstanding debt from variable-rate interest obligations to fixed-rate interest obligations. The decrease in interest expense is primarily due to the repayment of borrowings outstanding under our revolving credit facility.

Loss on Short-term Investments. During the year ended December 31, 2014, we incurred a loss on short-term investments related to the Regency common units we received as partial consideration for the Midstream Business Contribution. This loss consists of $9.5 million as a result of a losses on sale of the common units and $52.5 million as a result of a decrease in the fair value of the common units that was deemed to be other than temporary.

Income Tax Expense (Benefit) Provision. Income tax provision for 2014 and 2013 relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock Energy Acquisition Co., Inc. and Eagle Rock Energy Acquisition Co. II, Inc. and their wholly owned subsidiary corporations, Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., which are each subject to federal income taxes.

Discontinued Operations. On July 1, 2014, we completed the contribution of our Midstream Business to Regency. We have classified the assets and liabilities of our Midstream Business as held for sale and the operations as discontinued. Discontinued operations increased by $262.3 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013. The increase in discontinued operations for the year ended December 31, 2014 is primarily due to the gain on sale of the Midstream Business of $243.6 million. In addition, included within discontinued operations for the year ended December 31, 2014 are professional fees of $10.6 million and one-time termination benefits of $4.0 million. See Note 18 to the consolidated financial statements for the major line items that comprise discontinued operations.

Capital Expenditures. Capital expenditures increased by $0.1 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013. Changes in capital expenditures are primarily due to our drilling program.

During the year ended December 31, 2014, we drilled and completed 12 operated wells in the Mid-Continent and Alabama regions and participated with a working interest in 15 non-operated wells drilled and completed in the Mid-Continent region. Additionally, during the year ended December 31, 2014, we conducted seven recompletions, fifteen capital workovers and seven expense workovers across our operations.

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Adjusted EBITDA. Adjusted EBITDA, as defined under Item 6. Selected Financial Data - Non-GAAP Financial Measures, from continuing operations decreased by $1.1 million from $119.8 million for the year ended December 31, 2013 to $120.9 million for the year ended December 31, 2014. The following table presents the changes in operations impacting Adjusted EBITDA:



	Year Ended December 31,
	2014		2013		Change
	($ in thousands)
Revenues (a)	$	203,771	$	201,308	$	2,463
Commodity derivative settlements	4,669		15,557		(10,888		)
Operating expenses	56,595		54,354		(2,241		)
General and administrative expenses (b)	38,995		42,739		3,744
Distributions received from Regency	8,040		—		8,040
Adjusted EBITDA (c)	$	120,890	$	119,772	$	1,118

_________________________


(a)	Excludes the impact of imbalances.


(b)	Excludes non-cash compensation charges related to our long-term incentive program.


(c)	See "Part II, Item 6. Selected Financial Data - Non-GAAP Financial Measures" for a definition and reconciliation to GAAP.

Year Ended December 31, 2013 Compared with Year Ended December 31, 2012

Production Revenue. For the year ended December 31, 2013, production revenues decreased by $1.9 million as compared to the year ended December 31, 2012. The decrease in revenues was due to the sale of our Barnett properties, lower natural gas volumes, and lower NGL and sulfur prices, partially offset by higher oil and NGL volumes, and higher oil and natural gas prices for the year ended December 31, 2013, compared to the year ended December 31, 2012. Volumes during the year ended December 31, 2013, were negatively impacted by suspended operations at our Flomaton separation and treating facility, increased natural gas fuel consumption at our Big Escambia Creek treating and processing facility, higher than expected decline rates from our 2012 Cana Shale program wells, production delays associated with extended drilling time for certain wells in the Mid-Continent, an unsuccessful development well in the Mid-Continent and less than expected volumes from our Mid-Continent and Permian recompletion projects. Golden Trend and Southeast Cana volumes during the year ended December 31, 2013 were negatively impacted by a third-party processing plant being shutdown for eight days in September 2013. Volumes returned to normal production levels during the month of September. During November and December 2013, revenues were negatively impacted by approximately $1.2 million due to weather related events.

On February 7, 2013, we suspended operations at our Flomaton treating facility in Escambia County, Alabama due to the failure of certain plant equipment and inlet volumes that were insufficient to operate the facility's sulfur recovery unit. To increase inlet volumes of the field to operate the treating facility we attempted to restore production from two wells connected to the facility, but these operations were unsuccessful. We resumed facility operations on April 18, 2013, after repairing the equipment and increasing inlet volumes by diverting production from a nearby operated well; however, on May 24, 2013, we again suspended operations due to equipment failure at the treating facility. We estimate that during the year ended December 31, 2013, we lost revenues of approximately $1.2 million and incurred increased facility expenses of $0.2 million. During the first three months of 2013, we incurred increased operating expenses of approximately $2.4 million related to the production restoration attempts. On July 31, 2013, we received approval from the required percentage of owners of the Big Escambia Creek and Flomaton plants to resume operations by re-routing gas from the Flomaton facility to our Big Escambia Creek facility for treating and processing, while continuing to stabilize and sell the Flomaton field condensate at the Flomaton facility.

In August 2010, our East Texas oil and natural gas production was temporarily shut-in due to an unscheduled shut-down of the Eustace processing facility owned and operated by a third-party. The shut-in negatively impacted our net revenues from January 1, 2011 to March 11, 2011, the date the plant was brought back into service. During the year ended December 31, 2012, we received an $0.8 million settlement from the third-party operator related to this incident, which was recorded as other revenue.

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During the year ended December 31, 2012, we completed the following turnarounds at our Alabama processing facilities to make certain repairs and routine inspections of equipment.null

•In March 2012, our Flomaton facility was shut-down for approximately twelve days.


•	In May and June 2012, our Big Escambia Creek facility was shut-down for approximately eight and seven days, respectively.


•	In November and December 2012, our Big Escambia Creek facility was shut-down for 24 days, during which time we also installed a new Superclaus reactor within our existing sulfur recovery unit, which was required to reduce the facilities' SO2 emissions.

As a result of these turnarounds, and the shutting-in of wells within the fields that supply natural gas to the processing plants, we estimate the revenue impact due to the loss of production was $8.7 million and that we incurred additional operating expenses of approximately $2.8 million during the year ended December 31, 2012. In addition, these turnarounds reduced our production by approximately 759 MMcfe and 6,799 long ton of sulfur.

Commodity Risk Management Gains (Losses), net. During the year ended December 31, 2013, our commodity risk management gains increased by $32.0 million, as compared to the year ended December 31, 2012. During the year ended December 31, 2013, our losses due to the change in the mark-to-market value of our derivative contracts increased by $17.6 million, as compared to the year ended December 31, 2012, due to increases in the natural gas, NGL and crude oil forward curves. Our gains from derivative contracts that settled during the year ended December 31, 2013 decreased $14.5 million, as compared to the year ended December 31, 2012. This decrease was due to higher natural gas and crude oil index prices, partially offset by lower NGL index prices, in relation to the strike prices of our settled contracts, as compared to the same period in the prior year. In addition, the decrease was due to the higher level of direct NGL product contracts that settled during the year ended December 31, 2012, as compared to the same period in 2013.

Operating Expenses. Operating expenses increased by less than $0.1 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012.

Taxes Other Than Income. Taxes other than income, which includes severance and ad valorem taxes, decreased by $2.4 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012. The decrease was primarily due to the sale of our Barnett Shale properties, lower severance taxes resulting from decreased sales and from a refund received from the state of Oklahoma for taxes paid in prior years.

General and Administrative Expenses. General and administrative expenses increased by $2.1 million for the year ended December 31, 2013 as compared to the same period in 2012. This increase was primarily due to higher salaries and benefits, which was due to increased equity compensation expense due to additional grants as well as increased professional fees.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $1.3 million for the year ended December 31, 2013 as compared to the same period in 2012. The decrease was primarily a result of the sale of our Barnett Shale properties and impairment charges recorded during due to depletion and amortization expense incurred during the year ended December 31, 2013 for the properties acquired in the Mid-Continent Acquisition, partially offset by decreases as a result of the impairment charge recorded during 2013 and 2012.

Impairment and Other. During the year ended December 31, 2013, we recorded an impairment charge of $214.3 million due 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 expected to expire undrilled in 2014. During the year ended December 31, 2012, we incurred impairment and other charges of $45.3 million due to (i) certain unproved property leaseholds that we expected to expire undrilled in 2013 and (ii) our proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing relatively high operating costs associated with gas compression. In addition, we recorded a loss on the sale of our properties in the Barnett Shale in 2012.

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Total Other Expense. Total other expense primarily consisted of gains and losses from our interest rate swaps and interest expense related to our senior secured credit facility and our senior unsecured notes. During July 2012, in conjunction with our issuance of $250.0 million of senior unsecured notes, which increased our fixed interest rate exposure, we terminated the full $200.0 million notional amount of our existing 4.295% and 4.095% fixed rate interest rate swaps. During the year ended December 31, 2013, our interest rate risk management losses decreased by $3.6 million as compared to the year ended December 31, 2012, primarily due to the transactions described above and as a result of a decrease in the forward interest rate curves. Mark-to-market losses from our interest rate risk management activities do not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.

Interest expense, net increased by $2.5 million during the year ended December 31, 2013 as compared to the year ended December 31, 2012. Interest expense is shown before the impact of our interest rate derivatives, which convert a portion of our outstanding debt from variable-rate interest obligations to fixed-rate interest obligations. The increase in interest expense is due to the issuance of the senior unsecured notes, described above, along with increased borrowings under our revolving credit facility.

Income Tax (Benefit) Provision. Income tax provision for 2013 and 2012 relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock Energy Acquisition Co., Inc. and Eagle Rock Energy Acquisition Co. II, Inc. and their wholly owned subsidiary corporations, Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., which are each subject to federal income taxes.

Discontinued Operations. On July 1, 2014, we completed the contribution of our Midstream Business to Regency, and as a result, we have classified the assets and liabilities as held for sale and the operations as discontinued. For the year ended December 31, 2013, the loss from discontinued operations decreased by $70.2 million compared to the year ended December 31, 2012. The decrease was primarily due to impairment charges incurred within our Midstream Business during the year ended December 31, 2012. We did not incur any impairment charges in our Midstream Business during the year ended December 31, 2013. This decrease was offset by commodity risk management losses incurred during the year ended December 31, 2013 compared to commodity risk management gains incurred during the year ended December 31, 2012. In addition, discontinued operations during the year ended December 31, 2013 includes approximately $4.7 million of accounting, legal and advisory services expenses related to the contribution of our Midstream Business to Regency.

Capital Expenditures. Capital expenditures decreased by $29.5 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012. During the year ended December 31, 2013, we drilled and completed thirteen gross operated wells and participated in thirty-one gross non-operated wells and drilled and abandoned one unproductive well on leases in the Mid-Continent region. Additionally, during the year ended December 31, 2013, we conducted ten recompletions, twenty-four capital workovers and eight expense workovers across our operations.

Adjusted EBITDA. Adjusted EBITDA, as defined under Item 6. Selected Financial Data - Non-GAAP Financial Measures, from continuing operations decreased by $13.8 million from $133.6 million for the year ended December 31, 2012 to $119.8 million for the year ended December 31, 2013. The following table presents the changes in operations impacting Adjusted EBITDA:



	Year Ended December 31,
	2013		2012		Change
	($ in thousands)
Revenues (a)	$	201,308	$	203,522	$	(2,214	)
Commodity derivative settlements	15,557		30,044		(14,487		)
Operating expenses	54,354		56,734		2,380
General and administrative expenses (b)	42,739		43,271		532
Adjusted EBITDA (c)	$	119,772	$	133,561	$	(13,789	)

_________________________


(a)	Excludes the impact of imbalances


(b)	Excludes non-cash compensation charges related to our long-term incentive program.


(c)	See "Part II, Item 6. Selected Financial Data - Non-GAAP Financial Measures" for a definition and reconciliation to GAAP.

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LIQUIDITY AND CAPITAL RESOURCES

Historically, our sources of liquidity have included cash generated from operations, issuances of equity and debt securities, borrowings under our Credit Agreement and asset sales. Our primary cash requirements have included general and administrative expenses, operating expenses, maintenance and growth capital expenditures, short-term working capital needs, interest payments on our outstanding debt, distributions to our unitholders and acquisitions of new assets or businesses.

In connection with the consummation of the Midstream Business Contribution, we were able to improve our liquidity position by paying down our borrowings under our Credit Agreement, resulting in increased borrowing availability, and exchanging $498.9 million face amount of our outstanding senior notes, resulting in significantly decreased debt levels. In addition, we received 8,245,859 Regency common units as part of the consideration received for the Midstream Business Contribution. During the fourth quarter of 2014, we sold 1,852,202 Regency common units for net proceeds of $50.1 million and in 2015, we sold an additional 2,389,732 Regency common units through February 26, 2015 for net proceeds of $56.3 million. As of February 26, 2015, we still held 4,003,925 Regency common units (valued at approximately $95.8 million (based on the closing price of Regency common units on February 26, 2015), the ongoing sales of which will provide additional liquidity.

We believe that our improved liquidity position as a result of the Midstream Business Contribution and our historical sources of liquidity will be sufficient to satisfy our short-term liquidity needs and to fund our committed capital expenditures for at least the next twelve months. Our growth strategy entails pursuing attractive upstream acquisitions and organic drilling opportunities. We may utilize any of various available financing sources, including liquidity from the consummation of the Midstream Business Contribution, proceeds from the issuance of equity or debt securities, sales of Regency common units or borrowings from our Credit Agreement to fund all or a portion of our potential acquisitions and organic growth expenditures. Our ability to complete future offerings of equity or debt securities, sales of Regency common units and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition. As of February 26, 2015, our total liquidity was approximately $231 million, comprised of $135 million of availability under our senior secured credit facility and 4.0 million Regency units valued at approximately $96 million.

Capital Expenditures

The energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as (and, as necessary, allocate the attributable portion of our capital expenditures between) either:


•	growth capital expenditures, defined as expenditures to grow our natural gas, NGL, crude or sulfur production; or


•	maintenance capital expenditures, defined as expenditures necessary to maintain our natural gas, NGL, crude or sulfur production.

With respect to maintenance capital expenditures intended to maintain our natural gas, NGL, crude or sulfur production, we estimate these amounts based on current projections and expectations, and do not undertake to adjust any historical amounts based on the actual impact of such expenditures on production. As a result, the included amount of maintenance capital expenditures could fail to maintain production if actual performance does not meet our projections and expectations, including, without limitation, on account of: (i) unanticipated mechanical issues; (ii) unanticipated delays; (iii) poorer than expected production performance of our new wells and recompletions; and/or (iv) unanticipated loss of, or higher than anticipated decline in, existing production.

The primary impact of this categorization is that we reduce the amount of cash we consider available for distribution by the amount of our maintenance capital expenditures.

Our current 2015 capital budget anticipates that we will spend approximately $72.4 million in total, of which $18.1 million related to growth capital expenditures and $54.3 million related to maintenance capital expenditures. We anticipate that our capital spending will be made ratably throughout 2015. Our capital budget expectations could be adjusted up or down in the event of further declines or increases in applicable commodity prices.

Our capital expenditures, excluding amounts related to our Midstream Business, were approximately $134.5 million million for the year ended December 31, 2014, of which $58.5 million million related to maintenance capital expenditures and $76.1 million million related to growth capital expenditures.

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In order to lower sulfur dioxide ("SO₂") emissions from our Big Escambia Creek processing facility in Alabama, as required by our existing air emissions permit, our operating subsidiary initiated the first phase of an SO₂ emissions reduction project at our Big Escambia Creek processing facility in December 2011. This phase of the project involved adding a Superclaus reactor to the existing sulfur recovery unit to achieve the desired reduction in SO₂ emissions. The new unit began operations on December 17, 2012, and through December 31, 2014 had resulted in increased sulfur production and reductions in SO₂ emissions to levels within the required permitted levels.

The second and final phase of our SO₂ emissions reduction project involves replacing or upgrading certain components of our existing sulfur recovery unit at the Big Escambia Creek processing facility. This phase is designed to improve the operational reliability of the processing facility, further increase the quantity of marketable sulfur recovered from the inlet gas stream, reduce the frequency of facility turnarounds, extend the facility's operating life and achieve cost savings across our operations in Alabama. In the first of these planned upgrades, we expect to replace the incinerator portion of the sulfur recovery unit in 2017 at a cost of approximately $6 million net to our interest. The facility may require further upgrades to repair or replace certain sulfur recovery unit components beyond 2017.

Distribution Policy


•	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.

Pursuant to the foregoing distribution policy, the actual distributions we declare are 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 .

Revolving Credit Facility

On October 10, 2014, we entered into the Fifth Amendment (the "Fifth Amendment") to our Credit Agreement. The Fifth Amendment, among other items, provided for current commitments totaling $320 million, with the ability to increase commitments up to a total aggregate amount of $1.2 billion. The Fifth Amendment coincided with the semi-annual borrowing base redetermination by our commercial lenders and the next redetermination will be in April 2015. The Fifth Amendment extended the maturity to October 2019. In addition, as a result of the completion of the Midstream Business contribution, our borrowing base under the Credit Agreement is now strictly based on the value of our oil and natural gas properties and our commodity derivative contracts, which was formerly referred to as the upstream component of the borrowing base. 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.

As of December 31, 2014, our borrowing base totaled approximately $320 million, and based on our outstanding borrowings and letters of credit, we had approximately $107.4 million of availability under the Credit Agreement.

For a further discussion of our Credit Agreement and current availability, see Note 8 to our consolidated financial statements.

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Senior Unsecured Notes

On July 1, 2014, as part of the contribution of the Midstream Business to Regency, $498.9 million face amount of newly-issued Regency senior unsecured notes due 2019 were exchanged for $498.9 million face amount of our existing senior unsecured notes. Thus, as of July 1, 2014, only $51.1 million face amount of our senior unsecured notes remained outstanding.

For a further discussion of our Senior Notes, see Note 8 to our consolidated financial statements.

Debt Covenants

Our revolving credit facility requires us to maintain certain leverage and current ratios. As of December 31, 2014, we were in compliance with all of our debt covenants.

The following table presents the debt covenant levels specified in the Credit Agreement as of December 31, 2014:



Quarter Ended	Total Leverage Ratio	Current Ratio
December 31, 2014 and Thereafter until Maturity (October 2019)	< 4.0x	> 1.0x

Our actual financial covenant ratios as of December 31, 2014, were as follows:



Total leverage ratio	2.2
Current ratio	5.2

Our long-term target is to maintain our ratio of total outstanding debt to Adjusted EBITDA, or "total leverage ratio," at or below 3.5 to 1.0 on a long-term basis, while acknowledging that at times this ratio may exceed our targeted levels, particularly following acquisitions or major development projects.

Our Senior Notes that did not exchange as part of the Midstream Business Contribution remain outstanding under an amended indenture with substantially all of the restrictive covenants and certain events of default eliminated.

At December 31, 2014, we were in compliance with our covenants under the Senior Notes indenture.

For a further discussion of our revolving credit facility and Senior Notes, see Note 8 to our consolidated financial statements.

Common Unit Repurchase Program

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 our 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 acquire any, or any specific number of, units and may be discontinued at any time. We have cancelled, and will continue to cancel units repurchased under the repurchase program. We have funded repurchases, and intend to fund any future repurchases, with the proceeds of sales of Regency Common Units. The use of these sales proceeds is expressly permitted under our Credit Agreement. As of December 31, 2014, a total of 7,455,887 units had been repurchased under this program for approximately $19.2 million. We have also repurchased an additional 1,171,584 common units from January 1, 2015 through February 26, 2015 for approximately $2.6 million.

Equity Offerings

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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 up to $100 million. We are under no obligation to issue equity under the program. We intend to use the net proceeds from any sales under the program for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. As of December 31, 2014, a total of 1,521,086 units had been issued under this program for net proceeds of approximately $12.9 million. No sales were made under the program during the year ended December 31, 2014. The last time units were issued under this program was during 2013.

Cash Flows

Cash Distributions

The table below summarizes the distributions paid or payable and declared for the last three years.



Quarter Ended	Distribution per Unit		Record Date**	Payment Date
March 31, 2012+	$	0.2200	May 8, 2012	May 15, 2012
June 30, 2012+	$	0.2200	August 7, 2012	August 14, 2012
September 30, 2012+	$	0.2200	November 7, 2012	November 14, 2012
December 31, 2012+	$	0.2200	February 7, 2013	February 14, 2013
March 31, 2013+*	$	0.2200	May 7, 2013	May 15, 2013
June 30, 2013+*	$	0.2200	August 7, 2013	August 14, 2013
September 30, 2013+*	$	0.1500	November 7, 2013	November 14, 2013
December 31, 2013+*	$	0.1500	February 7, 2014	February 14, 2014
March 31, 2014***	$	—	N/A	N/A
June 30, 2014***	$	—	N/A	N/A
September 30, 2014+*	$	0.07	November 7, 2014	November 14, 2014
December 31, 2014+*	$	0.07	February 6, 2015	February 13, 2015

_____________________________


+	The distribution per unit represents distributions made only on common units, including eligible restricted common units issued under our Long-Term Incentive Plan ("LTIP"). Since July 30, 2010, the only other class of equity we have outstanding is a non-economic general partner interest.


*	The units eligible for the distribution exclude certain restricted units under the LTIP.


**	The "Record Date" set forth in the table above means the close of business on each of the listed Record Dates.


***	No distribution was declared or paid for this period.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. As of December 31, 2014, working capital, excluding assets and liabilities held for sale, was a positive $189.6 million as compared to a negative $52.8 million as of December 31, 2013.

The net increase in working capital of $242.4 million from December 31, 2013 to December 31, 2014 resulted primarily from the following factors:


•	cash and cash equivalents increased by $1.3 million primarily due to the timing of payments and receipt of cash;


•	short-term investments increased by $153.4 million as a result of Regency common units received as partial consideration in connection with the Midstream Business Contribution;


•	trade accounts receivable increased by $22.3 million primarily from higher volumes and the timing of receipt of payments;


•	prepayments and other current assets increased by $3.8 million primarily due to the payment of insurance premiums;


•	accounts payable decreased by $0.9 million primarily as a result of the timing of payments of unbilled expenditures;

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•	risk management net working capital balance increased by a net $47.6 million as a result of changes in current portion of mark-to-market unrealized positions as a result of decreases to the forward crude oil, natural gas and NGL price curves; and


•	accrued liabilities decreased by $15.1 million primarily as a result of lower interest and compensation accruals.

Cash Flows for the Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

Cash Flow from Operating Activities. Cash flows from operating activities decreased $36.1 million during the year ended December 31, 2014 as compared to the year ended December 31, 2013. This increase was primarily due to:


•	Timing of cash payments and cash receipts; and


•	A decrease in our results of operations as a result of increased operating costs and lower commodity risk management settlements as a result of increased oil and natural gas prices;

Cash Flows from Investing Activities. Cash flows used in investing activities for the year ended December 31, 2014 were $92.9 million as compared to cash flows used in investing activities of $149.9 million for the year ended December 31, 2013. The decrease was primarily driven by:


•	Proceeds from the sale of short-term investments increased by $43.8 million during the year ended December 31, 2014, as compared to the same period in 2013; and


•	A decrease in capital expenditures during the year ended December 31, 2014 of $13.3 million as compared to the same period in 2013, in particular, decreased spending on our drilling program.

Cash Flows from Financing Activities. Cash flows used in financing activities during the year ended December 31, 2014 were $555.4 million as compared to cash flows provided by financing activities of $69.7 million for the year ended December 31, 2013. The increase was driven by:


•	Increased net repayments of long-term debt of $463.6 million as compared to the same period in 2013 due to the use of cash received from the contribution of the Midstream Business to Regency to paydown a portion of the long-term debt outstanding.

This increase was partially offset by:


•	Decreased distributions of $90.9 million during the year ended December 31, 2014, as compared to the same period in 2013, as a result of the suspension of our quarterly distribution for the first and second quarters of 2014 and a lower reinstated quarterly distribution for the third quarter of 2014;


•	Proceeds from derivative contracts decreased by $6.3 million during the year ended December 31, 2014, as compared to the same period in 2013; and


•	Decreased net proceeds of $97.9 million from our equity offering during the year ended December 31, 2014, as compared to the same period in 2013.

Cash Flows Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Cash Flow from Operating Activities. Cash flows from operating activities increased $38.9 million during the year ended December 31, 2013 as compared to the year ended December 31, 2012. This increase was primarily due to:


•	Timing of cash payments and cash receipts, partially offset by a decrease in our results of operations as a result of increased operating costs and lower commodity risk management settlements as a result of increased oil and natural gas prices; and


•	During the year ended December 31, 2012, we made payments of $6.6 million to terminate certain interest rate swaps, adjust the strike price on an existing WTI crude oil swap and partially unwind certain other commodity derivative contracts. During the year ended December 31, 2013, we did not make any payments to unwind any derivative contracts.

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Cash Flows from Investing Activities. Cash flows used in investing activities for the year ended December 31, 2013 were $149.9 million as compared to cash flows used in investing activities of $152.5 million for the year ended December 31, 2012. The decrease was driven by:


•	A decrease in capital expenditures during the year ended December 31, 2013 of $18.0 million as compared to the same period in 2012, in particular, decreased spending on our drilling program; and


•	Decreased proceeds from the sale of assets of $15.3 million during the year ended December 31, 2013, as compared to the same period in 2012.

Cash Flows from Financing Activities. Cash flows provided by financing activities during the year ended December 31, 2013 were $69.7 million as compared to cash flows used by financing activities of $165.5 million for the year ended December 31, 2012. The decrease was due to:


•	During the year ended December 31, 2012, we received net proceeds of $22.3 million and $31.8 million, respectively, from the sale of our Senior Notes and the exercise of warrants;


•	Increased distributions of $6.7 million during the year ended December 31, 2013 as compared to the same period in 2012, as a result of an increase in our units outstanding;


•	Proceeds from derivative contracts decreased by $13.1 million during the year ended December 31, 2013, as compared to the same period in 2012; and


•	Net repayments on our revolving credit facility of $98.3 million during the year ended December 31, 2013 as compared to net repayments of $127.0 million during the year ended December 31, 2012.

The decrease was partially offset by:


•	Increased net proceeds of $6.2 million from our equity offering during the year ended December 31, 2013, as compared to the same period in 2012.

Hedging Strategy

We use a variety of hedging instruments such as fixed-price swaps, costless collars and put options to manage our risks related to our commodity price and interest rate exposure. At times our hedging strategy may involve adjusting strike prices of existing hedges to better reflect current market conditions or to meet other corporate objectives. These transactions also increase our exposure to the counterparties through which we execute the hedges. In addition, we may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges. Hedge transactions such as these impact our liquidity in that we are required to pay the present value of the difference between the hedged price and the current futures price.

For a further description of our hedging activity, see Note 11 to our consolidated financial statements.

Off-Balance Sheet Obligations.

We have no off-balance sheet transactions or obligations as of December 31, 2014.

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Total Contractual Obligations.

The following table summarizes our total contractual cash obligations as of December 31, 2014:



	Payments Due by Period
Contractual Obligations	Total		2015		2016		2017		2018-2019		Thereafter
	($ in millions)
Revolving Credit Facility (including interest)(a)	$	234,629	$	4,613	$	4,613	$	4,613	$	220,790	$	—
Senior Notes	70,027		4,281		4,281		4,281		57,184		—
Operating leases	12,989		5,853		3,899		2,799		438		—
Asset Retirement Obligations	50,873		2,966		2,263		3,095		9,146		33,403
Total contractual obligations	$	368,518	$	17,713	$	15,056	$	14,788	$	287,558	$	33,403

__________________________


(a)	These amounts exclude estimates of the effect of our interest rate swap contracts on our future interest obligations. As of December 31, 2014, the fair value of our interest rate swap contracts, which expire on December 31, 2019, totaled a liability of $5.8 million.

Recent Accounting Pronouncements

For a recent accounting pronouncements, please see Note 3 to our consolidated financial statements.

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

Risk and Accounting Policies

We are exposed to market risks associated with adverse changes in commodity prices, interest rates and counterparty credit. We may use financial instruments such as swaps, put and call options and other derivatives to mitigate the effects of the identified risks. Adverse effects on our cash flow from changes in crude oil, natural gas, NGL product prices or interest rates could adversely impact our ability to make distributions to our unitholders, meet debt service obligations, fund required capital expenditures, and other similar requirements. Our management has established a review of our market risks and has developed risk management policies and procedures to monitor and manage these market risks. Our general partner is responsible for the overall approval of market risk management policies, delegation of transaction authority levels, and for the establishment of a Risk Management Committee ("RMC"). The RMC is composed of officers (including, on an ex officio basis, our chief executive officer) who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The RMC is the entity responsible for creating and implementing a sound approach to managing our credit, commodity price and interest rate risk with respect to our budgetary exposure and stated risk tolerance. As such, the RMC’s responsibilities and authorities are to:


•	Identify sources of financial and credit risk;


•	Establish financial risk management policies (or ensure they are developed by appropriate departments within the partnership);


•	Develop, oversee, review, assess and implement the financial risk management processes and infrastructure;


•	Advise on controls for risk management activities, including credit, hedging transactions and financial risk reporting;


•	Measure and analyze our overall commodity price and interest rate risk exposure, at least quarterly;


•	Recommend and approve derivative hedging transactions to reduce our commodity price and interest rate risk;


•	Report quarterly to the Board of Directors on the performance of the hedge program. These reports disclose, but may not necessarily be limited to, the following: percentage of volumes and debt outstanding hedged; mark-to-market valuations of open positions; and realized hedge settlement.

The RMC is specifically charged with the following:


•	Establishing an organizational structure for financial risk management controls;


•	Establishing clearly-defined segregation of duties and delegations of authority related to derivatives hedging;


•	Identifying permitted transaction and product types; and


•	Executing derivative transactions on behalf of the Partnership.

The Audit Committee of our Board of Directors reviews with management the implementation of our policy.

We have implemented a Risk Management Policy which allows management to execute hedging instruments, which may include swaps, collars, options and other derivatives, in order to reduce exposure to substantial adverse changes in the prices of commodities and in interest rates. We monitor and ensure compliance with our corporate Risk Management Policy through senior level executives in our operations, finance and legal departments. Our Risk Management Policy includes the following provisions:

1. Anti-speculation

Speculative buying and selling of commodity or interest rate products is prohibited. “Speculation” includes, but is not limited to, buying or selling commodity or financial instruments that are not necessary for meeting forecasted production (with respect to commodity hedges), or outstanding debt service (with respect to interest rate hedges).

2. Maximum Transaction Term

The maximum term of any hedging transaction should be five (5) years, unless specifically approved by our Board of Directors.

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3. Maximum Transaction Volumes

Hedged commodity volumes are not to exceed, for any settlement period, 80% of the expected production for that settlement period, and hedged interest rates shall not exceed, for any settlement period, 100% of total expected outstanding indebtedness for that settlement period. Neither of these limitations shall be exceeded without the prior approval of the Board of Directors, which (with respect to commodity volumes) we did obtain for 2013 and 2014.

As measured on the date of execution of any new derivative, the aggregate notional volumes under commodity derivatives executed during a single financial quarter shall not exceed, for any settlement period, 20% of the hedgeable volumes (with respect to commodity hedges) or expected outstanding indebtedness (with respect to interest rate hedges) for that settlement period.

4. Portfolio Performance and Value Reporting

Our staff shall prepare performance reports containing an analysis of physical and financial positions of all energy price and interest rate hedge contracts for review by the Risk Management Committee and presentation to the Board of Directors or the Audit Committee. The frequency and content of performance reports shall be determined by the Risk Management Committee, but in no case will be done less frequently than quarterly.

Payment obligations in connection with our hedging transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we will have no obligation to post cash, letters of credit, or other additional collateral to secure these hedges at any time even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness.

See Notes 11 and 12 to our consolidated financial statements for additional discussion of our commodity hedging activities and related fair values.

We have not designated our contracts as accounting hedges based on authoritative guidance. As a result, we mark our derivatives to market with the resulting change in fair value included in our statement of operations.

We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

Our Board of Directors, through its Audit Committee, also plays an important role in our risk oversight function. The Audit Committee is primarily responsible for the oversight of: (i) the integrity of our financial statements and internal controls, (ii) our compliance with legal and regulatory requirements, (iii) our independent auditor's qualifications, independence and performance of our internal audit function, and (iv) matters related to our hedging activities, litigation/disputes and environmental issues.

See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations —Critical Accounting Policies — Risk Management Activities and Note 11 to our consolidated financial statements for further discussion of the accounting for our derivative contracts.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of crude oil, natural gas, NGLs and other commodities. Our profitability and cash flow are affected by changes in prices of these commodities. These prices are impacted by changes in the supply and demand for these commodities, as well as market uncertainty and other factors beyond our control. Historically, changes in the prices of NGLs have generally correlated with changes in the price of crude oil. For a discussion of the volatility of crude oil, natural gas and NGL prices, please see Item 1A. Risk Factors - 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 manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in our areas of operations, and the use of derivative contracts. Crude oil, natural gas and NGL prices can also indirectly affect our profitability by influencing the level of drilling activity and related opportunities for our service.

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We frequently use financial derivatives (“hedges”), which may include swaps, collars and options, among others, to reduce our exposure to commodity price risk. These hedges are only intended to mitigate the risk associated with our natural physical position.

As of December 31, 2014, our commodity hedge portfolio totaled $97.1 million, which consists of assets aggregating $97.1 million less liabilities aggregating $0.0 million. For additional information, see Notes 11 and 12 of our consolidated financial statements for additional discussion of our hedging activities and related fair values.

Effectiveness of Commodity Risk Management Activities

The goal of our commodity risk management activities is to reduce the impact of changing commodity prices on our ability to make future distributions to our unitholders. One way we evaluate the effectiveness of these activities is to analyze the theoretical change in our internal estimates of future Adjusted EBITDA given an assumed change in future commodity prices. Using this method, we estimate that a $10 per barrel change in NYMEX crude oil prices and a $1 per MMbtu change in NYMEX natural gas prices would result in changes to 2015 Adjusted EBITDA of approximately $3 million and less than $1 million, respectively, based on $50 per barrel and $3.00 per MMbtu commodity prices.

Users of this information should be aware that these estimates rely on a large number of assumptions that may ultimately prove to be false. These assumptions include, but are not limited to, future production rates, future costs and other economic conditions, and future relationships between crude oil prices and natural gas liquids prices.

Interest Rate Risk

We are exposed to variable interest rate risk as a result of borrowings under our Credit Agreement. To mitigate its interest rate risk, we have entered into various interest rate swaps that eliminate interest rate variability by effectively converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.

On November 21, 2014, we amended our existing interest rate swaps to lower the notional amount from $250 million to $175 million, extended the maturity date from their original maturity date of June 22, 2015 to a new maturity date of December 31, 2019 and blended the existing swap rate for these extended swaps with the then prevailing interest swap rate, which lowered the rate from 2.95% to 2.3195%.

We estimate that for 2015, a 10% increase or decrease in the current LIBOR rates would impact our interest expense by less than $0.1 million.

See Notes 11 and 12 of our consolidated financial statements for additional discussion of our interest rate hedging activities and related fair values.

The table below summarizes the changes in commodity and interest rate risk management assets for the applicable periods (excluding amounts classified as held for sale or discontinued):



	Year Ended
	December 31, 2014			December 31, 2013
	($ in thousands)
Net risk management assets (liabilities) at beginning of period	$	(1,756	)	$	12,086
Cash received (paid) from settled contracts	(354		)	8,801
Settlements of positions	354			(8,801		)
Change in mark-to-market valuations of positions	93,051			(13,842		)
Balance of risk management assets (liabilities) at end of period	$	91,295		$	(1,756	)

Credit Risk

Our principal natural gas sales customers are large industrial, commercial and utility companies. With respect to the sale of our NGLs and condensates, our principal customers are large natural gas liquids purchasers, fractionators and marketers, and

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large condensate aggregators that then typically sell to large multi-national petrochemical and refining companies. We also sell a small amount of propane to medium sized, local distributors.

All of our product sale contracts require payment within 30 days payment term deals, with credit based upon 60 days of deliveries.

The concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in the natural gas, natural gas liquids, petrochemical and other segments of the energy industry, the economy in general, the regulatory environment and other factors.

In evaluating credit risk exposure, we analyze the financial condition of each counterparty before entering into an agreement. Our corporate credit policy lists the resource materials and information required to assess the financial condition of each prospective customer. The credit threshold for each customer is also based upon a time horizon for exposure, which is typically 60 days or less. We establish these credit limits and monitor and adjust them on an ongoing basis. We also require counterparties to provide letters of credit or other collateral financial agreements for exposure in excess of the established threshold. All of our sales agreements contain adequate assurance provisions to permit us to mitigate or eliminate future credit risk, at our sole discretion, by suspending deliveries until obligations and payments are satisfied or by canceling the agreement.

Our derivative counterparties at December 31, 2014 included Wells Fargo Bank N. A., Comerica Bank, Bank of America Merrill Lynch, ING Capital Markets LLC, Regions Financial Corporation and CITIBANK, N.A.


Item 8.	Financial Statements and Supplementary Data.

Our consolidated financial statements, together with the report of KPMG, LLP ("KPMG") as the independent registered public accounting firm begin on page F-1 of this report.


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

None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

The Partnership maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Partnership's reports under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, and our Audit Committee of the Board of Directors, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. In addition, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the internal control system are met. Because of the inherent limitations of any internal control system, no evaluation of controls can provide absolute assurance that all control issues, if any, within a company have been detected.

Our management, with the participation of our Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial and accounting officer), evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2014. Based on the evaluation of our disclosure controls and procedures (as defined in the Rules 13a-15(e) and 15d-15(e) under the Exchange Act) required by Exchange Act Rules 13a-15(b) or 15d-15(b), our principal executive officer and principal financial officer have concluded that as of the end of the period covered by this report, our disclosure controls and procedures were effective at the reasonable assurance level to ensure that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

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Changes to Internal Control

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d - 15(f) under the Exchange Act) that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management's Annual Report On Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Management has conducted (i) an evaluation of the design of our internal control over financial reporting, and (ii) a testing of the effectiveness of our internal control over financial reporting, as it pertains to the calendar year 2014. The evaluation and testing was conducted by our internal auditor, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Our evaluation and testing followed the “Internal Control-Integrated Framework (1992)” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Our evaluation and testing was conducted as of the year ended December 31, 2014, which is the period covered by this report. Based on our assessment, we believe our internal controls over financial reporting are effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles based on the criteria of the COSO Framework.

KPMG LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Partnership included in this report, has issued an attestation report on the effectiveness of the Partnership's internal control over financial reporting as of December 31, 2014, which is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P.:

We have audited Eagle Rock Energy Partners, L.P.'s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Eagle Rock Energy Partners, L.P.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

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

In our opinion, Eagle Rock Energy Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Eagle Rock Energy Partners, L.P. as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, members' equity, and cash flows for each of the years in the three-year period ended December 31, 2014, and our report dated March 2, 2015 expressed an unqualified opinion on those consolidated financial statements.

/s/KPMG LLP

Houston, Texas

March 2, 2015

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Item 9B.	Other Information.

None.

PART III


Item 10.	Directors, Executive Officers and Corporate Governance.

Information required to be set forth in Item 10. Directors, Executive Officers and Corporate Governance, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2014 Annual Meeting of Unitholders to be filed no later than April 30, 2015.


Item 11.	Executive Compensation.

Information required to be set forth in Item 11. Executive Compensation, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2015 Annual Meeting of Unitholders to be filed no later than April 30, 2015.


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

Information required to be set forth in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2015 Annual Meeting of Unitholders to be filed no later than April 30, 2015.


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

Information required to be set forth in Item 13. Certain Relationships and Related Transactions, and Director Independence, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2015 Annual Meeting of Unitholders to be filed no later than April 30, 2015.


Item 14.	Principal Accounting Fees and Services.

Information required to be set forth in Item 14. Principal Accountant Fees and Services, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2015 Annual Meeting of Unitholders to be filed no later than April 30, 2015.

PART IV


Item 15.	Exhibits and Financial Statement Schedules.

(a)(1) Financial Statements:

The following financial statements and the Report of Independent Registered Public Accounting Firm are filed as a part of this report on the pages indicated:



Report of Independent Registered Public Accounting Firm	F- 2
Consolidated Balance Sheets as of December 31, 2014 and 2013	F- 3
Consolidated Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012	F- 4
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012	F- 5
Consolidated Statements of Members’ Equity for the Years Ended December 31, 2014, 2013 and 2012	F- 6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012	F- 7
Notes to Consolidated Financial Statements	F- 8

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(a)(2) Financial Statement Schedules:

All other schedules have been omitted since the required information is not significant or is included in the Consolidated Financial Statements or Notes thereto or is not applicable.

(a)(3) Exhibits:

The following documents are included as exhibits to this report:

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Exhibit Number	Description

2.1	Contribution Agreement dated as of December 23, 2013, by and among Eagle Rock Energy Partners, L.P., Regency Energy Partners LP and Regal Midstream LLC (incorporated by reference to Exhibit 2.1 to the registrant's Current Report on Form 8-K filed with the Commission on December 26, 2013)

3.1	Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 4.2 of the registrant's Current Report on Form 8-K filed with the Commission on July 30, 2010)

3.2	Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 of the registrant's Current Report on Form 8-K filed with the Commission on July 30, 2010)

3.3	Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant's Current Report on Form 8-K filed with the Commission on May 25, 2010)

3.4	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant's registration statement on Form S-1 (File No. 333-134750))

3.5	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 of the registrant's registration statement on Form S-1 (File No. 333-134750))

3.6	Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750))

3.7	Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 of the registrant's registration statement on Form S-1 (File No. 333-134750))

4.1	Third Supplemental Indenture dated as of July 1, 2014, among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the registrant's Current Report on Form 8-K filed with the Commission on July 3, 2014)

4.2	Second Supplemental Indenture dated as of November 19, 2012, among Eagle Rock Crude Pipelines, LLC, a subsidiary of Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.4 to the registrant's Form S-4 filed with the Commission on November 20, 2012)

4.3	First Supplemental Indenture dated as of June 28, 2011, among Eagle Rock Gas Services, LLC, a subsidiary of Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to the registrant's Quarterly Report on Form 10-Q filed with the Commission on August 4, 2011)

4.4	Indenture dated as of May 27, 2011 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the registrant's Current Report on Form 8-K filed with the Commission on May 27, 2011)

4.5	Registration Rights Agreement dated May 3, 2011 by and between Eagle Rock Energy Partners, L.P. and Natural Gas Partners VIII, L.P. (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on May 3, 2011)

4.6	Form of Common Unit Certificate (included as Exhibit A to the Second Amended and Restated Partnership Agreement of Eagle Rock Energy Partners, L.P.) (incorporated by reference to Exhibit 3.1 of the registrant’s Current Report on Form 8-K filed on May 25, 2010)

10.1	Fifth Amendment to the Amended and Restated Credit Agreement and First Amendment to Amendment and Restated Guaranty and Collateral Agreement, dated as of October 10, 2014, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on October 14, 2014)

10.2	Borrowing Base and Fourth Amendment to the Amended and Restated Credit Agreement, effective as of May 28, 2014, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on May 29, 2014)

10.3	Third Amendment to the Amended and Restated Credit Agreement, effective as of February 26, 2014, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on February 27, 2014)

10.4	Second Amendment to the Amended and Restated Credit Agreement, dated as of July 23, 2013, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on July 23, 2013)

10.5	First Amendment to Amended and Restated Credit Agreement by and between Agreement by and among the Partnership, the lenders party thereto and Wells Fargo Bank, National Association, as the administrative agent, dated December 28, 2012 (incorporated by reference to the registrant's Current Report on Form 8-K filed on December 31, 2012).

10.6	Amended and Restated Credit Agreement, dated as of June 22, 2011, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, and BNP Paribas, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on June 23, 2011)

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Exhibit Number	Description

10.7**	Administrative Services Agreement, dated as of July 30, 2010, between Eagle Rock Energy Partners, L.P. and Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on July 30, 2010)

10.8**	Voting Agreement dated May 3, 2011 by and between Eagle Rock Energy Partners, L.P. and Natural Gas Partners VIII, L.P. (incorporated by reference to Exhibit 10.2 to the registrant's Current Report on Form 8-K filed with the Commission on May 3, 2011)

10.9†	Raw Product Purchase and Sale Agreement, by and between Phillips 66 Company and Eagle Rock Field Services, L.P., dated December 23, 2013, (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K/A filed on February 28, 2014)

10.10	Second Amendment to Gas Gathering and Processing Agreement, by and between BP America Production Company and Eagle Rock Field Services, L.P., dated July 1, 2013(incorporated by reference to Exhibit 10.3 to the registrant's Quarterly Report on Form 10-Q filed with the Commission on November 1, 2013)

10.11	First Amendment to Gas Gathering and Processing Agreement, by and between BP America Production Company and Eagle Rock Field Services, L.P., dated July 1, 2013 (incorporated by reference to Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q filed with the Commission on November 1, 2013)

10.12†	Gas Gathering and Processing Agreement by and between BP America Production Company and Eagle Rock Field Services, L.P., dated as of October 1, 2012 (incorporated by reference to Exhibit 10.1 of the registrant's Current Report on Form 8-K filed on October 2, 2012)

10.13**	Confidentiality and Noncompete Agreement by and between Eagle Rock Energy G&P, LLC and Joseph A. Mills dated August 3, 2012 (incorporated by reference to Exhibit 10.2 of the registrant's Current Report on Form 10-Q filed on August 6, 2012)

10.14**	Confidentiality and Noncompete Agreement by and between Eagle Rock Energy G&P, LLC and Jeffrey P. Wood dated August 3, 2012 (incorporated by reference to Exhibit 10.3 of the registrant's Current Report on Form 10-Q filed on August 6, 2012)

10.15**	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC. and Charles C. Boettcher dated August 3, 2012 (incorporated by reference to Exhibit 10.4 of the registrant's Current Report on Form 10-Q filed on August 6, 2012)

10.16**	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Joseph Schimelpfening dated August 3, 2012 (incorporated by reference to Exhibit 10.5 of the registrant's Current Report on Form 10-Q filed on August 6, 2012)

10.17**	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Steven Hendrickson dated August 3, 2012 (incorporated by reference to Exhibit 10.6 of the registrant's Current Report on Form 10-Q filed on August 6, 2012)

10.18**	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Robert Hallett dated May 1, 2012

10.19**	Form of Confidentiality, Non-Competition and Non-Solicitation Agreement (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on March 26, 2012)

10.20**	Form of Supplemental Indemnification Agreement among Eagle Rock Energy G&P, LLC, Eagle Rock Energy GP, L.P., Eagle Rock Energy Partners, L.P. and officers and directors of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 10.1 of the registrant's Current Report on Form 8-K filed with the Commission on December 30, 2009)

10.21**	Executive Change of Control Agreement Policy (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on July 28, 2010)

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Exhibit Number	Description

10.22**	Form of Executive Change of Control Agreement (incorporated by reference to Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on July 28, 2010)

10.23**	Amended and Restated Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan effective June 24, 2014 (incorporated by reference to Exhibit 10.1 of the registrant's Current Report on Form 8-K filed on August 20, 2014)

10.24**	Form of Restricted Unit Agreement under the Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the registrant's Current Report on Form 8-K filed on August 20, 2014)

10.25**	Form of Performance Unit Agreement under the Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on August 20, 2014)

10.26**†	Eagle Rock Energy G&P, LLC 2014 Short-Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on February 28, 2014)

10.27**	Master Agreement between Eagle Rock Energy G&P, LLC and Roger A. Fox dated September 16, 2014, incorporated by reference to Exhibit 10.2 of the registrant's Quarterly Report on Form 10-Q filed with the Commission on October 31, 2014)

12.1*	Statement Regarding Computation of Ratio of Earnings to Fixed Charges

14.1	Code of Ethics for Chief Executive Officer and Senior Financial Officers posted on the Company’s website at www.eaglerockenergy.com.

21.1*	List of Subsidiaries of Eagle Rock Energy Partners, L.P.

23.1*	Consent of KPMG LLP

23.2*	Consent of Cawley, Gillespie & Associates, Inc.

31.1*	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002

31.2*	Certification of Periodic Financial Reports by Robert M. Haines in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002

32.1***	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002

32.2***	Certification of Periodic Financial Reports by Robert M. Haines in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002

99.1*	Report of Cawley, Gillespie & Associates, Inc.

101.INS*	XBRL Instance Document

101.SCH*	XBRL Taxonomy Extension Schema Document

101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*	XBRL Taxonomy Extension Label Linkbase Document

101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document


*	Filed herewith


**	Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.


***	Furnished herewith


†	Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 2, 2015.



	EAGLE ROCK ENERGY PARTNERS, L.P.

	By:		Eagle Rock Energy GP, L.P., its general partner

	By:		Eagle Rock Energy G&P, LLC, its general partner

	By:		/s/ JOSEPH A. MILLS
	Name:		Joseph A. Mills
	Title:		Chief Executive Officer

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



Signature	Title	Date

/s/ JOSEPH A. MILLS Joseph A. Mills	Chief Executive Officer (Principal Executive Officer)	March 2, 2015

/s/ ROBERT M. HAINES Robert M. Haines	Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	March 2, 2015

/s/ PEGGY A. HEEG Peggy A. Heeg	Director	March 2, 2015

/s/ CHRISTOPHER D. RAY Christopher D. Ray	Director	March 2, 2015

/s/ PHILIP B. SMITH Philip B. Smith	Director	March 2, 2015

/s/ WILLIAM A. SMITH William A. Smith	Director	March 2, 2015

/s/ DAVID W. HAYES David W. Hayes	Director	March 2, 2015

/s/ WILLIAM K. WHITE William K. White	Director	March 2, 2015

/s/ HERBERT C. WILLIAMSON III Herbert C. Williamson III	Director	March 2, 2015

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EAGLE ROCK ENERGY PARTNERS, L.P.

INDEX TO FINANCIAL STATEMENTS



Eagle Rock Energy Partners, L.P. Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm	F- 2
Consolidated Balance Sheets as of December 31, 2014 and 2013	F- 3
Consolidated Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012	F- 4
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012	F- 5
Consolidated Statements of Members’ Equity for the Years Ended December 31, 2014, 2013 and 2012	F- 6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012	F- 7
Notes to Consolidated Financial Statements	F- 8

F- 1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P.:

We have audited the accompanying consolidated balance sheets of Eagle Rock Energy Partners, L.P. and subsidiaries (collectively, the “Partnership”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, members’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2014. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Eagle Rock Energy Partners, L.P.’s internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 2, 2015 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

March 2, 2015

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EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2014 AND 2013

(In thousands, except unit amounts)



	December 31, 2014		December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,343	$	76
Short-term investments	153,448		—
Accounts receivable^(a)	39,596		17,250
Risk management assets	44,805		5,559
Prepayments and other current assets	9,911		6,123
Assets held for sale	—		1,259,382
Total current assets	249,103		1,288,390
PROPERTY, PLANT AND EQUIPMENT — Net	487,988		824,451
INTANGIBLE ASSETS — Net	3,072		3,268
DEFERRED TAX ASSET	2,315		1,438
RISK MANAGEMENT ASSETS	46,490		3,871
OTHER ASSETS	5,307		6,132
TOTAL	$	794,275	$	2,127,550

LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	49,226	$	50,158
Accrued liabilities	8,053		23,162
Taxes payable	2,246		149
Risk management liabilities	—		8,360
Liabilities held for sale	—		637,738
Total current liabilities	59,525		719,567
LONG-TERM DEBT	263,343		757,480
ASSET RETIREMENT OBLIGATIONS	47,907		37,306
DEFERRED TAX LIABILITY	30,321		34,097
RISK MANAGEMENT LIABILITIES	—		2,826
OTHER LONG TERM LIABILITIES	4,709		2,395
COMMITMENTS AND CONTINGENCIES (Note 13)
MEMBERS' EQUITY^(b)	388,470		573,879
TOTAL	$	794,275	$	2,127,550

________________________


(a)	Net of allowance for bad debt of $1,023 as of December 31, 2014 and $931 as of December 31, 2013.


(b)	150,154,909 and 156,644,153 common units were issued and outstanding as of December 31, 2014 and December 31, 2013, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 2,419,750 and 2,743,807 as of December 31, 2014 and December 31, 2013, respectively.

See accompanying notes to consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

(In thousands, except per unit amounts)



	Year Ended December 31,
	2014			2013			2012
REVENUE:
Natural gas, natural gas liquids, oil, condensate, and sulfur	$	203,792		$	200,608		$	201,719
Commodity risk management gains (losses), net	94,431			(3,937		)	28,110
Other revenue	(19		)	701			1,486
Total revenue	298,204			197,372			231,315
COSTS AND EXPENSES:
Operations and maintenance	43,670			41,426			41,391
Taxes other than income	12,925			12,928			15,343
General and administrative	47,193			53,131			50,990
Impairment and other	395,892			214,286			45,289
Depreciation, depletion and amortization	85,579			89,444			90,510
Total costs and expenses	585,259			411,215			243,523
OPERATING LOSS	(287,055		)	(213,843		)	(12,208		)
OTHER (EXPENSE) INCOME:
Interest expense, net	(15,247		)	(18,789		)	(16,276		)
Interest rate risk management losses, net	(1,734		)	(1,104		)	(4,727		)
Loss on short-term investments	(62,028		)	—			—
Other income (expense), net	8,294			(30		)	(28		)
Total other (expense) income	(70,715		)	(19,923		)	(21,031		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(357,770		)	(233,766		)	(33,239		)
INCOME TAX BENEFIT	(5,403		)	(5,595		)	(1,093		)
LOSS FROM CONTINUING OPERATIONS	(352,367		)	(228,171		)	(32,146		)
DISCONTINUED OPERATIONS, NET OF TAX	212,460			(49,808		)	(118,456		)
NET LOSS	$	(139,907	)	$	(277,979	)	$	(150,602	)



NET LOSS PER COMMON UNIT—BASIC AND DILUTED:
Loss from Continuing Operations
Common units - Basic	$	(2.25	)	$	(1.50	)	$	(0.26	)
Common units - Diluted	$	(2.25	)	$	(1.50	)	$	(0.26	)
Discontinued Operations
Common units - Basic	$	1.36		$	(0.32	)	$	(0.87	)
Common units - Diluted	$	1.36		$	(0.32	)	$	(0.87	)
Net Loss
Common units - Basic	$	(0.89	)	$	(1.82	)	$	(1.13	)
Common units - Diluted	$	(0.89	)	$	(1.82	)	$	(1.13	)
Weighted Average Units Outstanding (in thousands)
Common units - Basic	156,700			153,562			135,609
Common units - Diluted	156,700			153,562			135,609

See accompanying notes to consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

(In thousands)



	Year Ended December 31,
	2014		2013		2012
Net loss	(139,907	)	(277,979	)	(150,602	)
Other comprehensive income:
Gain on short-term investments	3,381		—		—
(Loss) on short-term investments	(3,381	)	—		—
COMPREHENSIVE LOSS	(139,907	)	(277,979	)	(150,602	)

See accompanying notes to consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

(in thousands, except unit amounts)



	Number of Common Units		Common Units			Total
BALANCE — January 1, 2012	127,606,229		$	1,007,347		$	1,007,347
Net loss	—		(150,602		)	(150,602		)
Distributions	—		(119,211		)	(119,211		)
Vesting of restricted units	1,101,323		—			—
Exercised warrants	5,300,588		31,804			31,804
Repurchase of common units	(286,716	)	(2,501		)	(2,501		)
Equity based compensation	—		9,882			9,882
Common units issued in equity offering	10,954,327		96,173			96,173
Unit issuance costs for equity offering	—		(4,518		)	(4,518		)
BALANCE — December 31, 2012	144,675,751		868,374			868,374
Net loss	—		(277,979		)	(277,979		)
Distributions	—		(125,911		)	(125,911		)
Vesting of restricted units	1,203,822		—			—
Repurchase of common units	(272,179	)	(1,858		)	(1,858		)
Equity based compensation	—		13,384			13,384
Common units issued in equity offering	11,036,759		102,388			102,388
Unit issuance costs for equity offering	—		(4,519		)	(4,519		)
BALANCE — December 31, 2013	156,644,153		573,879			573,879
Net loss	—		(139,907		)	(139,907		)
Distributions	—		(34,982		)	(34,982		)
Vesting of restricted units	1,305,433		—			—
Repurchase of common units	(7,794,677	)	(20,505		)	(20,505		)
Equity based compensation	—		9,985			9,985
BALANCE — December 31, 2014	150,154,909		$	388,470		$	388,470

See accompanying notes to consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

($ in thousands)



	Year Ended December 31,
	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(139,907	)	$	(277,979	)	$	(150,602	)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Discontinued operations	(212,460		)	49,808			118,456
Depreciation, depletion and amortization	85,579			89,444			90,510
Impairment and other	395,892			214,286			45,289
Amortization of debt issuance costs	2,241			2,151			1,735
Loss (gain) from risk management activities, net	(92,697		)	5,041			(23,383		)
Derivative settlements	4,669			7,478			5,368
Equity-based compensation	8,198			10,392			7,719
(Gain) loss on sale of assets	—			(76		)	—
Loss on short-term investments	62,028			—			—
Other	(2,574		)	(1,197		)	(592		)
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	(20,428		)	14,280			(26,742		)
Prepayments and other current assets	(3,788		)	1,838			2,087
Risk management activities	—			—			(6,607		)
Accounts payable	(5,023		)	1,738			14,198
Accrued liabilities	(4,138		)	(964		)	2,519
Other assets	(6		)	143			(2,985		)
Other current liabilities	540			(2,140		)	(1,634		)
Net cash provided by operating activities	78,126			114,243			75,336
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(136,694		)	(149,944		)	(167,907		)
Proceeds from sale of assets	—			76			15,398
Proceeds from sale of short-term investments	43,836			—			—
Net cash used in investing activities	(92,858		)	(149,868		)	(152,509		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	472,500			601,400			1,043,750
Repayment of long-term debt	(966,700		)	(503,100		)	(916,750		)
Proceeds from senior notes	—			—			22,889
Payment of debt issuance costs	(1,984		)	—			(614		)
Proceeds from derivative contracts	(5,022		)	1,323			14,449
Common units issued in equity offerings	—			102,388			96,173
Issuance costs for equity offerings	—			(4,519		)	(4,518		)
Exercise of warrants	—			—			31,804
Repurchase of common units	(19,170		)	(1,858		)	(2,501		)
Distributions to members and affiliates	(34,982		)	(125,911		)	(119,211		)
Net cash (used in) provided by financing activities	(555,358		)	69,723			165,471
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities	31,098			63,133			70,165
Investing activities	540,259			(97,180		)	(376,161		)
Financing activities	—			—			216,846
Net cash provided by (used in) discontinued operations	571,357			(34,047		)	(89,150		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,267			51			(852		)
CASH AND CASH EQUIVALENTS—Beginning of period	76			25			877
CASH AND CASH EQUIVALENTS—End of period	$	1,343		$	76		$	25

NONCASH INVESTING AND FINANCING ACTIVITIES:
Units received in divestiture	$	265,599		$	—		$	—
Investments in property, plant and equipment, not paid	$	12,154		$	9,469		$	29,568
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	$	43,705		$	65,309		$	45,614
Cash paid for taxes	$	—		$	59		$	1,085

See accompanying notes to consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Description of Business—Eagle Rock Energy Partners, L.P. ("Eagle Rock Energy" or the "Partnership") is a growth-oriented master limited partnership engaged in (a) the exploitation, development, and production of oil and natural gas properties and (b) ancillary gathering, compressing, treating, processing and marketing services with respect to its production of natural gas, natural gas liquids, condensate and crude oil. The Partnership's assets, located primarily in Alabama (where it also operates the associated gathering and processing assets), Texas, Oklahoma, Mississippi and Arkansas, are characterized by long-lived, high-working interest properties with extensive production histories and development opportunities.

On July 1, 2014, the Partnership contributed its business 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”) to Regency Energy Partners LP ("Regency") (such contribution, the "Midstream Business Contribution"). The consideration received by the Partnership pursuant to the Midstream Business Contribution 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 the Partnership's outstanding unsecured senior notes ("Senior Notes") for an equivalent amount of Regency unsecured senior notes. $51.1 million of the Partnership's Senior Notes did not exchange and remain outstanding under an amended indenture with substantially all of the restrictive covenants and certain events of default eliminated.

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. As a result of this transaction, the Partnership only reports as one segment.

The general partner of Eagle Rock Energy is Eagle Rock Energy GP, L.P., and the general partner of Eagle Rock Energy GP, L.P. is Eagle Rock Energy G&P, LLC, both of which are wholly-owned subsidiaries of the Partnership.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation—The accompanying audited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP").

All intercompany accounts and transactions are eliminated in the consolidated financial statements.

Use of Estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.

Cash and Cash Equivalents—Cash and cash equivalents include certificates of deposit and other highly liquid investments with maturities of three months or less at the time of purchase.

Short-term Investments— A portion of the consideration received for the Midstream Business Contribution included Regency common units, as further described in Note 1. These common units have a readily determinable fair value, are being classified as available-for-sale equity securities and are recorded as short-term investments on the consolidated balance sheets. Unrealized gains and losses associated with increases and decreases in the fair value of these securities are included in other comprehensive income until such time that the gains and losses become realized and then will be included in the consolidated statements of operations. Losses from declines in fair value determined to be other than temporary are recorded in the consolidated statement of operations. This loss is included in the consolidated statement of operations as a loss on short-term investments. Distributions received from Regency as a result of holding these common units are recorded as other income on the consolidated statement of operations. For the twelve months ended December 31, 2014, the Partnership received and recorded distributions from Regency of $8.0 million. During the fourth quarter of 2014, the Partnership recorded a $62.0

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million loss associated with losses as the result of sale of common units and the decrease in the fair value of these securities that was deemed to be other than temporary and the sale of common units. As of December 31, 2014, the Partnership still held 6,393,657 Regency common units, which does not include the transactions to sell 262,496 Regency common units that had not settled as of December 31, 2014 and for which a receivable of $6.3 million was recorded as part accounts receivable in the consolidated balance sheet.

Concentration and Credit Risk—Concentration and credit risk for the Partnership principally consists of cash and cash equivalents and accounts receivable.

The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. Industry concentrations have the potential to impact the Partnership's overall exposure to credit risk, either positively or negatively, in that the Partnership's customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes the risk posed by this industry concentration is offset by the creditworthiness of the Partnership's customer base. The Partnership's portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.

The following is the activity within the Partnership's allowance for doubtful accounts during the years ended December 31, 2014, 2013 and 2012.



	2014			2013			2012
($ in thousands)
Balance at beginning of period	$	931		$	753		$	670
Charged to bad debt expense	249			458			175
Write-offs/adjustments charged to allowance	(157		)	(280		)	(92		)
Balance at end of period	$	1,023		$	931		$	753

The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of assets held for sale within the audited consolidated balance sheets and discontinued operations within the audited consolidated statements of operations (see Note 18).

Certain Other Concentrations—For the year ended December 31, 2014, NGL Energy Partners LP, CVR Refining, LP and Oneok Partners, LP, the Partnership's largest customers, represented 15%, 12% and 11%, respectively, of its total sales revenue (excluding its commodity risk management gains and losses and revenue amounts classified as part of discontinued operations).

Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At December 31, 2013, the Partnership had $1.0 million of crude oil finished goods inventory, which is recorded as part of assets held for sale within the audited consolidated balance sheet.

Property, Plant and Equipment—Property, plant and equipment, including amounts classified as held for sale, consists primarily of gas gathering systems, gas processing plants, NGL pipelines, conditioning and treating facilities and other related facilities, and oil and natural gas properties, which are carried at cost less accumulated depreciation, depletion and amortization. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. The Partnership calculates depreciation on the straight-line method over estimated useful lives of the Partnership's newly developed or acquired assets. The weighted average useful lives are as follows:



Plant assets	20 years
Pipelines and equipment	20 years
Gas processing and equipment	20 years
Office furniture and equipment	5 years

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Plant assets, pipelines and equipment, gas process and equipment and certain office furniture and equipment related to the Partnership's Midstream Business have been classified as assets held for sale within the audited consolidated balance sheets. Depreciation expense related to these assets has been recorded as part of discontinued operations within the audited consolidated statements of operations (see Note 18).

Oil and Natural Gas Properties—The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. The Partnership carries the costs of an exploratory well as an asset if the well is found to have a sufficient quantity of reserves to justify its capitalization as a producing well as long as the Partnership is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves (developed and undeveloped), and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.

Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.

Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience, drilling plans and average lease-term lives. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units of production basis. Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.

Other Assets— As of December 31, 2014 and 2013, other assets, excluding amounts classified as held for sale (see Note 18), primarily consist of costs associated with debt issuance costs, net of amortization, of $5.3 million and $6.1 million, respectively.

Impairment of Long-Lived Assets—Management evaluates whether the carrying value of non-oil and natural gas long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment, including, but not limited to:


•	significant adverse changes in legal factors or in the business climate;


•	a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast which demonstrates continuing losses associated with the use of a long-lived asset;


•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;


•	significant adverse changes in the extent or manner in which an asset is used or in its physical condition;


•	a significant change in the market value of an asset; or


•	a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

For its oil and natural gas long-lived assets, the Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a negative revision or unfavorable projection of future oil and natural gas reserves and/or forward prices that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels.

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If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset's carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management's intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.

See Note 5 for further discussion on impairment charges.

Revenue Recognition—Revenues associated with sales of natural gas, NGLs, crude oil, condensate and sulfur are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs.

Revenues for the Partnership's Midstream Business included the sale of natural gas, NGLs, crude oil, condensate, sulfur and helium and from the compression, gathering, processing, treating and transportation of natural gas. Revenues associated with transportation and processing fees were recognized in the period when the services were provided. These revenues have been classified as discontinued operations within the unaudited condensed consolidated statements of operations.

Natural gas revenues produced from the Partnership's natural gas interests are based on the amount of natural gas sold to purchasers. The volumes of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. Differences between volumes sold and volumes based on entitlements create natural gas imbalances. Imbalances are reflected as adjustments to reported natural gas reserves and future cash flows. The Partnership had long-term imbalance payables totaling $0.3 million and $0.3 million as of December 31, 2014 and December 31, 2013.

Transportation and Exchange Imbalances—In the course of transporting natural gas and NGLs for others, the Partnership may receive for redelivery different quantities of natural gas or NGLs than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which are recovered or repaid through the receipt or delivery of natural gas or NGLs in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the audited consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2013, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $1.6 million. All transportation and exchange imbalance receivables and imbalance payables have been classified as assets and liabilities held for sale, respectively, within the audited consolidated balance sheets. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold, and have been classified as discontinued operations within the audited consolidated statements of operations.

Environmental Expenditures—Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures which relate to an existing condition caused by past operations and do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.

Income Taxes—Provision for income taxes is primarily applicable to the Partnership's state tax obligations under the Revised Texas Franchise Tax (the “Revised Texas Franchise Tax”) and certain federal and state tax obligations of Eagle Rock Energy Acquisition Co., Inc., Eagle Rock Acquisition Co. II, Inc., Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., all of which are consolidated subsidiaries. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of the tax paying entities for financial reporting and tax purposes.

In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, the Partnership's tax status in the State of Texas changed from non-taxable to taxable effective with the 2007 tax year.

Since the Partnership is structured as a pass-through entity, it is not subject to federal income taxes. As a result, its partners are individually responsible for paying federal and certain income taxes on their share of the Partnership's taxable

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income. Since the Partnership does not have access to information regarding each partner's tax basis, it cannot readily determine the total difference in the basis of the Partnership's net assets for financial and tax reporting purposes.

Derivatives—Authoritative guidance establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The guidance provides that normal purchase and sale contracts, when appropriately designated, are not subject to the guidance. Normal purchases and sales are contracts which provide for the purchase or sale of something, other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership's forward natural gas and crude oil purchase and sales contracts are designated as normal purchases and normal sales. The Partnership uses financial instruments such as swaps, collars and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the consolidated statement of cash flows. See Note 11 for a description of the Partnership's risk management activities.

Other Reclassifications—Certain prior period financial statement balances have been reclassified to conform to current period presentation. These reclassifications had no effect on the recorded net income.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In February 2013, the Financial Accounting Standards Board ("FASB") issued new guidance related to obligations resulting from joint and several liability arrangements. The new guidance provides for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 and did not have a material impact on the Partnership’s consolidated financial statements.

On April 10, 2014, the FASB issued new guidance which amends the definition of a discontinued operation and requires entities to provide additional disclosures about disposal transactions that do not meet the discontinued-operations criteria. Under the new guidance, a discontinued operation is defined as a disposal of a component or group of components that is disposed of or is classified as held for sale and represents a strategic shift that has or will have a major effect on an entity's operations and financial results. The new guidance is effective prospectively for all disposals (except disposals classified as held for sale before the adoption date) or components initially classified as held for sale in periods beginning on or after December 15, 2014, with early adoption permitted. The Partnership decided to early adopt this guidance in relation to its transaction to contribute its Midstream Business to Regency (see Notes 1 and 18).

On May 28, 2014, the FASB issued new guidance related to revenue from contracts with customers. This new guidance outlines a single comprehensive model for entities to use and supersedes most current revenue recognition guidance, including industry-specific guidance. This guidance is effective for annual reporting periods (including interim reporting periods within those periods) beginning after December 15, 2016. Early application of the guidance is not permitted. The Partnership is currently evaluating the potential impact, if any, of the adoption of this new guidance on its financial statements.

On August 27, 2014, the FASB issued new guidance on determining how to perform going concern assessments and when to disclose going concern uncertainties in the financial statements. The new guidance requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year after the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity's ability to continue as a going concern. This guidance is effective for annual periods ending after December 15, 2016, with early adoption permitted. The Partnership is currently evaluating the potential impact, if any, of the adoption of this new guidance on its financial statements.

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NOTE 4. ACQUISITIONS

Acquisition of Additional Working Interests

On December 9, 2014, the Partnership acquired certain additional interests in the Big Escambia Creek Field from LP 224 LLC for approximately $10.4 million. These interests are in wells in which the Partnership currently owns significant interest and are nearly 100% operated by the Partnership. The entire purchase price was allocated to proved properties.

Acquisition of Midstream Assets in the Texas Panhandle

On October 1, 2012, the Partnership completed the acquisition of two of BP America Production Company's ("BP") gas processing facilities, and the associated gathering systems, that are located in the Texas Panhandle. The aggregate purchase price of the system was $230.6 million, which the Partnership funded from borrowings under its revolving credit facility. The results of the operations of the system have been included in the consolidated financial statements since the acquisition date. The Partnership incurred $0.5 million of acquisition related expenses, which are included within discontinued operations for the year ended December 31, 2012. The Partnership incurred $0.1 million of acquisition related expenses, which are included within discontinued operations for the year ended December 31, 2013.

This acquisition was accounted for under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates.

The following presents the purchase price allocation for the system assets, based on estimates of fair value (in thousands):



Current assets	$	779
Property, plant, and equipment	206,849
Rights-of-way and easements	27,232
Current liabilities	(1,705		)
Asset retirement obligations	(2,600		)
	$	230,555

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of property, plant and equipment, rights-of-way and easements and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of property, plant and equipment include estimates of: (i) replacement costs; (ii) useful and remaining lives; (iii) physical deterioration; and (iv) functional and technical obsolescence. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change.

Pro forma data for the year ended December 31, 2012 has been deemed to be impracticable as BP did not separately manage its gathering and processing facilities with the activities of the acquired assets being integrated (financially and operationally) within its exploration and production segment. The amounts of revenue and net income generated by the acquired processing plants and gathering systems that are included within the Partnership's audited consolidated statement of operations for the year ended December 31, 2012 are as follows.



	Revenue		Net Income
	($ in thousands)
Actual from October 1, 2012 to December 31, 2012	$	81,013	$	5,057

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Assets acquired and liabilities assumed as part of this acquisition have been classified as part of assets and liabilities held for sale within the audited consolidated balance sheets. Operations related to these assets have been classified as part of discontinued operations within the audited consolidated statements of operations.

NOTE 5. PROPERTY, PLANT AND EQUIPMENT

Fixed assets consisted of the following:



	December 31, 2014			December 31, 2013
	($ in thousands)
Equipment and machinery	$	101		$	101
Vehicles and transportation equipment	212			212
Office equipment, furniture, and fixtures	3,020			1,391
Computer equipment	13,234			12,247
Proved properties	905,622			1,156,895
Unproved properties	7,512			10,022
Construction in progress	1,195			6,636
	930,896			1,187,504
Less: accumulated depreciation, depletion and amortization	(442,908		)	(363,053		)
Net property plant and equipment	$	487,988		$	824,451

Amounts in the table above do not include the property, plant and equipment related to the Partnership's Midstream Business, as these amounts have been classified as assets held for sale within the audited consolidated balance sheets (See Note 18).

The following table sets forth the total depreciation, depletion and impairment expense by type of asset within the Partnership's audited consolidated statements of operations:



	Year Ended December 31,
	2014		2013		2012
	($ in thousands)
Depreciation	$	2,971	$	2,018	$	1,795
Depletion	$	80,810	$	87,230	$	88,413

Impairment expense:
Proved properties (a)	$	395,892	$	207,085	$	38,943
Unproved properties (b)	$	—	$	7,201	$	785

__________________________________

(a)

During the year ended December 31, 2014, the Partnership incurred impairment charges related to certain proved properties in all of its regions due primarily to lower commodity prices, higher operating costs and lower well performance. During the year ended December 31, 2013, the Partnership incurred impairment charges related primarily to certain proved properties, primarily in the Cana Shale in the Mid-Continent region and the Permian region, due to lower reserve forecasts. During the year ended December 31, 2012, the Partnership incurred impairment charges related to its proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing high operating costs associated with gas compression.


(b)	During the year ended December 31, 2013, the Partnership incurred impairment charges related to certain leaseholds in the Mid-Continent regions that we expected to expire undrilled in 2014. During the year ended December 31, 2012, the Partnership incurred impairment charges related to certain unproved property leaseholds expected to expire undrilled in 2013.

The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of discontinued operations within the audited consolidated statements of operations (see Note 18).

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NOTE 6. ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes asset retirement obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. The Partnership records 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. The Partnership makes estimates of property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to increases in current abandonment costs, changes in regulatory requirements, technological advances and other factors that may be difficult to predict. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, the Partnership is required to recognize a liability for the fair value of a conditional asset retirement obligation upon initial recognition if the fair value of the liability can be reasonably estimated. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that covert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of (i) remediation costs, (ii) remaining lives, (iii) future inflation factors and (iv) a credit-adjusted risk free interest rate.

A reconciliation of the Partnership's liability for asset retirement obligations is as follows:



	2014			2013			2012
	($ in thousands)
Asset retirement obligations—January 1	$	48,564		$	38,991		$	26,227
Additional liabilities	237			1,076			1,400
Liabilities settled	(1,347		)	(2,240		)	(1,664		)
Revision to liabilities	168			7,654			11,146
Accretion expense	3,251			3,083			1,882
Asset retirement obligations—December 31 (a)	$	50,873		$	48,564		$	38,991

_____________________________________

(a) As of December 31, 2014 and 2013, $3.0 million and $11.3 million, respectively, were included within accrued liabilities in the audited consolidated balance sheets.

The table above does not include the balances or activity related to asset retirement obligations related to the Partnership's Midstream Business, as these amounts have been classified as liabilities held for sale within the audited consolidated balance sheets and discontinued operations within the audited consolidated statements of operations (see Note 18).

NOTE 7. INTANGIBLE ASSETS

Intangible assets consist of rights-of-way and easements which the Partnership amortizes over the estimated useful life of 20 years.

Intangible assets consisted of the following:



	December 31, 2014			December 31, 2013
	($ in thousands)
Rights-of-way and easements—at cost	$	3,920		$	3,920
Less: accumulated amortization	(848		)	(652		)
Net intangible assets	$	3,072		$	3,268

Amounts in the table above do not include the intangible assets related to the Partnership's Midstream Business, as these amounts have been classified as assets held for sale within the audited consolidated balance sheets (See Note 18).

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The following table sets forth the total amortization expense within the Partnership's audited consolidated statements of operations:



	Year Ended December 31,
	2014		2013		2012
	($ in thousands)
Amortization	$	196	$	196	$	302

Estimated future amortization expense related to the intangible assets at December 31, 2014, is as follows (in thousands):



Year ending December 31,
2015	$	196
2016	$	196
2017	$	196
2018	$	196
2019	$	196
Thereafter	$	2,092

The table above does not included amounts related to the Partnership's Midstream Business, as amortization expense ceases once assets have been classified as held for sale.

NOTE 8. LONG-TERM DEBT

Long-term debt consisted of the following:



	December 31, 2014			December 31, 2013
	($ in thousands)
Revolving credit facility:	$	212,600		$	706,800
Senior Notes:
8.375% Senior Notes due 2019	51,120			51,120
Unamortized bond discount	(377		)	(440		)
Total Senior Notes	50,743			50,680
Total long-term debt	$	263,343		$	757,480

Amounts in the table above do not include the portion of the Senior Notes that were exchanged for Regency unsecured senior notes upon the completion of the Midstream Business Contribution on July 1, 2014 (see Note 1). These notes have been classified as part of liabilities held for sale within the unaudited condensed consolidated balance sheet for December 31, 2013 and were exchanged on July 1, 2014 (see Note 18).

On July 1, 2014, the Partnership used the cash received from Regency for the Midstream Business Contribution (see Note 1) to paydown $570.4 million outstanding under its Credit Agreement.

Revolving Credit Facility

On October 10, 2014, the Partnership entered into the Fifth Amendment (the "Fifth Amendment") to its Amended and Restated Credit Agreement (as amended, the "Credit Agreement"). The Fifth Amendment, among other items, provided for current commitments totaling $320 million , with the ability to increase commitments up to a total aggregate amount of $1.2 billion. The Fifth Amendment coincided with the semi-annual borrowing base redetermination by the Partnership's commercial lenders, and

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the next redetermination will be in April 2015. The amendment extended the maturity to October 2019. In addition, as a result of the completion of the Midstream Business contribution, the Partnership's borrowing base under the Credit Agreement is now strictly based on the value of its oil and natural gas properties and its commodity derivative contracts, which was formerly referred to as the upstream component of the borrowing base.

In connection with the Credit Agreement, the Partnership incurred debt issuance costs of $1.6 million and recorded a charge of $0.6 million to write off a portion of the unamortized debt issuance costs related to the Prior Credit Agreement. As of December 31, 2014, the Partnership had unamortized debt issuance costs of $4.6 million.

As of December 31, 2014, the Partnership had approximately $107.4 million of availability under the credit facility based on its borrowing base on that date. The Partnership currently pays a 0.50% commitment fee (based on the Partnership's borrowing base utilization percentage) per year on the difference between total commitments and the amount drawn under the credit facility. The Credit Agreement includes a sub-limit for the issuance of standby letters of credit for a total of $50.0 million. As of December 31, 2014, the Partnership had no outstanding letters of credit.

At the Partnership's election, interest will accrue on the credit facility at either LIBOR plus a margin ranging from 1.50% to 2.50% (currently 2.00% per annum based on the Partnership's borrowing base utilization percentage) or the base rate plus a margin ranging from 0.50% to 1.50% (currently 1.00% per annum based on the Partnership's borrowing base utilization percentage). The applicable margin is determined based on the utilization of the then existing borrowing base. The borrowings under the Credit Agreement may be prepaid, without any premium or penalty, at any time. The base rate is generally the highest of the federal funds rate plus 0.5%, the prime rate as announced from time to time by the Administrative Agent, or daily LIBOR for a term of one month plus 1.0%. As of December 31, 2014, the weighted average interest rate (excluding the impact of interest rate swaps) on the Partnership's outstanding debt under its revolving credit facility was 2.17%.

The obligations under the Credit Agreement are secured by first priority liens on substantially all of the Partnership’s material assets, including a pledge of all of the equity interests of each of the Partnership’s material subsidiaries, but excluding the equity interests in Regency owned by the Partnership and the sales proceeds thereof.

The Credit Agreement requires the Partnership and certain of its subsidiaries to make certain representations and warranties that are customary for credit facilities of this type. The Credit Agreement also contains affirmative and negative covenants that are customary for credit facilities of this type, including compliance with financial covenants. The financial covenants prohibit the Partnership from exceeding defined limits with respect to:


•	As of any fiscal quarter-end, the ratio of Total Funded Indebtedness (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter (the “Total Leverage Ratio”).; and

•

As of any fiscal quarter-end the ratio of the Partnership’s consolidated current assets (including availability under the Credit Agreement up to the Loan Limit (as defined within the Credit Agreement), but excluding non-cash assets under the accounting guidance for derivatives) to consolidated current liabilities (excluding non-cash obligations under the accounting guidance for derivatives and current maturities under the Credit Agreement) (the “Current Ratio”).

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The following table presents the debt covenant levels specified in our revolving credit facility as of December 31, 2014:



Quarter Ended	Total Leverage Ratio(a)	Current Ratio(b)
December 31, 2014 and Thereafter until Maturity (October 2019)	4.0	1.0

_____________________


(a)	Amount represents the maximum ratio for the period presented.


(b)	Amount represents the minimum ratio for the period presented.

The following table presents our actual covenant ratios as of December 31, 2014:



Total leverage ratio	2.2
Current ratio	5.2

As of December 31, 2013, the Partnership was in compliance with the financial covenants under the Credit Agreement.

Senior Notes

On May 27, 2011 and July 13, 2012, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer and certain subsidiary guarantors, issued $300.0 million and $250.0 million, respectively, of senior unsecured notes (the "Senior Notes"), that bear a coupon of 8.375%, through private placement and all of which are treated as a single series. The Senior Notes will mature on June 1, 2019, and interest is payable on each June 1 and December 1. After the original discount of $2.2 million and $3.7 million, respectively, and excluding related offering expenses, the Partnership received net proceeds of approximately $297.8 million and $246.3 million, respectively, which were used to repay borrowings outstanding under its revolving credit facility.

As of December 31, 2014, the Partnership had unamortized debt issuance costs of $0.8 million and an unamortized debt discount of $0.4 million, which is recorded as an offset to the principal amount of the Senior Notes. As discussed above and within Note 1, a portion of the Senior Notes have been classified as part of liabilities held for sale within the audited consolidated balance sheets (see Note 18).

The Senior Notes are general unsecured senior obligations and rank equally in right of payment with all of the Partnership's existing and future senior indebtedness and rank senior in right of payment to any of the Partnership's future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Partnership's existing and future secured indebtedness and other obligations, including borrowings outstanding under the Partnership's Credit Agreement, to the extent of the value of the assets securing such indebtedness and other obligations. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by the Partnership's existing and future subsidiaries, who are referred to as the "subsidiary guarantors," that guarantee the Partnership's credit facility or other indebtedness.

As discussed in Note 1, the consideration received by the Partnership for the Midstream Business Contribution included the exchange of $498.9 million face amount of the Partnership's Senior Notes for an equivalent amount of Regency unsecured senior notes. $51.1 million of the Partnership's Senior Notes did not exchange and remain outstanding under an amended indenture with substantially all of the restrictive covenants and certain events of default eliminated.

The Partnership has the option to redeem all or a portion of the Senior Notes at any time on or after June 1, 2015 at the redemption prices specified in the indenture plus accrued and unpaid interest. The Partnership may also redeem the Senior Notes, in whole or in part, at a "make-whole" redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to June 1, 2015.

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Scheduled maturities of long-term debt as of December 31, 2014, were as follows:



	Principal Amount
	($ in thousands)
2015	$	—
2016	—
2017	—
2018	—
2019	263,720
2020 and after	—
	$	263,720

NOTE 9. MEMBERS’ EQUITY

At December 31, 2014, there were 150,154,909 common units outstanding. In addition, there were 2,419,750 unvested restricted common units outstanding.

On June 1, 2010, the Partnership launched its rights offering to the holders of its common and general partner units as of close of business on May 27, 2010, the record date. Each Right entitled the holder (including holders of Rights acquired during the subscription period) to purchase (i) one common unit and (ii) one warrant to purchase one additional common unit at $6.00 on certain specified days beginning on August 15, 2010 and ending on May 15, 2012. During the years ended December 31, 2013 and 2012 5,300,588 and 14,957,540 warrants, respectively, were exercised for an equivalent number of newly issued common units. The final exercise date for the warrants was May 15, 2012, and on that date the remaining unexercised warrants expired.

On May 31, 2012, the Partnership announced a program through which it may issue common units, from time to time, with an aggregate market value of up to $100 million. The Partnership is under no obligation to issue equity under the program. During the year ended December 31, 2014, no units were issued under this program. As of December 31, 2014, 686,759 units had been issued under this program for net proceeds of approximately $5.6 million.

On August 17, 2012, the Partnership closed an underwritten public offering of 10,120,000 common units, which included the full exercise of the underwriters' option to purchase additional common units to cover over-allotments, for net proceeds of approximately $84.3 million.

On March 12, 2013, the Partnership closed an underwritten public offering of 10,350,000 common units for net proceeds of approximately $92.3 million.

On October 27, 2014, the Partnership announced that the Board of Directors authorized 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 Partnership's 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 the Partnership to acquire any, or any specific number of, units and may be discontinued at any time. The Partnership intends to cancel any units it repurchases under the repurchase program. As of December 31, 2014, the Partnership had repurchased a total of 7,455,887 of its common units under this program for approximately $19.2 million, of which, transactions to repurchase 641,400 units had not settled as of December 31, 2014 and for which a liability of $1.3 million was recorded as part of accounts payable in the consolidated balance sheet.

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The table below summarizes the distributions paid or payable for the last three years



Quarter Ended	Distribution per Unit		Record Date**	Payment Date
March 31, 2012+	$	0.2200	May 8, 2012	May 15, 2012
June 30, 2012+	$	0.2200	August 7, 2012	August 14, 2012
September 30, 2012+	$	0.2200	November 7, 2012	November 14, 2012
December 31, 2012+	$	0.2200	February 7, 2013	February 14, 2013
March 31, 2013+*	$	0.2200	May 7, 2013	May 15, 2013
June 30, 2013+*	$	0.2200	August 7, 2013	August 14, 2013
September 30, 2013+*	$	0.1500	November 7, 2013	November 14, 2013
December 31, 2013+*	$	0.1500	February 7, 2014	February 14, 2014
March 31, 2014***	$	—	N/A	N/A
June 30, 2014***	$	—	N/A	N/A
September 30, 2014+*	$	0.07	November 7, 2014	November 14, 2014
December 31, 2014+*	$	0.07	February 6, 2015	February 13, 2015

_____________________________


+	The distribution per unit represents distributions made only on common units, including restricted common units issued under our Long Term Incentive Plan ("LTIP"). Since July 30, 2010, the only other class of equity we have outstanding is a non-economic general partner interest.


*	The distribution excludes certain restricted units under the LTIP.


**	The "Record Date" set forth in the table above means the close of business on each of the listed Record Dates.


***	No distribution was declared or paid for this period.

NOTE 10. RELATED PARTY TRANSACTIONS

The following table summarizes transactions between the Partnership and certain affiliated entities:



	Year Ended December 31,
	2014		2013		2012
Affiliates of Natural Gas Partners:	($ in thousands)
Natural gas purchases from affiliates	$	2,091	$	2,938	$	2,713
Payable as of December 31 (related to natural gas purchases)	$	—	$	18	$	428

The transactions above are all related to the Partnership's Midstream Business and have been classified as part of discontinued operations within the consolidated statements of operations and liabilities held for sale within the consolidated balance sheet (see Note 18).

In connection with the closing of the acquisition of certain fee minerals, royalties, overriding royalties and non-operated working interest properties from Montierra Minerals & Production, L.P. ("Montierra") and NGP-VII Co-Investment Opportunities, L.P. ("Co-Invest") on April 30, 2007, the Partnership entered into registration rights agreements with Montierra and Co-Invest. In the registration rights agreements, the Partnership agreed, for the benefit of Montierra and Co-Invest, to register the common units it holds, the common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.

In connection with the closing of the acquisition of all of the outstanding members interests of CC Energy II L.L.C. (together with its subsidiaries, "Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII"), the Partnership entered into a registration rights agreement ("Registration Rights Agreement") with NGP VIII. The Registration Rights Agreement grants NGP VIII and certain of its affiliates registration rights with respect to the common units acquired pursuant to the Partnership's acquisition of Crow Creek Energy and their outstanding warrants to purchase common units that were previously acquired by NGP VIII and certain of its affiliates in connection with the Partnership's previously completed recapitalization transaction. Pursuant to the Registration Rights Agreement, NGP VIII and certain of its affiliates have the ability to demand that the Partnership register for resale their common units acquired pursuant to the acquisition of Crow Creek Energy and their existing warrants to purchase common units. This registration may be an underwritten offering at the discretion of NGP VIII and certain of its affiliates. NGP VIII and certain of its affiliates may demand up to four such

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registrations, subject to an increase to up to seven if the registration rights are amended. Additionally, the Registration Rights Agreement provides that NGP VIII and certain of its affiliates have piggyback registration rights in certain circumstances, which would require inclusion of their common units and warrants on registration statements that the Partnership files, subject to certain customer exceptions. There are no limits on the number of times NGP VIII and certain of its affiliates can exercise these piggyback registration rights.

NOTE 11. RISK MANAGEMENT ACTIVITIES

Interest Rate Swap Derivative Instruments

To mitigate its interest rate risk, the Partnership enters into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.

For accounting purposes, the Partnership has not designated any of its interest rate derivative instruments as hedges; instead it marks these derivative contracts to fair value (see Note 12). Changes in fair values of the interest rate derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within other income (expense).

In November 2014, to align its interest rate swaps with the amendment to its revolving credit facility (see Note 8), the Partnership entered into the following transaction,


•	Reduced the notional value of its interest rate swaps from $250 million to $175 million;


•	Extended the original maturity date of June 22, 2015 to a new maturity date of December 31, 2019; and


•	Blended the existing swap rate for this extended swap with the then prevailing interest rate swap rate, which lowered the rate from 2.95% to 2.3195%.

There was no cost associated with this transaction.

The following table sets forth certain information regarding the Partnership's various interest rate swaps as of December 31, 2014:



Effective Date	Expiration Date	Notional Amount		Fixed Rate
12/31/2014	12/31/2019	$	175,000,000	2.3195	%

Commodity Derivative Instruments - Corporate

The prices of crude oil, natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors which are beyond the Partnership's control. These risks can cause significant changes in the Partnership's cash flows and affect its ability to achieve its distribution objectives and comply with the covenants of its revolving credit facility. In order to manage the risks associated with changes in the future prices of crude oil, natural gas and NGLs on its forecasted equity production, the Partnership engages in risk management activities that take the form of commodity derivative instruments. The Partnership has determined that it is necessary to hedge a substantial portion of its expected production in order to meaningfully reduce its future cash flow volatility. The Partnership generally limits its hedging levels to less than its total expected future production. While hedging at this level of production does not eliminate all of the volatility in the Partnership's cash flows, it allows the Partnership to mitigate the risk of situations where a modest loss of production would not put it in an over-hedged position. At times, the Partnership's strategy may involve entering into hedges with strike prices above current future prices or resetting existing hedges to higher price levels in order to meet its cash flow objectives or to stay in compliance with the covenants under its revolving credit facility. In addition, the Partnership may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges. Expected future production for its Upstream Business is derived from the proved reserves, adjusted for price-dependent expenses and revenue deductions. The Partnership applies the appropriate contract terms to these projections to determine its expected future equity share of the commodities.

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The Partnership uses fixed-price swaps, costless collars and put options to achieve its hedging objectives. Historically, the Partnership has hedged its expected future commodity volumes either with derivatives of the same commodity ("direct hedges") or with derivatives of another commodity which the Partnership expects will correlate well with the underlying commodity ("proxy hedges"). For example, the Partnership will often hedge the changes in future NGL prices using crude oil hedges because NGL prices have been highly correlated to crude oil prices and hedging NGLs directly is usually less attractive due to the relative illiquidity in the NGL forward market. The Partnership may use natural gas hedges to hedge a portion of its expected future ethane production because forward prices for ethane are often heavily discounted from its current prices. Also, natural gas prices provide support for ethane prices because in many processing plants ethane can be recombined with the residue gas stream and sold as natural gas. When the Partnership uses proxy hedges, it converts the expected volumes of the underlying commodity to equivalent volumes of the hedged commodity. In the case of NGLs hedged with crude oil derivatives,

these conversions are based on the historical relationship of the prices of the two commodities and management's judgment

regarding future price relationships of the commodities. In the case where ethane is hedged with natural gas derivatives, the

conversion is based on the thermal content of ethane. In recent quarters, the correlation of price changes in crude oil and NGLs

has weakened relative to longer-term averages as NGL prices have fallen while crude index prices have risen. This dynamic has

negatively impacted our hedging objectives

For accounting purposes, the Partnership has not designated any of its commodity derivative instruments as hedges; instead it marks these derivative contracts to fair value (see Note 12). Changes in fair values of the commodity derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within revenue.

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to counterparty credit risk. Historically, the Partnership's corporate derivative counterparties have all been participants or affiliates of participants within its revolving credit facility (see Note 8), which is secured by substantially all of the assets of the Partnership. Therefore, the Partnership is not currently required to post any collateral, nor does it require collateral from its counterparties. The Partnership minimizes the credit risk in derivative instruments by limiting exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's derivative contracts for certain counterparties are subject to counterparty netting agreements governing such derivatives, and when possible, the Partnership nets the open positions of each counterparty. See Note 12 for the impact to the Partnership's audited consolidated balance sheets of the netting of these derivative contracts.

The Partnership's commodity derivative counterparties as of December 31, 2014, included Wells Fargo Bank N.A., Comerica Bank, Bank of America Merrill Lynch, ING Capital Markets LLC, Regions Financial Corporation and CITIBANK, N.A.

The following tables set forth certain information regarding the Partnership's commodity derivatives. Within the table, some trades of the same commodities with the same tenors have been aggregated and shown as weighted averages.

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Commodity derivatives, as of December 31, 2014, that will mature during the years ended December 31, 2015, 2016, 2017, 2018 and 2019:



Underlying	Type	Notional Volumes (units) (a)	Floor Strike Price ($/unit)(b)		Cap Strike Price ($/unit)(b)
Portion of Contracts Maturing in 2015
Natural Gas	Swap (Pay Floating/Receive Fixed)	10,800,000	$	4.07
Crude Oil	Costless Collar	480,000	$	90.00	$	97.55
Crude Oil	Swap (Pay Floating/Receive Fixed)	630,000	$	89.78
Portion of Contracts Maturing in 2016
Natural Gas	Swap (Pay Floating/Receive Fixed)	9,480,000	$	4.25
Crude Oil	Swap (Pay Floating/Receive Fixed)	936,000	$	84.66
Portion of Contracts Maturing in 2017
Crude Oil	Swap (Pay Floating/Receive Fixed)	444,000	$	89.24
Portion of Contracts Maturing in 2018
Crude Oil	Swap (Pay Floating/Receive Fixed)	396,000	$	88.78
Portion of Contracts Maturing in 2019
Crude Oil	Swap (Pay Floating/Receive Fixed)	348,000	$	88.39

_______________________


(a)	Volumes of natural gas are measured in MMbtu, volumes of crude oil are measured in barrels, and volumes of natural gas liquids are measured in gallons.


(b)	Amounts represent the weighted average price. The weighted average prices are in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids.

Commodity Derivative Instruments - Marketing & Trading

Prior to the consummation of the Midstream Business Contribution, the Partnership conducted natural gas marketing and trading activities intended to capitalize on favorable price differentials between various receipt and delivery locations. This business was contributed to Regency as part of the Midstream Business Contribution completed on July 1, 2014. The assets and liabilities associated with this business have been classified as held for sale within the consolidated balance sheets and the operations as discontinued within the consolidated statements of operations (see Note 18).

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Fair Value of Interest Rate and Commodity Derivatives

Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the consolidated balance sheet as of December 31, 2014 and December 31, 2013:



	As of December 31, 2014
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	(3,165	)	Current liabilities	$	—
Interest rate derivatives - liabilities	Long-term assets	(2,641		)	Long-term liabilities	—
Commodity derivatives - assets	Current assets	47,971			Current liabilities	—
Commodity derivatives - assets	Long-term assets	49,130			Long-term liabilities	—
Commodity derivatives - assets	Assets held for sale	—			Liabilities held for sale	—
Commodity derivatives - liabilities	Current assets	—			Current liabilities	—
Commodity derivatives - liabilities	Long-term assets	—			Long-term liabilities	—
Commodity derivatives - liabilities	Assets held for sale	—			Liabilities held for sale	—
Total derivatives		$	91,295			$	—

	As of December 31, 2013
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	—		Current liabilities	$	(6,210	)
Interest rate derivatives - liabilities	Long-term assets	—			Long-term liabilities	(2,885		)
Commodity derivatives - assets	Current assets	6,841			Current liabilities	1,043
Commodity derivatives - assets	Long-term assets	4,669			Long-term liabilities	202
Commodity derivatives - assets	Assets held for sale	6,017			Liabilities held for sale	1,973
Commodity derivatives - liabilities	Current assets	(1,282		)	Current liabilities	(3,193		)
Commodity derivatives - liabilities	Long-term assets	(798		)	Long-term liabilities	(143		)
Commodity derivatives - liabilities	Assets held for sale	(824		)	Liabilities held for sale	(5,658		)
Total derivatives		$	14,623			$	(14,871	)

The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's audited consolidated statement of operations (in thousands):



Amount of Gain (Loss) Recognized in Income on Derivatives		Year Ended December 31,
		2014			2013			2012
Interest rate derivatives	Interest rate risk management losses, net	$	(1,734	)	$	(1,104	)	$	(4,727	)
Commodity derivatives	Commodity risk management gains (losses), net	94,431			(3,937		)	28,110
Commodity derivatives	Discontinued operations	(15,477		)	(14,596		)	29,784
Commodity derivatives -trading	Discontinued operations	(2,404		)	315			(192		)
	Total	$	74,816		$	(19,322	)	$	52,975

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NOTE 12. FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk inherent in the inputs to the valuation technique. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

The three levels of the fair value hierarchy are as follows:

Level 1 – Quoted prices are available in active markets for identical assets and liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the market place throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.

As of December 31, 2014, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and NGLs, at fair value. The Partnership reviews the classification of the inputs at the end of each period and has classified the inputs to measure the fair value of its interest rate swaps, crude oil derivatives and natural gas derivatives as Level 2. In addition, the Partnership recorded its investments in equity securities at fair value, and classified the inputs as Level 1.

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The following table discloses the fair value of the Partnership's derivative instruments and equity investments as of December 31, 2014 and 2013:



	As of December 31, 2014
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	78,516		$	—	$	—		$	78,516
Natural gas derivatives	—		18,585			—		—			18,585
Interest rate swaps	—		—			—		(5,806		)	(5,806		)
Equity investments	153,448		—			—		—			153,448
Total	$	153,448	$	97,101		$	—	$	(5,806	)	$	244,743

Liabilities:
Interest rate swaps	$	—	$	(5,806	)	$	—	$	5,806		$	—
Total	$	—	$	(5,806	)	$	—	$	5,806		$	—

____________________________


(a)	Represents counterparty netting under agreement governing such derivative contracts.



	As of December 31, 2013
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	6,151		$	—	$	(1,716	)	$	4,435
Natural gas derivatives	—		6,562			—		(1,567		)	4,995
NGL derivatives	—		42			—		(42		)	—
Total	$	—	$	12,755		$	—	$	(3,325	)	$	9,430

Liabilities:
Crude oil derivatives	$	—	$	(1,792	)	$	—	$	1,716		$	(76	)
Natural gas derivatives	—		(2,503		)	—		1,567			(936		)
NGL derivatives	—		(1,121		)	—		42			(1,079		)
Interest rate swaps	—		(9,095		)	—		—			(9,095		)
Total	$	—	$	(14,511	)	$	—	$	3,325		$	(11,186	)

____________________________


(a)	Represents counterparty netting under agreement governing such derivative contracts.

The tables above do not include the fair value of the derivative contracts that have been classified as assets and liabilities held for sale within the audited consolidated balance sheet (see Note 18).

Gains and losses, from continuing operations, related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the audited consolidated statements of operations. Gains and losses, from continuing operations, related to the Partnership's commodity derivatives are recorded as a component of revenue in the audited consolidated statements of operations.

Gains and losses associated with our short-term investments considered to be other than temporary are recorded in the audited consolidated statements of operations.

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Fair Value of Assets and Liabilities Measured on a Non-recurring Basis

For periods in which impairment charges have been incurred, the Partnership is required to write down the value of the

impaired asset to its fair value. See Note 5 for a further discussion of the impairment charges recorded during the year ended December 31, 2014. The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis for the year ended December 31, 2014:



	December 31, 2014		Level 1		Level 2		Level 3		Total Losses
	($ in thousands)
Proved properties	$	305,006	$	—	$	—	$	305,006	$	395,892
Plant assets	$	52	$	—	$	—	$	52	$	132
Pipeline assets	$	746	$	—	$	—	$	746	$	1,904
Rights-of-way	$	24	$	—	$	—	$	24	$	61

The plant, pipeline and rights-of-way assets and related impairment losses included in the table above are all attributable to the Partnership's Midstream Business and have been classified as discontinued operations within the consolidated statement of operations (see Note 18).

The Partnership calculated the fair value of the impaired assets using discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. Significant inputs to the valuation of fair value of the proved properties, plant, pipeline and intangible assets includes estimates of (i) future cash flows, including revenue, expenses and capital expenditures, (ii) timing of cash flows, (iii) forward commodity prices, adjusted for estimated location differentials, as of the impairment date and (iv) a discount rate reflective of the Partnership's cost of capital.

The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.

As of December 31, 2014, the outstanding debt associated with the Credit Agreement bore interest at a floating rate; as such, the Partnership believes that the carrying value of this debt approximates its fair value. The outstanding debt associated with the Senior Notes bore interest at a fixed rate; based on the market price of the Senior Notes as of December 31, 2014 and 2013, the Partnership estimates that the fair value of the Senior Notes, including amounts classified as held for sale, was $47.0 million and $599.5 million, respectively. Fair value of the senior notes was estimated based on prices quoted from third-party financial institutions, which are characteristic of Level 2 fair value measurement inputs.

NOTE 13. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation—The Partnership and its operating subsidiaries are subject to lawsuits which arise from time to time in the ordinary course of business. The Partnership had no accruals as of December 31, 2014 and 2013 related to legal matters and current lawsuits are not expected to have a material adverse effect on our financial position, results of operations or cash flows. Lawsuits the Partnership and/or its operating subsidiaries were subject to relating to the Partnership's midstream business were assumed by Regency on July 1, 2014 as part of the Midstream Business Contribution.

Insurance—The Partnership covers its operations and assets with insurance which management believes is consistent with that in force for other companies engaged in similar commercial operations with similar type properties. This insurance

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includes: (1) commercial general liability insurance covering liabilities to third parties for bodily injury, property damage and pollution arising out of the Partnership's operations; (2) workers’ compensation liability coverage for employees to required statutory limits; (3) automobile liability insurance covering liability to third parties for bodily injury and property damage arising out of the operation of all owned, hired and non-owned vehicles by its employees on company business; (4) property insurance covering the replacement cost of all owned real and personal property, including coverage for losses due to boiler and machinery breakdown, earthquake, flood and consequent business interruption/extra expense; (5) control of well/operator's extra expense insurance for operated and non-operated wells; and (6) corporate liability insurance including coverage for directors and officers and employment practices liabilities. In addition, the Partnership maintains excess liability insurance providing limits in excess of the established primary limits for commercial general liability and automobile liability insurance.

All coverages are subject to industry accepted policy terms, conditions, limits and deductibles comparable to that obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past year, reflecting the changing conditions in the insurance markets.

Environmental—Our business involves acquiring, developing and producing oil and natural gas working interests, and certain associated gathering and processing activities for our interests 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. The Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of developing and producing our oil and natural gas working interests, as well as planning, designing and operating our associated processing facility in Alabama, must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's combined results of operations, financial position or cash flows. At December 31, 2014 and 2013, the Partnership had accrued approximately $2.8 million and $2.5 million, respectively, for environmental matters. As of July 1, 2014, in connection with the Midstream Business Contribution, Regency agreed to indemnify the Partnership for losses arising from the Midstream Business, including potential losses associated with these laws and regulations and the Partnership agreed to use commercially reasonable efforts to mitigate such losses. Environmental accruals related to the Partnership's Midstream Business have been classified as liabilities held-for-sale within the consolidated balance sheet (see Note 18).

Retained Revenue Interest—Certain of the Partnership's assets are subject to retained revenue interests. These interests were established under purchase and sale agreements that were executed by the Partnership's predecessors in title. The terms of these agreements entitle the owners of the retained revenue interests to a portion of the revenues received from the sale of the hydrocarbons above specified base oil and natural gas prices. These retained revenue interests do not represent a real property interest in the hydrocarbons. The Partnership's reported revenues are reduced to account for the retained revenue interests on a monthly basis.

The retained revenue interests affect the Partnership's interest at the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama. With respect to the Partnership's Flomaton and Fanny Church fields, these retained revenue interests are in effect for any calendar year in which the Partnership surpasses certain average net production rates. The Partnership did not surpass such rates in 2014 and does not anticipate exceeding these rates in future years. With respect to the Partnership's Big Escambia Creek field, the retained revenue interest commenced in 2010 and continues through the end of 2019.

Other Commitments—The Partnership utilizes assets under operating leases for its corporate office, certain rights-of-way and facilities locations, vehicles and in several areas of its operations. Rental expense from continuing operations, including leases with no continuing commitment, amounted to approximately $2.6 million, $2.4 million and $3.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

At December 31, 2014, commitments under long-term non-cancelable operating leases for the next five years are as follows (in thousands):

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Year ending December 31,
2015	$	5,853
2016	$	3,899
2017	$	2,799
2018	$	438
2019	$	—

NOTE 14. EMPLOYEE BENEFIT PLAN

The Partnership offers a defined contribution benefit plan to its employees. For the three years ended December 31, 2014, the plan provided for a dollar for dollar matching contribution by the Partnership of up to 4% of an employee's contribution and 50% of additional contributions up to an additional 2%. Additionally, the Partnership may, at its sole discretion and election, contribute up to 6% of a participating employee's base salary annually, subject to vesting requirements. Expenses under the plan for the years ended December 31, 2014, 2013 and 2012 were approximately $1.1 million, $1.2 million and $0.8 million, respectively.

NOTE 15. INCOME TAXES

The Partnership's provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc, (acquiring entity of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (collectively the "Redman Acquisition") in 2007) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition in 2008) and their wholly owned corporations, Eagle Rock Upstream Development Company, Inc., (successor entity of certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity of certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”). In addition, the Partnership has become a taxable entity in the state of Texas. On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses.

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The Partnership's federal and state income tax provision is summarized below (in thousands):



	For the Year Ended December 31,
	2014			2013			2012
Current:
Federal	$	(475	)	$	(105	)	$	621
State	8			—			18
Total current provision	(467		)	(105		)	639
Deferred:
Federal	(2,593		)	(3,837		)	(2,776		)
State	(2,343		)	(1,653		)	1,044
Total deferred	(4,936		)	(5,490		)	(1,732		)
Total (benefit) provision for income taxes	$	(5,403	)	$	(5,595	)	(1,093		)

The effective rates for the years ended December 31, 2014, 2013 and 2012 are shown in the table below. In 2014, 2013 and 2012, the federal and state based income taxes were applied against book losses which resulted in effective tax rates of 1.5%, 2.4% and 3.3%, respectively. A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands):



	For the Year Ended December 31,
	2014			2013			2012
Pre-tax net book (loss) income from continuing operations	(357,770		)	(233,766		)	(33,239		)
State income tax current and deferred	(2,335		)	(1,653		)	1,062
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities	(2,680		)	(4,160		)	(2,155		)
Tax attributes used	(388		)	218			—
Benefit for income taxes from continuing operations	$	(5,403	)	$	(5,595	)	$	(1,093	)
Effective income tax rate on continuing operations	1.5		%	2.4		%	3.3		%

Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2014 and 2013 are as follows (in thousands):



	December 31, 2014			December 31, 2013
Deferred Tax Assets:
Statutory depletion carryover	$	1,842		$	1,438
Property, plant, equipment & amortizable assets	473			—
Total Deferred Tax Assets	2,315			1,438

Deferred Tax Liabilities:
Property, plant, equipment & amortizable assets	—			(2,011		)
Hedging transactions	(424		)	—
Book/tax differences from partnership investment	(29,897		)	(32,086		)
Total Deferred Tax Liabilities	(30,321		)	(34,097		)
Total Net Deferred Tax Liabilities	(28,006		)	(32,659		)
Current portion of total net deferred tax liabilities	—			—
Long-term portion of total net deferred tax liabilities	$	(28,006	)	$	(32,659	)

The largest single component of the Partnership's deferred tax liabilities is related to federal income taxes of the C Corporations described above, where the book/tax differences were created by the Redman and Stanolind Acquisitions. These book/tax temporary differences will be reduced as allocation of built-in gain in proportion to the assets contributed brings the

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book and tax basis closer together over time. This net deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets.

Due to the enactment of the Revised Texas Franchise Tax, the Partnership recorded a net deferred tax asset related to the book/tax differences in property, plant and equipment and hedging transactions.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2014, based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Partnership will realize the benefits of these deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

The Partnership adopted authoritative guidance related to accounting for uncertainty in income taxes on January 1, 2007. The Partnership has taken a position which is deemed to be “more likely than not” to be upheld upon review, if any, with respect to the deductibility of certain costs for the purpose of its franchise tax liability on a state franchise return. The Partnership has recorded a provision for the portion of this tax liability equal to the probability of recognition. In addition, the Partnership has accrued interest and penalties associated with these liabilities and has recorded these amounts within its state deferred income tax expense. The amount stated below relates to the tax returns filed for years ending 2012, 2011 and 2010 which are still open under current statute.

A reconciliation of the beginning and ending amount of the unrecognized tax benefits (liabilities) is as follows (in thousands):



	2014			2013			2012
Balance at beginning of period	$	(649	)	$	(830	)	$	(735	)
Increases related to current year tax positions	—			(128		)	(53		)
Increases related to tax interest and penalties	—			(39		)	(42		)
Decreases related to statutory limitations	226			267			—
Decreases related to tax interest and penalties	58			81			—
Balance at end of period	$	(365	)	$	(649	)	$	(830	)

NOTE 16. EQUITY-BASED COMPENSATION

Eagle Rock Energy G&P, LLC, the general partner of the general partner of the Partnership, has a long-term incentive plan, (as amended “LTIP”), for its employees, directors and consultants who provide services to the Partnership and its subsidiaries and affiliates. The LTIP provides for the issuance of an aggregate of up to 14,500,000 common units to be granted either as options, restricted units or phantom units, of which, as of December 31, 2014, a total of 6,475,632 common units remained available for issuance (which calculation reserves the maximum common units (i.e., 200%) that may potentially be earned and vested in respect of the outstanding performance units). Grants under the LTIP are made at the discretion of the board and to date have been made in the form of restricted units and performance units (i.e., phantom units subject to performance conditions). Distributions declared and paid on outstanding restricted units, where such restricted units are eligible to receive distributions, are paid directly to the holders of the restricted units. With respect to the performance units (as described below), distributions declared and paid will be grossed-up by an additional number of performance units as determined in the performance unit agreement. No options have been issued to date.

Restricted Units

Grants of restricted units eligible to receive distributions are valued at the market price as of the date issued, while grants of restricted units not eligible to receive distributions are valued at the market price as of the date issued less the present value of the expected distribution stream over the vesting period using the risk-free interest rate. The weighted average fair value of the units granted during the years ended December 31, 2014, 2013 and 2012 was $4.44, $9.16 and $9.50, respectively. The awards generally vest over three years on the basis of one third of the award each year.

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The Partnership recognizes compensation expense on a straight-line basis over the requisite service period for the restricted unit grants. During the restriction period, distributions associated with the grants of restricted units eligible to receive distributions are distributed to the awardees.

A summary of the changes in outstanding restricted common units for the year ended December 31, 2014 is provided below:



	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2013	2,743,807		$	9.37
Granted	1,903,333		$	4.44
Vested	(1,305,433	)	$	9.60
Forfeited	(921,957	)	$	8.12
Outstanding at December 31, 2014	2,419,750		$	6.06

Performance Units

On August 19, 2014, the Board of Directors of Eagle Rock Energy G&P, LLC, upon the recommendation of its compensation committee, approved a grant of 715,263 target performance unit awards to the Partnership's executive officers subject to performance and service-based vesting conditions pursuant to the LTIP. Performance units are described in the LTIP as phantom units subject to restrictions that lapse based on the performance of the Partnership, as measured by total unitholder return in comparison to a peer group of upstream master limited partnerships and a continued service requirement that spans a three-year period.

The performance units represent hypothetical common units of the Partnership and therefore do not carry any of the rights and privileges (including voting privileges) associated with actual common units. Performance units settle in common units rather than cash. The fair value of the performance units is estimated using a Monte Carlo simulation at the grant date. The Partnership recognizes compensation expense for the performance unit grants over the three-year vesting period.

The amount to vest each year for the three-year vesting period will be determined on each vesting date based on a two-step approach. The right to receive units with respect to the performance units depends first on the level of total unitholder return attained by the Partnership over the applicable performance period (generally July 1, 2014 through June 30, 2016), as measured against the Partnership's peer group. The number of units that may be earned will either by 0% for performance at anything less than the 50th percentile of the peer group, or in the range of 70% to 200% for performance from the 50th percentile to the 100th percentile of the peer group over the performance period. Second, the right to receive actual common units with respect to the earned performance units depends on the satisfaction of a continued service requirement, which is generally continued service through June 30, 2016 for two-thirds of the performance units and through June 30, 2017 for the remaining one-third of the performance units.

In the event the Partnership pays any distributions in respect of its outstanding units, the target performance units and any earned performance units will be grossed-up to reflect such distribution by an additional number of target performance units or earned performance units, as applicable. Any target performance units that do not become earned performance units shall terminate, expire and otherwise be forfeited by the named executive officer on the last day of the performance periods. Any earned performance units that vest (based on fulfillment of the continued service requirement) shall be converted into actual common units. Any earned performance units that do not vest (based on fulfillment of the continued service requirement) shall terminate, expire and otherwise be forfeited by the named executive officer.

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A summary of the changes in outstanding performance units for the year ended December 31, 2014 is provided below:



	Number of Performance Units		Weighted Average Fair Value
Outstanding at December 31, 2013	—		$	—
Granted	715,263		$	3.63
Forfeited	(67,475	)	3.59
Outstanding at December 31, 2014	647,788		3.63

Equity Based Compensation

For the years ended December 31, 2014, 2013 and 2012, non-cash compensation expense of approximately $8.2 million, $10.4 million and $7.7 million, respectively, was recorded related to the granted restricted units and performance units as general and administrative expense on the consolidated statements of operations.

As of December 31, 2014, unrecognized compensation costs related to the outstanding restricted units and performance units under the LTIP totaled approximately $12.2 million. The remaining expense is to be recognized over a weighted average of 2.0 years.

In connection with the vesting of certain restricted units during the years ended December 31, 2014, 2013 and 2012, 338,790, 272,179 and 286,716, respectively, of the newly-vested common units were cancelled by the Partnership in satisfaction of $1.4 million, $1.9 million and $2.5 million, respectively, of minimum employee tax liability paid by the Partnership. Pursuant to the terms of the LTIP, these cancelled units are available for future grants under the LTIP.

NOTE 17. EARNINGS PER UNIT

Basic earnings per unit is computed by dividing the net income (loss) by the weighted average number of units outstanding during a period. To determine net income (loss) allocated to each class of ownership (common and restricted common units), the Partnership first allocates net income (loss) in accordance with the amount of distributions made for the quarter by each class, if any. The remaining net income is allocated to each class in proportion to the class weighted average number of units outstanding for a period, as compared to the weighted average number of units for all classes for the period, with the exception of net losses. Net losses are allocated to just the common units.

As of December 31, 2014, 2013 and 2012, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units are considered in the diluted weighted average common unit outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.

The majority of the restricted units granted under the LTIP, as discussed in Note 16, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are required to be included in the computation of earnings per unit pursuant to the two-class method. Restricted units granted in 2013 to certain senior executives and members of the board of directors are not eligible to receive the distributions declared by the Partnership and therefore do not meet the definition of participating securities.

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The following table presents the Partnership's calculation of basic and diluted units outstanding for the periods indicated:



	Year Ended December 31,
	2014	2013	2012
	(in thousands)
Weighted average units outstanding during period:
Common units - Basic	156,700	153,562	135,609
Common units - Diluted	156,700	153,562	135,609

The following table presents the Partnership's basic and diluted income (loss) per unit for the year ended December 31, 2014:



	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(352,367	)
Distributions	21,763			$	21,464		$	299
Assumed loss from continuing operations after distribution to be allocated	(374,130		)	(374,130		)	—
Assumed allocation of loss from continuing operations	(352,367		)	(352,666		)	299
Discontinued operations, net of tax	212,460			212,460			—
Assumed net loss to be allocated	$	(139,907	)	$	(140,206	)	$	299

Basic loss from continuing operations per unit				$	(2.25	)
Basic discontinued operations per unit				$	1.36
Basic net loss per unit				$	(0.89	)

Diluted loss from continuing operations per unit				$	(2.25	)
Diluted discontinued operations per unit				$	1.36
Diluted net loss per unit				$	(0.89	)

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The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2013:



	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(228,171	)
Distributions	117,294			$	115,351		$	1,943
Assumed loss from continuing operations after distribution to be allocated	(345,465		)	(345,465		)	—
Assumed allocation of loss from continuing operations	(228,171		)	(230,114		)	1,943
Discontinued operations, net of tax	(49,808		)	(49,808		)	—
Assumed net loss to be allocated	$	(277,979	)	$	(279,922	)	$	1,943

Basic loss from continuing operations per unit				$	(1.50	)
Basic discontinued operations per unit				$	(0.32	)
Basic net loss per unit				$	(1.82	)

Diluted loss from continuing operations per unit				$	(1.50	)
Diluted discontinued operations per unit				$	(0.32	)
Diluted net loss per unit				$	(1.82	)

The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2012:



	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(32,146	)
Distributions	124,235			$	121,504		$	2,731
Assumed loss from continuing operations after distribution to be allocated	(156,381		)	(156,381		)	—
Assumed allocation of loss from continuing operations	(32,146		)	(34,877		)	2,731
Discontinued operations, net of tax	(118,456		)	(118,456		)	—
Assumed net loss to be allocated	$	(150,602	)	$	(153,333	)	$	2,731

Basic loss from continuing operations per unit				$	(0.26	)
Basic discontinued operations per unit				$	(0.87	)
Basic net loss per unit				$	(1.13	)

Diluted loss from continuing operations per unit				$	(0.26	)
Diluted discontinued operations per unit				$	(0.87	)
Diluted net loss per unit				$	(1.13	)

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NOTE 18. DIVESTITURE RELATED ACTIVITIES

As discussed in Note 1, on July 1, 2014, the Partnership completed the contribution of its Midstream Business to Regency. As a result of this transaction, the assets and liabilities of the Partnership's Midstream Business have been classified as held for sale and the operations as discontinued (See Note 1).

On December 20, 2012, the Partnership sold its Barnett Shale properties (which was accounted for in its Upstream Business). The Partnership received net proceeds of $14.8 million, which resulted in a loss on the sale of $4.5 million. The loss is included within impairment expense in the audited consolidated statement of operations. In addition, as this transaction did not meet the criteria for discontinued operations, the operations related to these assets are not included in the discontinued operations table below.

The following is the reconciliation of the major classes of assets and liabilities classified as held for sale.



	December 31, 2014		December 31, 2013
	($ in thousands)
Assets held-for-sale
Accounts Receivable	$	—	$	128,713
Property, plant and equipment	—		1,004,317
Intangible assets	—		102,352
Other current assets	—		5,663
Other long-term assets	—		18,337
Total assets held-for-sale	$	—	$	1,259,382

Liabilities held-for-sale
Long-term debt	$	—	$	494,582
Accounts payable and accrued liabilities	—		119,966
Other current liabilities	—		9,471
Other long-term liabilities	—		13,719
Total liabilities held-for-sale	$	—	$	637,738

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The following table represents the reconciliation of major classes of line items classified as discontinued operations for midstream business for the years ended December 31, 2014, 2013 and 2012:



	December 31, 2014			December 31, 2013			December 31, 2012

	($ in thousands)
Class of statement of operations line item of discontinued operations:
Revenues	$	552,574		$	997,907		$	752,644
Cost of natural gas, natural gas liquids, condensate and helium	447,519			790,618			532,719
Operations, maintenance and taxes other than income	50,154			101,121			82,526
General and administrative	18,392			28,083			19,004
Depreciation, amortization and impairment	41,936			77,726			202,249
Interest expense	27,350			49,973			35,202
Other (expense) income	(68		)	287			(10		)
Operating loss from discontinued operations before taxes	(32,845		)	(49,327		)	(119,066		)
Gain on sale of assets	243,637			—			—
Income tax expense	(1,668		)	481			(610		)
Discontinued operations, net of tax	$	212,460		$	(49,808	)	$	(118,456	)

Allocation of interest expense

Per accounting guidance provided by the FASB related to discontinued operations, interest on debt that is to be assumed by the buyer and interest on debt that is required to be repaid as a result of a disposal transaction should be allocated to discontinued operations. Per the Partnership's Credit Agreement, as a result of the contribution of the Midstream Business, the Partnership is required to pay down outstanding debt to the amount of the upstream portion of the borrowing base. Thus, interest expense in the table above includes the the interest expense related to the portion of the Partnership's unsecured Senior Notes exchanged for Regency unsecured senior notes on July 1, 2014 (see Note 1) and interest related to the difference between the total amount outstanding under the Credit Agreement and the upstream portion of the borrowing base.

Restructuring activities

In connection with the contribution of the Midstream Business to Regency, the Partnership accrued one-time employee termination benefits and lease payments of the partial abandonment of an operating lease of $4.0 million and $0.6 million during the year ended December 31, 2014. The accruals are recorded as part of accrued liabilities within the unaudited condensed consolidated balance sheet, while the expenses are recorded as part of discontinued operations within the unaudited condensed consolidated statement of operations. The following table summarizes activity related to liabilities associated with the Partnership's restructuring activities during the year ended December 31, 2014.



	Employee Related Costs			Facility and Other Costs			Total
	($ in thousands)
Balance at December 31, 2013	$	—		$	—		$	—
Additions	4,033			563			4,596
Payments and other adjustments	(3,198		)	(73		)	(3,271		)
Balance at December 31, 2014	$	835		$	490		$	1,325

In addition, in connection with the contribution of the Midstream Business, the Partnership incurred expenses of $1.7 million during the year ended December 31, 2014 to write-off certain software licenses used by the Midstream Business that were not acquired by Regency.

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NOTE 19. SUBSIDIARY GUARANTORS

The Partnership has issued registered debt securities guaranteed by its subsidiaries. As of December 31, 2014, all guarantors were wholly-owned or available to be pledged and such guarantees were joint and several and full and unconditional. Although the guarantees of our subsidiary guarantors are considered full and unconditional, the guarantees are subject to certain customary release provisions. Such guarantees will be released in the following circumstances:


•	in connection with any sale or other disposition of all or substantially all of the properties or assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us;


•	in connection with any sale or other disposition of capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us, such that, the guarantor ceases to be a restricted subsidiary of us as a result of the sale or other disposition;


•	if we designate any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the applicable provisions of the indenture;


•	upon legal defeasance or satisfaction and discharge of the indenture;


•	upon the liquidation or dissolution of such guarantor provided no default or event of default has occurred that is continuing;


•	at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers or any guarantor; or


•	upon such guarantor consolidating with, merging into or transferring all of its properties or assets to us or another guarantor, and as a result of, or in connection with, such transaction such guarantor dissolving or otherwise ceasing to exist.

In accordance with Rule 3-10 of Regulation S-X, the Partnership has prepared Condensed Consolidating Financial Statements as supplemental information. The following condensed consolidating balance sheets at December 31, 2014 and December 31, 2013, condensed consolidating statements of operations for the years ended December 31, 2014, 2013 and 2012, and condensed consolidating statements of cash flows for the years ended December 31, 2014, 2013 and 2012, present financial information for Eagle Rock Energy as the Parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the co-issuer and the subsidiary guarantors, which are all 100% owned by the Parent, on a stand-alone basis, and the consolidation and elimination entries necessary to arrive at the information for the Partnership on a consolidated basis. The subsidiary guarantors are not restricted from making distributions to the Partnership. Pursuant to the Contribution of the Midstream Business, all of the Partnership's Midstream Subsidiaries were contributed to Regency on July 1, 2014 and released from their guarantees under the indenture and Credit Agreement.

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Condensed Consolidating Balance Sheet

December 31, 2014



	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	838,656		$	—	$	—		$	—	$	(838,656	)	$	—
Other current assets	211,213			1		37,889			—		—			249,103
Total property, plant and equipment, net	1,334			—		486,654			—		—			487,988
Investment in subsidiaries	(413,023		)	—		—			—		413,023			—
Total other long-term assets	52,272			—		4,912			—		—			57,184
Total assets	$	690,452		$	1	$	529,455		$	—	$	(425,633	)	$	794,275
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—		$	—	$	838,656		$	—	$	(838,656	)	$	—
Other current liabilities	37,850			—		21,675			—		—			59,525
Other long-term liabilities	789			—		82,148			—		—			82,937
Long-term debt	263,343			—		—			—		—			263,343
Equity	388,470			1		(413,024		)	—		413,023			388,470
Total liabilities and equity	$	690,452		$	1	$	529,455		$	—	$	(425,633	)	$	794,275

Condensed Consolidating Balance Sheet

December 31, 2013



	Parent Issuer		Co-Issuer		Subsidiary Guarantors		Non-guarantor investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	691,588	$	—	$	—	$	—	$	(691,588	)	$	—
Assets held for sale	8,762		—		1,250,620		—		—			1,259,382
Other current assets	6,927		1		22,080		—		—			29,008
Total property, plant and equipment, net	2,318		—		822,133		—		—			824,451
Investment in subsidiaries	1,133,217		—		—		908		(1,134,125		)	—
Total other long-term assets	10,012		—		4,697		—		—			14,709
Total assets	$	1,852,824	$	1	$	2,099,530	$	908	$	(1,825,713	)	$	2,127,550
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	—	$	691,588	$	—	$	(691,588	)	$	—
Liabilities held for sale	500,291		—		137,447		—		—			637,738
Other current liabilities	15,688		—		66,141		—		—			81,829
Other long-term liabilities	5,486		—		71,138		—		—			76,624
Long-term debt	757,480		—		—		—		—			757,480
Equity	573,879		1		1,133,216		908		(1,134,125		)	573,879
Total liabilities and equity	$	1,852,824	$	1	$	2,099,530	$	908	$	(1,825,713	)	$	2,127,550

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Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2014



	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	93,940		$	—	$	204,264		$	—		$	—		$	298,204
Operations and maintenance	3			—		43,667			—			—			43,670
Taxes other than income	—			—		12,925			—			—			12,925
General and administrative	9,654			—		37,539			—			—			47,193
Depreciation, depletion and amortization	641			—		84,938			—			—			85,579
Impairment and other	—			—		395,892			—			—			395,892
Income (loss) from operations	83,642			—		(370,697		)	—			—			(287,055		)
Interest expense, net	(15,247		)	—		—			—			—			(15,247		)
Other non-operating income	16,998			—		4,741			—			(13,445		)	8,294
Other non-operating expense	(7,396		)	—		(7,783		)	—			13,445			(1,734		)
Loss on short term investments	(62,028		)	—		—			—			—			(62,028		)
Income (loss) before income taxes	15,969			—		(373,739		)	—			—			(357,770		)
Income tax benefit	(3,791		)	—		(1,612		)	—			—			(5,403		)
Equity in earnings of subsidiaries	(683,371		)	—		—			—			683,371			—
Loss from continuing operations	(663,611		)	—		(372,127		)	—			683,371			(352,367		)
Discontinued operations, net of tax	523,704			—		(311,235		)	(9		)	—			212,460
Net loss	$	(139,907	)	$	—	$	(683,362	)	$	(9	)	$	683,371		$	(139,907	)

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2013



	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(3,937	)	$	—	$	201,309		$	—		$	—		$	197,372
Operations and maintenance	—			—		41,426			—			—			41,426
Taxes other than income	—			—		12,928			—			—			12,928
General and administrative	13,145			—		39,986			—			—			53,131
Depreciation, depletion and amortization	454			—		88,990			—			—			89,444
Impairment	—			—		214,286			—			—			214,286
Loss from operations	(17,536		)	—		(196,307		)	—			—			(213,843		)
Interest expense, net	(17,891		)	—		(898		)	—			—			(18,789		)
Other non-operating income	9,025			—		9,298			—			(18,323		)	—
Other non-operating expense	(6,904		)	—		(12,553		)	—			18,323			(1,134		)
Loss before income taxes	(33,306		)	—		(200,460		)	—			—			(233,766		)
Income tax provision (benefit)	(1,653		)	—		(3,942		)	—			—			(5,595		)
Equity in earnings of subsidiaries	(191,071		)	—		—			—			191,071			—
Loss from continuing operations	(222,724		)	—		(196,518		)	—			191,071			(228,171		)
Discontinued operations, net of tax	(55,255		)	—		5,457			(10		)	—			(49,808		)
Net loss	$	(277,979	)	$	—	$	(191,061	)	$	(10	)	$	191,071		$	(277,979	)

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Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2012



	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	28,110		$	—	$	203,205		$	—		$	—		$	231,315
Operations and maintenance	—			—		41,391			—			—			41,391
Taxes other than income	—			—		15,343			—			—			15,343
General and administrative	8,745			—		42,245			—			—			50,990
Depreciation, depletion and amortization	296			—		90,214			—			—			90,510
Impairment	—			—		45,289			—			—			45,289
Income (loss) from operations	19,069			—		(31,277		)	—			—			(12,208		)
Interest expense, net	(16,299		)	—		23			—			—			(16,276		)
Other non-operating income	9,039			—		10,961			—			(20,000		)	—
Other non-operating expense	(12,189		)	—		(12,566		)	—			20,000			(4,755		)
Loss before income taxes	(380		)	—		(32,859		)	—			—			(33,239		)
Income tax provision (benefit)	1,041			—		(2,134		)	—			—			(1,093		)
Equity in earnings of subsidiaries	(113,200		)	—		—			—			113,200			—
Loss from continuing operations	(114,621		)	—		(30,725		)	—			113,200			(32,146		)
Discontinued operations, net of tax	(35,981		)	—		(82,457		)	(18		)	—			(118,456		)
Net loss	$	(150,602	)	$	—	$	(113,182	)	$	(18	)	$	113,200		$	(150,602	)

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Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2014



	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments		Consolidating Entries		Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(28,661	)	$	—	$	106,787		$	—	$	—	$	78,126
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	344			—		(137,038		)	—		—		(136,694		)
Proceeds from sale of short-term investments	43,836			—		—			—		—		43,836
Net cash flows provided by (used in) investing activities	44,180			—		(137,038		)	—		—		(92,858		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	472,500			—		—			—		—		472,500
Repayment of long-term debt	(966,700		)	—		—			—		—		(966,700		)
Payment of debt issuance cost	(1,984		)	—		—			—		—		(1,984		)
Proceeds from derivative contracts	(5,022		)	—		—			—		—		(5,022		)
Repurchase of common units	(19,170		)	—		—			—		—		(19,170		)
Distributions to members and affiliates	(34,982		)	—		—			—		—		(34,982		)
Net cash flows used in financing activities	(555,358		)	—		—			—		—		(555,358		)
Net cash flows provided by discontinued operations	541,288			—		30,047			22		—		571,357
Net increase (decrease) in cash and cash equivalents	1,449			—		(204		)	22		—		1,267
Cash and cash equivalents at beginning of year	1,237			1		(1,389		)	227		—		76
Cash and cash equivalents at end of year	$	2,686		$	1	$	(1,593	)	$	249	$	—	$	1,343

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Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2013



	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments		Consolidating Entries		Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(34,610	)	$	—	$	148,853		$	—	$	—	$	114,243
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(115		)	—		(149,829		)	—		—		(149,944		)
Proceeds from sale of asset	—			—		76			—		—		76
Net cash flows used in investing activities	(115		)	—		(149,753		)	—		—		(149,868		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	601,400			—		—			—		—		601,400
Repayment of long-term debt	(503,100		)	—		—			—		—		(503,100		)
Proceeds from derivatives contracts	1,323			—		—			—		—		1,323
Common unit issued in equity offerings	102,388			—		—			—		—		102,388
Issuance costs for equity offerings	(4,519		)	—		—			—		—		(4,519		)
Repurchase of common units	(1,858		)	—		—			—		—		(1,858		)
Distributions to members and affiliates	(125,911		)	—		—			—		—		(125,911		)
Net cash flows provided by financing activities	69,723			—		—			—		—		69,723
Net cash flows provided by (used in) discontinued operations	(35,431		)	—		1,343			41		—		(34,047		)
Net (decrease) increase in cash and cash equivalents	(433		)	—		443			41		—		51
Cash and cash equivalents at beginning of year	1,670			1		(1,832		)	186		—		25
Cash and cash equivalents at end of year	$	1,237		$	1	$	(1,389	)	$	227	$	—	$	76

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Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2012



	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments		Consolidating Entries			Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(108,061	)	$	—	$	183,397		$	—	$	—		$	75,336
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(1,551		)	—		(166,356		)	—		—			(167,907		)
Proceeds from sale of asset	—			—		15,398			—		—			15,398
Contribution to subsidiaries	(236,971		)	—		—			—		236,971			—
Net cash flows used in investing activities	(238,522		)	—		(150,958		)	—		236,971			(152,509		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	1,043,750			—		—			—		—			1,043,750
Repayment of long-term debt	(916,750		)	—		—			—		—			(916,750		)
Proceed from senior notes	22,889			—		—			—		—			22,889
Payments of debt issuance cost	(614		)	—		—			—		—			(614		)
Proceeds from derivative contracts	14,449			—		—			—		—			14,449
Common unit issued in equity offerings	96,173			—		—			—		—			96,173
Issuance costs for equity offerings	(4,518		)	—		—			—		—			(4,518		)
Exercise of Warrants	31,804			—		—			—		—			31,804
Repurchase of common units	(2,501		)	—		—			—		—			(2,501		)
Distributions to members and affiliates	(119,211		)	—		—			—		—			(119,211		)
Net cash flows provided by financing activities	165,471			—		—			—		—			165,471
Net cash flows provided by (used in) discontinued operations	181,463			—		(33,699		)	57		(236,971		)	(89,150		)
Net increase (decrease) in cash and cash equivalents	351			—		(1,260		)	57		—			(852		)
Cash and cash equivalents at beginning of year	1,319			1		(572		)	129		—			877
Cash and cash equivalents at end of year	$	1,670		$	1	$	(1,832	)	$	186	$	—		$	25

NOTE 20. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of proved oil and natural gas reserves is very complex, and requires significant subjective decisions in the evaluation of the available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and changing operating and market conditions. As a result, revisions to reserve estimates may occur from time to time. Although reasonable effort is made to ensure the reported reserve estimates are accurate, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

There are numerous uncertainties inherent in estimating the quantities of proved reserves, the future rates of production and the timing of development expenditures. Reserves data represent estimates only and should not be construed as being exact. Moreover, the Standardized Measure of Oil and Gas (“SMOG”) should not be construed as the current market value of the proved oil and natural gas reserves or as the costs that would be incurred to obtain equivalent reserves. A market

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value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risks.

Proved Reserves Summary

The following table illustrates the Partnership's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley, Gillespie and Associates. 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.

As shown in the following reconciliation table, the Partnership recognized significant negative revisions to its estimates of proved reserves in 2014. These revisions to previous estimates were primarily the result of recategorizing a number of undeveloped locations from proved to probable reserves due to poor expected economic performance (a decrease of 3.0 Bcfe), recategorizing other proved undeveloped locations as contingent resources since they were non-commercial at the time (a decrease of 0.2 Bcfe), and other factors including increased costs, negative changes to forecast performance expectations and widening product price differentials (a decrease of 44.6 Bcfe).

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	Proved Reserves
	Oil (MBbls)		Gas (MMcf)		Natural Gas Liquids (MBbls)
Proved reserves, January 1, 2012	11,522		234,022		11,347
Extensions and discoveries	1,405		31,524		2,136
Purchase of minerals in place	104		128		18
Production	(1,184	)	(16,443	)	(1,121	)
Sales of mineral in place	—		(13,331	)	—
Revision of previous estimates	1,137		(41,471	)	486
Proved reserves, December 31, 2012	12,984		194,429		12,866
Extensions and discoveries	2,712		29,137		3,180
Purchase of minerals in place	—		—		—
Production	(1,222	)	(12,804	)	(1,156	)
Revision of previous estimates	(932	)	(33,536	)	(253	)
Proved reserves, December 31, 2013	13,542		177,226		14,637
Extensions and discoveries	1,080		22,990		2,224
Purchase of minerals in place	326		769		170
Production	(1,313	)	(11,995	)	(1,158	)
Revision of previous estimates	(2,618	)	(19,897	)	(2,039	)
Proved reserves, December 31, 2014	11,017		169,093		13,834

Proved Developed Reserves
Proved developed reserves, January 1, 2012	10,271		165,269		9,307
Proved developed reserves, December 31, 2012	10,993		136,545		10,445
Proved developed reserves, December 31, 2013	10,153		126,950		10,766
Proved developed reserves, December 31, 2014	9,595		126,783		10,895

Proved Undeveloped Reserves
Proved undeveloped reserves, January 1, 2012	1,251		68,753		2,040
Proved undeveloped reserves, December 31, 2012	1,991		57,884		2,421
Proved undeveloped reserves, December 31, 2013	3,389		50,276		3,871
Proved undeveloped reserves, December 31, 2014	1,412		42,310		2,939

The primary drivers, other than production, behind the changes to our proved reserves for the years ended December 31, 2012, 2013 and 2014 are described in more detail below.

2012:


•	Purchase of minerals in place were insignificant in 2012;


•	extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma;


•	sales of minerals in place were related to the sale of our Barnett Shale assets in December 2012; and


•	revisions of previous estimates were primarily the result of lower natural gas prices which reduced the economic life and reserves of many wells.

2013:


•	Purchases and sales of minerals in place did not occur in 2013;

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•	extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma; and

•

revisions of previous estimates were the result of recategorizing a number of undeveloped locations from proved to probable reserves due to poor expected economic performance (a decrease of 27.8 Bcfe), recategorizing other proved undeveloped locations as contingent resources since they were non-commercial at the time (a decrease of 8.1Bcfe), changes in ownership of interests including those that occurred when third party owners elected to not participate in future drilling activities for certain wells (an increase of 1.6 Bcfe) and other factors including changes to costs (an increase of 2.5 Bcfe). All of these revisions were primarily in the Mid-Continent Region.

2014:


•	Purchases of minerals in place in 2014 included 3.7 Bcfe of proved developed producing reserves in the Big Escambia Creek field in Alabama, but there were no sales of minerals in place;


•	extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma and in addition, a number of well locations primarily in the Mid-Continent Region were moved to proved developed non-producing and proved undeveloped as a result of becoming economic at higher gas prices; and

•

revisions of previous estimates were the result of recategorizing a number of undeveloped locations from proved to probable reserves due to poor expected economic performance (a decrease of 3.0 Bcfe), recategorizing other proved undeveloped locations as contingent resources since they were non-commercial at the time (a decrease of 0.2Bcfe), and other factors including changes to costs, forecast performance expectations and product price differentials (a decrease of 44.6 Bcfe).

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization at December 31, 2014, 2013 and 2012:



	As of December 31, 2014			As of December 31, 2013			As of December 31, 2012
($ in thousands)
Proved properties	$	905,622		$	1,156,895		$	1,213,622
Unproved properties—excluded from depletion	7,512			10,022			31,823
Gross oil and gas properties	913,134			1,166,917			1,245,445
Accumulated depreciation, depletion, amortization	(431,555		)	(353,679		)	(269,376		)
Net oil and gas properties	$	481,579		$	813,238		$	976,069

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows for the years ended December 31, 2014, 2013 and 2012:



	Year Ended December 31,
	2014		2013		2012
($ in thousands)
Property acquisition costs, proved	$	10,861	$	—	$	2,582
Development costs	122,387		124,032		135,692
Total costs	$	133,248	$	124,032	$	138,274

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following information has been developed utilizing authoritative guidance procedures and is based on oil and natural gas reserves estimated by the Partnership's independent reserves engineer. It can be used for some comparisons, but should not be the only method used to evaluate the Partnership or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Partnership.

The Partnership believes that the following factors should be taken into account when reviewing the following information:


•	future costs and selling prices will probably differ from those required to be used in these calculations;


•	due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; and


•	a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues.

Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes were computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows were reduced to present value amounts by applying a 10% discount factor.

The Partnership's hydrocarbon reserves in Alabama and East Texas contain hydrogen sulfide that must be removed from the natural gas stream before the hydrocarbons are sold. As part of the process to remove the hydrogen sulfide, the Partnership produces and sells elemental sulfur. The Partnership generated revenue from the sale of sulfur of $8.2 million, $8.1 million and $14.0 million in 2014, 2013 and 2012, respectively. The cost of removing the sulfur is included in the future production costs in the Standardized Measure table below. However, since sulfur is not considered a hydrocarbon, revenues from the sale of sulfur are excluded from the computation of the Standardized Measure.

The Standardized Measure is as follows as of December 31, 2014, 2013 and 2012:



	As of December 31, 2014			As of December 31, 2013			As of December 31, 2012

($ in thousands)
Future cash inflows	$	2,187,346		$	2,423,350		$	2,279,735
Future production costs	(759,966		)	(737,468		)	(767,004		)
Future development costs	(240,886		)	(318,778		)	(354,690		)
Future net cash flows before income taxes	1,186,494			1,367,104			1,158,041
Future income tax (expense) benefit	(833		)	(1,212		)	(1,086		)
Future net cash flows before 10% discount	1,185,661			1,365,892			1,156,955
10% annual discount for estimated timing of cash flows	(591,421		)	(715,386		)	(621,826		)
Total standardized measure of discounted future net cash flows	$	594,240		$	650,506		$	535,129

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Partnership's proved oil and natural gas reserves for the years ended December 31, 2014, 2013 and 2012:

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	Year Ended December 31,
	2014			2013			2012

($ in thousands)
Beginning of year	$	650,506		$	535,129		$	642,586
Sale of oil and gas produced, net of production costs	(152,097		)	(150,457		)	(132,451		)
Net changes in prices and production costs	(63,142		)	2,720			(78,247		)
Extensions, discoveries and improved recovery, less related costs	74,684			136,464			66,460
Previously estimated development costs incurred during the period	49,409			21,470			53,111
Net changes in future development costs	71,800			107,951			36,914
Revisions of previous quantity estimates	(149,993		)	(103,351		)	(76,434		)
Purchases of property	11,904			—			2,811
Sales of property	—			—			(5,063		)
Accretion of discount	59,818			49,233			60,734
Net changes in income taxes	169			(36		)	317
Other	41,182			51,383			(35,609		)
End of year	$	594,240		$	650,506		$	535,129

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Results of Operations

The following are the results of operations for the Partnership's oil and natural gas producing activities for the years ended December 31, 2014, 2013 and 2012:



	Year Ended December 31,
	2014			2013			2012
($ in thousands)
Revenues:
Sales to third parties	$	190,057		$	146,210		$	135,842
Intercompany sales	5,475			47,048			53,343
Total revenues	195,532			193,258			189,185
Costs and expenses:
Production costs	56,595			54,354			56,734
General and administrative	8,166			11,419			12,162
Depreciation, depletion, and amortization	81,030			87,456			88,777
Impairment and other	395,892			214,286			45,289
Total costs and expenses	541,683			367,515			202,962
Total result of operations	$	(346,151	)	$	(174,257	)	$	(13,777	)

* * * *

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Index to Exhibits



Exhibit Number	Description

2.1	Contribution Agreement dated as of December 23, 2013, by and among Eagle Rock Energy Partners, L.P., Regency Energy Partners LP and Regal Midstream LLC (incorporated by reference to Exhibit 2.1 to the registrant's Current Report on Form 8-K filed with the Commission on December 26, 2013)

3.1	Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 4.2 of the registrant's Current Report on Form 8-K filed with the Commission on July 30, 2010)

3.2	Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 of the registrant's Current Report on Form 8-K filed with the Commission on July 30, 2010)

3.3	Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant's Current Report on Form 8-K filed with the Commission on May 25, 2010)

3.4	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant's registration statement on Form S-1 (File No. 333-134750))

3.5	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 of the registrant's registration statement on Form S-1 (File No. 333-134750))

3.6	Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750))

3.7	Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 of the registrant's registration statement on Form S-1 (File No. 333-134750))

4.1	Third Supplemental Indenture dated as of July 1, 2014, among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the registrant's Current Report on Form 8-K filed with the Commission on July 3, 2014)

4.2	Second Supplemental Indenture dated as of November 19, 2012, among Eagle Rock Crude Pipelines, LLC, a subsidiary of Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.4 to the registrant's Form S-4 filed with the Commission on November 20, 2012)

4.3	First Supplemental Indenture dated as of June 28, 2011, among Eagle Rock Gas Services, LLC, a subsidiary of Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to the registrant's Quarterly Report on Form 10-Q filed with the Commission on August 4, 2011)

4.4	Indenture dated as of May 27, 2011 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the registrant's Current Report on Form 8-K filed with the Commission on May 27, 2011)

4.5	Registration Rights Agreement dated May 3, 2011 by and between Eagle Rock Energy Partners, L.P. and Natural Gas Partners VIII, L.P. (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on May 3, 2011)

4.6	Form of Common Unit Certificate (included as Exhibit A to the Second Amended and Restated Partnership Agreement of Eagle Rock Energy Partners, L.P.) (incorporated by reference to Exhibit 3.1 of the registrant’s Current Report on Form 8-K filed on May 25, 2010)

10.1	Fifth Amendment to the Amended and Restated Credit Agreement and First Amendment to Amendment and Restated Guaranty and Collateral Agreement, dated as of October 10, 2014, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on October 14, 2014)

10.2	Borrowing Base and Fourth Amendment to the Amended and Restated Credit Agreement, effective as of May 28, 2014, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on May 29, 2014)

10.3	Third Amendment to the Amended and Restated Credit Agreement, effective as of February 26, 2014, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on February 27, 2014)

10.4	Second Amendment to the Amended and Restated Credit Agreement, dated as of July 23, 2013, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on July 23, 2013)

10.5	First Amendment to Amended and Restated Credit Agreement by and between Agreement by and among the Partnership, the lenders party thereto and Wells Fargo Bank, National Association, as the administrative agent, dated December 28, 2012 (incorporated by reference to the registrant's Current Report on Form 8-K filed on December 31, 2012).

10.6	Amended and Restated Credit Agreement, dated as of June 22, 2011, among Eagle Rock Energy Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, and BNP Paribas, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on June 23, 2011)

F- 51

Table of Contents



Exhibit Number	Description

10.7**	Administrative Services Agreement, dated as of July 30, 2010, between Eagle Rock Energy Partners, L.P. and Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on July 30, 2010)

10.8**	Voting Agreement dated May 3, 2011 by and between Eagle Rock Energy Partners, L.P. and Natural Gas Partners VIII, L.P. (incorporated by reference to Exhibit 10.2 to the registrant's Current Report on Form 8-K filed with the Commission on May 3, 2011)

10.9†	Raw Product Purchase and Sale Agreement, by and between Phillips 66 Company and Eagle Rock Field Services, L.P., dated December 23, 2013, (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K/A filed on February 28, 2014)

10.10	Second Amendment to Gas Gathering and Processing Agreement, by and between BP America Production Company and Eagle Rock Field Services, L.P., dated July 1, 2013(incorporated by reference to Exhibit 10.3 to the registrant's Quarterly Report on Form 10-Q filed with the Commission on November 1, 2013)

10.11	First Amendment to Gas Gathering and Processing Agreement, by and between BP America Production Company and Eagle Rock Field Services, L.P., dated July 1, 2013 (incorporated by reference to Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q filed with the Commission on November 1, 2013)

10.12†	Gas Gathering and Processing Agreement by and between BP America Production Company and Eagle Rock Field Services, L.P., dated as of October 1, 2012 (incorporated by reference to Exhibit 10.1 of the registrant's Current Report on Form 8-K filed on October 2, 2012)

10.13**	Confidentiality and Noncompete Agreement by and between Eagle Rock Energy G&P, LLC and Joseph A. Mills dated August 3, 2012 (incorporated by reference to Exhibit 10.2 of the registrant's Current Report on Form 10-Q filed on August 6, 2012)

10.14**	Confidentiality and Noncompete Agreement by and between Eagle Rock Energy G&P, LLC and Jeffrey P. Wood dated August 3, 2012 (incorporated by reference to Exhibit 10.3 of the registrant's Current Report on Form 10-Q filed on August 6, 2012)

10.15**	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC. and Charles C. Boettcher dated August 3, 2012 (incorporated by reference to Exhibit 10.4 of the registrant's Current Report on Form 10-Q filed on August 6, 2012)

10.16**	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Joseph Schimelpfening dated August 3, 2012 (incorporated by reference to Exhibit 10.5 of the registrant's Current Report on Form 10-Q filed on August 6, 2012)

10.17**	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Steven Hendrickson dated August 3, 2012 (incorporated by reference to Exhibit 10.6 of the registrant's Current Report on Form 10-Q filed on August 6, 2012)

10.18**	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Robert Hallett dated May 1, 2012

10.19**	Form of Confidentiality, Non-Competition and Non-Solicitation Agreement (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on March 26, 2012)

10.20**	Form of Supplemental Indemnification Agreement among Eagle Rock Energy G&P, LLC, Eagle Rock Energy GP, L.P., Eagle Rock Energy Partners, L.P. and officers and directors of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 10.1 of the registrant's Current Report on Form 8-K filed with the Commission on December 30, 2009)

10.21**	Executive Change of Control Agreement Policy (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on July 28, 2010)

F- 52

Table of Contents



Exhibit Number	Description

10.22**	Form of Executive Change of Control Agreement (incorporated by reference to Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on July 28, 2010)

10.23**	Amended and Restated Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan effective June 24, 2014 (incorporated by reference to Exhibit 10.1 of the registrant's Current Report on Form 8-K filed on August 20, 2014)

10.24**	Form of Restricted Unit Agreement under the Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the registrant's Current Report on Form 8-K filed on August 20, 2014)

10.25**	Form of Performance Unit Agreement under the Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on August 20, 2014)

10.26**†	Eagle Rock Energy G&P, LLC 2014 Short-Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on February 28, 2014)

10.27**	Master Agreement between Eagle Rock Energy G&P, LLC and Roger A. Fox dated September 16, 2014, incorporated by reference to Exhibit 10.2 of the registrant's Quarterly Report on Form 10-Q filed with the Commission on October 31, 2014)

12.1*	Statement Regarding Computation of Ratio of Earnings to Fixed Charges

14.1	Code of Ethics for Chief Executive Officer and Senior Financial Officers posted on the Company’s website at www.eaglerockenergy.com.

21.1*	List of Subsidiaries of Eagle Rock Energy Partners, L.P.

23.1*	Consent of KPMG LLP

23.2*	Consent of Cawley, Gillespie & Associates, Inc.

31.1*	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002

31.2*	Certification of Periodic Financial Reports by Robert M. Haines in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002

32.1***	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002

32.2***	Certification of Periodic Financial Reports by Robert M. Haines in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002

99.1*	Report of Cawley, Gillespie & Associates, Inc.

101.INS*	XBRL Instance Document

101.SCH*	XBRL Taxonomy Extension Schema Document

101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*	XBRL Taxonomy Extension Label Linkbase Document

101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document


*	Filed herewith


**	Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.


***	Furnished herewith


†	Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

F- 53

EXHIBIT 12.1

RATIO OF EARNINGS TO FIXED CHARGES

The table below sets forth the Ratios of Earnings to Fixed Charges for us for the periods indicated. On October 26, 2006, we completed our initial public offering whereby we became the successor to the business of Eagle Rock Pipeline, L.P. For purposes of computing the ratios of earnings to fixed charges, earnings consist of income (loss) from continuing operations before adjustment for equity income from equity method investees, and our share of pretax losses of investees for which charges arising from guarantees are included in fixed charges, each as accounted for under the equity method, less capitalized interest, preference security dividend requirements of consolidated subsidiaries, and the non-controlling interest in pre-tax income of subsidiaries that have not incurred fixed charges. Fixed charges consist of the sum of interest expensed and capitalized, plus amortized premiums, discounts and capitalized expenses related to indebtedness, an estimated interest component of rental expense, and preference security dividend requirements of consolidated subsidiaries.



	Years Ended December 31,
	2010		2011		2012		2013		2014
($ in thousands)
Interest expense	24,697		27,841		26,503		25,545		20,270
Capitalized interest	—		—		—		—		265
Estimated interest associated with rental expense (a)	186		351		1,251		808		862
Total fixed charges	24,883		28,192		27,754		26,353		21,397

Net income (loss) from continuing operations before income taxes	(43,452	)	50,299		(33,239	)	(233,766	)	(357,770	)
Capitalized interest	—		—		—		—		(265	)
Depreciation of capitalized interest	—		—		—		—		7
Fixed charges	24,883		28,192		27,754		26,353		21,397
Total earnings	(18,569	)	78,491		(5,485	)	(207,413	)	(336,631	)

Ratio of earnings to fixed charges (b)	—	%	278.42	%	—	%	—	%	—	%

______________________________


(a)	Calculated as one third of rent expense, which is a reasonable approximation of the interest factor.


(b)	For the years ended December 31, 2010, 2012, 2013 and 2014, earnings were inadequate to cover fixed charges by $43.5 million, $33.2 million, $233.8 million and $358.0 million, respectively.

Exhibit 21.1

List of Subsidiaries of Eagle Rock Energy Partner, L.P



Subsidiary		Jurisdiction of Formation
Eagle Rock Energy Finance Corp.		Delaware
EROC Production, LLC		Delaware
Eagle Rock Energy Acquisition Co., Inc.		Delaware
Eagle Rock Upstream Development Company, Inc.		Delaware
Eagle Rock Acquisition Partnership, L.P.		Delaware
Eagle Rock Upstream Development II, L.P.		Texas
Eagle Rock Energy Acquisition Co. II, Inc.		Delaware
Eagle Rock Upstream Development Company II, Inc.		Delaware
Eagle Rock Acquisition Partnership II, L.P.		Delaware
Escambia Operating Co. LLC		Delaware
Escambia Asset Co. LLC		Delaware
Eagle Rock Energy G&P Holding, Inc.		Delaware
Eagle Rock Energy G&P, LLC		Delaware
Eagle Rock Energy GP, L.P.		Delaware
Eagle Rock Mid-Continent Holding, LLC		Delaware
Eagle Rock Mid-Continent Asset, LLC		Delaware
Eagle Rock Mid-Continent Operating, LLC		Delaware

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P.:

We consent to the incorporation by reference in the registration statements on Form S-3 (No. 333‑147244, No. 333-187553 and No. 333-198824), on Form S-4 (No. 333-177958), and on Form S-8 (No. 333-169472) of Eagle Rock Energy Partners, L.P. of our reports dated March 2, 2015, with respect to the consolidated balance sheets of Eagle Rock Energy Partners, L.P. as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, members’ equity, and cash flows for each of the years in the three-year period ended December 31, 2014, and the effectiveness of internal control over financial reporting as of December 31, 2014, which report appears in the December 31, 2014 annual report on Form 10‑K of Eagle Rock Energy Partners, L.P.

/s/ KPMG LLP

Houston, Texas

March 2, 2015

EXHIBIT 23.2

CONSENT OF CAWLEY, GILLESPIE & ASSOCIATES, INC.

The undersigned hereby consents to the inclusion of the information included in this Annual Report on Form 10-K with respect to the oil and gas reserves of Eagle Rock Energy Partners, L.P. as of the year ended December 31, 2014. We hereby further consent to all references to our firm included in this Annual Report on Form 10-K and to the incorporation by reference in the Registration Statements on Form S-3, No. 333-147244, No. 333-187553 and No. 333-198824, and the Registration Statement on Form S-8, No. 333-169472, of such information.

/s/ CAWLEY, GILLESPIE & ASSOCIATES, INC.

Fort Worth, Texas

March 2, 2015

Exhibit 31.1

I, Joseph A. Mills, certify that:


1.	I have reviewed this annual report on Form 10-K for the year ended December 31, 2014 of Eagle Rock Energy Partners, L.P.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a - 15(f) and 15d - 15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	March 2, 2015	/s/ JOSEPH A. MILLS
		Joseph A. Mills
		Chief Executive Officer of Eagle Rock Energy G&P, LLC,
		General Partner of Eagle Rock Energy GP, L.P.,
		General Partner of Eagle Rock Energy Partners, L.P.

Exhibit 31.2

I, Robert M. Haines, certify that:


1.	I have reviewed this annual report on Form 10-K for the year ended December 31, 2014 of Eagle Rock Energy Partners, L.P.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a - 15(f) and 15d - 15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	March 2, 2015	/s/ ROBERT HAINES
		Robert M. Haines
		Senior Vice President
		Chief Financial Officer of Eagle Rock
		Energy G&P, LLC, General Partner of Eagle Rock
		Energy GP, L.P., General Partner of Eagle Rock
		Energy Partners, L.P.

Exhibit 32.1

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

In connection with the Annual Report of Eagle Rock Energy Partners, L.P. (the Partnership) on Form 10-K for the year ended December 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Joseph A. Mills, Chief Executive Officer of Eagle Rock Energy G&P, LLC, the general partner of Eagle Rock Energy GP, L.P., the general partner of the Partnership, hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. § 1350), that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.



Date:	March 2, 2015	/s/ JOSEPH A. MILLS
		Joseph A. Mills
		Chief Executive Officer of Eagle Rock Energy G&P, LLC,
		General Partner of Eagle Rock Energy GP, L.P.,
		General Partner of Eagle Rock Energy Partners, L.P.

Exhibit 32.2

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

In connection with the Annual Report of Eagle Rock Energy Partners, L.P. (the Partnership) on Form 10-K for the year ended December 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Robert Haines, Senior Vice President and Chief Financial Officer of Eagle Rock Energy G&P, LLC, the general partner of Eagle Rock Energy GP, L.P., the general partner of the Partnership, hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. § 1350), that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.



Date:	March 2, 2015	/s/ ROBERT HAINES
		Robert Haines
		Senior Vice President and
		Chief Financial Officer of Eagle Rock
		Energy G&P, LLC, General Partner of Eagle Rock
		Energy GP, L.P., General Partner o Eagle Rock
		Energy Partners, L.P.

EXHIBIT 99.1

CAWLEY, GILLESPIE & ASSOCIATES, INC.



PETROLEUM CONSULTANTS
13640 BRIARWICK DRIVE, SUITE 100	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1707	FORT WORTH, TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
512-249-7000	817-336-2461	713-651-9944
	www.cgaus.com

February 11, 2015

Mr. Kevin D. Neeley

Director - A&D and Reserves

Eagle Rock Energy Partners, L.P.

1415 Louisiana Street, Suite 2700

Houston, TX 77002

Re: Evaluation Summary

Eagle Rock Energy Partners, L.P. Interests

Total Proved Reserves

Certain Properties in Various States

As of December 31, 2014

Pursuant to the Guidelines of the

Securities and Exchange Commission for

Reporting Corporate Reserves and

Future Net Revenue

Dear Mr. Neeley:

As requested, we are submitting our estimates of total proved reserves and forecasts of economics attributable to the interests located in certain properties in various states within the United States. This report, completed February 11, 2015 covers 100% of the proved reserves estimated for Eagle Rock Energy Partners, L.P. (“Eagle Rock”). This evaluation utilized an effective date of December 31, 2014, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (“SEC”). This report was prepared for the preparation of the Eagle Rock 2014 10-K filing.

The reserves and economics for the Total Proved, Proved Developed and Proved Undeveloped are summarized as follows:

Eagle Rock Energy Partners, L.P. Interests

February 11, 2015

Page 2



	Proved
	Total		Developed		Undeveloped

Net Reserves
Oil - Mbbl	11,016.5		9,595.3		1,421.2
Gas - MMcf	169,092.6		126,783.0		42,309.6
NGL - Mbbl	13,834.0		10,895.2		2,938.7
Net Revenue
Oil - M$	969,060.4		836,134.6		132,925.9
Gas - M$	736,450.7		550,920.5		185,530.3
NGL - M$	481,834.5		389,475.4		92,359.1
Exxon Retained - M$	(24,178.7	)	(24,178.7	)	—
Other Revenue - M$	—		—		—

Severance Taxes - M$	147,768.0		121,266.9		26,501.1
Ad Valorem Taxes - M$	19,035.1		17,163.0		1,872.1
Operating Expenses - M$	479,677.8		448,431.9		31,245.9
Other Deductions - M$	89,306.2		65,662.2		23,644.0
Investments - M$	240,886.0		130,964.5		109,921.6
Net Operating Income (BFIT) - M$	1,186,493.8		968,863.3		217,630.5
Discounted @ 10% - M$	583,205.9		513,574.8		69,631.1
(Present Worth)

The Proved Developed reserves are the summation of the Proved Developed Producing (“PDP”), Proved Developed Non-Producing (“PDNP”) and Proved Developed Shut-In (“PDSI”) estimates. The Proved Developed reserves and economics, with a breakout of PDP, PDNP and PDSI, are summarized as follows:



	Proved Developed
	Total		Producing		Non-Producing	Shut-In

Net Reserves
Oil - Mbbl	9,595.3		9,028.9		566.4	—
Gas - MMcf	126,783.0		115,852.5		10,930.5	—
NGL - Mbbl	10,895.3		10,106.1		789.2	—
Net Revenue
Oil - M$	836,134.5		783,827.5		52,307.0	—
Gas - M$	550,920.5		504,073.7		46,846.8	—
NGL - M$	389,475.4		363,088.8		26,386.6	—
Exxon Retained - M$	(24,178.7	)	(24,178.7	)	—	—
Other Revenue - M$	—		—		—	—

Severance Taxes - M$	121,266.9		113,521.2		7,745.7	—
Ad Valorem Taxes - M$	17,163.0		15,929.9		1,233.1	—
Operating Expenses - M$	448,431.9		439,885.8		8,546.1	—
Other Deductions - M$	65,662.2		60,035.5		5,626.7	—
Investments - M$	130,964.5		111,883.2		19,081.3	—
Net Operating Income (BFIT) - M$	968,863.3		885,555.7		83,307.6	—
Discounted @ 10% - M$	513,574.8		484,080.6		29,494.2	—
(Present Worth)

Eagle Rock Energy Partners, L.P. Interests

February 11, 2015

Page 3

Net revenue is prior to deducting state production taxes and Ad Valorem taxes. Future net cash flow is after deducting these taxes, future capital costs, operating expenses and other deductions, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

The oil reserves include oil and condensate. Oil and natural gas liquid (NGL) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.

Hydrocarbon Pricing

The base oil and gas prices calculated for December 31, 2014 were $94.99/BBL and $4.35/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price and NGL price is based upon WTI-Cushing oil spot prices during 2014 and the base gas price is based upon Henry Hub spot prices during 2014.

The base prices were adjusted for oil, NGL and gas differentials, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices over the life of the total proved properties were estimated to be $87.964 per barrel of oil, $4.355 per mcf of natural gas and $34.830 per barrel of natural gas liquids. All economic factors were held constant in accordance with SEC guidelines. No revenues obtained from the sale of sulfur products are included in this report.

Economic Parameters

Ownership was accepted as furnished and has not been independently confirmed. Oil, NGL and gas price differentials, lease operating expenses (LOE), other deductions and investments were calculated and prepared by you and were thoroughly reviewed by us for accuracy and completeness. LOE (column 22) was determined at the well level using averages determined from historical lease operating statements. Other Deductions (column 27) are expenses calculated by volume and include compression-gathering expenses, transportation costs and water disposal costs. All economic parameters, including expenses and investments, were held constant (not escalated) throughout the life of these properties.

Severance tax rates were applied at normal state percentages of oil and gas revenue. Ad valorem tax rates were forecast as provided by Eagle Rock.

Exxon Retained Revenue

In certain properties and time periods, the future cash flow estimates in this reserve report include a reduction to future revenues due to a “Retained Revenue Interest” owned by ExxonMobil. These interests were retained by ExxonMobil at the time they sold them to Eagle Rock’s predecessors, and remain in effect. In general, these interests require Eagle Rock to make payments of a percentage of the revenues received over a Base Price from the sale of oil, natural gas and/or natural gas liquids production. Except for severance taxes, the interests are free of operating and capital expenses. The effect of the interest has been treated as a reduction to the revenues that Eagle Rock will derive from the sale of its reserves. An Exxon Retained section is included that contains only the revenue from the Retained Revenue Interest.

Eagle Rock Energy Partners, L.P. Interests

February 11, 2015

Page 4

The Retained Revenue Interest does not necessarily apply to all of the interest that Eagle Rock owns in the wells that are subject to the interest, nor does it necessarily apply to all of the wells in the fields in which the subject wells are located. This is due to the fact that Eagle Rock’s predecessors did not acquire all of the interest that Eagle Rock now owns from ExxonMobil. The portions of Eagle Rock’s ownership that was acquired from other parties are not subject to the Retained Revenue Interest.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

This evaluation includes 97 PUD locations based in various fields throughout the United States. Each of these drilling locations proposed as part of Eagle Rock’s development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, Eagle Rock has indicated they have intent to complete this development plan within the next five (5) years. Furthermore, Eagle Rock has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five (5) year development plan will be fully executed.

Reserve Estimation Methods

Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to offset production, both of which are considered to provide a relatively high degree of accuracy. In the Big Escambia Creek and Flomaton fields in Alabama, Eagle Rock’s pentane volumes are shown separately in the plant statements and are not tracked in public records. Therefore, these volumes were added to the condensate yield in this report to properly match the company’s sales volumes.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for Eagle Rock properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

General Discussion

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

Eagle Rock Energy Partners, L.P. Interests

February 11, 2015

Page 5

An on-site field inspection of the properties has not been performed nor have the mechanical operation or condition of the wells and their related facilities been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging at abandonment has been included.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. We do not own an interest in the properties or Eagle Rock Energy Partners, L.P. and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office. We consent to the filing of this report as an exhibit to the Annual Report on Form 10-K of Eagle Rock Energy Partners, L.P. for the year end December 31, 2014.

Yours very truly,

Robert D. Ravnaas, P.E.

President

CAWLEY,GILLESPIE &ASSOCIATES, INC.

TEXAS REGISTERED ENGINEERING FIRM F-693

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