UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________ to ________

Commission File 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  x    No  o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the 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.  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (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, 2013, the aggregate market value of the registrant's common units held by non-affiliates of the registrant was $812,447,684 based on the closing sale price as reported on NASDAQ Global Select Market.

The issuer had 159,405,268 common units outstanding as of February 24, 2014.

 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, 2013, are incorporated by reference into Part III of this report for the year ended December 31, 2013.

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	2
Item 1A.	Risk Factors	32
Item 1B.	Unresolved Staff Comments	56
Item 2.	Properties	56
Item 3.	Legal Proceedings	56
Item 4.	Mine Safety Disclosures	56
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	57
Item 6.	Selected Financial Data	59
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	65
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	102
Item 8.	Financial Statements and Supplementary Data	106
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	106
Item 9A.	Controls and Procedures	107
Item 9B.	Other Information	109
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	109
Item 11.	Executive Compensation	109
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	109
Item 13.	Certain Relationships and Related Transactions, and Director Independence	109
Item 14.	Principal Accounting Fees and Services	109
PART IV
Item 15.	Exhibits and Financial Statement Schedules	110

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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 Annual Report on Form 10-K. These factors include but are not limited to:

• Risks related to the Midstream Business Contribution;

• 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;

• Our significant existing indebtedness;

• Hedging activities;

• Ability to obtain credit and access capital markets;

• Ability to remain in compliance with the covenants set forth in our credit facility and senior notes;

• Conditions in the securities and/or capital markets;

• Future processing volumes and throughput;

• Loss of significant customers;

• 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;

• Ability to make favorable acquisitions and integrate operations from such acquisitions;

• Shortages of personnel and equipment;

• Potential losses associated with trading in derivative contracts;

• 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; and

• 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.

• 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.

Bcf/d:  One billion cubic feet of natural gas per day. 

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.

btu:    British thermal unit.

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.

dry gas:Natural gas that does not require plant processing prior to delivery to the interstate or intrastate pipeline systems.

equity liquids or gallons:    Natural gas liquid and condensate production that equates to an entity's contractual share of the production.

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 or fee mineral interest:    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.

frac spread:    The difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent value of those NGLs in a keep-whole arrangement.

gpm:    Gallons of natural gas liquids per million cubic feet of gas.

gross acres or gross wells:    The total acres or wells, as the case may be, in which a working interest is owned.

Hp:    Horsepower.

MBbls:    One thousand barrels of crude oil or other liquid hydrocarbons.

MBO/d:    One thousand barrels of crude oil or other liquid hydrocarbons per day.

Mcf:    One thousand cubic feet of natural gas.

Mcf/d:    One thousand cubic feet of natural gas per day.

Mcfe:    One thousand cubic feet of natural gas equivalent, determined using 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.

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MMBoe:    One million barrels of oil equivalent.

MMBtu:    One million British thermal units.

MMcf:    One million cubic feet of natural gas.

MMcf/d:    One million cubic feet of natural gas 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 or net wells:    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.

overriding royalty or overriding royalty interest:    A non-cost bearing interest in the production from a well that is carved out of the working interest. It expires when the underlying oil and/or natural gas lease expires.

probable locations:    Locations that are near proved undeveloped locations, but do not meet the definition of a proved location.

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 locations:    Locations that geological and engineering data demonstrate with reasonable certainty to recover reserves in future years from known reservoirs under existing economic and operating conditions.

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 or PUDs:    Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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.

undeveloped acreage:    Lease acreage 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 or not such acreage contains proved reserves.

unit development cost (UDC):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.

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wet gas:Natural gas that requires plant processing in order to meet the interstate and intrastate gas quality specifications.

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.

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In this Annual Report on Form 10-K, 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” refer to Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. 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 limited partnership currently engaged in the business of (i) developing and producing interests in oil and natural gas properties, which we call our “Upstream Business;” and (ii) gathering, compressing, treating, processing and transporting natural gas; fractionating and transporting natural gas liquids (“NGLs”); crude oil and condensate logistics and marketing; and natural gas marketing and trading, which collectively we call our “Midstream Business.”

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

Our Upstream Business consists of properties located in four significant oil and gas producing regions: (i) South Alabama (which includes the associated gathering, processing and treating assets); (ii) Mid-Continent (which includes areas in Oklahoma, Arkansas and the Texas Panhandle); (iii) Permian (which includes areas in West Texas); and (iv) East Texas/South Texas/Mississippi/Louisiana. As of December 31, 2013, these working interest properties included 562 gross operated productive wells and 1,202 gross non-operated wells with net production to us of approximately 74.2 MMcfe/d and proved reserves of approximately 177.2 Bcf of natural gas, 13.5 MMBbls of crude oil, and 14.6 MMBbls of natural gas liquids, of which 73% are proved developed.

Our Midstream Business is located in four significant natural gas producing regions: (i) the Texas Panhandle; (ii) East Texas/Louisiana; (iii) South Texas; and (iv) the Gulf of Mexico. These four regions are productive, mature, natural gas producing basins that have historically experienced significant drilling activity. As of December 31, 2013, our natural gas gathering systems across all our regions comprised approximately 8,302 miles of natural gas gathering pipelines with approximately 4,426 well connections, 17 natural gas processing plants with approximately 793 MMcf/d of plant processing capacity and 300,219 horsepower of compression.  Our Midstream Business averaged 567 MMcf/d of gathered volumes and 525 MMcf/d of processed volumes during the fourth quarter of 2013.

We report on our businesses in five accounting segments, as outlined in Note 14 of our consolidated financial statements.  We report our Upstream Business as one segment. We report our Midstream Business' financial results in the following segments: (i) Texas Panhandle, (ii) East Texas and Other Midstream and (iii) Marketing and Trading. Our final reporting segment is our functional (Corporate) Segment, in which we account for our risk management, intersegment eliminations and other corporate activities, including general and administrative expenses.

On December 23, 2013, we entered into an agreement to contribute our Midstream Business (the "Midstream Business Contribution") to Regency Energy Partners, LP ("Regency") for total consideration of up to $1.325 billion, including $200 million of Regency common units and a combination of debt assumption and cash. As part of this transaction, Regency will conduct an offer to exchange our $550 million of outstanding senior unsecured notes into an equivalent amount of Regency senior unsecured notes with the same tenor, coupon and a comparable covenant package. The cash portion of the purchase price will be reduced by the amount of notes exchanged subject to a 10% adjustment factor, such that if all $550 million of bonds are exchanged, the total consideration will equal $1.27 billion ($1.325 billion less $55 million) consisting of $200 million in Regency units, $550 million of assumed debt and $520 million of cash proceeds. Upon the consummation of the Midstream Business Contribution, we intend to remain a master limited partnership ("MLP") focused on our Upstream Business. Importantly, the completion of the Midstream Business Contribution is subject to regulatory and unitholder

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approvals. As a result, we can provide no assurance that the Midstream Business Contribution will be completed within our anticipated time frame, or at all. As the sale of the Midstream Business is conditioned upon the approval of our common unitholders, we have not classified the assets of our Midstream Business as assets-held-for-sale or the operations as discontinued.

On February 28, 2014, we announced that ourself and Regency had received a request for additional information and documents from the Federal Trade Commission in connection with the proposed contribution of our Midstream Business to Regency.

Ownership Structure

The diagram below depicts our ownership structure as of February 24, 2014.  The ownership percentages shown below are calculated on a fully-diluted basis:

________________________

(a) "NGP" refers collectively to Natural Gas Partners VII, L.P., a Delaware limited partnership; Natural Gas Partners VIII, L.P., a Delaware limited partnership; and such other entities as set forth on that certain Schedule 13D/A filed with the Securities and Exchange Commission on December 30, 2013 including, without limitation, Montierra Minerals & Production, L.P., a Texas limited partnership and Montierra Management LLC, a Texas limited liability company. For a discussion of certain members of management's ownership in the Montierra entities, 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 2014 Annual Meeting of Unitholders.

(b) Ownership structure chart does not assume completion of the Midstream Business Contribution.

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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. We have not included the proposed Midstream Business Contribution as it remains subject to regulatory and unitholder approvals.

Table of Significant Acquisitions/Dispositions in the Past Five Years

Closing Date	Transactions	Amount  ($ in Millions)		Financing Sources ($ in Millions)								Segment
				Cash		Debt		Equity to Sellers		Cash from equity offerings
Acquisitions:
10/19/2010	Centerpoint Acquisition	$	27.0	$	27.0	$	—	$	—	$	—	Midstream
5/3/2011	Mid-Continent Acquisition	$	563.7	$	15.0	$	212.6	$	336.1	$	—	Upstream
10/1/2012	Panhandle Acquisition	$	230.6	$	—	$	146.3	$	—	$	84.3	Midstream
Dispositions:
5/24/2010	Minerals Business Disposition (a)	$	174.5	$	174.5	$	—	$	—	$	—	Minerals
12/20/2012	Barnett Shale Properties	$	14.8	$	14.8	$	—	$	—	$	—	Upstream

_______________________________

(a) Amount includes approximately $2.9 million of cash received from the Minerals Business after the effective date of the sale.

The following is a chart that depicts the costs of our organic growth projects by year and reportable segment over the past five years:

Table of Organic Growth Project Costs in the Past Five Years

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The following graph depicts our historical trends in Adjusted EBITDA and quarterly distribution rate per common unit over the past three years:

For a definition of Adjusted EBITDA and reconciliation to GAAP, see Part II, Item 6. Selected Financial Data-Non-GAAP Financial Measures.

  Due to our enhanced liquidity position resulting from the Recapitalization and Related Transactions described below, our debt reduction efforts and improved economic conditions, we increased our distribution rate for the fourth quarter of 2010 and throughout 2011. In the first quarter of 2012, natural gas and NGL prices began a substantial and extended decline. As a result, we held the distribution rate flat throughout 2012. The combination of weak commodity prices and elevated debt levels led us to reduce the distribution rate beginning in the third quarter of 2013.

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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An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. Please read carefully the risks described under Part I, Item 1A. Risk Factors. 

Our Two Lines of Business

Upstream Business

Upstream Business Overview

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

• South Alabama, which includes the associated gathering, processing and treating assets;

• Mid-Continent, which includes areas in Oklahoma, Arkansas and the Texas Panhandle acquired in conjunction with our CC Energy II L.L.C. acquisition ("Mid-Continent Acquisition") in May 2011;

• Permian, which includes areas in West Texas; and

• East Texas/South Texas/Mississippi/Louisiana.

As of December 31, 2013, these working interest properties included 562 gross operated productive wells and 1,202 gross non-operated wells with net production of approximately 74.2 MMcfe/d and proved reserves of approximately 177.2 Bcf of natural gas, 13.5 MMBbls of crude oil, and 14.6 MMBbls of natural gas liquids, of which 73% were proved developed. The reserve life index is approximately 13 years based on our average daily production for the year ended 2013.

The Golden Trend field in Oklahoma (including the portion of the SCOOP play that is designated as part of the Golden Trend field) contains 41% of our proved reserves. As of December 31, 2012, the Golden Trend field accounted for 23% of our reserves, but the percentage increased in 2013 due to the large amount of extensions and discoveries in the SCOOP Play during 2013, and our decision to reclassify of many proved undeveloped reserves to probable reserves in other fields. The next largest field is the Big Escambia Creek field (located in South Alabama) which contains 13%; no other field exceeds 10%.

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The following table summarizes our producing properties by region:

Region	Average net daily production			Gross productive wells
	Oil, Bbl/d	Natural gas, Mcf/d	Natural gas liquids, Bbl/d	Operated	Non- Operated
December 31, 2013
South Alabama Region	1,342	2,635	652	27	3
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
Permian Region	469	1,471	198	192	53
East Texas/South Texas/Mississippi/Louisiana Region	214	3,076	477	44	102
Total	3,349	35,080	3,166	562	1,202
December 31, 2012
South Alabama Region	1,406	3,651	644	26	3
Mid-Continent Region
Golden Trend (a)	774	8,107	1,113	78	95
All other Mid-Continent Region	313	27,430	602	208	983
Permian Region	472	1,450	190	207	55
East Texas/South Texas/Mississippi/Louisiana Region	272	4,299	515	40	113
Total	3,237	44,937	3,064	559	1,249
December 31, 2011
South Alabama Region	1,649	4,133	693	26	3
Mid-Continent Region (b)
Golden Trend (a)	586	5,320	651	74	95
All other Mid-Continent Region	130	18,371	171	242	959
Permian Region	455	1,439	210	206	22
East Texas/South Texas/Mississippi/Louisiana Region	243	5,358	481	43	118
Total	3,063	34,621	2,206	591	1,197

 ____________________________

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

(b) 2011 average net daily production for the Mid-Continent Region were calculated using volumes beginning on May 3, 2011 divided by 365 days.

South Alabama Region. The South 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 11,568 gross (7,436 net) Eagle Rock operated acres.  We operate eighteen productive wells with an average ownership of 63% working interest and 54% 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 (2,252 net) Eagle Rock operated acres and produces from the Norphlet formation at depths from approximately 15,000 to 16,000 feet.  We operate three productive wells with an approximate average 91% working interest and 78% net revenue interest.  

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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 or the Flomaton Treating Facility, and the effluent gas is further processed for the removal of natural gas liquids in our Big Escambia Creek Gas Processing Facility. During 2013, the Flomaton facility sulfur recovery unit was shut down due to equipment failure. The untreated Flomaton facility gas was re-routed to the Big Escambia Creek facility for treating and processing, while continuing to stabilize and sell the Flomaton and Fanny Church condensate at the Flomaton facility. The operation of the wells and the facilities 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.

Mid-Continent Region. The Mid-Continent region consists of operated and non-operated properties in the Golden Trend field, Cana 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" intervals.

We have a significant ownership position in the new and expanding Cana (Woodford) Shale and Southeast Cana Shale plays in western Oklahoma. We have approximately 17,427 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 horizontal wells drilled to vertical depths of 11,000 to 15,500 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 299 productive wells and own a working interest in an additional 1,044 non-operated productive wells. The average working interest in these productive operated and non-operated wells is 83% and 9%, respectively. The net production averaged approximately 46.9 MMcfe/d in the year ended 2013, of which approximately 73% was produced from wells we operated. Most of the non-operated production comes from the properties within the Cana Shale play, 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 are operated by large upstream companies with significant experience and expertise in developing shale gas reserves.

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 192 productive wells and own an interest in another 53 non-operated productive wells across approximately 5,875 net acres in this area.   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 34 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 84% and 3%, 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. 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 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 ten 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 926 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.

Productive Wells

On December 31, 2013, we had under operation 280 gross (253 net) productive oil wells and 282 gross (235 net) productive natural gas wells. On December 31, 2013, we owned non-operated interests in an additional 173 gross (26 net) productive oil wells and 1,029 gross (72 net) productive natural gas wells.

Developed and Undeveloped Acreage

The following table describes the leasehold acreage we owned as of December 31, 2013:

	Developed Acreage(a)		Undeveloped Acreage(b)		Total Acreage
	Gross	Net	Gross	Net	Gross	Net
Total	504,610	188,536	23,001	10,842	527,611	199,378

____________________________

(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, 2013, 2012 and 2011:

	Year ended December 31, 2013		Year ended December 31, 2012		Year ended December 31, 2011
	Gross	Net	Gross	Net	Gross	Net
Development wells (a):
Productive	44	13	33	15	42	13
Dry	1	1	—	—	—	—
Total	45	14	33	15	42	13

____________________________

(a) Includes extension wells.

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 across our Upstream segment. Overall, the capital program achieved a unit development cost of $20.34/Boe.As of December 31, 2013, two operated wells (1.9 net) were being completed and three operated wells (1.4 net) were in the process of being drilled.

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,

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recompletion and workover projects were conducted on thirty-one operated wells and one non-operated well across our Upstream segment. Overall, the capital program generated a unit development cost of $22.08/Boe.

From the close of our Mid-Continent Acquisition in May 2011 through December 31, 2011, we drilled and completed eleven operated wells in our Mid-Continent region which included two wells in the Cana Shale play, four wells in the Golden Trend field, and three wells in the Texas Panhandle. Additionally we participated with a working interest in thirty-one non-operated wells drilled and completed in the region. In our remaining operated regions, we drilled and completed one well in our Edgewood field in East Texas, and one well in our Big Escambia Creek field. Our success rate in 2011 was approximately 81% for the forty-two well drilling program with a total program unit development cost of $13.86/Boe. During 2011, recompletion and capital workover projects were conducted on thirteen operated wells across our Upstream segment. Eight of the thirteen recompletion and capital workovers were successful. The program unit development cost for these operations was $7.44/Boe.

During the years ended December 31, 2013, 2012 and 2011, 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, 2013 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 2013, 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 reporting 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 Annual Report on Form 10-K.

In the preparation of its report, CGA relies on engineering, financial and other data provided by our staff and is overseen by our Senior Vice President - Technical Evaluations, Mr. Steven Hendrickson.  Mr. Hendrickson is a State of Texas Licensed Professional Engineer (License #65951) with over 30 years of experience in petroleum engineering, operations, economics, finance, acquisitions and risk management.  He earned a bachelors of science degree in chemical engineering from the University of Texas and a masters of science degree in finance from the University of Houston.  He is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

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 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.

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• 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 Senior Vice President – Technical Evaluations 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 Senior Vice President – Technical Evaluations 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 their 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 in the Upstream Business on December 31, 2013. These values are based on independent reserve reports prepared by Cawley, Gillespie & Associates, Inc.

	As of December 31, 2013
Reserve Data: Upstream Business
Estimated net proved reserves:
Natural gas (Bcf)	177.2
Oil (MMBbls)	13.5
Natural Gas Liquids (MMBbls)	14.6
Total (Bcfe)	346.3
Proved developed (Bcfe)	252.5
Proved developed reserves as % of total proved reserves	73	%
Estimated net undeveloped reserves:
Natural gas (Bcf)	50.3
Oil (MMBbls)	3.4
Natural Gas Liquids (MMBbls)	3.9
Total (Bcfe)	93.8
Proved undeveloped (Bcfe)	93.8

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Proved Undeveloped Reserves

As of December 31, 2013, our proved undeveloped reserves totaled 50.3 Bcf of natural gas, 3.4 MMBbls of oil and 3.9 MMBbls of natural gas liquids. The total proved undeveloped reserves of 93.8 Bcfe results from an increase of approximately 9.4 Bcfe, or 11.1%, from total proved undeveloped reserves of approximately 84.4 Bcfe as of December 31, 2012. The changes in our proved undeveloped reserves during 2013 were primarily attributable to:

• An increase of 52.5 Bcfe due to extensions and discoveries, primarily in our Golden Trend area and Southeast Cana Woodford play;

• A decrease of approximately 11.3 Bcfe resulting from transfers to the proved developed producing category as a result of development drilling;

• A decrease of approximately 35.9 Bcfe due to revisions to previous estimates, 27.8 Bcfe of which was due to recategorizing a number of undeveloped locations from proved to probable reserves due to poor economic expectations or because they are operated by others and we are not reasonably certain they will be drilled; and the remainder of which was due to recategorizing proved undeveloped reserves as contingent resources associated with future drilling locations that do not currently meet the definition of proved reserves under SEC guidelines

We spent approximately $38.4 million of capital expenditures in 2013 to drill wells classified as proved undeveloped as of December 31, 2012. Our working interest in these wells at the time they were drilled was often significantly greater than our working interest as of December 31, 2012 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 2013 was often significantly greater than the wells’ estimated proved undeveloped reserves as of December 31, 2012. In addition, the amount of reserves transferred into the proved developed producing category on account of wells drilled in 2013 was often different from the wells’ estimated proved undeveloped reserves as of December 31, 2012 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, 2013, we had 106 drilling locations associated with proved undeveloped reserves, most of which were acquired in the Mid-Continent Acquisition.

We approach the development of our undeveloped reserves in 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.

Our undeveloped drilling locations are concentrated in the Mid-Continent region, primarily in the Golden Trend field of Grady County, Oklahoma and the Cana Shale and Southeast Cana Shale plays in western Oklahoma.

Of the forty-five wells drilled during the year ended December 31, 2013, seven of the operated wells and four of the non-operated wells were proved undeveloped locations. In 2012, of the thirty-three wells drilled, eight of the operated wells and three of the non-operated wells were proved undeveloped locations. In 2011, of the forty-two wells drilled, six of the operated wells and two of the non-operated wells were proved undeveloped locations.

Oil and Natural Gas Production

For detail and a discussion of our net production, realized prices by product and production costs for the years ended December 31, 2013, 2012 and 2011, see our discussion of the results of operations for our Upstream Business within Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Year Ended December 31, 2013 Compared with Year Ended December 31, 2012 and Year Ended December 31, 2012 Compared with Year Ended December 31, 2011.  Production costs, excluding ad valorem and severance taxes for our Upstream Business for the years ended December 31, 2013, 2012 and 2011 were $8.16/Boe, $7.14/Boe and $7.44/Boe, respectively.  

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Midstream Business

Midstream Industry Overview

General. Raw natural gas produced from the wellhead is gathered and delivered to a processing plant or markets located near the production field, where it is treated, dehydrated, and/or processed, while condensate is collected and sold upstream of processing. Processing natural gas involves the separation and treating of raw natural gas resulting in a pipeline quality natural gas, primarily methane and mixed NGLs. Natural gas treating entails the removal of impurities, such as water, sulfur compounds, carbon dioxide and nitrogen. Interstate and intrastate pipelines deliver the processed natural gas to markets. Mixed NGLs are typically transported via NGL pipelines or by truck to a fractionator which separates the NGLs into its components such as ethane, propane, normal butane, isobutane and natural gasoline. The component NGLs are then sold to end users. In many cases condensate is stabilized to further reduce its vapor pressure in order to meet truck transport requirements. Blending of light and heavy gravity condensate is also done to improve the quality, market optionality and associated sales price.

The following diagram shows the process of gathering, processing, marketing and transporting natural gas, NGLs and condensate.

_________________________

Note: The shaded area above represents processes in which we are directly involved in our Midstream Business and for which we own the underlying assets.

Gathering. A gathering system typically consists of a network of small diameter pipelines and a compression system which together collect natural gas from producing wells and delivers it to larger pipelines for further transportation. We own and operate large gathering systems in four geographic regions of the United States.

Compression. Gathering systems are operated at design pressures that seek to maximize the total throughput volumes from all connected wells. Since wells produce at progressively lower field pressures as they age, the raw natural gas must be compressed to deliver the remaining production against higher pressure that exists in the connected gathering system or transport pipelines. Natural gas compression is a mechanical process in which a volume of natural gas at a lower pressure is increased, or compressed, to a desired higher pressure, allowing natural gas that no longer naturally flows into a higher pressure downstream pipeline to be brought to market. Field compression is used to lower the wellhead pressure while maintaining the exit pressure of a gathering system to deliver natural gas into higher pressure downstream pipelines and plants. We own or lease, and operate, all compression on our systems.

Treating and Processing. Raw natural gas produced at the wellhead is often unsuitable for pipeline transportation or commercial use and must be processed and/or treated to remove the heavier hydrocarbon components and/or contaminants. The principal components of pipeline-quality natural gas are methane and ethane, but most raw natural gas also contains varying amounts of heavier hydrocarbon components (such as propane, normal butane, isobutane, and natural gasoline) and impurities

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(such as water, sulfur compounds, carbon dioxide, oxygen and nitrogen). We own and operate natural gas processing and/or treating plants in four geographic regions.

Fractionation. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, normal butane, isobutane and natural gasoline. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock and as a heating fuel, an engine fuel and an industrial fuel. Normal butane is used as a petrochemical, and as a blend stock for motor gasoline. Isobutane is typically fractionated from mixed butane (a stream of normal butane and isobutane in solution), principally for use in enhancing the octane content of motor gasoline. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock. We operate a fractionation facility to produce propane at one of our facilities in the Texas Panhandle Segment.  In our East Texas and Other Midstream Segment we own a 3.07% interest, which was updated to a 2.1% interest in January 2014, in the Tebone Fractionator, a fractionation facility operated by Enterprise Products Partners L.P. in southern Louisiana.

Condensate Stabilization. Natural gas condensate is a low-density mixture of hydrocarbon liquids found in the raw natural gas stream. Condensate stabilization is a process by which the vapor pressure of the condensate is reduced. As a result, the condensate is better positioned to meet truck transportation limitations and end-user specifications. We own and operate condensate stabilization facilities in our Texas Panhandle Segment.

Marketing and Trading. Natural gas marketing and trading involves the sale of natural gas either produced by processing plants or purchased from gathering systems or other pipelines. NGL marketing involves the sale of the unfractionated (or "y-grade") products or fractionated products recovered at the processing plants. We market and trade natural gas, and market NGLs and condensate for our own account and for the benefit of most of our producer customers in our Midstream Business and for certain working interest owners in our Upstream Business. In the fourth quarter of 2010, we created a marketing subsidiary to develop, implement, and launch marketing uplift strategies surrounding crude oil and condensate in Alabama and in the Texas Panhandle. Strategies include marketing and transportation, including the use of rail, barge, and storage facilities, and product blending to enhance product net-back prices. Currently, our crude marketing subsidiary does not own marketing-related natural gas or natural gas liquid pipelines, storage or other transportation assets, nor does it utilize financial derivatives in the marketing of our products. In 2011, we created a natural gas marketing and trading subsidiary to capitalize on the physical and financial opportunities that naturally extend from our upstream and midstream assets. Where in the past we generally sold to wholesale buyers at the tailgates and wellheads of our assets, now this subsidiary holds transportation agreements and moves our product to many locations and types of buyers. This strategy diversifies our credit and performance risk and allows us to capitalize on daily, monthly and seasonal changes in market conditions. With these transportation and marketing options in place, our gas marketing and trading subsidiary has been successful in buying and marketing third party gas in various operating areas.

Transportation. Natural gas transportation consists of moving pipeline-quality natural gas from gathering systems, processing plants and other pipelines and delivering it to wholesalers, utilities and other pipelines. Other than our North and Central systems in Texas, we do not own any natural gas transportation assets. Condensate is typically transported locally by truck and aggregated into storage tanks before being delivered to end markets via a range of transportation alternatives, including truck, rail, barge or pipeline.

Natural gas is gathered and processed pursuant to a variety of industry-standard arrangements generally categorized as fee-based, percent-of-proceeds, fixed recovery, percent-of-index and keep-whole, described in greater detail as follows:

• Fee-Based Arrangements. Under these arrangements, we are paid a fixed cash fee per unit volume for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. A sustained decline, however, in commodity prices could result in a decline in volumes and, thus, a decrease in fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments.

• Percent-of-Proceeds Arrangements. Under these arrangements, raw natural gas is gathered from producers at the wellhead, moved through the gathering system, processed and sold at prices based on published index prices. Producers are paid an agreed-upon percentage of the proceeds. The value paid to producers is based on an agreed percentage of the products produced multiplied by the actual sale price or an index price. Contracts in which the gatherer/processor shares only in specified percentages of the proceeds from the sale of NGLs and in which the producer receives 100% of the proceeds from natural gas sales, are referred to as “percent-of-liquids” arrangements but are still generally categorized as percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, the margin correlates directly with the prices of natural gas and NGLs, as applicable; under percent-of-liquids

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arrangements, the margin correlates directly with the price of NGLs. Percentage-of-Proceeds arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments.

• Fixed Recovery Arrangements. Under these arrangements, raw natural gas is gathered from producers at the wellhead, transported through our gathering system and processed. We sell the processed natural gas and NGLs at prices based on published index prices. The value paid to the producers for NGLs is calculated as the product of agreed-upon theoretical product recovery factors multiplied by the theoretical wellhead gallons for each NGL component. Each resulting component volume is then multiplied by a contractual percentage and an index price or the actual sales price. The value paid for the remaining share of natural gas is multiplied by a contractual percentage and an index price or the actual sales price. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. These arrangements also provide greater upside to us for greater efficiency and better actual recoveries and tend to penalize us when efficiency and recoveries turn-out not to be as expected.

• Percent-of-Index Arrangements.  Under percent-of-index arrangements, we purchase either liquids-rich or dry wellhead natural gas at either (i) a percentage discount to a specified index price, (ii) a specified index price less a fixed amount or (iii) a weighted average sales price based on natural gas sales.  We generally then gather and deliver the dry natural gas to third-party pipelines and gather and process the liquids-rich natural gas and sell the resulting NGLs and residue gas to third parties.  Generally, when we gather dry natural gas and deliver it directly into a third-party pipeline, we are able to resell the natural gas at the index price or at a different percentage discount to the index price which reduces commodity price exposure.  Generally, when we gather and process liquids-rich natural gas, our revenues and net operating margins increase as the price of NGLs and condensate increases relative to the price of natural gas and decrease as the price of NGLs and condensate decrease relative to the price of natural gas, resulting in commodity exposure to us that is similar to that of a keep-whole arrangement. 

• Keep-Whole Arrangements. Under these arrangements, raw natural gas is processed to extract NGLs, and the processor pays the producer the full thermal equivalent volume of raw natural gas received from the producer in the form of either processed natural gas or its cash equivalent. Processors are generally entitled to retain the processed NGLs and to sell them for their account. Margin is a function of the difference between the value of the NGLs produced and the cost of the natural gas needed to replace the thermal equivalent volume of natural gas used in processing (i.e. the frac spread). The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs, but also to the price of natural gas relative to NGL prices. These arrangements can provide improved profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many keep-whole arrangements include provisions that reduce commodity price exposure, including (i) conditioning floors that require the keep-whole arrangements to convert to a fee-based arrangement if the NGLs have a lower value than their thermal equivalent in natural gas, (ii) discounts to the applicable natural gas index price used to reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer, or (iii) fixed cash fees for ancillary services, such as gathering, treating and compressing.

Midstream Business Overview

As discussed within Item 1. - Business - Overview, we announced on December 23, 2013 that we have entered into an agreement to contribute our Midstream Business to Regency. This agreement is subject to the approval of our unitholders and regulatory review.

We own natural gas gathering and processing assets in four significant natural gas producing regions: the Texas Panhandle, East Texas/Louisiana, South Texas and the Gulf of Mexico. During 2013, we remained focused on contracting new gas to our systems and initiating organic growth projects to meet the increasing demand for processing services by our producer customers.  The majority of our growth projects are designed to enhance and expand our processing capacity in the Granite Wash and surrounding plays in the Texas Panhandle. In 2013, we completed the installation of our 60 MMcf/d Wheeler plant. In October 2012, we acquired from BP the Sunray and Hemphill processing plants (with a total combined capacity of approximately 218 MMcf/d) and the associated 2,551 mile gathering system ("Panhandle Acquisition"). Concurrent with the Panhandle Acquisition, we entered into a 20-year, fixed-fee Gas Gathering and Processing Agreement with BP under which we will gather and process BP's natural gas production from the existing wells connected to the acquired gathering system. Furthermore, BP has committed itself to us under the same agreement and committed its farmees to us under substantially the same terms, with respect to all future natural gas production from new wells drilled within an initial two-year period from closing, subject to mutually-agreed extensions, and within a two-mile radius of any portion of our gathering system

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serving such BP connected wells. As of December 31, 2013, we have increased our high-efficiency processing capacity servicing Texas Panhandle production to 503 MMcf/d from approximately 157 MMcf/d at the beginning of 2010.

Within our geographic areas of operation, we strive to be a competitive and low cost natural gas gatherer and processor. To achieve this end, we coordinate the operations and commercial activities of our gathering and processing assets to provide better customer service.  From an operations perspective, our key strategy is to provide our customers safe and reliable service at reasonable costs and to improve our competitiveness in securing new customers through more efficient operations.  From a commercial perspective, our focus is to assist our customers in maximizing the value of their production by providing options and capacity for the movement and marketing of their natural gas and NGLs.  We are well positioned to take advantage of continued growth opportunities in the Texas Panhandle Granite Wash play and in the Austin Chalk play in East Texas.  In an effort to comply with the competitive environment of our operating areas, we often provide a combination of “fixed recovery agreement” with a “fee-based agreement” component.  These are typically structured to comply with producer preference and also to help alleviate the level of commodity exposure that we have on any single agreement. As of December 31, 2013, the percentage of natural gas wellhead volumes under various contractual arrangements were 36% fixed recovery, 29% fee-based, 29% percent-of-proceeds (which includes percent-of-liquids) and 6% percent-of-index (blended/combination contracts are categorized based upon which arrangement within the contract generates the majority of the margin).

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As of December 31, 2013, our Midstream Business consisted of the following:  

Asset	Length (miles)	Available Compression (Horsepower)	Processing Plant Through-put Volume Capacity (MMcf/d)
Texas Panhandle Segment	6,514	225,500	503
Canadian gathering system	359		n/a
Phoenix Arrington Ranch cryogenic plant and gathering system	757		80
Woodall plant (b)	n/a		60
Wheeler plant (b)	n/a		60
Hemphill plant and gathering system	1,766		50
Sunray plant and gathering system	785		168
Red Deer cryogenic plant (a)(c)	n/a		24
Roberts County gathering system (a)	14		n/a
System 97 gathering system (e)	77		n/a
Buffalo Wallow gathering system (e)	113		n/a
Cargray cryogenic plant and gathering system	905		30
Gray cryogenic plant and gathering system (a)	615		20
Lefors cryogenic plant and gathering system	663		11
Stinnett gathering system	451		n/a
Turkey Creek gathering system	9		n/a
East Texas and Other Midstream Segment	1,788	74,719	290
Brookeland cryogenic plant and gathering system	733		100
Indian Springs cryogenic plant (25% non-operated) and Camp Ruby gathering system (20% non-operated) (f)	n/a		36
Tyler County gathering system	73		n/a
Panola gathering system	33		n/a
Quitman gathering system	51		n/a
Rosewood mechanical refrigeration plant and gathering system (a)	42		10
Vixen gathering system (e)	8		n/a
Belle Bower JT plant and gathering system (a)	68		20
Simsboro gathering system (e)	30		n/a
Sligo gathering system (e)	10		n/a
ETML gathering system (e)	169		n/a
Douglas East gathering system (e)	80		n/a
BGS gathering system (e)	28		n/a
Robertson County gathering system (e)	36		n/a
North gathering system (h)	85		n/a
Central mechanical refrigeration plant and gathering system (i)	102		2
New Ulm gathering system	15		n/a
Phase 1 gathering system	70		n/a
Raymondville gathering system	31		n/a
Raymondville JT plant (a)	n/a		40
San Ignacio gathering system	6		n/a
TGP McAllen JT plant and gathering system	13		40
Various South Texas gathering systems	49		n/a
Sweeny gathering system (50% non-operated)	16		n/a
North Terrebonne refrigerated lean oil plant (3.07% non-operated) (g)	n/a		42
Tebone Fractionator (3.07% non-operated) (h)	n/a		n/a
Galveston Bay gathering (50% non-operated)	12		n/a
CMA Pipeline segments (non-operated)	28		n/a
TOTAL Midstream Businesses	8,302	300,219	793

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(a) The plant is owned by us, but we lease the plant site.

(b) The plant processes gas from the Phoenix Arrington Ranch gathering system.

(c) The plant processes gas from the Canadian gathering system.

(e) The systems gather dry natural gas that does not require processing to meet pipeline hydrocarbon dew point quality specifications.

(f) Our net plant capacity is based on the plant expansion to 145 MMcf/d total capacity in February 2008.

(g) The available capacity shown is net to our ownership share. Available capacity is based on the previous year's allocated throughput volume for each owner and to existing owners and potential new owners who are adding new production volumes. Our ownership in North Terrebonne changed in January 2014 to 2.1% from 3.07%.

(h) The Tebone Fractionator has 30,000 Bbl/d of capacity. Our ownership share is tied to our ownership percentage in the North Terrebonne Plant which changed to 2.1% from 3.07% in January 2014.

(i) Sections of the system are subject to FERC jurisdiction under Section 311 of the NGPA.

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The following graph depicts plant processing capacity and utilization by month.  The volumes shown include only the gas volumes that we gathered that were processed before entering the interstate or intrastate pipeline systems (we refer to such natural gas as wet gas) and excludes the gas volumes that we gathered that were not processed prior to delivery to the interstate or intrastate pipeline systems (we refer to such natural gas as dry gas).

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Note.  Reflects the installation of the Phoenix-Arrington Ranch plant in 2010 and its expansion in October of 2011, the installation of the Woodall plant in June 2012, the acquisition of the Sunray and Hemphill plants in October 2012 and the installation of the Wheeler plant in July 2013.  Other changes are attributable to adjustments of plant ownership percentages at North Terrebonne and Yscloskey, the shut-down of the Yscloskey plant in September 2012 and the abandonment of two small JT plants.

Texas Panhandle Segment

Our Texas Panhandle Segment covers 14 counties in Texas and two counties in Oklahoma. Through the systems within this segment we offer midstream wellhead-to-market services, including gathering, compressing, treating, processing and selling of natural gas, and fractionating and selling of NGLs. As of December 31, 2013, approximately 358 producers and 3,884 wells and central delivery points were connected to the systems in our Texas Panhandle Segment. The Texas Panhandle Segment averaged gathered volumes for the fourth quarter of 2013 of approximately 397 MMcf/d. As of December 31, 2013, BP America Production and Linn Energy Holdings represented 25.6% and 10.4%, respectively, of the total volumes of our Texas Panhandle Segment. The following is a map of our Texas Panhandle Segment:

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As of December 31, 2013, the Texas Panhandle Segment consisted of: approximately 6,514 miles of natural gas gathering pipelines, ranging from two inches to 24 inches in diameter; ten active natural gas processing plants with an aggregate capacity of 503 MMcf/d; a propane fractionation facility with capacity of 1.0 MBbls/d; and four condensate collection and stabilization facilities.

Natural Gas Supply. Our systems in the East Panhandle (defined as northern Wheeler, Hemphill, Lipscomb, Ochiltree, Hansford and Roberts counties, Texas) gather and process natural gas produced from multiple geological reservoirs, including the Cottage Grove, Tonkawa, Cleveland, Hogshooter, Granite Wash and Morrow formations of the Anadarko basin. Approximately 98% of the natural gas gathered from these areas is processed to recover the NGL content, which generally ranges from 4.0 to 5.0 gpm, with the remaining volume not processed but treated for removal of carbon dioxide and hydrogen sulfide to make the natural gas marketable. This natural gas can be isolated and sent to treating facilities, while the remaining system is used to gather the natural gas into the processing plants. This area has experienced substantial drilling and reserve growth since 2002.  Producers are increasing their use of horizontal drilling in the Tonkawa, Cleveland, Hogshooter and Granite Wash plays.  The enhanced economics associated with horizontally drilled wells and the relatively high levels of liquids found in the reservoir has led to an overall increase in the number of wells permitted for the greater these plays. In response to increased demand for processing capacity by our producer customers operating in the Granite Wash and surrounding plays, we completed construction on two new cryogenic processing plants, our 60 MMcf/d Woodall Plant and 60 MMcf/d Wheeler Plant. In addition, during 2012 we substantially expanded our presence in the area through the Panhandle Acquisition.

Our systems in the West Panhandle (defined as Moore, Potter, Gray, Hutchinson, Carson, Sherman, Hartley, Collingsworth and southern Wheeler counties, Texas) gather and process natural gas produced from the Brown Dolomite formations in the Anadarko basin. These areas are fully developed, and as a result there is limited new drilling activity in the area served by our West Panhandle systems. Natural gas production from wells located within the West Panhandle area generally are low volume wells being gathered at very low pressure. Natural gas from wells located in this area generally have an annual rate of decline of 6% to 9%.  This natural gas is processed to recover the NGL content which generally ranges from 8.0 to 18.0 gpm.

In the Panhandle Segment, natural gas is contracted at the wellhead primarily under (i) percent-of proceeds (which includes percent-of-liquids), (ii) fixed recovery, (iii) percent-of-index and (iv) fee-based arrangements that range from one to five years in term. As of December 31, 2013, approximately 21%, 47%, 4% and 28% of our total throughput was under percent-of-proceeds, fixed recovery, percent-of-index, and fee-based arrangements, respectively.

In addition, we produced approximately 3,189 equity barrels per day of condensate in the Texas Panhandle Segment during the fourth quarter of 2013. We stabilized approximately 3,022 barrels per day at our Superdrip, Cargray, Woodall, Wheeler and Sunray stabilizers during the fourth quarter of 2013.   

Competition. With the production growth in the Granite Wash, Cleveland, Tonkawa and Hogshooter plays, a number of midstream companies have built plants in the area. Our primary competitors in this area are DCP Midstream, LLC and Midcoast Energy Partners, L.P. The key drivers in this high growth area, in order to continue to connect producer wells, are the ability to provide low pressure gathering services, to provide outlet capacity for the natural gas as it is brought into producing status and to provide high value efficient plant processing. We have extensive gathering systems that are situated in the Granite Wash and surrounding plays, and in response to the increased need for processing capacity in this play, we placed into service our Woodall plant and completed the Panhandle Acquisition during 2012. In addition, we placed our Wheeler Plant into service during the first half of 2013. During 2012, we expanded the Phoenix gathering system by over 33.3 miles of 8 inch to 12 inch pipeline at a cost of $20.9 million.

Texas Panhandle Markets. Our residue gas is marketed primarily by our natural gas marketing subsidiary. Our NGLs are marketed primarily to ONEOK Hydrocarbons ("ONEOK") and ConocoPhillips Company.   Under our existing contractual relationship with ONEOK, we believe we have secured sufficient takeaway capacity for our existing operations. Our condensate is sold under contract terms of one year or less. In addition, condensate produced and stabilized is sold to regional markets on a multi-month basis through various supply, trading and logistics companies.

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East Texas and Other Midstream Segment

Our East Texas and Other Midstream Segment operates in the East Texas/Louisiana, South Texas and the Gulf of Mexico natural gas producing regions.

Through our East Texas/Louisiana region, we offer producers natural gas gathering, treating, processing and transportation and NGL transportation across 21 counties in East Texas and seven parishes in West Louisiana. Our systems in the East Texas/Louisiana region which serve liquids-rich basins have experienced consistent drilling activity in recent years, whereas our systems in this region serving dry-gas basins have experienced reduced drilling activity.

Our operations in the South Texas region primarily gather natural gas and recover NGLs and condensate from natural gas produced in the Frio, Vicksburg, Miocene, Canyon Sands and Wilcox formations in South Texas.

Our operations in the Gulf of Mexico region are non-operated ownership interests in pipelines and onshore plants which are all located in southern Louisiana. In August 2012, the Yscloskey processing plant in Louisiana suffered significant damage due to Hurricane Isaac and has been shut-down indefinitely. The Gulf of Mexico region also provides producer services by arranging for the processing of producers’ natural gas into third-party processing plants, which we describe as our Mezzanine Processing Services.  The following is a map of our East Texas and Other Midstream Segment:

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Natural Gas Supply. As of December 31, 2013, approximately 599 wells and central delivery points were connected to our systems in the East Texas and Other Midstream Segment. As of December 31, 2013, the East Texas and Other Midstream Segment provided gathering and/or marketing services to approximately 126 producers. The East Texas and Other Midstream Segment averaged gathered volumes of approximately 194 MMcf/d during the fourth quarter of 2013.

The supply of natural gas into our East Texas and Other Midstream Segment is highly dependent upon drilling activity over which we have no ownership or control. We have experienced throughput declines in this segment since 2008, primarily due to decreased drilling activity by our producer customers driven by low natural gas prices. As of December 31, 2013, Anadarko E&P Company LP ("Anadarko") and BBX Operating, LLC represented 13.1% and 11.7%, respectively, of the total volumes of our East Texas and Other Midstream Segment. The natural gas supplied to us in this region is generally dedicated to us under individually negotiated long-term and life-of-lease contracts. Contracts associated with this production are primarily percent-of-proceeds (which includes percent-of-liquids) and fee-based arrangements, with some percent-of-index and fixed recovery. As of December 31, 2013, the percentage of natural gas under the contract structures were 48% percent-of-proceeds, 32% fee-based, 10% percent-of-index, and 10% fixed recovery.

Markets. In the East Texas/Louisiana region, approximately 74% of the residue gas remaining after processing is sold by our natural gas marketing subsidiary and the balance is a combination of direct pipeline sales and taken in kind by the producer customers into the markets available at the tailgates of the plants or pipeline interconnects.  Residue gas pipelines include Houston Pipeline Company, Natural Gas Pipeline Company, Tennessee Gas Pipeline, Crosstex Energy L.P. and Southern Natural Pipeline. Our NGLs are sold to various companies including Williams NGL Marketing, LLC.

In the South Texas region, natural gas is processed primarily for hydrocarbon dewpoint control to satisfy the gas quality requirements of the receiving interstate pipelines such as Tennessee Gas Pipeline Company and Enterprise Texas Pipeline. Our systems in the Gulf of Mexico region primarily process natural gas from interstate pipelines including Transco and Tennessee Gas Pipeline and recover NGLs and condensate from natural gas produced in the Outer Continental Shelf of the Gulf of Mexico.  The majority of NGLs produced from the Gulf of Mexico region are transported by pipelines for fractionation at the Norco, Toca and Tebone fractionators.  Once fractionated, the NGLs are sold to Enterprise Products Partners L.P. under a year-to-year contract.

Many of the interstate pipelines in our area are constrained from time to time. Offering multiple market outlets is important to our customers to ensure that they can produce their natural gas.

Competition. Our primary competition in the East Texas/Louisiana and South Texas regions includes Crosstex Energy, L.P., DCP Midstream, LLC, Energy Transfer Partners, LP and Enterprise Products Partners, L.P. Producers in the East Texas / Louisiana area value high run-time rates of the processing assets, connections to premium markets and low pressure gathering services.

The key drivers in the South Texas region are low pressure gathering and multiple market outlets for natural gas. Much of the natural gas drilled within the vicinity of our gathering systems is of sufficient wellhead pressure to deliver directly to the high pressure interstate pipelines; however, the wells quickly decline in pressure. We operate our systems at lower pressures which offers the producers an alternative to installing their own compression.

Our competition in the Gulf of Mexico region at the North Terrebonne Plant is primarily from other owners in those plants as well as the plant operators who are attempting to contract with the producers on behalf of all the plant owners.  In our Mezzanine Processing Services, the primary competition comes from the plant operators at the various third party plants in which we have contracts.

Marketing and Trading Segment

We formed our marketing subsidiary during the fourth quarter of 2010 to develop and implement marketing uplift strategies surrounding crude oil and condensate production in Alabama and in the Texas Panhandle. Through the end of 2013, our marketing subsidiary purchased product from our Upstream Segment and certain other working interest owners in the Big Escambia Creek, Fanny Church and Flomaton fields in Alabama, and sought to increase the value of the product through: (i) blending and treating to lower the gravity and reduce the contaminants, respectively, of the purchased condensate; and (ii) transporting the higher quality condensate to premium market locations. In this regard, neither our Upstream Segment nor the other participating working interest owners bore increased risk in the relocating and treating of the condensate. The contract between our crude oil marketing subsidiary and our Upstream Segment expired December 31, 2013.

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We also conduct natural gas marketing and trading activities, which began during the third quarter of 2011. We seek to capitalize on the physical and financial arbitrage opportunities that naturally extend from our upstream and midstream assets. Where in the past we generally sold to wholesale buyers at the tailgates and wellheads of our assets, now, through our natural gas marketing and trading subsidiary, we hold transportation agreements and move our product to many locations and types of buyers. This strategy diversifies our credit and performance risk and allows us to capitalize on daily, monthly, and seasonal changes in market conditions.

Markets. Our marketing subsidiary sells crude and condensate to various customers, typically on a multi-month basis.

For natural gas, we sell to wholesale and retail markets at various market hubs and specific facility locations, depending on market conditions. These sales are typically priced based upon a published daily or monthly price index. We lease third-party pipeline capacity downstream of our natural gas assets under firm transportation contracts, which capacity is dependent on the volumes of natural gas from our natural gas assets. This capacity is leased for various lengths of times and at rates that allow us to diversify our customer base by expanding our service territory.

Competition. Our Marketing and Trading Segment has numerous competitors, including large natural gas marketing companies, marketing affiliates of pipelines, major oil and natural gas producers, independent aggregators and regional marketing companies.

Regulation of Our Operations

Safety and Maintenance Regulation

Upstream Business

Our Upstream Business implicates safety matters with respect to the drilling and production of hydrocarbons and carries consequences of non-compliance consistent with those discussed below under the safety matters for the Midstream Business.  This segment of our business is subject to OSHA, EPA Risk Management Plan and DOT standards.  For more information regarding the regulations that may impact us, see "Item 1A.Risk Factors - We may incur significant costs and liabilities resulting from safety and compliance-related regulations."

Our Upstream Business is also subject to safety rules and regulations promulgated by 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."

Midstream Business

Our Midstream Business is subject to several federal and state laws and regulations, including federal safety standards developed under the Occupational Safety and Health Act of 1970, as amended (“OSHA”), and comparable state statutes, the purpose of which are to protect the safety and health of workers.  We incur costs related to compliance (including training) with all of these laws and regulations and for monitoring and maintaining our facilities in safe operating conditions.  Consequences of non-compliance with these laws and regulations are potential fines from the federal or state government agencies and disruption of operations due to injuries or equipment failure.

The OSHA process safety management (“PSM”) standard is designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. This standard applies to most processes that involve a chemical at or above the specified thresholds and certain processes which handle more than 10,000 lbs. of flammable liquids or gas, as defined in the regulation, excluding such flammable materials or processes specifically exempted within the regulation. Some of our facilities are covered by the PSM standard. Among other things, the PSM standard requires us to conduct compliance audits every three years. We are on schedule to timely complete these audits.

We are also subject to the EPA’s Risk Management Plan (“RMP”) regulations at certain facilities. These regulations are intended to work with the OSHA Process Safety Management regulations to minimize the offsite consequences of catastrophic releases. The regulations require companies to develop and implement a risk management program that includes a five-year accident history, an offsite consequence analysis process, a prevention program and an emergency response program.

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Safety matters associated with our pipelines are regulated at the federal level by the Pipeline and Hazardous Materials Safety Administration ("PHMSA") of the U.S. Department of Transportation ("DOT") Office of Pipeline Safety ("OPS"). The safety of our pipelines is also regulated by the states in which we operate. States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. Because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. For more information regarding the regulations that may impact us, see "Item 1A.Risk Factors - We may incur significant costs and liabilities resulting from safety and compliance-related regulations."

FERC and Similar State Regulations

Under the Natural Gas Act of 1938, or NGA, as amended by the Energy Policy Act of 2005, or EPAct 2005, the Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation of natural gas in interstate commerce and the sale of natural gas for resale in interstate commerce, and entities engaged in such activities.  FERC also possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of non-interstate pipelines and other natural gas market participants. FERC possesses substantial enforcement authority for violations of the NGA, including the ability to assess civil penalties, order disgorgement of profits and recommend criminal penalties.  

EPAct 2005 amended the NGA to grant FERC new authority to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce, and to prohibit market manipulation.  FERC's anti-manipulation regulations apply to FERC jurisdictional activities, which has been broadly construed by the FERC. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial civil and criminal penalties, including civil penalties of up to $1.0 million per day, per violation.

In 2008, FERC took additional steps to enhance its market oversight and monitoring of the natural gas industry.  Order No. 704, as clarified in orders on rehearing, requires buyers and sellers of natural gas above a de minimis level, including entities not otherwise subject to FERC jurisdiction, to submit an annual report to FERC describing their wholesale physical natural gas transactions that use an index or that contribute to or may contribute to the formation of a gas index.  The FERC is currently contemplating expanding the industry's reporting requirements. On November 15, 2012, the FERC issued a Notice of Inquiry seeking comments whether requiring quarterly reporting of every gas transaction within the FERC's jurisdiction that entails physical delivery for the next day or the next month would provide useful information for improving natural gas market transparency. Comments on the Notice of Inquiry were submitted in February 2013. Following consideration of the comments received, FERC sent out data requests to certain marketers to obtain information related to natural gas sales transactions in July 2013.

Our natural gas gathering operations are generally exempt from direct FERC regulation under the NGA; however, FERC has enforcement authority over certain aspects of our business through its jurisdiction over natural gas markets and intrastate pipelines that engage in interstate transportation services.

Our Eagle Rock DeSoto Pipeline, L.P., operations are subject to FERC regulation of the rates, terms and conditions of service to the extent that the DeSoto Pipeline transports gas in interstate commerce under Section 311 of the Natural Gas Policy Act, or NGPA. Rates for Section 311 transportation service must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. For additional information regarding the applicability of Section 311 to us, see "Item 1A. Risk Factors - Our Eagle Rock DeSoto Pipeline, L.P. (“DeSoto Pipeline”) transports gas in interstate commerce on its Central and North Texas Systems and is therefore subject to FERC regulation under Section 311 of the NGPA."

In 2010, the FERC issued Order No. 735, (as further clarified by Order No. 735-A), which requires intrastate pipelines providing transportation services under Section 311 of the NGPA to report on a quarterly basis more detailed transportation and storage transaction information, including: the full name of each shipper and whether there is an affiliate relationship between the pipeline and the shipper; the type of service performed; rates charged by the pipeline under each contract; primary receipt and delivery points covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; total volumes transported, stored, injected or withdrawn for each shipper; and every fourth quarter, annual revenues received for each shipper, excluding storage revenues. Order No. 735 further requires that such information be supplied through a new electronic reporting system and be posted on FERC's website, and that such quarterly reports may not contain information redacted as privileged. Order No. 735 also extends the Commission's periodic review of the rates charged by the subject pipelines from three years to five years. On July 18, 2013, the FERC issued Order No. 781, effective September 30, 2013, which provides optional, streamlined procedures for processing uncontested NGPA Section 311 rate filings. Under such procedures, the filing would be deemed approved without issuance of a FERC order if no protest is filed within a specified period of time, or if any

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protests are resolved within a reconciliation period. Further, intrastate pipelines with unchanged state-based rates can meet the periodic rate review requirement by certifying that the state-approved rates continue to satisfy the requirements of the FERC regulations.

FERC issued a Notice of Inquiry on October 21, 2010, requesting comments on whether and how holders of firm capacity on intrastate pipelines providing transportation services under Section 311 of the NGPA should be permitted to allow others to make use of their firm intrastate capacity. Comments were filed in January 2011, and FERC action is pending. The Notice of Inquiry may lead to regulations that impact our DeSoto Pipeline operations.

Upstream Business

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 any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

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

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may be more stringent" and "Item 1A. Risk Factors - We may incur significant costs and liabilities resulting from safety and compliance-related regulations."

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.

Midstream Business

Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.

Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from direct regulation by the FERC, but does not define or provide any guidance as to what constitutes “gathering.” For more information regarding the applicability of Section 1(b) of the NGA, see "Item 1A. Risk Factors- A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase."

Our purchasing and gathering operations are subject to ratable take and common purchaser statutes. Texas and Louisiana have adopted a complaint-based form of regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints to resolve grievances relating to natural gas gathering access and rate discrimination.  The Texas Railroad Commission ("TRRC") has authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process, and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers through the imposition of administrative, civil and criminal penalties. For more information on the applicability of the common purchaser and like statutes on us, see "Risk Factors Item 1.A- We may incur significant costs and liabilities resulting from safety and compliance-related regulations."

The TRRC is subject to a sunset condition and a sunset review occurred during the 2013 legislative session. The sunset legislation did not pass, but the Texas Legislature approved continuation of the TRRC for an additional four-year period to September 1, 2017.

The DOT regulates the design, installation, testing, construction, operation, replacement, and management of our pipeline facilities. In addition, we must permit access to and copying of records, and must make certain reports and provide information, as required by the Secretary of Transportation. The states in which we have pipelines have comparable regulations.

We are subject to regulation by the DOT under the Accountable Pipeline and Safety Partnership Act of 1996, sometimes referred to as the Hazardous Liquid Pipeline Safety Act (“HLPSA”), and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to (i) comply with such regulations, (ii) permit access to and copying of records, (iii) file certain reports and (iv) provide information as required by the Secretary of Transportation.

We are subject to the DOT regulation requiring qualification of pipeline personnel. The regulation requires pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. The intent of this regulation is to ensure a qualified work force and to reduce the probability and consequence of incidents caused by human error. The regulation establishes qualification requirements for individuals performing covered tasks.

We are also subject to the DOT Integrity Management regulations, which specify how companies should assess, evaluate, validate and maintain the integrity of pipeline segments that, in the event of a release, could impact High Consequence Areas (“HCAs”). HCAs are defined to include populated areas, unusually sensitive environmental areas and commercially navigable waterways. We are required to develop and implement an Integrity Management Program (“IMP”) that utilizes internal pipeline inspection, pressure testing, or other equally effective means to assess the integrity of HCA pipeline segments. We are also required to periodically review HCA pipeline segments to ensure adequate preventative and mitigative measures exist and take prompt action to address integrity issues raised by the assessment and analysis.

Intrastate Natural Gas Pipeline Regulation. The TRRC has authority over the rates, terms and conditions of service for our DeSoto Pipeline's intrastate transportation activities.

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Intrastate NGL Pipeline Regulation. We do not own any NGL pipelines subject to FERC regulation. We do own and operate an intrastate common carrier NGL pipeline subject to the regulation of the TRRC. The TRRC requires that intrastate NGL pipelines file tariff publications that contain all the rules and regulations governing the rates and charges for service performed. The applicable Texas statutes require that NGL pipeline rates provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions have generally not been aggressive in regulating common carrier pipelines and have generally not investigated the rates or practices of NGL pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although we cannot assure that our intrastate rates would ultimately be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.  

Sales of Natural Gas. Our sales of natural gas for resale in interstate commerce are conducted pursuant to a blanket marketing certificate issued by the FERC. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting the natural gas industry. These initiatives may affect the intrastate transportation of natural gas under certain circumstances.  FERC has imposed an annual reporting requirement on all industry participants, including otherwise non-jurisdictional entities, engaged in wholesale physical natural gas sales and purchases in excess of a de minimis level, and is currently considering imposing quarterly reporting requirements for certain gas sales.  Further, our physical purchases and sales of natural gas, our gathering and/or transportation of natural gas, and any related hedging activities that we undertake are subject to anti-market manipulation regulation by FERC and/or the Commodity Futures Trading Commission.  These agencies hold substantial enforcement authority, including the ability to assess substantial civil penalties, to order disgorgement of profits, and to recommend criminal penalties for violations of anti-market manipulation laws and related regulations.  Violation of the anti-market manipulation laws and regulations could also subject us to related third-party damage claims.  We do not believe that we will be affected by these anti-market manipulation requirements materially differently than other natural gas marketers with whom we compete.

Environmental Matters

Upstream Business

Our Upstream Business involves acquiring, developing and producing oil and natural gas working interests.  

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 Upstream Business is subject to the same environmental laws and regulations that are discussed in our Midstream Business section above. Like our Midstream Business, our Upstream Business could be impacted by any legislation or regulations that are adopted to address greenhouse gas emissions in the United States. For further discussion of these environmental laws and regulations, see “Midstream Business” above and “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, 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;

• 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;

• 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.

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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.”

Midstream Business

We operate pipelines, plants, and other facilities for gathering, compressing, treating, processing, fractionating, or transporting natural gas, NGLs, and other products that 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. We have programs and policies designed to keep our pipelines, plants, and other facilities in compliance with existing environmental laws and regulations. For more information regarding the impact of environmental regulations on us, 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."

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 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 orprocess.”

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.

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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 midstream natural gas and NGL activities. 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. One or more species proposed for 2014 listing as endangered or threatened, has critical habitat that affects the areas where we operate. Specifically, the Lesser Prairie Chicken, which is proposed for listing as threatened, has potential critical habitat that overlaps with areas in which we operate. If the Lesser Prairie Chicken is listed as threatened, we would likely incur additional costs to operate in those areas.

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 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

   Upstream Business

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 proved 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/or 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/or 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.

Midstream Business

Our midstream real property falls into two categories: (i) parcels that we own in fee simple and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We, or our predecessors, have leased these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease,

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easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

Employees

To carry out our operations, as of December 31, 2013, Eagle Rock Energy G&P, LLC or its affiliates employed approximately 586 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. Unless explicitly stated otherwise herein, the information on our website is not incorporated by reference into this Annual Report on Form 10-K.

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.

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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 the Midstream Business Contribution

The following is not intended to constitute a solicitation of any vote or proxy, which will be solicited only by means of a definitive proxy statement or appropriate soliciting materials. The descriptions below are intended only to serve as an overview of the material risks associated with the Midstream Business Contribution.

There can be no assurance that the Midstream Business Contribution will be completed in the anticipated time frame, or at all, or that the anticipated benefits of the Midstream Business Contribution will be realized.

The completion of the Midstream Business Contribution is subject to the satisfaction of customary closing conditions, including unitholder and regulatory approvals. In addition to the required unitholder approval, one of the most significant of these conditions is the need for the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Failure to satisfy these conditions, if not waived, would prevent us from consummating the Midstream Business Contribution. As a result, we can provide no assurance that the Midstream Business Contribution will be completed within the anticipated time frame, or at all.

In addition, even if we are able to complete the Midstream Business Contribution, we may be unable to realize the anticipated benefits of the disposition. For example, a portion of the consideration for the Midstream Business Contribution is in the form of Regency common units, the holding of which exposes us to the risks disclosed by Regency as “risk factors” in their Annual Reports on Form 10-K and subsequent quarterly reports on Form 10-Q. Moreover, the total consideration we receive for the Midstream Business Contribution may be reduced if we suffer certain losses prior to closing or if our working capital is sufficiently negative. Any delay in our ability to consummate the Midstream Business Contribution could make it more difficult to realize these benefits. Further, there are restrictions on the conduct of our business prior to the consummation of the Midstream Business Contribution, requiring us to conduct our business in all material respects only in the ordinary course, subject to specific limitations.

Additionally, even if the Midstream Business Contribution is successfully completed, our smaller scale and greater degree of commodity exposure as a pure-play upstream master limited partnership could result in a higher cost of capital. Moreover, Regency's offer to exchange our $550 million of outstanding senior unsecured notes into an equivalent amount of Regency senior unsecured notes with the same tenor, coupon and a comparable covenant package (the "Exchange Offer") may not be fully subscribed, resulting in our continuing to be subject to certain restrictive covenants in the indenture governing the notes, including limitations on our ability to use the cash proceeds from the Midstream Business Contribution.

Finally, even if we are able to complete the Midstream Business Contribution, we may be unable to quickly identify attractive acquisition candidates or negotiate acceptable purchase contracts with them to acquire suitable upstream assets, or find them (at least on the planned time frame) or that we could have to pay more for these assets than anticipated.

The failure to complete the Midstream Business Contribution could adversely affect the price of our common units and otherwise have an adverse effect on us.

There can be no assurance that the conditions to the completion of the Midstream Business Contribution, many of which are out of our control, will be satisfied. Among other things, we cannot be certain that (i) holders of a majority of our common units will vote in favor of the Midstream Business Contribution or (ii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 will occur within the required timeframe.

If the Midstream Business Contribution is not completed, we may not be able to find alternative means of reducing our debt and improving our liquidity position on favorable terms. This could enhance the risk that we may violate the leverage

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covenant ratio in our revolving credit facility and restrict our ability to grow our businesses and pay distributions to our unitholders.

Further, a failed transaction may result in negative publicity or a negative impression of us in the investment community and may affect our relationship with employees, vendors, creditors and other business partners. Accordingly, if the Midstream Business Contribution is not completed, the price of our common units may be adversely affected. 

In the event of a failed transaction, the Partnership will still have to pay certain costs associated with the Midstream Business Contribution, which will be significant and will primarily consist of advisors’ fees, accounting fees, financial printing and other related costs. These costs could adversely affect our operations and cash flows available for distributions to our unitholders, while not being offset by consideration for the Midstream Business Contribution.

In addition, pursuant to the Contribution Agreement, in certain specified circumstances if the Midstream Business Contribution is not consummated the Partnership may be required to pay Regency a termination fee, which would adversely affect our operations and cash flows available for distributions to our unitholders.

Unitholders may have additional taxable income as a result of ordinary income and capital gain from the Midstream Business Contribution.

We anticipate that the Midstream Business Contribution will result in ordinary income and capital gain allocable to our common unitholders. Such income and gain represents the portion of the built-in gain inherent in the unitholders’ units that is attributable to our midstream business. As a result, any income and gain recognized from the Midstream Business Contribution by a unitholder will provide such unitholder an increase in the basis of such holder's units, which will reduce the amount of income and gain that would have been recognized by that unitholder on any future sale of such units. The amount of ordinary income and capital gain allocated to each unitholder from the Midstream Business Contribution will depend on that unitholder’s particular situation, including the times and prices at which the unitholder purchased its common units. We anticipate that a substantial portion of the gain will be ordinary income. We also anticipate that many existing unitholders have suspended passive losses which, depending on each unitholder’s particular situation, may be utilized to offset a portion or all of the ordinary income or capital gain allocated to them from the Midstream Business Contribution.

Risks Related to Our Business Generally

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 production of oil and natural gas we gather, treat, compress, process, transport and sell; and the volume of NGLs we capture, transport and sell in our Midstream Business;

• the level of oil, natural gas, NGLs and condensate that we produce in our Upstream Business;

• 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 operators’ and other producers’ drilling activities and success of such programs; and

• the level of competition from other upstream and midstream 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 and the indenture governing our 8.375% Senior Notes Due 2019 (the "senior notes") 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

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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.

Natural gas, NGLs, crude oil and other commodity prices are volatile, and an adverse movement in these prices 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.

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 2013, the settlement price of the prompt month NYMEX natural gas contract ranged from $3.11 per MMBtu to $4.46 per MMBtu, and the settlement price of prompt month NYMEX crude oil contract ranged from $86.68 per barrel to $110.53 per barrel.

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 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; 

• 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 our Upstream Business and our Midstream Business's producer-customers can economically produce. As a result, especially during periods of low commodity prices, we or our producer customers 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.

Low commodity prices may result in additional write-downs of our asset carrying values.

In our Upstream Business, low oil and natural gas prices may result in substantial downward adjustments to our estimated proved reserves.  Furthermore, if our estimates of development costs increase, production data factors change or drilling results 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.  Low oil and natural gas prices also may result in reduced drilling activity and declines in future cash flows within our Midstream Business.

We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated future cash flows of our assets, the carrying value may not be recoverable and therefore may require a write-down. During the year ended December 31, 2013, we incurred total impairment 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. See Note 5 and Note 12 to our consolidated financial statements for further discussion. During the year ended December 31, 2012, we incurred total impairment and other charges of $177.0 million, primarily as a result of (i) reduced throughput volumes as our producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment, (ii) the loss of significant gathering contracts on various systems, (iii) the substantial damage incurred at our Yscloskey processing plant as a result of Hurricane Isaac in August 2012, (iv) certain leaseholds in our unproved properties that we expected to expire undrilled and (v) our proved properties in certain regions that are expected to have reduced operating income resulting from natural production declines, lower future natural gas prices and ongoing relatively high operating costs associated with gas

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compression.   We may incur additional impairment charges in the future, which could have a material adverse effect on our results of operations and financial position in the period incurred.

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. Separate from our hedge portfolio, we capitalize on financial arbitrage opportunities and diversify our credit and performance risk for discrete products on a limited basis through our gas marketing and trading subsidiary. 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. For more information about the activities of our trading and marketing subsidiary, which are not listed within our hedging portfolio, see "Part I, Item 1. Our Two Lines of Business - Midstream Business - Marketing and Trading Segment."

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 supply and 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 extreme 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 and other regulators. Issues such as our continued ability to pledge non-cash collateral and the impact of proposed position limits for derivatives could affect the cost and structure of our hedging program. While we expect these issues to be resolved during 2014, we cannot be certain when final rules will be issued. Until final rules are issued, we cannot predict the impact to our hedging activities. For related discussion, see the risk factor below regarding Dodd-Frank.

We have significant 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, 2013, we had $706.8 million outstanding under our senior secured credit facility, leaving approximately $49.2 million of available borrowing capacity as of that date,  and $545.3 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; 

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• 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 or senior notes, 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 comprised of two components: the upstream component and the midstream component. The upstream component of the borrowing base is typically determined semi-annually as an amount equal to the loan value of our proved oil and gas reserves. The midstream component of the borrowing base is determined quarterly as an amount equal to the lesser of (i) 55% of the total borrowing base (subject to increase for certain periods following certain material acquisitions up to 60% of the total borrowing base) and (ii) 3.75 times Consolidated EBITDA attributable to our midstream assets for the trailing four fiscal quarters (which for certain periods may be increased to 4.00 times at our election). For a further discussion of the Credit Agreement amendment, see Note 22 to our consolidated financial statements.

As a result, a reduction in the value of our proved oil and gas reserves due to decreases in commodity prices could result in a reduction in the upstream component of our borrowing base. Moreover, because the midstream component of our borrowing base is limited to 55% of the total borrowing base, we have limited ability to offset any reductions in our upstream borrowing base with increases in our midstream borrowing base. If the amount outstanding under our revolving credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings. If such an event were to occur, it could materially and adversely affect our operations and financial condition.

Covenants in our credit facility and the indenture governing our senior notes may limit our ability to make distributions, enter into certain types of acquisitions or engage in other business transactions.

Our credit facility and the indenture governing our senior notes contain 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 and the indenture governing our senior notes contain covenants requiring us to maintain certain financial ratios and tests. Any subsequent replacement, restatement or amendment of our credit facility and the indenture governing our senior notes 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 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.

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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 upstream assets and oil and natural gas production and reserves, and potentially of midstream assets if the Midstream Business Contribution is not consummated.. In 2014, our capital expenditure budget is expected to be approximately $188 million, excluding acquisitions, of which $124 million relates to upstream capital expenditures, $61 million relates to midstream capital expenditures (before taking into consideration the Midstream Business Contribution) and $2 million relates to corporate capital expenditures. We intend to finance 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. 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:

• volume throughput through our pipelines and processing facilities; 

• 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 or that of our midstream customers; 

• 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, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, or to pursue our growth strategy. Our credit facility and the indenture governing our senior notes 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 gathering and processing available capacity or 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, and 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 respective 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.

In our Upstream Business, 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 of its 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 Midstream Business, we rely on certain natural gas producer customers for a significant portion of our natural gas and NGL supply. The number and relative significance of gas suppliers can change for a number of reasons, including the relative success of the producers’ drilling programs, additions or cancellations of gathering and processing agreements, and the acquisition of new systems. Additionally, some of our competitors may expand or construct gathering, processing and transportation systems or may develop their own gathering, processing and transportation systems in lieu of using ours. Our

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ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. Unless we are able to acquire comparable volumes from other sources, all of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.

In both the Upstream and Midstream Businesses 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 attractive midstream assets, 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 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.

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The weather, unforeseen events or events of force majeure (such as acts of nature or acts of terrorism) in the areas in which we operate can 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). For example, unseasonably wet or dry weather, extended periods of below freezing weather, hurricanes, lightning strikes, tornadoes, electrical outages, domestic attacks or threats of violence may cause disruptions or suspensions of our operations, which could 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. Disruption or suspensions of our operations could adversely affect our operating results. During the fourth quarter of 2013, below freezing weather negatively impacted our results by approximately $4.6 million.

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 the drilling, producing, gathering, compressing, treating, processing and transporting of 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 attorney's fees and other expenses incurred in the prosecution or defense of litigation and may result in curtailment or suspension of our related operations. 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 environmental 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.

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

All of our upstream operated properties are located in Texas, Oklahoma, Alabama, Arkansas, and Mississippi, and all of our midstream assets are located in the Texas Panhandle, East and South Texas and Louisiana. Due to our limited diversification in industry type and location, an adverse development in one of these businesses or operating 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.

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 and perhaps even to continue our current level of service to our current customers will 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 customers and other counterparties, such as our lenders and other hedge counterparties. Any deterioration in the financial health of our customers and 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. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default 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.

Our commodity derivatives trading activities expose us to additional risks associated with selling and marketing products in energy markets.

In 2011, we began conducting commodity derivatives trading activities through our natural gas marketing subsidiary, Eagle Rock Gas Services, LLC. Our portfolio of derivative and other energy contracts may consist of contracts to buy and sell commodities that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. In the past, certain marketing and trading companies have experienced severe financial problems due to price volatility in the energy commodity markets. In certain instances this volatility has caused companies to be unable to deliver energy commodities that they had guaranteed under contract. If such a delivery failure were to occur in one of our contracts, we might incur additional losses to the extent of amounts, if any, already paid to, or received from, counterparties. As a result, our business, results of operations, financial condition and ability to pay distributions to our unitholders may be adversely affected.

Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of production and supplies of oil, natural gas and NGLs, which are dependent on certain factors, many of which are beyond our control. Our success is also dependent on developing current reserves. Any decrease in production or supplies of oil, natural gas or NGLs could adversely affect our business and operating results.

The volume of gas that we gather, process and/or produce is dependent on the level of production from hydrocarbon-producing wells.  The production rate of these wells naturally will decline over time, and as a result, our cash flows associated with them will also decline over time. In order to maintain or increase the throughput levels of our assets we must continually obtain new supplies of natural gas to offset these declines.

In our Midstream Business, the primary factors affecting our ability to obtain new supplies of natural gas and NGLs and attract new customers to our assets include: (i) the level of successful drilling activity by producers near our systems and (ii) our ability to compete for volumes from successful new wells.  The level of drilling activity is dependent on economic and business factors that are beyond our control. The primary factor that impacts producers’ drilling decisions is natural gas prices.

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A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our gathering systems and our natural gas treating and processing plants, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers’ capital budgets, the ability of producers to obtain capital and necessary drilling and other governmental permits and regulatory changes. Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, we and other producers may choose not to develop those reserves.

In our Upstream Business, we also have risks inherent with declining reserves. Our producing reservoirs experience production rate declines that vary depending upon reservoir characteristics and other factors. The overall production decline rate of our upstream business 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, and the number and attractiveness of properties for sale. 

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, determining gas processing settlements and making timely payment to our customers, 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.

Risks Related to Our Upstream Business Specifically

Our upstream 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 market the oil, natural gas and NGLs we produce, 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 only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our 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, gas and NGL 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 upstream 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;

• 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.

We do not provide midstream services to all of our upstream activities. Any curtailment to the gathering systems we use 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 or significant increase in drilling costs 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.

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.

Devon Energy Production Co LP, Continental Resources, Inc., Newfield Exploration Mid-Continent Inc. 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;

• 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.

Risks Related to Our Midstream Business Specifically

Failure of the natural gas, NGLs, condensate or other products produced at our plants or shipped on our pipelines to meet the specifications of interconnecting pipelines or markets could result in curtailments by the pipelines or markets.

The markets and pipelines to which we deliver natural gas, NGLs, condensate or other products establish specifications for the products they are willing to accept.  These specifications include requirements such as hydrocarbon dewpoint, compositions, temperature, and foreign content (such as water, sulfur, carbon dioxide, and hydrogen sulfide), and these specifications can vary by product, pipeline or markets.  If the total mix of a product that we deliver to a pipeline or market fails to meet the applicable product quality specifications, the pipeline or market may refuse to accept all or a part of the products scheduled for delivery to it or may invoice us for the costs to handle or damages from receiving the out-of-specification products. In those circumstances, we may be required to find alternative markets for that product or to shut-in the producers of the non-conforming natural gas that is causing the products to be out of specification, potentially reducing our through-put volumes or revenues.

If third-party pipelines and other facilities interconnected to our midstream systems become unavailable to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.

We depend upon third-party pipelines, natural gas gathering systems and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our midstream customers. Since we do not own or operate any of these pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines and other facilities become unavailable or limited in their ability to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.

Our construction of new assets is subject to regulatory, environmental, political, legal and economic risks, and therefore, may not increase revenue as expected; this could adversely affect our results of operations and financial condition.

One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at the budgeted cost, or at all. For example, the potential listing of one or more species as endangered or threatened under the Endangered Species

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Act could increase our costs or limit our ability to conduct operations in certain areas. The Lesser Prairie Chicken, which is being considered for listing as threatened in 2014, has associated critical habitat that overlaps some areas in which we operate.

Our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a pipeline, the construction expenditures may occur over an extended period of time, yet we will not receive any material increases in revenues until the project is completed. Also, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate. As a result, new or expanded facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

The construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.

We purchase from producers and other parties a substantial amount of the natural gas that flows through our natural gas gathering, processing and transportation systems for resale to third parties, including natural gas pipelines, marketers and a reduced number of end-users. We may not be successful in balancing our purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to be unbalanced. If our purchases and sales are unbalanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income and cash flows.

We do not own all of the land on which our pipelines and facilities are located, so our operations could be disrupted by actions of the landowners.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights of way or if such rights of way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions.

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 appoints three of our directors, and thus it could exert certain significant influence over us.

As of February 24, 2014, NGP beneficially owned 51,386,169 common units, representing over 32% 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.

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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 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.

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;

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• 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.

We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and 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 24, 2014, our management team, directors and NGP (including through their interests in Montierra) beneficially owned an aggregate of 54,375,358 common units, including 1,694,423 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.

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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.

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 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.

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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, oftentimes 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. Most of our midstream assets have been used for midstream activities for a number of years, oftentimes by third parties, whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. We may not be able to recover some or any of these costs from insurance. 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, in response to the April 2010 Macondo well incident the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”) and the Office of Natural Resource Revenue ("ONRR"), in addition to their regulatory predecessors, have adopted a series of regulatory initiatives that impose a variety of new safety and operating measures on oil and natural gas exploration and production operators in federal waters in the U.S. Gulf of Mexico that are intended to help prevent a similar incident in the future. Additional proposed changes in laws, regulations, guidance and policy could affect exploration and production operators in federal waters of the U.S. Gulf of Mexico and, in turn, adversely affect our midstream business that relies, in part, on the receipt of natural gas from such operators.

In addition, 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. In addition, gas wells are required to use completion combustion device equipment (i.e., flaring) by October 15, 2012 if emissions cannot be directed to a gathering line. 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 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 gathering facilities. 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.

Additionally, we are required to comply with common purchaser statutes which generally require gatherers to purchase without undue discrimination as to source of supply or producer. Ratable take statutes generally require gatherers to

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take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or gather oil or natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale; for example, state regulation of production rates and maximum daily production allowable from gas wells.  Although our proprietary gathering lines are currently subject to limited state regulation, there is a risk that state laws will be changed, and this may give producers a stronger basis to challenge the proprietary status of a line, or the rates, terms and conditions of a gathering line providing gathering service. Please see Part I, Item 1. Business—Regulation of Our Operations.

The majority of our gathering systems in Texas have been deemed non-utilities by the TRRC, with the exception being our Turkey Creek gathering system, which is regulated as a utility by the TRRC. Our Hesco Pipeline Company, LLC and the East Texas segment of our DeSoto Pipeline are also regulated by the TRRC. The TRRC has authority over the rates, terms and conditions of service for our DeSoto Pipeline's intrastate transportation activities. 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.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair, or preventative or remedial measures, as well as more stringent pipeline safety standards.

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in "high consequence areas." The regulations require operators to:

• perform ongoing assessments of pipeline integrity; 

• identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

• improve data collection, integration and analysis; 

• repair and remediate the pipeline as necessary; and 

• implement preventive and mitigating actions.

We currently estimate that we may incur costs of $1.8 million in 2014 for specific plant and pipeline integrity management program testing along certain segments of our pipeline, as required by existing DOT and OSHA regulations to be completed this year. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial.

We may incur significant expenses if anomalous pipeline conditions are discovered or due to the implementation of more stringent pipeline safety standards as a result of new or amended legislation. For example, in January 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“Pipeline Safety Act”), which requires increased safety measures for gas and hazardous liquids transportation pipelines. Among other things, the Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, and leak detection system installation. The Pipeline Safety Act also directs owners and operators of interstate and intrastate gas transmission pipelines to verify their records confirming the maximum allowable pressure of pipelines in certain class locations and high consequence areas, requires promulgation of regulations for conducting tests to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas, and increases the maximum penalty for violation of pipeline safety regulations from $1 million to $2 million. PHMSA is also considering changes to its natural gas transmission pipeline regulations to, among other things, expand the scope of “high consequence areas,” strengthen integrity management requirements applicable to existing operators; strengthen or expand non-integrity pipeline management standards relating to such matters as valve spacing, automatic or remotely-controlled valves, corrosion protection, and gathering lines; and add new regulations to govern the safety of underground natural gas storage facilities including underground storage caverns and

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injection or withdrawal well piping that are not regulated today. We cannot predict the final outcome of these legislative or regulatory efforts or the precise impact that compliance with any resulting new requirements may have on our business.

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.

In 2010, Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act ("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 Commodity Futures Trading Commission (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.

The Act also may require the counterparties to the Company's derivative instruments to spin off some of their derivatives activities to a separate entity, which entity may not be as creditworthy as the current counterparty.

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.

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.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

The Federal Energy Regulatory Commission ("FERC") has developed tests for determining which facilities constitute gathering facilities exempt from FERC regulation under the Natural Gas Act of 1938 (NGA). From time to time, FERC may reconsider the elements of such tests. We cannot predict when and under what circumstances FERC may elect to re-examine activities that could fall within the scope of our business with respect to gathering.

We believe that, currently, the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so

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the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation. Although our natural gas gathering and intrastate transportation operations are generally exempt from direct FERC regulation, FERC has jurisdiction over natural gas markets and intrastate pipelines engaged in interstate transportation services.  FERC’s policies and practices across the range of its oil and natural gas regulatory activities, such as its policies on open access transportation, ratemaking, price transparency, market manipulation, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued policies to increase competition, which could increase FERC's regulation over Eagle Rock DeSoto Pipeline.

Our Eagle Rock DeSoto Pipeline, L.P. (“DeSoto Pipeline”) transports gas in interstate commerce on its Central and North Texas Systems and is therefore subject to FERC regulation under Section 311 of the NGPA.  

Our Eagle Rock DeSoto Pipeline is subject to FERC regulation under Section 311 of the Natural Gas Policy Act, or NGPA. In October 2008, DeSoto Pipeline filed a request for FERC approval to continue to use DeSoto Pipeline's currently-effective rate for NGPA Section 311 service, which is based on a city-gate transportation rate approved by the TRRC as being fair and equitable and not in excess of a cost-based rate.  In March 2009, FERC approved a settlement authorizing DeSoto Pipeline to continue to charge the currently-effective rate for NGPA Section 311 service, subject to a requirement that on or before May 1, 2010, DeSoto Pipeline must either file a new application for rate approval with FERC or file an election to use its then-effective rates for intrastate city-gate transportation service on file with the TRRC.  If the latter, then DeSoto Pipeline was required to make a filing with the TRRC for a cost-based rate determination.  On September 14, 2010, the FERC granted an extension of time to May 1, 2012 for DeSoto Pipeline to file a new application for rate approval or to file the election. On April 23, 2012 DeSoto Pipeline filed an application with the TRRC for a cost-based review of the reasonableness of the currently-effective transportation rate to be used for NGPA Section 311 service, and on May 1, 2012, DeSoto Pipeline filed with the FERC a notice of its election to continue to use DeSoto Pipeline's rates for intrastate city-gate transportation service on file with the TRRC for NGPA Section 311 service. The TRRC issued an order on March 26, 2013 determining that DeSoto’s existing transportation rate is fair and equitable and not in excess of a cost-based rate, and DeSoto filed a copy of the TRRC’s order with the FERC on March 29, 2013. FERC approved DeSoto’s notice of rate election on February 12, 2014. DeSoto will be required to make another filing for approval of its NGPA Section 311 rates with FERC on or before May 1, 2017.  Any failure on our part to comply with the rates approved by the FERC for Section 311 service, to comply with the terms and conditions of service established in our FERC-approved Statement of Operating Conditions, or to comply with applicable FERC regulations, the NGPA, or certain state laws and regulations could result in an alteration of the jurisdictional status of DeSoto Pipeline and the imposition of civil and/or criminal penalties.

A change in the regulations related to a state's use of eminent domain could inhibit our ability to secure rights-of-way for future pipeline construction projects.

Certain states where we operate are considering the adoption of laws and regulations that would limit or eliminate a state's ability to exercise eminent domain over private property.  This, in turn, could make it more difficult or costly for us to secure rights-of-way for future pipeline construction and other projects. Further, states may amend their procedures for certain entities within the state to use eminent domain. For example, in response to a recent decision from the Texas Supreme Court, the TRRC may alter the process for a pipeline company to claim common carrier status under Texas law.

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

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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 upstream and midstream 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 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 November 23, 2011, the EPA announced that it was granting in part a petition to initiate a rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in the hydraulic fracturing process. 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 that it plans to develop standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works (POTWs), which will be proposed in 2014. 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

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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 and is expected to release draft final report in 2014 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 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, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS challenge will reduce our cash available for distribution.

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

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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 recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax year in which the technical termination occurs.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department 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. If the IRS were to challenge this 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.

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

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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 Fiscal Year 2014 Budget proposed by the President 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 geological and geophysical amortization period for independent producers. It is unclear whether any such changes will be enacted or 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.

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Item 1B. Unresolved Staff Comments.

Not Applicable.

Item 2. Properties.

For a complete description of our significant properties, see Item 1. Business, which descriptions are incorporated into this item by reference. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that may have been subordinated to the right-of-way grants. We have obtained, where deemed necessary, license or permit agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, waterways, county or parish roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipeline was built was purchased in fee.

We believe that we have satisfactory title to our assets. Title to property may be subject to encumbrances and liens on substantially all of our assets as collateral support of our credit facility. We believe that none of these encumbrances will materially detract from the value of our properties or from our interest in these properties or will they materially interfere with their use in the operation of our business.

While we own our facilities, plants and gathering systems, in many cases we do not always own the land upon which the facilities, plants and gathering systems reside.  In cases where the land is leased (and not owned), we are ordinarily in long-term leases. From time to time, these long-term leases expire, and we are forced to negotiate new terms at market rates or exit the premises.  For more information, see our table of assets within Part I, Item 1 Business – Our Two Lines of Business and Our Five Reporting Segments – Midstream Business.

As discussed within Part I, Item 1 Business above, we entered into an agreement to contribute our Midstream Business to Regency. The sale is conditioned upon the approval of our common unitholders and is subject to regulatory approval. Upon completion of the Midstream Business Contribution, we will remain an MLP focused on our Upstream Business.

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, but otherwise we are not currently a party to any material litigation. We maintain insurance policies with insurers 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. We have been indemnified up to a certain dollar amount for two lawsuits. If there ultimately is a finding against us in these two indemnified cases, we would expect to make a claim against the indemnification up to limits of the indemnification.

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

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, 2012	$	11.81	$	9.74	$	0.2200	May 8, 2012	May 15, 2012
June 30, 2012	$	10.00	$	8.25	$	0.2200	August 7, 2012	August 14, 2012
September 30, 2012	$	9.81	$	8.55	$	0.2200	November 7, 2012	November 14, 2012
December 31, 2012	$	10.58	$	8.23	$	0.2200	February 7, 2013	February 14, 2013
March 31, 2013	$	9.84	$	8.73	$	0.2200	May 7, 2013	May 15, 2013
June 30, 2013	$	10.52	$	7.46	$	0.2200	August 7, 2013	August 14, 2013
September 30, 2013	$	8.25	$	6.01	$	0.1500	November 7, 2013	November 14, 2013
December 31, 2013	$	7.88	$	5.01	$	0.1500	February 7, 2014	February 14, 2014

The last reported sale price of our common units on the NASDAQ Global Select Market on February 24, 2014 was $5.06. As of that date, there were 115 holders of record and approximately 35,455 beneficial owners of our common units.

Cash Distribution Policy

We intend to distribute to our unitholders, on a quarterly basis, all of our available cash 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 on hand at the end of that quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of 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 and the general partner in respect of any one or more of the next four quarters. 

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.

Repurchases of Common Units

The following table sets forth certain information with respect to repurchases of common units during the three months ended December 31, 2013: 

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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, 2013 to October 31, 2013	—	—		—	—
November 1, 2013 to November 30, 2013	157,367	$	5.45	—	—
December 1, 2013 to December 31, 2013	—	—		—	—
Total	157,367	$	5.45	—	—

All of the units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units.  As a result, we are deeming the surrenders to be “repurchases.”  These repurchases were not part of a publicly announced program to repurchase our common units, nor do we have a publicly announced program to repurchase our common units.

Sales of Unregistered Securities

We did not sell our equity securities in unregistered transactions during the twelve months ended December 31, 2013.

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 the Alerian MLP Total Return Index (the “Alerian MLP”). The Alerian MLP is a composite of the 50 most prominent energy master limited partnerships and limited liability companies, as determined by Standard & Poor’s using a float-adjusted market capitalization methodology. The graph assumes an investment of $100 in our common units, and in each of the S&P 500 Index and the Alerian MLP on December 31, 2007 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.

______________________________

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 (the "Securities Act"), or the Securities Exchange Act of 1934, as amended (the "Exchange Act"), except to the extent that we specifically incorporate it by reference into any such filing.

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 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, 2009 to December 31, 2013. 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 our Minerals Business (assets acquired from Montierra and MacLondon Acquisitions) 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. Financial information for these assets for 2008 and 2009 have been retrospectively adjusted to reflect as assets and liabilities held-for-sale and discontinued operations.

• On June 30, 2010, we closed our Rights Offering, for which we received gross proceeds of $53.9 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility.

• On October 19, 2010, we completed the acquisition of certain natural gas gathering systems and related facilities from Centerpoint Energy Field Services, Inc. for $27.0 million of cash. As a result, financial results for the periods prior to October 19, 2010 do not include the financial results from these assets.

• 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 20, 2011, we sold our Wildhorse Gathering System in our East Texas and Other Midstream Segment. Operations related to these assets for 2011 have been recorded as part of discontinued operations. Financial information for these assets for 2009 and 2010 have been retrospectively adjusted to reflect as assets and liabilities held-for-sale and discontinued operations.

• 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 (the "Senior 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 Senior Notes were exchanged for registered notes on February 15, 2012.

• 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.

• 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. The Senior Notes issued in May 2011 and July 2012 are treated as a single series.

• 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 October 1, 2012, we completed the Panhandle Acquisition for total consideration of $230.6 million. As a result, financial results for the periods prior to October 1, 2012 do not include the financial results from these assets.

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

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	Year Ended December 31, 2013			Year Ended December 31, 2012			Year Ended December 31, 2011			Year Ended December 31, 2010			Year Ended December 31, 2009
Statement of Operations Data:
Sales to external customers	$	1,213,812		$	926,065		$	1,027,398		$	741,095		$	679,220
Commodity risk management gains (losses), net	(18,533		)	57,894			32,510			(8,786		)	(106,290		)
Total revenues	1,195,279			983,959			1,059,908			732,309			572,930
Cost of natural gas, NGLs and condensate	790,618			532,719			633,184			468,304			470,099
Operating and maintenance expense	135,205			119,828			93,048			76,415			71,496
Taxes other than income	20,270			19,432			19,148			12,226			10,709
General and administrative expense	81,214			69,994			57,891			45,775			45,819
Other operating (income) expense	—			—			(2,893		)	—			(3,552		)
Impairment expense	214,286			177,003			16,288			6,666			21,788
Depreciation, depletion and amortization	167,170			161,045			131,611			106,398			108,530
Operating (loss) income	(213,484		)	(96,062		)	111,631			16,525			(151,959		)
Interest expense, net	69,866			56,205			41,023			42,171			27,751
Other expense (income)	(257		)	38			184			(450		)	136
(Loss) income from continuing operations before income taxes	(283,093		)	(152,305		)	70,424			(25,196		)	(179,846		)
Income tax (benefit) provision	(5,114		)	(1,703		)	(2,432		)	(2,585		)	989
(Loss) income from continuing operations	(277,979		)	(150,602		)	72,856			(22,611		)	(180,835		)
Discontinued operations, net of tax	—			—			276			17,262			9,577
Net (loss) income	$	(277,979	)	$	(150,602	)	$	73,132		$	(5,349	)	$	(171,258	)
(Loss) income from continuing operations per common unit - diluted	$	(1.82	)	$	(1.13	)	$	0.61		$	(0.26	)	$	(2.38	)
Balance Sheet Data (at period end):
Property, plant and equipment, net	$	1,828,768		$	1,968,206		$	1,763,674		$	1,137,239		$	1,124,695
Total assets	2,127,550			2,294,216			2,045,688			1,349,397			1,534,818
Long-term debt	1,252,062			1,153,103			779,453			530,000			754,383
Net equity	573,879			868,374			1,007,347			579,113			530,398
Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	177,376		$	145,501		$	117,800		$	94,128		$	77,228
Investing activities	(247,048		)	(528,670		)	(373,936		)	73,545			(37,284		)
Financing activities	69,723			382,317			251,970			(175,446		)	(73,260		)
Discontinued operations	—			—			994			9,090			18,132
Other Financial Data:
Cash distributions per common unit (declared)	$	0.74		$	0.88		$	0.75		$	0.23		$	0.10
Adjusted EBITDA(a)	$	230,348		$	245,815		$	208,208		$	126,026		$	172,587

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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).

Non-GAAP Financial Measures

We include in this report Adjusted EBITDA, 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.

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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; excluding certain general and administrative expenses incurred in connection with the Partnership’s strategic review and Midstream Business Contribution.  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 revolving credit facility which is designed to measure our viability and our ability to perform under the terms of our revolving credit facility uses 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 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 of 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 under 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 U.S. GAAP.

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

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	Year Ended December 31, 2013			Year Ended December 31, 2012			Year Ended December 31, 2011			Year Ended December 31, 2010			Year Ended December 31, 2009
Reconciliation of “Adjusted EBITDA” to net cash flows provided by operating activities and net income (loss):
Net cash flows provided by operating activities	$	177,376		$	145,501		$	117,800		$	94,128		$	77,228
Add (deduct):
Discontinued operations, net of tax	—			—			276			17,262			9,577
Depreciation, depletion, amortization and impairment	(381,456		)	(338,048		)	(147,899		)	(113,064		)	(130,318		)
Amortization of debt issuance cost	(4,465		)	(3,483		)	(2,415		)	(1,305		)	(1,068		)
(Loss) gain from risk management activities, net	(19,322		)	53,389			21,571			(35,921		)	(112,637		)
Derivative settlements - operating	(17,965		)	(27,070		)	43,939			38,111			(55,486		)
Other	(13,114		)	(9,151		)	(1,489		)	(5,319		)	(2,878		)
Accounts receivable and other current assets	5,418			35,951			13,394			(10,500		)	(18,810		)
Accounts payable, due to affiliates and accrued liabilities	(30,702		)	(17,524		)	189			3,418			34,903
Risk management activities	—			7,664			25,510			8,136			29,311
Other assets and liabilities	6,251			2,169			2,256			(295		)	(1,080		)
Net income (loss)	(277,979		)	(150,602		)	73,132			(5,349		)	(171,258		)
Add:
Interest expense, net	75,261			61,705			46,618			35,007			40,280
Depreciation, depletion, amortization and impairment	381,456			338,048			147,899			113,064			130,318
Income tax (benefit) provision	(5,114		)	(1,703		)	(2,432		)	(2,585		)	989
EBITDA	173,624			247,448			265,217			140,137			329
Add:
Loss (gain) from risk management activities, net	19,322			(53,389		)	(21,571		)	35,921			112,637
Derivative settlements	19,288			41,517			(37,670		)	(36,981		)	64,425
Restricted unit compensation expense	13,384			9,882			5,145			5,407			6,685
Non-cash mark-to-market Upstream imbalances	(1		)	317			74			(746		)	1,505
Discontinued operations, net of tax	—			—			(276		)	(17,262		)	(9,577		)
Other income	—			40			182			(450		)	135
Other operating (income) expense (a)	4,731			—			(2,893		)	—			(3,552		)
ADJUSTED EBITDA(b)	$	230,348		$	245,815		$	208,208		$	126,026		$	172,587

________________________

(a) Includes $4.7 million of non-recurring general and administrative expenses incurred related to the potential contribution of our Midstream Business to Regency during the year ended December 31, 2013, $2.9 million related to the release of reserves due to the expiration of repurchase obligations for certain receivables which were sold in previous periods during the year ended December 31, 2011 and $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of our purchase price allocation for our acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings, L.P. during the year ended December 31, 2009.

(b) Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the years ended December 31, 2010 and 2009 of $4.0 million and  $48.4 million, respectively.  Including these amortization costs, our Adjusted EBITDA for the years ended December 31, 2010 and 2009, would have been $122.1 million and $124.2 million, respectively.

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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	$	298,921		$	306,820		$	269,392		$	254,200
Gathering and treating services	21,430			21,134			20,153			20,942
Commodity risk management gains (losses), net	(4,284		)	(26,834		)	30,493			(17,908		)
Other revenues	97			113			113			497
Total revenues	316,164			301,233			320,151			257,731
Cost of natural gas, NGLs, oil and condensate	211,361			213,509			185,760			179,988
Operating and maintenance expense	40,308			38,900			40,182			36,085
General and administrative expense	22,434			20,537			19,396			18,847
Depreciation, depletion, amortization and impairment expense	194,193			104,030			42,996			40,237
Interest expense, net	(17,594		)	(17,475		)	(16,609		)	(17,084		)
Interest rate risk management losses, net	(338		)	(459		)	(151		)	(156		)
Income tax benefit	(1,059		)	(2,033		)	(862		)	(1,160		)
Other income (expense), net	73			79			113			(8		)
Net (loss) income	$	(168,932	)	$	(91,565	)	$	16,032		$	(33,514	)
(Loss) earnings per common 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 in our Upstream Segment, 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 $22.3 million during the quarter ended June 30, 2013, while we recorded mark-to-market losses of $27.9 million, $29.6 million and $8.7 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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The following table summarizes our quarterly financial data for 2012:

	For the Quarters Ended
	December 31, 2012			September 30, 2012			June 30, 2012			March 31, 2012
	($ in thousands, except earnings per unit)
Sales of natural gas, NGLs, oil and condensate	$	284,732		$	184,494		$	172,945		$	222,713
Gathering and treating services	21,265			13,604			10,451			11,511
Commodity risk management gains (losses), net	6,040			(35,503		)	95,965			(8,608		)
Other revenues	374			794			3,043			139
Total revenues	312,411			163,389			282,404			225,755
Cost of natural gas, NGLs, oil and condensate	193,921			110,430			97,914			130,454
Operating and maintenance expense	43,057			31,822			32,182			32,199
General and administrative expense	17,610			16,807			18,736			16,841
Depreciation, depletion, amortization and impairment expense	97,181			96,295			59,756			84,816
Interest expense, net	(16,391		)	(14,199		)	(10,647		)	(10,241		)
Interest rate risk management losses, net	(567		)	(1,118		)	(1,463		)	(1,579		)
Income tax benefit	(1,147		)	(386		)	(79		)	(91		)
Other income (expense), net	6			1			4			(49		)
Net (loss) income	$	(55,163	)	$	(106,895	)	$	61,789		$	(50,333	)
(Loss) earnings per unit—diluted	$	(0.39	)	$	(0.78	)	$	0.46		$	(0.40	)

During our fiscal year ended December 31, 2012, we recorded the following unusual or infrequently occurring items:

• On October 1, 2012, we completed the Panhandle Acquisition for an aggregate purchase price of $230.6 million. We commenced recording results of operations relating to this acquisition during the quarter ended December 31, 2012.

• During the quarter ended March 31, 2012, we incurred impairment charges of $45.5 million in our East Texas and Other Segment. During the quarter ended June 30, 2012, we incurred impairment charges of $21.4 million related to our Upstream Segment and East Texas and Other Segment. During the quarter ended September 30, 2012, we incurred impairment charges of $55.9 million in our Upstream Segment and East Texas and Other Segment. During the quarter ended December 31, 2012, we incurred impairment charges of $54.2 million in our Upstream Segment and East Texas and Other Segment. 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, 2012.

• 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 2012.  For example, we recorded mark-to-market gains of $79.5 million during the quarter ended June 30, 2012, while we recorded mark-to-market losses of $14.8 million, $51.3 million and $6.9 million during the quarters ended March 31, 2012, September 30, 2012 and December 31, 2012, 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 Annual Report.

OVERVIEW

We are a domestically-focused, growth-oriented, publicly-traded Delaware limited partnership engaged in the following two businesses:

• Upstream Business—developing and producing oil and natural gas property interests.

• Midstream Business—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; and 

We conduct, evaluate and report on our Upstream Business as one segment. On May 3, 2011, we completed our acquisition of CC Energy II L.L.C. (the "Mid-Continent Acquisition"), as discussed below. Our Upstream Segment includes 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 Southern Alabama (which also includes two treating facilities and one natural gas processing plant and related gathering systems). During the year endedDecember 31, 2013, our Upstream Business generated an operating loss of $154.8 million compared to operating income of $12.4 million during the year endedDecember 31, 2012.  The operating loss generated during the year endedDecember 31, 2013 included impairment and other charges of $214.3 million, compared to impairment and other charges of $45.3 million included in the operating income generated during year endedDecember 31, 2012.

We conduct, evaluate and report on our Midstream Business within three distinct segments—the Texas Panhandle Segment, the East Texas and Other Midstream Segment (which consolidates our former East Texas/Louisiana, South Texas and Gulf of Mexico Segments) and the Marketing and Trading Segment. On October 1, 2012, we completed our acquisition of BP America Production Company's ("BP") Texas Panhandle midstream assets, as discussed further below. Our Texas Panhandle Segment consists of gathering and processing assets in the Texas Panhandle. Our East Texas and Other Midstream Segment consists of gathering and processing assets in East Texas/Northern Louisiana, South Texas, Southern Louisiana, the Gulf of Mexico and Galveston Bay. Our Marketing and Trading Segment consists of crude oil and condensate logistics and marketing in Texas Panhandle and Alabama and natural gas marketing and trading.  During the year endedDecember 31, 2013, our Midstream Business generated operating income from continuing operations of $43.3 million compared to operating loss from continuing operations of $95.9 million during the year endedDecember 31, 2012. As discussed in "Recent Developments," on December 23, 2013, we entered into an agreement to contribute our Midstream Business to Regency Energy Partners, LP ("Regency").

The final segment that we report on is our Corporate and Other Segment, which is where we account for our risk management activity (excluding any risk management activity associated with our natural gas marketing and trading activities), intersegment eliminations and our general and administrative expenses.  During the year endedDecember 31, 2013, our Corporate and Other Segment generated an operating loss of $102.0 million compared to an operating loss of $12.6 million during the year endedDecember 31, 2012.  Results reflected net gains on our commodity derivatives of $18.5 million during the year endedDecember 31, 2013, compared to net gains on our commodity derivatives of $57.9 million during the year endedDecember 31, 2012.  See "Summary of Consolidated Operating Results - Corporate and Other Segment" for a further discussion of the impact of our commodity derivatives.

Recent Developments

On December 23, 2013, we announced that we had entered into a definitive agreement to contribute our Midstream Business to Regency for total consideration of up to $1.325 billion, consisting of $200 million of newly issued Regency common units and a combination of cash and assumed debt, subject to certain closing conditions. As part of this transaction, Regency will conduct an offer to exchange our $550 million of outstanding senior unsecured notes into an equivalent amount of Regency senior unsecured notes with the same tenor, coupon and a comparable covenant package. The cash portion of the purchase price will be reduced by the amount of notes exchanged subject to a 10% adjustment factor, such that if all $550 million of bonds are exchanged, the total consideration will equal $1.27 billion ($1.325 billion less $55 million) consisting of $200 million in Regency units, $550 million of assumed debt and $520 million of cash proceeds. The transaction is subject to

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the approval of our unitholders, Hart-Scott-Rodino Antitrust Improvements Act of 1976 approval and other customary closing conditions.

As the sale of the Midstream Business is conditioned upon the approval of our unitholders, we have not classified the assets of our Midstream Business as assets-held-for-sale or the operations as discontinued.

On February 28, 2014, we announced that ourself and Regency had received a request for additional information and documents from the Federal Trade Commission in connection with the proposed contribution of our Midstream Business to Regency.

Acquisitions

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

In addition, on October 1, 2012, we entered into a 20-year, fixed-fee Gas Gathering and Processing Agreement with BP under which we will gather and process BP's natural gas production from the existing wells connected to the acquired gathering system. Furthermore, BP has committed itself to us under the same agreement, and committed its farmees to us under substantially the same terms, with respect to all future natural gas production from new wells drilled within an initial two-year period from closing, subject to mutually-agreed extensions, and within a two-mile radius of any portion of our gathering system serving such BP connected wells.

On May 3, 2011, we completed the Mid-Continent Acquisition -- the acquisition of all of the outstanding membership interests of CC Energy II L.L.C. ("Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII". The oil and natural gas properties acquired from Crow Creek Energy are located in multiple basins across Oklahoma, north Texas and Arkansas (the "Mid-Continent Properties") and provide us with an extensive inventory of low-risk development prospects.

Impairment

During the year endedDecember 31, 2013, we recorded impairment in our Upstream Segment 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 out Mid-Continent region unproved properties that we expect to expire undrilled in 2014. During the year endedDecember 31, 2013, we recorded no impairment charges in our Midstream Businesses. During the year endedDecember 31, 2012, we recorded impairment charges in our Midstream Business for certain assets within our East Texas and Other Midstream Segment of $131.7 million, due to (i) reduced throughput volumes as our producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment, (ii) the loss of significant gathering contracts on various systems and (iii) the substantial damage incurred at the Yscloskey processing plant as a result of Hurricane Isaac in August 2012. During the year endedDecember 31, 2012, we recorded impairment and other charges in our Upstream Segment of $45.3 million, due to (i) certain leaseholds in our unproved properties that we expect to expire undrilled in 2013 and (ii) our proved properties in the Barnett Shale, East Texas and Permian regions that are expected to have reduced cash flows resulting from lower natural gas prices and ongoing relatively high operating costs associated with gas compression. In addition, we recorded a loss on the sale of our properties in the Barnett Shale.

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.  Further declines in commodity prices and other factors could result in additional impairment charges and changes to the fair value of our derivative instruments.

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, margin, operating expenses and Adjusted EBITDA (defined in Part II, Item 6. Selected Financial Data) on a company-wide basis.

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Volumes (by Business)

Upstream Volumes. In the Upstream Segment, we continually monitor the production rates of the wells we operate. 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 workover and 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. 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).

Midstream Volumes. In our Midstream Business, due to the natural production decline of the wells connected to our systems, we must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. Our ability to maintain existing supplies of natural gas and obtain new supplies is impacted by (1) successful drilling activity and the level of workovers or recompletions of existing connected wells in areas currently dedicated to our pipelines, (2) our ability to compete for volumes from successful new wells in other areas and (3) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.

We rely on producer drilling activity to maintain and grow our midstream volumes.  Generally, producer drilling activity is correlated to the current and expected price of natural gas, and to NGLs in producing basins that have liquids-rich gas reservoirs.  As such, throughput volume in our existing midstream assets will typically increase in times of rising natural gas and NGL prices and will typically decrease in times of falling natural gas and NGL prices. In producing basins that have liquids-rich gas reservoirs, the rise and fall of throughput volumes tends to correlate more predominately with the rise and fall of NGL prices, in particular when natural gas prices approach or achieve historical lows.

Net Revenues

Commodity Pricing.  Revenues, and the associated cost of natural gas, natural gas liquids and condensate, in our Midstream Business generally are positively correlated to NGL and condensate prices, and may be adversely impacted to the extent the price of NGLs declines in relation to the price of natural gas. We refer to the price of NGLs in relation to the price of natural gas as the "fractionation spread." In our Upstream Segment, 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. The impact of our risk management activities are captured in our Corporate Segment. For a further discussion of our risk management activities, see Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Operating Expenses

Upstream Operating Expenses. We monitor and evaluate our Upstream Segment operating 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 Upstream Segment operating costs is associated with the operation of the Big Escambia Creek treating and processing facilities. These facilities are overseen by members of our midstream 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.

Midstream Operating Expenses. We monitormidstream operating expenses as a measure of the operating efficiency of our field operations. Direct labor, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. These expenses are largely independent of the volumes through our systems, but fluctuate depending on the activities performed during a specific period.

Adjusted EBITDA

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

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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.

Natural Gas Supply, Demand and Outlook

Since 2006, the United States has experienced significant growth in natural gas production due to drilling for gas in shale plays (such as the Haynesville and Marcellus plays), and the production of associated gas from wells drilled in liquids-rich shale and other unconventional plays (such as the Eagle Ford and Granite Wash plays). In response to greater supply, natural gas prices have stayed consistently below $5.00/mmbtu at Henry Hub since 2009, but these relatively low prices have not dampened the intensity of development of these reserves. Given this observation and the large amount of undeveloped gas reserves in these types of plays, we expect operators to continue to aggressively develop them as long as natural gas prices remain at or above an average Henry Hub price around $4.00/mmbtu.

The increase in US natural gas production has been absorbed through a reduction in natural gas imports from Canada via pipelines and from other countries as LNG, and through an increase in consumption for electricity generation. Because US electricity generation has been relatively flat over this period, almost all of the increase in natural gas-fired generation has come at the expense of coal-fired generation. Despite lower natural gas prices, other uses for natural gas (such as industrial, residential and vehicle uses) have not grown significantly, and we do not expect them to do so in the next few years. Also, it is uncertain whether natural gas can continue to gain market share from coal in the electrical power generation market. Therefore, 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 (less than $4.50/mmbtu) unless significant new sources of demand arise, such as additional fuel switching in the electrical power generation industry (perhaps due to increased regulation of emissions from coal-fired generators) or the export of natural gas to other markets in the form of LNG.

Crude Oil Supply, Demand and Outlook

Crude oil is a global commodity and the majority of the world’s reserves are controlled by foreign governments and state-owned companies. Much of the world’s reserves are in politically unstable regions, particularly in the Middle East and Africa, and supply disruptions (or even the threat of supply disruptions) can cause large increases in the price of crude oil. Since 2000, worldwide petroleum supply has grown at a modest pace, but not all oil producing countries have experienced increases in production. Almost all of the increase can be explained by 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. We believe that as long as WTI prices remain above $70-80/bbl, many of these plays will generate economic returns and US production growth will continue for the next several years.

The non-OECD countries currently account for almost half of worldwide petroleum consumption, and since 2000, substantially all of the increase in worldwide consumption has occurred in them. Within that group of countries, the leading consumers are China, India, Brazil and Russia, followed by Saudi Arabia, Iran and Indonesia. These seven countries account for 60% of non-OECD consumption and each of them has increased its petroleum consumption over the last decade. The most significant in terms of quantity consumed and consumption growth rate is China.

We believe that the factors that have resulted in flat or declining consumption in the OECD countries (low population growth, an aging population and increased fuel efficiency) are likely to persist, so future oil demand growth will must come from the non-OECD countries. We are optimistic that these countries will continue to increase their rates of oil consumption as their economies continue to grow and mature. The performance of the Chinese economy will continue to be an important factor in global oil demand, and we believe that if it continues to grow modestly and shifts to a more consumer-driven economy, it will provide an important source of demand growth to support oil prices.

As a result of the supply and demand trends, we believe that crude oil prices in the United States will stay in a range between $70 and $100/bbl over the next few years, but we recognize that infrastructure constraints may create short-lived periods of prices below this range.

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Natural Gas Liquids Supply, Demand and Outlook

The high levels 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 declined significantly in 2012 and remained low in 2013. Historically, natural gas liquids prices have tended to have a high correlation to crude oil prices, especially for propane and heavier NGLs, This correlation weakened in 2012, and in 2013 was almost non-existent. We do not expect the prices of NGL’s and crude oil to be well-correlated in the short term, and we are uncertain if and when the correlation will resume.

The majority of the NGLs we produce are delivered into the Conway, Kansas hub. During 2013, the difference between NGL prices at the Conway Hub and the Mont Belvieu, Texas hub were relatively modest, and actually improved in the final months of the year By the end of 2013, prices for propane, iso-butane, and normal-butane were trading at Conway at a slight premium to the Mont Belvieu prices.

Ethane comprises the largest volumetric percentage of the typical NGL barrel, and ethane prices historically have been substantially less correlated to crude oil than have the heavier NGLs. Increased supply, driven by drilling in NGL-rich plays, led to multi-year lows in ethane prices during 2012 and these low prices largely continued in 2013. Ethane demand is primarily driven by global petrochemical production, specifically by its use as a feedstock for ethylene production. Ethane's low price relative to heavier ethylene feedstocks has resulted in strong worldwide demand, and chemical manufacturers have recently announced projects to increase their ethylene production capacity using ethane. These projects have long lead-times, however, and we do not expect the demand response to offset the existing supply for several years. .

 Sulfur Supply, Demand and Outlook

Much of the natural gas that we produce in the East Texas and Alabama regions within our Upstream Segment contains high, naturally-occurring concentrations of hydrogen sulfide. This is a corrosive, poisonous gas that must be removed from the natural gas stream before it can be processed for NGL extraction or sale. The process of removing the hydrogen sulfide yields a large amount of elemental sulfur, which we sell or otherwise dispose of. The process of removing hydrogen sulfide from natural gas, and similar processes for the removal of hydrogen sulfide from sour crude oils (prior to refining), are the primary sources of sulfur production in the United States and the world.

The primary use of sulfur is the production of sulfuric acid, and one of the major uses of sulfuric acid is the production of phosphoric acid. In turn, phosphoric acid is a key raw material in the manufacture of phosphate fertilizers. Therefore, one of the major factors influencing the demand for sulfur is the demand for fertilizer. The region around Tampa, Florida contains a large amount of fertilizer manufacturing facilities, and Tampa also serves as an export hub for sulfur.

As with many commodities, the developing economies are responsible for much of the global demand growth for fertilizer. Sulfur prices at Tampa in 2013 ranged from a high of $155 per long ton in the second quarter to a low of $75 per long ton in the fourth quarter. Sulfur prices were $110 per long ton in the first quarter of 2014. We expect demand to remain strong relative to supply in 2014, and, that over the next few years, the performance of the emerging economies, uncertain global economic conditions, and the start-up of significant sulfur-producing operations in the Middle East could result in supply/demand imbalances and cause significant price volatility.

Impact of Regulation of Greenhouse Gas Emissions

The operations of and use of the products produced by the natural gas and oil industry are sources of emissions of certain greenhouse gases ("GHG"), namely carbon dioxide and methane. The United States Environmental Protection Agency ("EPA"), by virtue of a 2007 Supreme Court decision, was deemed to have authority to regulate carbon dioxide and other GHG emissions under the Clean Air Act. It is possible that legislation will be proposed to amend the Clean Air Act to exclude GHG, although the probability of the enactment of such legislation is uncertain.

The EPA has already promulgated GHG regulations applicable to the natural gas and oil industry. Moreover, the current presidential administration has indicated that it may pursue additional GHG regulation through executive and administrative means in the absence of federal legislation, but the potential scope and content of such regulation are undetermined at this time. Because of the uncertainty of the nature of any potential future federal GHG regulations at this time, we are unable to forecast how future regulation of GHG emissions would negatively impact our operations.  We will continue to monitor regulatory developments and to assess our ability to reasonably predict the economic impact of these developments on our business.

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The commercial risk associated with the exploration and production of fossil fuels lies in the uncertainty of regulations that may affect our customers, which could affect the demand for crude oil and natural gas.  Such an impact on demand could have an adverse impact on the demand for our services, and could have an impact on our financial condition, results of operations and cash flows. On the other hand, when burned, natural gas produces less greenhouse gas emissions than other fossil fuels, such as refined petroleum products or coal.  As a result, climate change legislation or GHG emissions regulations could create an increased demand for natural gas.

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 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 in our Upstream Segment 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.

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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 above 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.

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 Upstream Business production estimates, we have hedged approximately 80% of our 2014 expected hedgeable crude, condensate and natural gas liquids (heavier than ethane) volumes related to our Upstream Business and 96% of our natural gas and ethane production related to our Upstream Business. Similarly based on the production estimates in our current Midstream Business forecast, we have hedged approximately 81% of our 2014 expected hedgeable crude, condensate and natural gas liquids (heavier than ethane) volumes related to our Midstream Business and 115% of our natural gas and ethane production related to our Midstream Business.

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 June 2015 for our interest rate hedges and December 2016 for our commodity hedges. We monitor and review hedging positions regularly.

Depreciation Expense and Cost Capitalization Policies. Our midstream assets consist primarily of natural gas gathering pipelines and processing plants. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the cost of funds used in construction. The cost of funds used in construction represent capitalized interest. These costs are then expensed over the life of the constructed asset through the recording of depreciation expense.

As discussed in Note 2 to our consolidated financial statements, depreciation of our midstream assets is generally computed using the straight-line method over the estimated useful life of the assets. The costs of renewals and betterments which extend the useful life of property, plant and equipment are also capitalized. The costs of repairs, replacements and maintenance projects are expensed as incurred.

The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values which would impact future depreciation expense.

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;

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• 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 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. For our long-lived assets in our Midstream Business, our estimate of cash flows is based on assumptions regarding the long-lived asset, including future commodity prices and estimate future natural gas production in the region (which is dependent in part on commodity prices). Our estimate of natural gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to: (i) changes in the general economic conditions in which the long-lived asset is located, (ii) the availability and prices of the natural gas supply, (iii) our dependence on certain significant customers and producers of natural gas and (iv) improvements in exploration and production technologies.

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

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the years ended December 31, 2013and 2012. Operating results for our individual operating segments are also presented in tables in this Item 7.

		Year Ended December 31,
		2013			2012
	($ in thousands)
Revenues:
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales		$	1,129,333		$	864,884
Gathering, compression, processing and treating fees		83,659			56,831
Commodity risk management gains (losses), net		(18,533		)	57,894
Other revenue		820			4,350
Total revenues		1,195,279			983,959
Cost of natural gas, natural gas liquids, condensate and helium		790,618			532,719
Costs and expenses:
Operating and maintenance		135,205			119,828
Taxes other than income		20,270			19,432
General and administrative		81,214			69,994
Impairment and other		214,286			177,003
Depreciation, depletion and amortization		167,170			161,045
Total costs and expenses		618,145			547,302
Total operating loss		(213,484		)	(96,062		)
Other income (expense):
Interest expense, net		(68,762		)	(51,478		)
Interest rate risk management losses, net		(1,104		)	(4,727		)
Other (expense) income, net		257			(38		)
Total other expense		(69,609		)	(56,243		)
Loss from continuing operations before income taxes		(283,093		)	(152,305		)
Income tax benefit		(5,114		)	(1,703		)
Loss from continuing operations		(277,979		)	(150,602		)
Discontinued operations, net of tax		—			—
Net loss		$	(277,979	)	$	(150,602	)
Adjusted EBITDA(a)		$	230,348		$	245,815

________________________

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

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Upstream Segment

	Year Ended December 31,
	2013			2012
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Oil and condensate	$	67,677		$	58,420
Intersegment sales - condensate	39,075			43,004
Natural gas	37,249			32,105
Intersegment sales - natural gas	7,973			10,339
NGLs	40,583			43,831
Sulfur	8,051			14,020
Other	701			1,486
Total revenue	201,309			203,205
Operating Costs and expenses:
Operations and maintenance	54,354			56,734
Depletion, depreciation and amortization	87,456			88,777
Impairment and other	214,286			45,289
Total operating costs and expenses	356,096			190,800
Operating (loss) income	$	(154,787	)	$	12,405
Capital expenditures	$	129,099		$	160,330
Realized average prices:
Oil and condensate (per Bbl)	$	87.34		$	85.65
Natural gas (per Mcf)	$	3.53		$	2.58
NGLs (per Bbl)	$	35.12		$	39.12
Sulfur (per Long ton)	$	76.38		$	137.46
Production volumes:
Oil and condensate (Bbl)	1,222,270			1,184,200
Natural gas (Mcf)	12,804,475			16,442,579
NGLs (Bbl)	1,155,639			1,120,522
Total (Mcfe)	27,071,929			30,270,911
Sulfur (Long ton)	105,394			102,002

Revenue. For the year endedDecember 31, 2013, Upstream Segment revenues decreased by $1.9 million as compared to the year endedDecember 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 endedDecember 31, 2013, compared to the year endedDecember 31, 2012. Volumes during the year endedDecember 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 endedDecember 31, 2013 were negatively impacted by a third-party processing plant being shutdown for eight days in September. 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

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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 endedDecember 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.

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.

• 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.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, decreased by $2.4 million for the year endedDecember 31, 2013 as compared to the year endedDecember 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.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $1.3 million for the year endedDecember 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 2013 and 2012.

Impairment and Other. During the year endedDecember 31, 2013, we recorded an impairment charges in our Upstream Segment 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 expect to expire undrilled in 2014. During the year endedDecember 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.

Capital Expenditures.  Capital expenditures decreased by $31.2 million for the year endedDecember 31, 2013 as compared to the year endedDecember 31, 2012.   During the year endedDecember 31, 2013, we drilled and completed thirteen gross operated wells, 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 endedDecember 31, 2013, we conducted ten recompletions, twenty-four capital workovers and eight expense workovers across our operations.

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Midstream Business (Three Segments)

Texas Panhandle Segment

	Year Ended December 31,
	2013		2012
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids, oil, condensate and helium sales	$	484,634	$	334,295
Intersegment sales - natural gas	226,576		105,759
Gathering, compression, processing and treating fees	53,739		25,743
Other revenue (a)	119		2,864
Total revenue	765,068		468,661
Cost of natural gas, natural gas liquids, condensate and helium (b)(c)	594,325		332,875
Operating costs and expenses:
Operations and maintenance	81,186		60,884
Depreciation and amortization	57,781		44,451
Total operating costs and expenses	138,967		105,335
Operating income	$	31,776	$	30,451
Capital expenditures	$	81,590	$	131,928
Realized prices (d):
Oil and condensate (per Bbl)	$	84.41	$	82.64
Natural gas (per Mcf)	$	3.45	$	2.63
NGLs (per Bbl)	$	36.31	$	36.00
Production volumes:
Gathering volumes (Mcf/d)(e)	370,606		212,617
NGLs (net equity Bbls)	805,190		1,270,601
Condensate (net equity Bbls)	1,155,590		801,828
Natural gas (MMbtu/d)(e)	7,747		547

_______________________

(a) The year ended December 31, 2012 included the receipt of an insurance payment of $2.9 million for business interruption related to the downtime to our Cargray plant caused by the severe winter weather in 2011.

(b) Includes the cost of gathering, compression, processing and treating fees of $2.0 million and $1.5 million for the year endedDecember 31, 2013 and 2012, respectively.

(c) Includes purchase of natural gas of $200 and $83 from the Upstream Segment for the year endedDecember 31, 2013 and 2012, respectively.

(d) Excludes the impact of adjustments related to prior periods, including true-ups of estimates.

(e) Gathering volumes (Mcf/d) and natural gas positions (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.

Revenue and Cost of Natural Gas and NGLs. For the year endedDecember 31, 2013, revenues minus cost of natural gas, NGLs, condensate and helium for our Texas Panhandle Segment operations totaled $170.7 million compared to $135.8 million for the year endedDecember 31, 2012. The addition of volumes from the Panhandle Acquisition, which closed on October 1, 2012, positively impacted the Texas Panhandle Segment's revenues minus cost of natural gas, NGLs, condensate and helium relative to the corresponding prior year period positively by $37.1 million during the year endedDecember 31, 2013 compared to 2012. The increase resulting from the Panhandle Acquisition during the year endedDecember 31, 2013 was partially offset by the following: (i) the harsh winter storms in the Texas Panhandle in early January and late February 2013 and again in late November and the entirety of December 2013, which resulted in lower volumes and lower-than-normal NGL recovery rates; and (ii) adjustments related to amounts recorded during the three months ended December 31, 2012. During the year endedDecember 31, 2013, we received new information related to the assets acquired in the Panhandle Acquisition, which were operated by BP during the three months ended December 31, 2012. We were informed that the cost of natural gas, NGLs

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and condensate on the assets was higher than previously communicated. Due to these adjustments, our results for the year endedDecember 31, 2013 were negatively impacted by $3.2 million.

Our NGL equity volumes were lower in part due to our decision to reject ethane during the year ended December 31, 2013. Our election to reject ethane is an economic decision based on our contract portfolio and the price spread between ethane and natural gas.  This decision also has a positive impact on our natural gas volumes as the ethane remains unprocessed and sold as natural gas.

Our Texas Panhandle Segment lies within 14 counties in Texas and two counties in Oklahoma and consists of our East Panhandle System and our West Panhandle System. The limited drilling activity in the West Panhandle System is not sufficient to offset the natural declines experienced on this system. The combination of our contract mix and the high NGL content of the natural gas gathered in the West Panhandle System provides us with a high level of equity NGL and condensate production. As such, any declines in gathered volumes from the West Panhandle System must be offset with increases in gathered volumes from other systems on a greater than one-to-one basis in order to maintain our total equity NGL and condensate production. We have seen continued drilling activity in the East Panhandle System by our producer customers and continue to expect drilling activity and the resulting volumes to continue during the remainder of 2014.

Operating Expenses. Operating expenses, including taxes other than income, for the year endedDecember 31, 2013 increased $20.3 million as compared to the year endedDecember 31, 2012. The increase was primarily driven by $17.7 million of costs related to the operation of the assets acquired in the Panhandle Acquisition for the year endedDecember 31, 2013 compared to 2012. Excluding the acquisition, operating expenses increased primarily due to costs associated with the new Wheeler Plant and a full 12 months of operations at the Woodall Plant.

Depreciation and Amortization. Depreciation and amortization expenses for the year endedDecember 31, 2013 increased $13.3 million as compared to the year endedDecember 31, 2012. The increase was due to increased depreciation expense primarily associated with the new Woodall and Wheeler Plants, Panhandle Acquisition and other capital expenditures placed into service during the period.

Capital Expenditures. Capital expenditures for the year endedDecember 31, 2013 decreased by $50.3 million compared to the year endedDecember 31, 2012. The decrease was primarily driven by spending related to the construction of our Woodall Plant in 2012, partially offset by spending related to construction of our Wheeler Plant in 2013.

On July 8, 2013, we announced the successful startup of our previously announced 60 MMcf/d high-efficiency cryogenic processing plant in Wheeler County, Texas, in the heart of the Granite Wash play. With the completion of the Wheeler Plant, we now have in excess of 500 MMcf/d of high-efficiency cryogenic processing capacity serving the Granite Wash play. The construction of the Wheeler Plant and associated gathering and compression cost approximately $68 million.

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East Texas and Other Midstream Segment

	Year Ended December 31,
	2013		2012
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids, oil and condensate sales	$	106,889	$	125,512
Intersegment sales - natural gas	37,716		39,099
Gathering, compression, processing and treating fees	29,748		31,017
Total revenue	174,353		195,628
Cost of natural gas, natural gas liquids and condensate (a)	131,966		147,493
Operating costs and expenses:
Operations and maintenance	19,943		21,762
Impairment	—		131,714
Depreciation and amortization	19,476		25,771
Total operating costs and expenses	39,419		179,247
Operating income (loss)	$	2,968	$	(131,112	)
Capital expenditures	$	7,827	$	9,328
Realized prices (b):
Oil and condensate (per Bbl)	$	99.36	$	96.91
Natural gas (per Mcf)	$	3.58	$	2.85
NGLs (per Bbl)	$	30.03	$	37.83
Production volumes:
Gathering volumes (Mcf/d)(c)	195,235		255,752
NGLs (net equity Bbls)	160,235		338,636
Condensate (net equity Bbls)	31,025		38,350
Natural gas (MMbtu/d)(c)	296		1,530

_________________________

(a) Includes the cost of gathering, compression, processing and treating fees of $3.0 million and $4.4 million for the year endedDecember 31, 2013 and 2012, respectively.

(b) Excludes the impact of adjustments related to prior periods, including true-ups of estimates.

(c) Gathering volumes (Mcf/d) and natural gas position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.

Revenue and Cost of Natural Gas and NGLs. For the year endedDecember 31, 2013, revenues minus cost of natural gas and NGLs for our East Texas and Other Midstream Segment totaled $42.4 million compared to $48.1 million for the year endedDecember 31, 2012. During the years endedDecember 31, 2013 and 2012, we recorded revenues associated with deficiency payments of $6.2 million and $5.0 million, respectively. We receive deficiency payments under certain of our gathering contracts when delivered volumes fail to meet certain thresholds. These amounts are included within gathering and treating services revenue. Excluding these deficiency payments, revenues minus cost of natural gas, NGLs and condensate for the years endedDecember 31, 2013 and 2012 would have been $36.2 million and $43.2 million, respectively. The decrease, excluding deficiency payments, for the year endedDecember 31, 2013 compared to the year endedDecember 31, 2012, is primarily due to a decrease in gathering and equity volumes and lower NGL prices, partially offset by an increase in condensate and natural gas prices.

The gathering volumes for the year endedDecember 31, 2013, decreased as compared to the year endedDecember 31, 2012, due in part to the impact of Hurricane Issac in August 2012, which caused significant damage to the Yscloskey Plant in Louisiana, in which we have a non-operated ownership interest. The owners of the Yscloskey Plant elected to shut down the facility following Hurricane Isaac. We estimate this negatively impacted gathering volumes by approximately 52 MMcf/d and NGL volumes by approximately 28,900 Bbls for the year endedDecember 31, 2013. In addition, our volumes declined due to the loss of customers on our Panola system, which we estimate negatively impacted gathering volumes by approximately 4 MMcf/d, NGL volumes by approximately 35,300 Bbls and condensate volumes by approximately 8,400 Bbls for the year

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endedDecember 31, 2013. Also contributing to the decrease in gathering volumes were natural declines in the production of the existing wells and reduced drilling activity in dry-gas formations related to a decline in natural gas prices.

Operating Expenses. Operating expenses for the year endedDecember 31, 2013 decreased $1.8 million compared to the year endedDecember 31, 2012, primarily due to the lower operating expenses at Yscloskey and Panola.

Impairment. No impairment charges were recorded during the year endedDecember 31, 2013. We recorded impairment charges of $131.7 million during the year endedDecember 31, 2012 on certain assets due to (i) reduced throughput volumes as our producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment during the first three months of 2012, (ii) the loss of significant gathering contracts on our Panola system during the year endedDecember 31, 2012 and (iii) the substantial damage incurred at the Yscloskey processing plant as a result of Hurricane Issac in August 2012.

Depreciation and Amortization. Depreciation and amortization expenses for the year endedDecember 31, 2013, decreased $6.3 million compared to the year endedDecember 31, 2012. The decrease was primarily a result of the impairment charge recorded during the year ended2012.

Capital Expenditures. Capital expenditures for the year endedDecember 31, 2013, decreased $1.5 million compared to the year endedDecember 31, 2012. The decrease was due to fewer new well connects in 2013 compared to 2012.

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Marketing and Trading Segment

	Year Ended December 31,
	2013			2012
	($ in thousands)
Revenues:
Natural gas, oil and condensate sales (a)	$	384,250		$	256,701
Intersegment sales - natural gas and condensate	(272,116		)	(154,992		)
Gathering, compression, processing and treating fees	172			71
Total revenue	112,306			101,780
Cost of oil and condensate	64,527			52,434
Intersegment cost of oil and condensate	38,844			44,317
Operating costs and expenses:
Operations and maintenance	(8		)	2
Depreciation and amortization	428			273
Total operating costs and expenses	420			275
Operating income	$	8,515		$	4,754
Capital Expenditures	$	309		$	5,489

_________________________

(a) Includes losses of $0.4 million and $0.2 million for the year endedDecember 31, 2013 and 2012, respectively, as a result of marking derivative contracts to market and gains of $0.7 million and $0.4 million for the year endedDecember 31, 2013 and 2012, respectively, from derivative contracts that settled during the respective periods.

Our Marketing and Trading Segment is comprised of our crude and condensate marketing operations and our natural gas marketing and trading activities. Our crude and condensate operations consist of developing and implementing marketing uplift strategies surrounding crude oil and condensate production in Alabama, the Texas Panhandle and Oklahoma. Through our natural gas marketing and trading activities, we seek to capitalize on opportunities that naturally extend from our upstream and midstream assets. Where in the past, we generally sold our natural gas to wholesale buyers at the tailgates and wellheads of our assets, now we hold transportation agreements and move our product to many locations and many types of buyers. This strategy diversifies our credit and performance risk and allows us to capitalize on daily, monthly and seasonal changes in market conditions.

As part of our natural gas marketing and trading activities, we enter into both financial derivatives and physical contracts. Our financial derivatives, primarily basis swaps, are transacted, among other things: (i) to economically hedge subscribed capacity exposed to market rate fluctuations; and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction.

A commodity-related derivative contract may be designated as a "normal" purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as "normal," the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement. Commodity-related contracts that do not qualify for the normal designation are accounted for as derivatives and are marked-to-market each period.

For the years endedDecember 31, 2013 and 2012, revenues minus cost of oil and condensate totaled $8.9 million and $5.0 million, respectively. The increase in revenues minus cost of oil and condensate was primarily the result of increased activity in both our natural gas and condensate marketing and trading businesses.

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Corporate and Other Segment

	Year Ended December 31,
	2013			2012
	($ in thousands)
Revenues:
Commodity risk management gains (losses), net	$	(18,533	)	$	57,894
Intersegment elimination - Sales of natural gas and condensate	(39,224		)	(43,209		)
Total revenue	(57,757		)	14,685
Intersegment elimination - Cost of natural gas and condensate	(39,044		)	(44,400		)
General and administrative	81,214			69,994
Intersegment elimination - Operations and maintenance	—			(122		)
Depreciation and amortization	2,029			1,773
Operating loss	(101,956		)	(12,560		)
Other income (expense):
Interest expense, net	(68,762		)	(51,478		)
Interest rate risk management losses, net	(1,104		)	(4,727		)
Other (expense) income, net	257			(38		)
Total other expense	(69,609		)	(56,243		)
Loss from continuing operations before taxes	(171,565		)	(68,803		)
Income tax benefit	(5,114		)	(1,703		)
Segment loss	$	(166,451	)	$	(67,100	)

Revenue. Our Corporate and Other Segment's revenue consists of our intersegment eliminations and our commodity derivatives activity (excluding any risk management activity associated with our natural gas marketing and trading activity). Our commodity derivatives activities impact our Corporate and Other Segment revenues through: (i) gains or losses due to the changes in mark-to-market value of our commodity derivatives scheduled to settle in future periods; and (ii) the gains or losses on our commodity derivatives settled in the indicated period. In general, the change in the mark-to-market value of our derivative position may be due to several factors including the settlement of derivative instruments during the period, the addition of new derivative positions during the period, changes in the forward curves of the underlying commodities from the beginning to the end of the period, changes in interest rates used in the mark-to-market calculations from the beginning to the end of the period and the passage of time during the period.  

During the year endedDecember 31, 2013, our commodity risk management losses increased by $76.4 million, as compared to the year endedDecember 31, 2012. During the year endedDecember 31, 2013, our losses due to the change in the mark-to-market value of our derivative contracts increased by $50.5 million, as compared to the year endedDecember 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 endedDecember 31, 2013 decreased $26.0 million, as compared to the year endedDecember 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 endedDecember 31, 2012, as compared to the same period in 2013.

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.

Intersegment Eliminations. During the years endedDecember 31, 2013 and 2012, our Upstream Segment sold condensate and natural gas to the Marketing and Trading Segment within our Midstream Business for resale. In addition, during the years endedDecember 31, 2013 and 2012, our Upstream segment sold natural gas to our Panhandle Segment.

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General and Administrative Expenses. General and administrative expenses increased by $11.2 million for the year endedDecember 31, 2013 as compared to the same period in 2012. This increase was primarily due to higher salaries and benefits, which was due to (i) an increase in our headcount due to the Panhandle Acquisition and (ii) increased equity compensation expense due to additional grants, as well as increased professional fees. During the year ended December 31, 2013 we incurred approximately $4.7 million of accounting, legal and advisory services expenses related to the potential contribution of our Midstream Business to Regency. The advisory services included the cost of the issuance of fairness opinions, which we will be able to credit against the total amount of advisory fees due if the transaction is successful.

We do not allocate our general and administrative expenses to our operational segments.

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 endedDecember 31, 2013, our interest rate risk management losses decreased by $3.6 million as compared to the year endedDecember 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 increased by $17.3 million during the year endedDecember 31, 2013, as compared to the year endedDecember 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 benefit 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.

Adjusted EBITDA

Adjusted EBITDA, as defined under "Non-GAAP Financial Measures," decreased by $15.5 million from $245.8 million for the year endedDecember 31, 2012 to $230.3 million for the year endedDecember 31, 2013. The following table presents the changes in operations, by segment, impacting Adjusted EBITDA:

	Year Ended December 31,
	2013			2012		Change
	($ in thousands)
Revenues minus cost of natural gas and NGLs - Midstream (a)	$	222,419		$	189,142	$	33,277
Revenues - Upstream (b)	201,308			203,522		(2,214		)
Intercompany elimination revenues minus cost of natural gas and condensate	(180		)	1,191		(1,371		)
Commodity derivative settlements - Corporate and Other	25,375			51,332		(25,957		)
Total incremental revenues minus cost of natural gas and NGLs	448,922			445,187		3,735
Operating expenses - Midstream	101,121			82,648		18,473
Operating expenses - Upstream	54,354			56,734		(2,380		)
General and administrative expenses (c)	63,099			59,990		3,109
Adjusted EBITDA (d)	$	230,348		$	245,815	$	(15,467	)

_________________________

(a) Excludes derivative mark-to-market gains/losses from the Marketing and Trading Segment.

(b) Excludes the impact of imbalances

(c) Excludes non-cash compensation charges related to our long-term incentive program and non-recurring charges incurred during the year ended December 31, 2013 related to the potential contribution of our Midstream Business to Regency.

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(d) 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, 2012 Compared with Year Ended December 31, 2011

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the years ended December 31, 2012 and 2011. Operating results for our individual operating segments are presented in tables in this Item 7.

	Year Ended December 31,
	2012			2011
	($ in thousands)
Revenues:
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales	$	864,884		$	977,952
Gathering, compression, processing and treating fees	56,831			47,770
Commodity risk management gains (losses), net	57,894			32,510
Other revenue	4,350			1,676
Total revenues	983,959			1,059,908
Cost of natural gas, natural gas liquids, and condensate	532,719			633,184
Costs and expenses:
Operating and maintenance	119,828			93,048
Taxes other than income	19,432			19,148
General and administrative	69,994			57,891
Other operating income	—			(2,893		)
Impairment	177,003			16,288
Depreciation, depletion and amortization	161,045			131,611
Total costs and expenses	547,302			315,093
Total operating income (loss)	(96,062		)	111,631
Other income (expense):
Interest expense, net	(51,478		)	(29,622		)
Interest rate risk management losses, net	(4,727		)	(11,401		)
Other expense, net	(38		)	(184		)
Total other expense	(56,243		)	(41,207		)
(Loss) income from continuing operations before income taxes	(152,305		)	70,424
Income tax benefit	(1,703		)	(2,432		)
(Loss) income from continuing operations	(150,602		)	72,856
Discontinued operations, net of tax	—			276
Net (loss) income	$	(150,602	)	$	73,132
Adjusted EBITDA(a)	$	245,815		$	208,208

________________________

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

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 Upstream Segment

	Year Ended December 31,
	2012		2011 (a)
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Oil and condensate	$	58,420	$	51,574
Intersegment sales - condensate	43,004		42,716
Natural gas	32,105		42,551
Intersegment sales - natural gas	10,339		5,487
NGLs	43,831		42,553
Sulfur	14,020		17,753
Other	1,486		1,676
Total revenues	203,205		204,310
Operating Costs and expenses:
Operations and maintenance	56,734		47,723
Depletion, depreciation and amortization	88,777		65,531
Impairment	45,289		11,728
Total operating costs and expenses	190,800		124,982
Operating income	$	12,405	$	79,328
Capital expenditures	$	160,330	$	92,660
Realized average prices:
Oil and condensate (per Bbl)	$	85.65	$	84.36
Natural gas (per Mcf)	$	2.58	$	3.69
NGLs (per Bbl)	$	39.12	$	54.58
Sulfur (per Long ton)	$	137.46	$	180.46
Production volumes:
Oil and condensate (Bbl)	1,184,200		1,117,778
Natural gas (Mcf)	16,442,579		12,636,473
NGLs (Bbl)	1,120,522		805,359
Total (Mcfe)	30,270,911		24,175,295
Sulfur (Long ton)	102,002		98,372

________________________

(a) Includes operations related to the Mid-Continent Acquisition starting on May 3, 2011.

Revenue. For the year endedDecember 31, 2012, Upstream Segment revenues decresed by $1.1 million as compared to the year endedDecember 31, 2011.  The addition of production volumes from the acquisition of Crow Creek Energy, which closed on May 3, 2011, positively impacted the Upstream Segment's revenues by $22.3 million during the year ended December 31, 2012. Excluding the acquisition, revenues decreased due to lower volumes and lower natural gas and NGL prices for the year endedDecember 31, 2012, compared to the year endedDecember 31, 2011.

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, by approximately $3.9 million (excluding recoveries). We recognized $5.0 million related to our business interruption insurance claim in other revenue, of which $2.0 million was recognized in the three months ended March 31, 2011 and $3.0 million was recognized in the fourth quarter of 2010. The maximum recovery under our business interruption insurance policy is $5.0 million per occurrence. During the three months ended September 30, 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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In March 2012, we completed a scheduled turnaround of our Flomaton facility in Escambia County, Alabama to make certain equipment repairs and routine inspections of equipment. During the turnaround, both the Flomaton facility and all wells in the Flomaton and Fanny Church fields were shut-in. The duration of the plant turnaround and the field shut-in was approximately twelve days. We estimate the revenue impact due to the loss of production was approximately $0.5 million and the turnaround expense was approximately $0.6 million.

In May and June 2012, we completed turnarounds of approximately eight and seven days, respectively, of our Big Escambia Creek facility to make certain equipment repairs and routine inspections of equipment. We estimate the net revenue impact due to the loss of production was approximately $3.8 million and the turnaround expense was approximately $0.5 million. The turnarounds reduced our production by approximately 334 MMcfe and 3,400 long ton of sulfur.

In November and December 2012, our Big Escambia Creek oil and natural gas production was temporarily shut-in 24 days to perform a plant turnaround to install a new Superclaus reactor within our existing sulfur recovery unit.  The new reactor was required to reduce the facility's SO2 emissions as required by our existing air emissions permit.  In addition, certain equipment repairs and routine inspections were conducted during the turnaround. We estimate the net revenue impact due to the loss of production was approximately $4.4 million and the turnaround expense was approximately $1.7 million. The turnaround reduced our production by approximately 387 MMcfe and 3,322 long ton of sulfur.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, increased by $9.0 million for the year endedDecember 31, 2012 as compared to the year endedDecember 31, 2011.  The increase was due primarily to higher production expenses related to twelve months of operations of the properties acquired in the Mid-Continent Acquisition during the year endedDecember 31, 2012 compared to eight months of operations during 2011.

On July 19, 2012, one of our operated wells in Wayne County, Mississippi experienced an uncontrolled flow event during a well workover operation. The incident required the mobilization of our emergency response personnel to control the well's flow and secure the area in coordination with local, county and state emergency management agencies. Various contractors, including well control contractors, were mobilized to assist our response team. The flow from the well was fully controlled and secured on July 24, 2012. We have Control of Well insurance and are currently pursuing reimbursement for this incident. We estimate the cost of the incident to be between $17 - $18 million and have offset amounts paid above our deductible of $150,000 by recording a receivable for reimbursement under our insurance policy. During the year ended December 31, 2012, we received $6.0 million reimbursement for this incident and as of December 31, 2012, we had an additional receivable of $8.8 million related to the expected reimbursement. On February 21, 2013, we received an additional $3.0 million reimbursement for this incident.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense increased by $23.2 million for the year endedDecember 31, 2012 as compared to the same period in 2011.  The increase was primarily due to depletion and amortization expense incurred during the year endedDecember 31, 2012 for the properties acquired in the Mid-Continent Acquisition, partially offset by decreases as a result of the impairment charge recorded during the year endedDecember 31, 2012.

Impairment and Other. During the year endedDecember 31, 2012, we incurred impairment and other charges of $45.3 million due to (i) certain unproved property leaseholds that we expect 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. During the year endedDecember 31, 2011, we incurred impairment charges of $11.7 million due to (i) certain legacy drilling locations in our unproved properties which we no longer intend to develop based on the performance of offsetting wells, (ii) certain proved properties of the Jourdanton field in South Texas due to lower natural gas prices and relatively high operating costs, and (iii) certain drilling locations in our unproved properties which we no longer intend to develop.

Capital Expenditures.  Capital expenditures increased by $67.7 million for the year endedDecember 31, 2012 as compared to the year endedDecember 31, 2011.   During the year endedDecember 31, 2012, we drilled and completed twelve gross operated wells and participated in twenty-one gross non-operated wells on leases in the Mid-Continent region. Additionally, during the year endedDecember 31, 2012, we conducted eleven recompletions, fifteen capital workovers and six expense workovers across our operations.

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Midstream Business (Three Segments)

Texas Panhandle Segment

	Year Ended December 31,
	2012		2011
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids, oil and condensate sales	$	334,295	$	378,917
Intersegment sales - natural gas	105,759		60,237
Gathering and treating services	25,743		17,074
Other revenue (a)	2,864		—
Total revenues	468,661		456,228
Cost of natural gas, natural gas liquids, oil & condensate (b)(c)	332,875		327,775
Operating costs and expenses:
Operations and maintenance	60,884		41,749
Depreciation and amortization	44,451		37,034
Impairment	—		4,560
Total operating costs and expenses	105,335		83,343
Operating income	$	30,451	$	45,110
Capital expenditures	$	131,928	$	71,351
Realized prices (d):
Oil and condensate (per Bbl)	$	82.64	$	80.41
Natural gas (per Mcf)	$	2.63	$	3.74
NGLs (per Bbl)	$	36.00	$	52.67
Production volumes:
Gathering volumes (Mcf/d)(e)	212,617		155,122
NGLs (net equity gallons)(f)	1,270,601		880,348
Condensate (net equity gallons)(f)	801,828		962,982
Natural gas short position (MMbtu/d)(e)	547		(5,622		)

________________________

(a) The year ended December 31, 2012 included the receipt of an insurance payment of $2.9 million for business interruption related to the downtime to our Cargray plant caused by the severe winter weather in 2011.

(b) Includes the cost of gathering, compression, processing and treating fees of $1.5 million and $0.4 million for the year endedDecember 31, 2012 and 2011, respectively.

(c) Includes purchase of natural gas of $83 from the Upstream Segment for the year endedDecember 31, 2012.

(d) Excludes the impact of adjustments related to prior periods, including true-ups of estimates.

(e) Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.

(f) Effective January 2012, reported NGL volumes include those volumes recovered from our equity condensate through stabilization. These NGL volumes were previously reported as condensate. This change results in an increase to reported NGL equity barrels and a corresponding decrease to reported condensate equity barrels.

Revenue and Cost of Natural Gas and NGLs. For the year endedDecember 31, 2012, revenues minus cost of natural gas, NGLs and condensate for our Texas Panhandle Segment operations totaled $135.8 million compared to $128.5 million for the year endedDecember 31, 2011. The addition of volumes from the Panhandle Acquisition, which closed on October 1, 2012, impacted the Panhandle Segment's revenues minus cost of natural gas, NGLs, condensate and helium relative to the corresponding prior year period positively by $17.8 million during the year endedDecember 31, 2013. Excluding the acquisition, revenues minus cost of natural gas, NGLs, condensate and helium decreased, primarily driven by the decline in natural gas and NGL prices and lower NGL and condensate equity volumes. In addition, on April 30, 2012, we reported an incident and related fire at our Phoenix-Arrington Ranch processing facility which caused the facility to remain shut-in until July 2, 2012. After restarting, the plant experienced efficiency and run time issues as the NGL recovery rates were slow to come back to pre-incident levels. Experiencing

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lower-than-normal NGL recovery rates on stable or growing throughput volumes is particularly problematic for us in the Texas Panhandle Segment because of the significant number of fixed NGL recovery contracts. As such, during times of low NGL recovery, we continue to pay our producer customers at the agreed-upon fixed recovery rates notwithstanding our reduced actual NGL recoveries. As of the end of December 2012, the efficiency and run-time for our Phoenix-Arrington Ranch processing facility were back at their pre-incident levels. We estimate that our results (revenues less cost of natural gas, NGLs and condensate) were negatively impacted due to the downtime by approximately $7.3 million for the year endedDecember 31, 2013. We have business interruption insurance and expect to pursue reimbursement for the downtime associated with the incident above the associated deductible. As of December 31, 2013, we had not accrued any amounts related to our business interruption insurance. In addition, during the three months ended March 31, 2012, a third-party-owned fractionation plant, which services all of our Panhandle processing plants, experienced downtime for approximately nine days. During that time, we curtailed NGL production through reduced recoveries at our plants. We estimate that our results for the year endedDecember 31, 2013, were negatively impacted by approximately $1.0 million due to such downtime.

On June 4, 2012, we announced the successful start-up of the Woodall Plant. Due to an incident in early June 2012 on a third-party pipeline that serves as a major residue outlet, our processing volumes in the Texas Panhandle were curtailed, primarily at the Woodall Plant. We initially mitigated this reduced flow by utilizing capacity on another residue outlet. In September 2012, we connected into a third residue outlet, which fully alleviated the processing restrictions. We estimate that our results were negatively impacted by this incident by approximately $3.1 million during the year endedDecember 31, 2013.

These decreases were offset by the receipt of insurance proceeds totaling $2.9 million in 2012 related to business interruptions at the Cargray processing facility incurred in 2011. The operating downtime and the affected recoveries at the Cargray facility impacted revenues minus cost of natural gas by $3.6 million across the Texas Panhandle Segment during the year endedDecember 31, 2011.

Our Texas Panhandle Segment lies within 14 counties in Texas and two counties in Oklahoma and consists of our East Panhandle System and our West Panhandle System. The limited drilling activity in the West Panhandle System is not sufficient to offset the natural declines experienced on this system. The combination of our contract mix and the high NGL content of the natural gas gathered in the West Panhandle System provides us with a high level of equity NGL and condensate production. As such, any declines in gathered volumes from the West Panhandle System must be offset with increases in gathered volumes from other systems on a greater than one-to-one basis in order to maintain our total equity NGL and condensate production. We have seen continued drilling activity in the East Panhandle System by our producer customers and continue to expect drilling activity and the resulting volumes to continue during the remainder of 2013. Accordingly, in August 2011 and April 2012, we entered into amendments to our Natural Gas Liquids Exchange Agreement with ONEOK to increase the maximum allowable volumes of natural gas liquids that we may deliver from our East Panhandle System to ONEOK for transportation and fractionation services and to correspondingly decrease the maximum allowable volumes from our West Panhandle System. Under the amendments, our maximum NGL volumes increased with the completion of our Woodall Plant in 2012 and allows for a further increase upon completion of our Wheeler Plant, which is discussed below.

Operating Expenses. Operating expenses, including taxes other than income, for the year endedDecember 31, 2012, increased $19.1 million as compared to the year endedDecember 31, 2011. The increase was primarily driven by increased costs related to the Panhandle Acquisition, expansion of the Phoenix-Arrington Ranch Plant, labor and related expenses associated with the new Woodall Plant and repair costs related to the Phoenix incident. The incident and resulting fire that occurred at our Phoenix-Arrington Ranch Plant in April 2012 is covered under our property insurance, and we expect to be reimbursed for repair costs above our associated deductible. Through December 31, 2012, we incurred repair costs of $2.7 million, of which we have received a partial payment of $0.5 million, and recorded a receivable of $1.7 million as an offset against this amount.

Depreciation and Amortization. Depreciation and amortization expenses for the year endedDecember 31, 2012 decreased $7.4 million from the year endedDecember 31, 2011. The increase was due to increased depreciation expense primarily associated with the new Woodall Plant, Panhandle Acquisition and other capital expenditures placed into service during the period.

Impairment. No impairment charges were incurred during the during the year endedDecember 31, 2012. During the year ended December 31, 2011, we recorded an impairment charge of $4.6 million in our Texas Panhandle Segment to fully write down our idle Turkey Creek plant. We determined that the components of our Turkey Creek plant could not be used elsewhere within our business, and thus we decided to remove all above ground equipment and structures.

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Capital Expenditures. Capital expenditures for the year endedDecember 31, 2012 increased by $60.6 million compared to the year endedDecember 31, 2011. The increase was primarily driven by spending related to the construction of our Woodall and Wheeler Plants located in the Texas Panhandle.

  East Texas and Other Midstream Segment

	Year Ended December 31,
	2012			2011
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Natural gas, natural gas liquids, oil and condensate sales	$	125,512		$	243,673
Intersegment sales-natural gas	39,099			16,654
Gathering and treating services	31,017			30,688
Total revenues	195,628			291,015
Cost of natural gas and natural gas liquids (a)	147,493			231,642
Operating costs and expenses:
Operations and maintenance	21,762			22,790
Impairment	131,714			—
Depreciation and amortization	25,771			27,629
Total operating costs and expenses	179,247			50,419
Operating income (loss) from continuing operations	(131,112		)	8,954
Discontinued operations (c)	—			(128		)
Operating income (loss)	$	(131,112	)	$	8,826
Capital expenditures	$	9,328		$	10,860
Realized prices (b):
Oil and condensate (per Bbl)	$	96.91		$	95.08
Natural gas (per Mcf)	$	2.85		$	4.15
NGLs (per Bbl)	$	37.83		$	49.72
Production volumes:
Gathering volumes (Mcf/d)(d)	255,752			319,892
NGLs (net equity gallons)	338,636			451,048
Condensate (net equity gallons)	38,350			46,242
Natural gas short position (MMbtu/d)(d)	1,530			1,913

_______________________

(a) Includes the cost of gathering, compression, processing and treating fees of $4.4 million and $4.6 million for the year endedDecember 31, 2012 and 2011, respectively.

(b) Excludes the impact of adjustments related to prior periods, including true-ups of estimates.

(c) Includes purchase of natural gas of $66 from the Upstream Segment for the year endedDecember 31, 2011.

(d) Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.

Revenue and Cost of Natural Gas and NGLs. For the year endedDecember 31, 2012, revenues minus cost of natural gas and NGLs for our East Texas and Other Midstream Segment totaled $48.1 million compared to $59.4 million for the year endedDecember 31, 2011. During the years endedDecember 31, 2012 and 2011, we recorded revenues associated with deficiency payments of $5.0 million and $1.6 million, respectively. We receive deficiency payments under certain of our gathering contracts when delivered volumes fail to meet certain thresholds. These amounts are included within gathering and treating services revenue. Excluding these deficiency payments, revenues minus cost of natural gas, NGLs and condensate for the years endedDecember 31, 2012 and 2011 would have been $43.2 million and $57.7 million, respectively. The decrease,

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excluding deficiency payments, for the year endedDecember 31, 2012 compared to the year endedDecember 31, 2011, is primarily due to a decrease in gathering and equity volumes and lower natural gas and NGL prices.

The gathering volumes for the year endedDecember 31, 2012, decreased as compared to the year endedDecember 31, 2011, due in part to the impact of Hurricane Issac in August 2012, which caused significant damage to the Yscloskey Plant in Louisiana, in which we have a non-operated ownership interest. The owners of the Yscloskey Plant elected to shut down the facility following Hurricane Isaac. We estimate this negatively impacted 2012 gathering volumes by approximately 52 MMcf/d and 2012 NGL volumes by approximately 9,600 Bbls. Also contributing to the decrease in gathering volumes were natural declines in the production of the existing wells and reduced drilling activity in dry-gas formations related to a decline in natural gas prices.

On October 3, 2012, we announced that we entered into an Amendment (the "Amendment") to our existing Gas Gathering and Processing Agreement (the "Agreement") with Anadarko E&P Company LP ("Anadarko") to support Anadarko's drilling program in western Louisiana.

Operating Expenses. Operating expenses for the year endedDecember 31, 2012 decreased $1.0 million compared to the year endedDecember 31, 2011 as a result of lower maintenance costs.

Impairment. We recorded impairment expense of $131.7 million during the year endedDecember 31, 2012, on certain assets due to (i) reduced throughput volumes as our producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment, (ii) the loss of significant gathering contracts on our Panola and other systems and (iii) the substantial damage incurred at the Yscloskey Plant as a result of Hurricane Isaac in August 2012. No impairment charges were incurred in the year endedDecember 31, 2011.

Depreciation and Amortization. Depreciation and amortization expenses for the year endedDecember 31, 2012, decreased $1.9 million compared to the year endedDecember 31, 2011. The decrease was primarily a result of the impairment charge recorded during the year ended2012.

Capital Expenditures. Capital expenditures for the year endedDecember 31, 2012, decreased $1.5 million compared to the year endedDecember 31, 2011. Capital expenditures for the year endedDecember 31, 2011, were offset by the sale of $2.3 million of excess pipe inventory related to the East Texas Mainline expansion project which was cancelled in 2010. Excluding this transaction, capital expenditures in the year endedDecember 31, 2012, decreased $3.8 million compared to the same period in 2011, due to fewer new well connects.

Discontinued Operations. No discontinued operations were recorded during the year endedDecember 31, 2012. On May 20, 2011, we sold the Wildhorse Gathering System. For the year endedDecember 31, 2011, we generated revenues of $6.9 million, and income from operations of $0.5 million from the Wildhorse Gathering System.

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Marketing and Trading Segment

	Year Ended December 31,
	2012			2011
	(Amounts in thousands)
Revenues:
Natural gas, oil and condensate sales (a)	$	256,701		$	200,931
Intersegment sales - natural gas and condensate	(154,992		)	(82,378		)
Gathering, compression, processing and treating fees	71			8
Total revenue	101,780			118,561
Cost of oil and condensate	52,434			73,767
Intersegment cost of oil and condensate	44,317			41,382
Operating costs and expenses:
Operations and maintenance	2			—
Depreciation and amortization	273			—
Total operating costs and expenses	275			—
Operating income	$	4,754		$	3,412
Capital Expenditures	$	5,489		$	2,205

_________________________

(a) Includes mark-to-market losses from derivative activity of $0.2 million and $0.8 million for the year endedDecember 31, 2012 and 2011, respectively, and gains of $0.4 million and $0.2 million for the year endedDecember 31, 2012 and 2011, respectively, from derivative contracts that settled during the respective periods.

For a description of our Marketing and Trading Segment activities, see the discussion within the Year Ended December 31, 2013 Compared with Year Ended December 31, 2012 section.

For the years endedDecember 31, 2013 and 2012, revenues minus cost of oil and condensate totaled $5.0 million and $3.4 million, respectively. The increase in revenues minus cost of oil and condensate is primarily due to a full year of activity for our natural gas marketing and trading activities during 2012 compared to six months of activity in 2011.

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Corporate and Other Segment

	Year Ended December 31,
	2012			2011
	($ in thousands)
Revenues:
Commodity risk management gains (losses), net	$	57,894		$	32,510
Intersegment elimination - Sales of natural gas, oil and condensate	(43,209		)	(42,716		)
Total revenues	14,685			(10,206		)
Intersegment elimination - Cost of oil and condensate	(44,400		)	(41,382		)
General and administrative	69,994			57,891
Intersegment elimination - Operations and maintenance	(122		)	(66		)
Other operating income	—			(2,893		)
Depreciation and amortization	1,773			1,417
Operating loss	(12,560		)	(25,173		)
Other income (expense):
Interest expense, net	(51,478		)	(29,622		)
Interest rate risk management losses, net	(4,727		)	(11,401		)
Other expense, net	(38		)	(184		)
Total other expense	(56,243		)	(41,207		)
Loss from continuing operations before taxes	(68,803		)	(66,380		)
Income tax benefit	(1,703		)	(2,432		)
Loss from continuing operations	(67,100		)	(63,948		)
Discontinued operations, net of tax	—			404
Segment loss	$	(67,100	)	$	(63,544	)

Revenue. Our Corporate and Other Segment's revenue consists of our intersegment eliminations and our commodity derivatives activity (excluding any risk management activity associated with our natural gas marketing and trading activity). Our commodity derivatives activities impact our Corporate and Other Segment revenues through (i) gains or losses due to the change in the mark-to-market value of our commodity derivatives scheduled to settle in future periods; and (ii) the gains or losses on our commodity derivatives settled in the indicated period.   In general, the change in the mark-to-market value of our derivative position may be due to several factors including the settlement of derivative instruments during the period, the addition of new derivative positions during the period, changes in the forward curves of the underlying commodities from the beginning to the end of the period, changes in interest rates used in the mark-to-market calculations from the beginning to the end of the period and the passage of time during the period.  

During the year endedDecember 31, 2012, our commodity risk management gains increased by $25.4 million, as compared to the year endedDecember 31, 2011. During the year endedDecember 31, 2012, our gains due to the change in the mark-to-market value of our derivative contracts decreased by $46.3 million, as compared to the year endedDecember 31, 2011, due to increases in the natural gas, NGL and crude oil forward curves.  This decrease was offset by an increase in gains of $71.7 million from derivative contracts that settled during the year endedDecember 31, 2012, as compared to the year endedDecember 31, 2011, which was due to the settlement of contracts assumed in the Mid-Continent Acquisition and lower natural gas and NGL market prices, 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.

Intersegment Eliminations. During the year endedDecember 31, 2012, our Upstream Segment sold condensate and natural gas to the Marketing and Trading Segment within our Midstream Business for resale. In addition, during the year ended December 31, 2012, our Upstream segment sold natural gas to our Panhandle Segment and it purchased natural gas from our Marketing and Trading Segment to be used for fuel. During the year endedDecember 31, 2012, our Upstream Segment purchased natural gas from our East Texas and Other Midstream Segment to be used as fuel.

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General and Administrative Expenses. General and administrative expenses increased by $12.1 million for the year endedDecember 31, 2012 as compared to the same period in 2011. This increase was primarily due to (i) higher salaries and benefits, which was due to an increase in our headcount due to the Mid-Continent Acquisition and increased equity compensation expense due to additional grants and (ii) increased professional and legal fees primarily due to expenses associated with the Panhandle Acquisition, transition and management fees. In addition, we also incurred higher insurance expense related to the increase in our insurable property and to higher insurance rates during the year endedDecember 31, 2013. We expect our insurance expense to continue to increase in 2013 due to the increase in our insurable property as a result of our Panhandle Acquisition, and due to our claims history. The increases for the year endedDecember 31, 2012, were partially offset by higher professional fees incurred during the same period in 2011, primarily associated with the Mid-Continent Acquisition in May 2011.

We do not allocate our general and administrative expenses to our operational segments.

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. On June 22, 2011, we terminated a $150 million notional amount 2.56% fixed rate interest rate swap at a total cost of $5.0 million, and extended the maturity of $250 million notional amount of our 4.095% fixed rate interest rate swaps from December 31, 2012 to June 22, 2015, with a fixed rate of 2.95%. 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 endedDecember 31, 2012, our interest rate risk management losses decreased by $6.7 million as compared to the year endedDecember 31, 2011, due primarily to the transactions described above and 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 $21.9 million during the year endedDecember 31, 2012 s compared to the year endedDecember 31, 2011. 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.  On May 27, 2011, we issued $300.0 million of senior unsecured notes with a coupon of 8.375% through a private placement, and on June 22, 2011, we entered into an Amended and Restated Credit Agreement which as of December 31, 2012 bore interest at LIBOR plus 2.25%.  and on July 13, 2012, we issued an additional $250 million of senior unsecured notes.  The increases in interest expense were due to the transactions discussed above along with increased borrowings under our Credit Agreement.

Income Tax (Benefit) Provision. Income tax provision for 2012 and 2011 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 May 24, 2010, we completed the sale of our fee mineral and royalty interests as well as our equity investment in Ivory Working Interests, L.P. During the year endedDecember 31, 2011, we received payments of $0.5 million related to pre-effective date operations and recorded this amount as part of discontinued operations

Adjusted EBITDA

Adjusted EBITDA, as defined and reconciled to GAAP under "Part II, Item 6. Selected Financial Data - Non-GAAP Financial Measures," increased by $37.6 million from $208.2 million for the year endedDecember 31, 2011 to $245.8 million for the year endedDecember 31, 2012. The following table presents the changes in operations, by segment, impacting Adjusted EBITDA:

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	Year Ended December 31,
	2012		2011			Change
	($ in thousands)
Revenues minus cost of natural gas and NGLs - Midstream (a)	$	189,142	$	190,466		$	(1,324	)
Revenues - Upstream (b)	203,522		204,384			(862		)
Intercompany elimination revenues minus cost of natural gas and condensate	1,191		(1,334		)	2,525
Commodity derivative settlements - Corporate and Other	51,332		(20,366		)	71,698
Total incremental revenues minus cost of natural gas and NGLs	445,187		373,150			72,037
Operating expenses - Midstream	82,648		64,539			18,109
Operating expenses - Upstream	56,734		47,723			9,011
General and administrative expenses (c)	59,990		52,680			7,310
Adjusted EBITDA (d)	$	245,815	$	208,208		$	37,607

_________________________

(a) Excludes mark-to-market gains/losses from the Marketing and Trading Segment.

(b) Excludes the impact of imbalances

(c) Excludes non-cash compensation charges related to our long-term incentive program and other non-recurring items.

(d) 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 revolving credit facility 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.

We believe that 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 expenditures on organic projects and new drilling activity. We also intend to continue to pursue attractive development and acquisition opportunities. Accordingly, we may utilize various available financing sources, including the issuance of equity or debt securities, to fund all or a portion of our organic growth expenditures and potential acquisitions. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

At December 31, 2013, our liquidity was limited by our amount of debt outstanding and by our debt ratios relative to the covenant levels specified in our revolving credit facility, as discussed further below. We expect the proposed contribution of our Midstream Business to Regency to significantly reduce our leverage and improve our liquidity. We intend to use the net proceeds from the Midstream Business Contribution to reduce debt outstanding under the revolving credit facility. In addition, as part of the consideration for the Midstream Business Contribution, Regency has agreed to conduct an exchange offer for the full $550 million face value of our outstanding senior unsecured notes. If less than all the senior unsecured notes are tendered for exchange in the exchange offer, Regency has agreed to pay us a dollar amount equal to 110% of the difference between $550 million and the face value of the notes tendered. In this scenario, any of our senior unsecured notes that are not tendered for exchange would remain outstanding, and we would use the additional cash proceeds from Regency to repay borrowings under our credit facility or retain excess cash to pursue acquisitions. Our annual interest expense would initially be higher under this scenario than if all of our senior unsecured notes were exchanged.

The completion of the Midstream Business Contribution is subject to regulatory and unitholder approvals. As a result, we can provide no assurance that the Midstream Business Contribution will be completed within our anticipated time frame, or at all. If the Midstream Business Contribution is not consummated, we will continue to be constrained in the near-term by limited liquidity and greater risk that our debt ratios may exceed the covenant levels in our revolving credit facility. In this event we will seek to fund our liquidity needs and reduce our debt levels through some combination of reduced spending, equity financings and asset sales.

Equity Offerings

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, 2013, 1,521,086 units had been issued under this program for net proceeds of approximately $12.9 million During the year endedDecember 31, 2013, 686,759 units had been issued under this program for net proceeds of approximately $5.6 million. Issuance costs associated with the program for the year endedDecember 31, 2013 were $0.4 million. No sales were made under the program during the three months endedDecember 31, 2013.

During the first quarter of 2013, we closed an underwritten public offering of 10,350,000 common units for net proceeds of approximately $92.3 million. The net proceeds were used to repay a portion of the outstanding borrowings under our revolving credit facility.

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, which are made to (i) acquire, construct, expand or upgrade our gathering, processing and treating assets or (ii) grow our natural gas, NGL, crude or sulfur production; or

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• maintenance capital expenditures, which are made to (i) replace partially or fully depreciated assets, meet regulatory requirements, or maintain the existing operating capacity of our gathering, processing and treating assets or (ii) maintain our natural gas, NGL, crude or sulfur production. With respect to maintenance capital expenditures intended to maintain the Partnership's 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 2014 capital budget anticipates that we will spend, excluding the potential divestiture of our Midstream Business, approximately $188 million in total, of which $112 million relates to growth capital expenditures and $76 million relates to maintenance capital expenditures. The allocation by business of our 2014 capital budget is as follows; $124 million ($66 million of growth and $58 million for maintenance) relates to upstream capital expenditures, $61 million ($43 million for growth and $18 million for maintenance) relates to midstream capital expenditures (before taking into consideration the Midstream Business Contribution) and $2 million ($1.4 million for growth and $0.6 million) relates to corporate capital expenditures. We anticipate that our capital spending, for both our Upstream and Midstream businesses, will be made ratably throughout 2014.

Our capital expenditures, excluding acquisitions, were approximately $224.2 million for the year endedDecember 31, 2013, of which $65.8 million related to maintenance capital expenditures and $158.3 million related to growth capital expenditures.

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, 2013 had resulted in increased sulfur production and reductions in SO₂ emissions to levels well below the required permitted levels. The total cost of this phase to date was approximately $21.0 million net to our interest.

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 Southern Alabama. The improvements to our sulfur recovery unit will also further reduce SO₂ emissions, helping to ensure our compliance with the National Ambient Air Quality Standards the Environmental Protection Agency enacted in mid-2010.  In the first of these planned upgrades, we expect to replace the incinerator portion of the sulfur recovery unit in 2015 at a cost of approximately $11.6 million net to our interest.

Distribution Policy

Our distribution policy is to distribute to our unitholders, on a quarterly basis, all of our available cash 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 on hand at the end of that quarter less the amount of cash reserves that the general partner determines to establish 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 and the general partner in respect of any one or more of the next four quarters.

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The actual distributions we will declare will be subject to our operating performance, prevailing market conditions (including forward oil, natural gas 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.

Revolving Credit Facility

On June 22, 2011, we entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) with 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, BNP Paribas, as documentation agent, and the other lenders who are parties to the Credit Agreement. The Credit Agreement amended and restated our prior $880 million Credit Agreement (the “Prior Credit Agreement”). Upon the effectiveness of the Credit Agreement, all commitments of the lenders party to the Prior Credit Agreement were terminated and all of our loans and other indebtedness under the Prior Credit Agreement were renewed and extended, inclusive of new lender commitments, on the terms and conditions of the Credit Agreement. The Credit Agreement matures on June 22, 2016.

On December 28, 2012, we received increased commitments from our lending group under the Credit Agreement. Aggregate commitments increased from $675 million to $820 million. We have the option to request further increases, subject to the terms and conditions of the Credit Agreement, up to a total aggregate amount of $1.2 billion. Availability under the Credit Agreement is subject to a borrowing base comprised of two components: the upstream component and the midstream component. As of December 31, 2013, our borrowing base totaled approximately $775 million.

As of December 31, 2013, we had approximately $49.2 million of availability under the revolving credit facility.

Senior Unsecured Notes

On May 27, 2011, we completed the sale of $300 million of our 8.375% senior unsecured notes due 2019 through a private placement, which were exchanged for registered notes on February 15, 2012 (the "Senior Notes"). The Senior Notes will mature on June 1, 2019, and interest is payable on June 1 and December 1 each year. We used the net proceeds of approximately $290.3 million to repay borrowings outstanding under our revolving credit facility.

On July 13, 2012, we completed the sale of an additional $250 million of senior notes (the "2012 Senior Notes") through a private placement. After the original discount of $3.7 million and excluding related offering expenses, we received net proceeds of approximately $246.3 million, which were used to repay borrowings outstanding under our revolving credit facility.

In connection with our Midstream Business Contribution with Regency, Regency will conduct an offer to exchange the full $550 million face value of our senior unsecured notes into an equivalent amount of Regency senior unsecured notes with the same tenor, coupon and a comparable covenant package. Should all holders elect to tender their notes in the exchange, we will no longer have any of the senior unsecured notes outstanding.

Debt Covenants

On July 23, 2013, the Credit Agreement was amended to allow for a temporary step-up in the Total Leverage Ratio and the Senior Secured Leverage Ratio, as defined therein, through the third quarter of 2014 and the third quarter of 2013, respectively. The amendment also extends the period of time we are subject to the Senior Secured Leverage Ratio from September 30, 2013 to September 30, 2014.

Our revolving credit facility requires us to maintain certain leverage, current and interest coverage ratios. As of December 31, 2013, we were in compliance with all of our debt covenants.

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The following table presents the debt covenant levels specified in our revolving credit facility as of December 31, 2013:

Quarter Ended	Total Leverage Ratio	Senior Secured Leverage Ratio	Interest Coverage Ratio	Current Ratio
December 31, 2013	5.50x	3.15x	2.50x	1.0x
March 31, 2014	5.25x	3.10x	2.50x	1.0x
June 30, 2014	5.00x	3.05x	2.50x	1.0x
September 30, 2014	4.75x	2.95x	2.50x	1.0x
Thereafter	4.50x	NA	2.50x	1.0x

Our actual financial covenant ratios as of December 31, 2013, were as follows:

Interest coverage ratio	3.1
Total leverage ratio	5.4
Senior secured leverage ratio	3.06
Current ratio	1.1

As of December 31, 2013, we were in compliance with all of our debt covenants.

On February 26, 2014, we and our lender group amended the revolving credit facility to, among other items, allow for a temporary step-up in the Total Leverage Ratio and Senior Secured Leverage Ratio, and allow for additional liquidity at our election. For a further discussion of the Credit Agreement amendment, see Note 22 to our consolidated financial statements.

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. For example, our total leverage ratio exceeded our long-term target as of December 31, 2013, due in part to: (i) our funding of ongoing drilling and other capital projects and (ii) lower NGL prices and other factors negatively impacting our Adjusted EBITDA. As discussed in previous filings, we conducted a process in 2013 in which we explored a number of alternatives to reduce our leverage ratio. That process culminated in the proposed contribution of our Midstream Business to Regency for total consideration of up to $1.325 billion. We expect the Midstream Business Contribution to substantially improve our liquidity and debt ratios through the elimination of significant debt currently outstanding under our revolving credit facility and the proposed assumption of all of our senior unsecured notes via an exchange offer to be conducted by Regency. The completion of the Midstream Business Contribution is subject to regulatory and unitholder approvals. As a result, we can provide no assurance that the Midstream Business Contribution will be completed within our anticipated time frame, or at all. Should the Midstream Business Contribution not be consummated, we intend to explore alternative means to reduce our leverage ratios, which may include asset sales or purchases, equity financings, the separation of our upstream and midstream businesses or other alternatives.

Our Senior Notes were issued under an indenture that contains certain covenants limiting our ability to, among others, pay distributions, repurchase our equity securities, make certain investments, incur additional indebtedness, and sell assets. At December 31, 2013, 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.

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Cash Flows

Cash Distributions

The Partnership has declared a cash distribution for each quarter since its initial public offering. The table below summarizes these distributions for the last three years. 

Quarter Ended	Distribution per Unit		Record Date**	Payment Date
March 31, 2011+	$	0.1500	May 9, 2011	May 13, 2011
June 30, 2011+	$	0.1875	August 5, 2011	August 12, 2011
September 30, 2011+	$	0.2000	November 4, 2011	November 14, 2011
December 31, 2011+	$	0.2100	February 7, 2012	February 14, 2012
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

_____________________________

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

* The distribution per unit represents distributions made only on common units (including restricted common units issued under our Long Term Incentive Plan) and general partner units.

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

Working Capital

Working capital is the amount by which current assets exceed current liabilities. As of December 31, 2013, working capital was a negative $47.9 million as compared to a positive $0.5 million as of December 31, 2012.

The net decrease in working capital of $48.3 million from December 31, 2012 to December 31, 2013 resulted primarily from the following factors:

• risk management net working capital balance decreased by a net $34.0 million as a result of changes in current portion of mark-to-market positions as a result of increases to the forward crude oil, natural gas and NGL price curves, partially offset by increases in the interest rate forward curve;

• accrued liabilities increased by $10.2 million primarily reflecting increases in current asset retirement obligations;

• accounts payable increased by $9.7 million primarily as a result of activities and timing of payments, including capital expenditure activities; and

• other current assets decreased by $1.7 million primarily as a result of timing of payments of prepaid expenses; partially offset by

• trade accounts receivable increased by $7.2 million primarily from the impact of the Panhandle Acquisition; and

• cash balances and marketable securities increased overall by $0.1 million.

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

Cash Flow from Operating Activities. Cash flows from operating activities increased $31.9 million during the year endedDecember 31, 2013 as compared to the year endedDecember 31, 2012. This increase was primarily due to:

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• 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 endedDecember 31, 2012, we made payments of $3.9 million, $2.8 million and $1.1 million, respectively, 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 endedDecember 31, 2013, we did not make any payments to unwind any derivative contracts.

Cash Flows from Investing Activities. Cash flows used in investing activities for the year endedDecember 31, 2013 were $247.0 million as compared to cash flows used in investing activities of $528.7 million for the year endedDecember 31, 2012. The decrease was driven by:

• During the year ended December 31, 2012, we spent $230.6 million for the Panhandle Acquisition;

• A decrease in capital expenditures during the year endedDecember 31, 2013 of $62.6 million as compared to the same period in 2012, in particular, decreased spending on drilling in our Upstream Segment, and in our Texas Panhandle Segment we were only constructing our Wheeler plant during the year endedDecember 31, 2013, as compared to the same period in 2012 when we were constructing both our Woodall and Wheeler plants; and  

• Decreased proceeds from the sale of assets of $15.1 million during the year endedDecember 31, 2013, as compared to the same period in 2012.

Cash Flows from Financing Activities. Cash flows provided by financing activities during the year endedDecember 31, 2013 were $69.7 million as compared to cash flows provided by financing activities of $382.3 million for the year endedDecember 31, 2012. The decrease was driven by:

• During the year endedDecember 31, 2012, we received net proceeds of $239.1 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 endedDecember 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 endedDecember 31, 2013, as compared to the same period in 2012; and

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

These decreases were partially offset by:

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

Cash Flows Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Cash Flow from Operating Activities. Cash flows from operating activities increased $27.7 million during the year endedDecember 31, 2012 as compared to the year endedDecember 31, 2011. This increase was primarily due to:

• An increase in our results of operations from our Mid-Continent Acquisition and higher commodity prices, which resulted in higher cash flows from the sale of our equity crude oil and NGLs volumes and higher cash flows from the sale of sulfur;  

• Lower commodity prices also resulted in us realizing net settlement losses on our commodity derivatives during the year endedDecember 31, 2012; and

• During the year endedDecember 31, 2012, we made payments of $3.9 million to terminate the full $200.0 million notional amount of our existing 4.295% and 4.095% fixed rate interest rate swaps and $2.8 million to adjust the strike price on an existing WTI crude oil swap. During the year endedDecember 31, 2011, we made payments of $5.0

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million and $4.8 million to unwind interest rate derivative contracts and certain commodity derivative contracts, respectively, and a $14.6 million payment to adjust the strike price on certain existing commodity derivative contracts, as compared to our payment of $1.1 million to partially unwind certain commodity derivative contracts during the year endedDecember 31, 2012.

Cash Flows from Investing Activities. Cash flows used in investing activities for the year endedDecember 31, 2012 were $528.7 million as compared to cash flows used in investing activities of $373.9 million for the year endedDecember 31, 2011. The increase was driven by:

• An increase in net cash outlay of $230.6 million for the Panhandle Acquisition during year endedDecember 31, 2012, as compared to the net cash outlay of $220.3 million for the Mid-Continent Acquisition during the year endedDecember 31, 2011; and

• Increased capital expenditures of $151.1 million for capital expenditures, in particular spending related to our Woodall and Wheeler Plants, as well as increased drilling in our Upstream Segment during year endedDecember 31, 2012, compared to the same period in 2011, in particular, increased spending on drilling in our Upstream Segment, and in our Texas Panhandle Segment we were constructing our Wheeler and Woodall plants during the year endedDecember 31, 2012, as compared to the same period in 2011 when we were constructing our Woodall plant and Phoenix-Arrington Ranch Plant Construction and Expansion.  

• These increases were partially offset by;

• Increased proceeds from the sale of assets of $9.7 million during the year endedDecember 31, 2012, as compared to the same period in 2011.

Cash Flows from Financing Activities. Cash flows provided by financing activities during the year endedDecember 31, 2012 were $382.3 million as compared to cash flows provided by financing activities of $252.0 million for the year endedDecember 31, 2011. The increase was due to:

• Net borrowings on our revolving credit facility of $127.0 million during the year endedDecember 31, 2012 as compared to net repayments of $48.5 million to our revolving credit facility during the year endedDecember 31, 2011;

• Increased net proceeds of $91.7 million from our equity offering during the year endedDecember 31, 2012, as compared to the same period in 2011; and

• Proceeds from derivative contracts increased by $8.2 million during the year endedDecember 31, 2012, as compared to the same period in 2011.

These increases were partially offset by:

• During the year endedDecember 31, 2012 we received net proceeds of $239.1 million from the sale of our Senior Notes compared to net proceeds of $280.4 million during the year endedDecember 31, 2012;

• Increased distributions of $44.7 million during the year endedDecember 31, 2012 as compared to the same period in 2011, as a result of increasing our quarterly distribution and units outstanding; and

• During the year endedDecember 31, 2012 we received proceeds of $31.8 million due to the exercise of warrants, as compared to $89.7 million from the exercise of warrants during the same period in 2011.

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.  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.  These transactions also increase our exposure to the counterparties through which we execute the hedges.

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Off-Balance Sheet Obligations.

We have no off-balance sheet transactions or obligations. 

Total Contractual Obligations.

The following table summarizes our total contractual cash obligations as of December 31, 2013:

	Payments Due by Period
Contractual Obligations	Total		2014		2015		2016		2017-2018		Thereafter
	($ in millions)
Revolving Credit Facility (including interest)(a)	$	753,491	$	18,873	$	18,873	$	715,745	$	—	$	—
Senior Notes	799,496		46,063		46,063		46,063		92,125		569,182
Operating leases	21,388		7,060		6,045		4,997		3,286		—
Asset Retirement Obligations	58,964		13,116		1,336		2,123		9,982		32,407
Total contractual obligations	$	1,633,339	$	85,112	$	72,317	$	768,928	$	105,393	$	601,589

__________________________

(a) These amounts exclude estimates of the effect of our interest rate swap contracts on our future interest obligations. As of December 31, 2013, the fair value of our interest rate swap contracts, which expire on June 22, 2015, totaled a liability of $9.1 million.

Recent Accounting Pronouncements

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

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 comprehensive 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; and

• Monitor and enforce the risk policy and controls for our natural gas marketing subsidiary, Eagle Rock Gas Services, LLC ("ERGS").

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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 monitors the implementation of our policy, and we have engaged an independent firm to provide additional oversight.

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. The activities of ERGS are governed under a separate risk policy. 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, consumption, or outstanding debt service.

2. Maximum Transaction Term

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

3. Maximum Transaction Volumes

Hedged commodity volumes are not to exceed 80% of the expected production or consumption in any settlement period, and hedged interest rates shall not exceed 100% of total outstanding indebtedness. 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 2012 and 2013.

In any quarter, newly-hedged volumes (i.e., added during that quarter) shall not exceed 20% of the expected production, consumption, or indebtedness for any settlement period without the prior approval of the Board of Directors.

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. 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.

We also have implemented a separate risk policy and controls document for ERGS to ensure appropriate identification, monitoring and control of risk relating to its trading activities. This document establishes the risk management methodologies that limit exposure and track potential changes in portfolio value. The ERGS risk policy and controls document is consistent with our corporate risk objectives, organizational structures and control environment.

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

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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 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 as a result of our gathering, processing, producing and marketing activities, which produce a naturally long position in these 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 read “Risk Factors.”

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.

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.

In 2011, we began conducting commodity derivative trading activities through ERGS, our natural gas marketing and trading subsidiary. ERGS's trading portfolio includes transactions that are settled through the physical delivery of the underlying product and financially settled contracts, primarily basis derivatives transacted to capture spread differentials between physical index points where transportation capacity has been subscribed. If the value of these positions change in a direction or manner that we did not anticipate or cannot manage, it could negatively impact our cash flows.

As of December 31, 2013, our commodity hedge portfolio totaled $8.8 million, which consists of assets aggregating $20.7 million less liabilities aggregating $11.9 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 2013 Adjusted EBITDA of $8 million and $2 million, respectively, based on $85 per barrel and $3.75 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 volumes delivered to our plants and systems, future costs and other economic conditions, and future relationships between crude oil prices and natural gas liquids prices.

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Interest Rate Risk

We are exposed to variable interest rate risk as a result of borrowings under our existing credit agreement. To mitigate its interest rate risk, we have entered 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.

On June 20, 2011, we extended $250 million notional amount of our interest rate swaps from their original maturity dates of December 31, 2012 to a new maturity date of June 22, 2015 and blended the existing swap rate for these extended swaps with the then prevailing interest swap rate, which lowered the rate from 4.095% to 2.95%.

Based upon the transactions discussed in the paragraph above, we estimate that for 2013, 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:

	Year Ended
	December 31, 2013			December 31, 2012
	($ in thousands)
Net risk management assets at beginning of period	$	38,362		$	18,828
Cash paid (received) to terminate contracts, net	—			7,664
Cash received (paid) from settled contracts	19,288			41,105
Settlements of positions	(19,288		)	(41,105		)
Change in mark-to-market valuations of positions	(38,610		)	11,870
Balance of risk management liabilities at end of period	$	(248	)	$	38,362

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 principle customers are large natural gas liquids purchasers, fractionators and marketers, and 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.

For the year ended December 31, 2013, Oneok, Inc. and Chevron Corporation, our largest customers, represented 22% and 11%, respectively, of our total sales revenue (including gains and losses on commodity derivatives).  All of our natural gas sales are under 30 day payment term deals, with credit based upon 60 days of deliveries and almost all other product sales contracts are under 30 day payment term arrangements.

This 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.

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Our derivative counterparties include BNP Paribas, Wells Fargo Bank, National Association, Comerica Bank, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs), ING Capital Markets LLC, BBVA Compass Bank, Royal Bank of Canada, 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 Annual Report on Form 10-K.

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

None.

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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 Securities Exchange Act of 1934, as amended (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, 2013. Based on the evaluation of our disclosure controls and procedures (as defined in the Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (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 Securities and Exchange Commission 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.

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 2013.  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, 2013, which is the period covered by this Annual Report on Form 10-K. 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 Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Partnership's internal control over financial reporting as of December 31, 2013, 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. and subsidiaries (collectively, the "Partnership") internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership'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, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, 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 the Partnership as of December 31, 2013 and 2012, and the related consolidated statements of operations, members' equity, and cash flows for each of the years in the three-year period ended December 31, 2013, and our report dated March 3, 2014 expressed an unqualified opinion on those consolidated financial statements.

/s/KPMG LLP

Houston, Texas

March 3, 2014

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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, 2014.

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 2014 Annual Meeting of Unitholders to be filed no later than April 30, 2014.

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 2014 Annual Meeting of Unitholders to be filed no later than April 30, 2014.

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 2014 Annual Meeting of Unitholders to be filed no later than April 30, 2014.

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 2014 Annual Meeting of Unitholders to be filed no later than April 30, 2014.

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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, 2013 and 2012	F- 3
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011	F- 4
Consolidated Statements of Members’ Equity for the Years Ended December 31, 2013, 2012 and 2011	F- 6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011	F- 7
Notes to Consolidated Financial Statements	F- 8

(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:

110

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)
2.2	Purchase and Sale Agreement by and between BP America Production Company and Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 1.1 of the registrant's Current Report on Form 8-K filed on August 10, 2012)
2.3	Membership Interest Contribution Agreement, by and among (i) CC Energy II L.L.C., Crow Creek Energy II L.L.C. and Crow Creek Operating Company II L.L.C., (ii) Natural Gas Partners VIII, L.P. and the other contributors party thereto and (iii) Eagle Rock Energy Partners, L.P., dated as of April 12, 2011 (incorporated by reference to Exhibit 2.1 to the registrant's Current Report on From 8-K filed on April 13, 2011)
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	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)
4.2	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)
4.3	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)
4.4	Registration Rights Agreement dated as of July 13, 2012 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.3 of the registrant's Current Report on Form 8-K filed on July 13, 2012)
4.5	Registration Rights Agreement dated as of May 27, 2011 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.2 to the registrant's Current Report on Form 8-K filed with the Commission on May 27, 2011)
4.6	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)
4.7	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	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)
10.2	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)
10.3	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).
10.4	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)
10.5	Purchase Agreement dated as of July 10, 2012 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 of the registrant's Current Report on Form 8-K filed on July 13, 2012)
10.6	Purchase Agreement dated as of May 24, 2011 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on May 27, 2011)

111

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	Contribution Agreement, dated May 24, 2010, by and among the Partnership, Eagle Rock Holdings, L.P. and Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on May 25, 2010)
10.10†	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)
10.11	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)
10.12	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)
10.13†	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)
10.14†	Amendment to Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and Eagle Rock Field Services, L.P. (successor to ONEOK Texas Field Services, L.P.) dated April 6, 2012 (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on April 12, 2012)
10.15†	Amendment to Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P, and Eagle Rock Field Services, L.P. (incorporated by reference to Exhibit 10.1 of the registrants Current Report on Form 8-K filed with the Commission on August 23, 2011)
10.16†	Amendment to Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and Eagle Rock Field Services L.P. (successor to ONEOK Texas Field Services, L.P.) dated December 3, 2010 (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on December 9, 2010)
10.17†	Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and ONEOK Texas Field Services, L.P. (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.5 of the registrant's registration statement on Form S-1 (File No. 333-134750))
10.18	Gas Sales and Purchase Agreement between MC Panhandle, Inc. (Chesapeake Energy Marketing Inc.) and MidCon Gas Services Corp. (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.6 of the registrant's registration statement on Form S-1 (File No. 333-134750))
10.19†	Amendment to Brookeland Gas Facilities Gas Gathering and Processing Agreement by and between Anadarko E&P Company LP and Eagle Rock Operating, L.P. (incorporated by reference to Exhibit 10.1 of the registrant's Current Report on Form 8-K filed on October 3, 2012)
10.20	Brookeland Gas Facilities Gas Gathering and Processing Agreement between Union Pacific Resources Company (Anadarko E&P Company LP) and Sonat Exploration Company (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.7 of the registrant's registration statement on Form S-1 (File No. 333-134750))
10.21	Gas Purchase Contract between Warren Petroleum Company (Eagle Rock Field Services, L.P.) and Wallace Oil & Gas, Inc. (Cimarex Energy Co.) (incorporated by reference to Exhibit 10.10 of the registrant's registration statement on Form S-1 (File No. 333-134750))
10.22	Base Contract for Sale and Purchase of Natural Gas between Eagle Rock Field Services, L.P. and Odyssey Energy Services, LLC (incorporated by reference to Exhibit 10.13 of the registrant's registration statement on Form S-1 (File No. 333-134750))
10.23**	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)
10.24**	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)
10.25**	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)
10.26**	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)
10.27**	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)
10.28**	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Robert Hallett dated May 1, 2012
10.29**	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)
10.30**	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)
10.31**	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)

112

Exhibit Number	Description
10.32**	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)
10.33**	Amended and Restated Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan dated September 17, 2010 (incorporated by reference to Exhibit 10.1 of the registrant's Current Report on Form 8-K filed on September 17, 2010)
10.34**	Form of Restricted Unit Agreement for Non-Employee Directors 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 July 30, 2010)
10.35**	Form of Restricted Unit Agreement for Officers 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 December 30, 2009)
10.36**†	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)
10.37**†	Eagle Rock Energy G&P, LLC 2013 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 11, 2013)
10.38**†	Eagle Rock Energy G&P, LLC 2012 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 10, 2012)
10.39**	Amendments to certain company performance goals under the Eagle Rock Energy G&P, LLC 2011 Short Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.3 to the registrant's Current Report on Form 8-K filed with the Commission on May 3, 2011)
10.40**†	Eagle Rock Energy G&P, LLC 2011 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 14, 2011)
10.41**†	Eagle Rock Energy G&P, LLC 2010 Short Term Incentive Bonus Plan approved and adopted on December 30, 2009 (incorporated by reference to Exhibit 10.3 of the registrant's Current Report on Form 8-K filed with the Commission on December 30, 2009)
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 Jeffrey P. Wood 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 Jeffrey P. Wood 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.  

113

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 3, 2014.

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 3, 2014
/s/    JEFFREY P. WOOD Jeffrey P. Wood	Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	March 3, 2014
/s/    PEGGY A. HEEG        Peggy A. Heeg	Director	March 3, 2014
/s/    CHRISTOPHER D. RAY        Christopher D. Ray	Director	March 3, 2014
/s/    WILLIAM J. QUINN        William J. Quinn	Director	March 3, 2014
/s/    PHILIP B. SMITH        Philip B. Smith	Director	March 3, 2014
/s/    WILLIAM A. SMITH        William A. Smith	Director	March 3, 2014
/s/    DAVID W. HAYES        David W. Hayes	Director	March 3, 2014
/s/    WILLIAM K. WHITE         William K. White	Director	March 3, 2014
/s/    HERBERT C. WILLIAMSON III         Herbert C. Williamson III	Director	March 3, 2014

114

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, 2013 and 2012	F- 3
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011	F- 4
Consolidated Statements of Members’ Equity for the Years Ended December 31, 2013, 2012 and 2011	F- 6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011	F- 7
Notes to Consolidated Financial Statements	F- 8

F- 1

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, 2013 and 2012, and the related consolidated statements of operations, members' equity, and cash flows for each of the years in the three-year period ended December 31, 2013. 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 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 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 audit provides 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, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December31, 2013 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, 2013, based on 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 3, 2014, expressed an unqualified opinion on the effectiveness of the Partnership's internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

March 3, 2014

F- 2

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2013 AND 2012

($ in thousands)

	December 31, 2013		December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	76	$	25
Accounts receivable (a)	145,963		138,732
Risk management assets	9,162		33,340
Prepayments and other current assets	8,183		9,867
Total current assets	163,384		181,964
PROPERTY, PLANT AND EQUIPMENT — Net	1,828,768		1,968,206
INTANGIBLE ASSETS — Net	105,620		111,515
DEFERRED TAX ASSET	1,438		1,656
RISK MANAGEMENT ASSETS	5,461		7,953
OTHER ASSETS	22,879		22,922
TOTAL	$	2,127,550	$	2,294,216
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	170,124	$	160,473
Accrued liabilities	29,970		19,764
Taxes payable	149		46
Risk management liabilities	11,023		1,231
Total current liabilities	211,266		181,514
LONG-TERM DEBT	1,252,062		1,153,103
ASSET RETIREMENT OBLIGATIONS	45,849		44,814
DEFERRED TAX LIABILITY	37,953		43,000
RISK MANAGEMENT LIABILITIES	3,848		1,700
OTHER LONG TERM LIABILITIES	2,693		1,711
COMMITMENTS AND CONTINGENCIES (Note 13)
MEMBERS' EQUITY (b)	573,879		868,374
TOTAL	$	2,127,550	$	2,294,216

________________________ 

(a) Net of allowance for bad debt of $1,188 as of December 31, 2013 and $972 as of December 31, 2012.

(b) 156,644,153 and 144,675,751 common units were issued and outstanding as of December 31, 2013 and December 31, 2012, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 2,743,807 and 2,608,035 as of December 31, 2013 and December 31, 2012, respectively.

See accompanying notes to consolidated financial statements.  

F- 3

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011

($ in thousands)

	Year Ended December 31,
	2013			2012			2011
REVENUE:
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales	$	1,129,333		$	864,884		$	977,952
Gathering, compression, processing and treating fees	83,659			56,831			47,770
Commodity risk management gains (losses), net	(18,533		)	57,894			32,510
Other revenue	820			4,350			1,676
Total revenue	1,195,279			983,959			1,059,908
COSTS AND EXPENSES:
Cost of natural gas, natural gas liquids, condensate and helium	790,618			532,719			633,184
Operations and maintenance	135,205			119,828			93,048
Taxes other than income	20,270			19,432			19,148
General and administrative	81,214			69,994			57,891
Other operating income	—			—			(2,893		)
Impairment and other	214,286			177,003			16,288
Depreciation, depletion and amortization	167,170			161,045			131,611
Total costs and expenses	1,408,763			1,080,021			948,277
OPERATING (LOSS) INCOME	(213,484		)	(96,062		)	111,631
OTHER INCOME (EXPENSE):
Interest expense, net	(68,762		)	(51,478		)	(29,622		)
Interest rate risk management losses, net	(1,104		)	(4,727		)	(11,401		)
Other (expense) income, net	257			(38		)	(184		)
Total other expense	(69,609		)	(56,243		)	(41,207		)
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(283,093		)	(152,305		)	70,424
INCOME TAX BENEFIT	(5,114		)	(1,703		)	(2,432		)
(LOSS) INCOME FROM CONTINUING OPERATIONS	(277,979		)	(150,602		)	72,856
DISCONTINUED OPERATIONS, NET OF TAX	—			—			276
NET (LOSS) INCOME	$	(277,979	)	$	(150,602	)	$	73,132

 See accompanying notes to consolidated financial statements.  

F- 4

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS (continued)

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011

	Year Ended December 31,
	2013			2012			2011
NET INCOME PER COMMON UNIT—BASIC AND DILUTED:
Income (loss) from Continuing Operations
Common units - Basic	$	(1.82	)	$	(1.13	)	$	0.65
Common units - Diluted	$	(1.82	)	$	(1.13	)	$	0.61
Discontinued Operations
Common units - Basic	$	—		$	—		$	—
Common units - Diluted	$	—		$	—		$	—
Net Income (loss)
Common units - Basic	$	(1.82	)	$	(1.13	)	$	0.65
Common units - Diluted	$	(1.82	)	$	(1.13	)	$	0.62
Weighted Average Units Outstanding (in thousands)
Common units - Basic	153,562			135,609			110,435
Common units - Diluted	153,562			135,609			116,941

See accompanying notes to consolidated financial statements.  

F- 5

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011

(in thousands, except unit amounts)

	Number of Common Units		Common Units			Total
BALANCE — January 1, 2011	83,425,378		$	579,113		$	579,113
Net income	—		73,132			73,132
Distributions	—		(74,512		)	(74,512		)
Vesting of restricted units	608,122		—			—
Exercised warrants	14,957,540		89,745			89,745
Repurchase of common units	(137,985	)	(1,401		)	(1,401		)
Equity based compensation	—		5,145			5,145
Units issued for acquisitions	28,753,174		336,125			336,125
BALANCE — December 31, 2011	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		—			—
Exercised warrants	—		—			—
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

 See accompanying notes to consolidated financial statements.  

F- 6

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011

($ in thousands)

	Year Ended December 31,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(277,979	)	$	(150,602	)	$	73,132
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations	—			—			(276		)
Depreciation, depletion and amortization	167,170			161,045			131,611
Impairment and other	214,286			177,003			16,288
Amortization of debt issuance costs	4,465			3,483			2,415
Loss (gain) from risk management activities, net	19,322			(53,387		)	(21,573		)
Derivative settlements	17,965			27,068			(43,937		)
Equity-based compensation	13,384			9,882			5,145
Loss (gain) on sale of assets	(190		)	(28		)	166
Other operating income	—			—			(2,893		)
Other	(80		)	(703		)	(929		)
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	(7,102		)	(39,823		)	(5,418		)
Prepayments and other current assets	1,684			3,872			(7,976		)
Risk management activities	—			(7,664		)	(25,510		)
Accounts payable	29,750			16,087			(2,067		)
Accrued liabilities	952			1,437			1,878
Other assets	(4,111		)	575			(1,216		)
Other current liabilities	(2,140		)	(2,744		)	(1,040		)
Net cash provided by operating activities	177,376			145,501			117,800
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(243,430		)	(306,024		)	(154,916		)
Acquisitions, net of cash acquired	—			(230,640		)	(220,326		)
Proceeds from sale of assets	285			15,398			5,712
Purchase of intangible assets	(3,903		)	(7,404		)	(4,406		)
Net cash used in investing activities	(247,048		)	(528,670		)	(373,936		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	601,400			1,043,750			964,279
Repayment of long-term debt	(503,100		)	(916,750		)	(1,012,779		)
Proceeds from senior notes	—			246,253			297,837
Payment of debt issuance costs	—			(7,132		)	(17,466		)
Proceeds from derivative contracts	1,323			14,449			6,267
Common units issued in equity offerings	102,388			96,173			—
Issuance costs for equity offerings	(4,519		)	(4,518		)	—
Exercise of warrants	—			31,804			89,745
Repurchase of common units	(1,858		)	(2,501		)	(1,401		)
Distributions to members and affiliates	(125,911		)	(119,211		)	(74,512		)
Net cash provided by financing activities	69,723			382,317			251,970
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities	—			—			994
Net cash provided by discontinued operations	—			—			994
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	51			(852		)	(3,172		)
CASH AND CASH EQUIVALENTS—Beginning of period	25			877			4,049
CASH AND CASH EQUIVALENTS—End of period	$	76		$	25		$	877
NONCASH INVESTING AND FINANCING ACTIVITIES:
Units issued for acquisitions	$	—		$	—		$	336,125
Investments in property, plant and equipment, not paid	$	9,469		$	29,568		$	31,374
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	$	65,309		$	45,614		$	24,682
Cash paid for taxes	$	59		$	1,085		$	1,516

See accompanying notes to consolidated financial statements.

F- 7

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011

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 limited partnership engaged in (i) the 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 (the “Midstream Business”); and (ii) the business of developing and producing interests in oil and natural gas properties (the “Upstream Business”). The Partnership's midstream assets are strategically located in four productive, mature natural gas producing regions; the Texas Panhandle, East Texas/Louisiana, South Texas and the Gulf of Mexico, and its natural gas pipelines gather natural gas from designated points near producing wells and transport these volumes to third-party pipelines, the Partnership's gas processing plants, utilities and industrial consumers. Natural gas transported to the Partnership's gas processing plants, either in the Partnership's pipelines or third party pipelines, is treated to remove contaminants and conditioned or processed into marketable natural gas and NGLs. The Partnership reports its Midstream Business results through three segments: the Texas Panhandle Segment, the East Texas and Other Midstream Segment and the Marketing and Trading Segment.  The Partnership's upstream assets are characterized by long-lived, high-working interest properties with extensive production histories and development opportunities. Its upstream assets are located in the United States, primarily in South Alabama (where it also operates the associated gathering and processing assets), Texas, Oklahoma and Arkansas. The Partnership reports its Upstream Business through 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 became wholly-owned subsidiaries of the Partnership on July 30, 2010. The transaction with Eagle Rock Energy GP, L.P. was accounted for by the Partnership as a recapitalization. The acquisition of Eagle Rock Energy G&P, LLC was accounted for as an acquisition of entities under common control, which requires the Partnership to present its financial statements as if the two entities had always been combined, similar to the pooling of interests method.

Recent Developments—On December 23, 2013, the Partnership announced that it had entered into a definitive agreement to contribute its Midstream Business to Regency Energy Partners LP ("Regency") for total consideration of up to $1.325 billion, consisting of $200 million of newly issued Regency common units and a combination of cash and assumed debt, subject to certain closing conditions. As part of this transaction, Regency will conduct an offer to exchange the Partnership's$550 million of outstanding senior unsecured notes for an equivalent amount of Regency senior unsecured notes with the same tenor, coupon and a comparable covenant package. The cash portion of the purchase price will be reduced by the amount of notes exchanged subject to a 10% adjustment factor, such that if all $550 million of bonds are exchanged, the total consideration will equal $1.27 billion ($1.325 billion less $55 million) consisting of $200 million in Regency units, $550 million of assumed debt and $520 million of cash proceeds. The transaction is subject to the approval of the Partnership's unitholders, Hart-Scott-Rodino Antitrust Improvements Act of 1976 approval and other customary closing conditions.

As the sale of the Midstream Business is conditioned upon the approval of the Partnership's common unitholders, the Partnership has not classified the assets of its Midstream Business as assets-held-for-sale or the operations as discontinued.

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). Eagle Rock Energy is the owner of non-operating undivided interests in certain gas processing plants and gas gathering systems. Eagle Rock Energy owns these interests as tenants-in-common with the majority owner-operator of the facilities. Accordingly, Eagle Rock Energy includes its pro-rata share of assets, liabilities, revenues and expenses related to these assets in its financial statements. 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

F- 8

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.

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, 2013, 2012 and 2011.

	2013			2012			2011
($ in thousands)
Balance at beginning of period	$	972		$	1,347		$	4,496
Charged to bad debt expense	291			58			54
Write-offs/adjustments charged to allowance	(75		)	(433		)	(3,203		)
Balance at end of period	$	1,188		$	972		$	1,347

During the year ended December 31, 2011, the write off charged to the allowance related to the payment the Partnership received related to the sale of its 503(b)(9) claims related to SemGroup, L.P. ("SemGroup"). This amount relates to the non-503(b)(9) claims and the portion of the receivables sold in August 2009 (see Note 20 for further discussion).

Certain Other Concentrations—The Partnership relies on natural gas producers for its Midstream Business's natural gas and natural gas liquid supply, with the top two producers (by segment) accounting for 36% of its natural gas supply in the Texas Panhandle Segment and 25% of its natural gas supply in the East Texas and Other Midstream Segment for the year ended December 31, 2013. While there are numerous natural gas and natural gas liquid producers, and some of these producers are subject to long-term contracts, the Partnership may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. If the Partnership were to lose all or even a portion of the natural gas volumes supplied by these producers and was unable to acquire comparable volumes, the Partnership's results of operations and financial position could be materially adversely affected. These percentages are calculated based on natural gas volumes gathered during the year ended December 31, 2013. For the year ended December 31, 2013, Oneok, Inc. and Chevron Corporation, the Partnership's largest customers, represented 22% and 11%, respectively, of its total sales revenue (including its commodity risk management gains and losses).

Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At December 31, 2013 and December 31, 2012, the Partnership had $1.0 million and $0.8 million, respectively, of crude oil finished goods inventory which is recorded as part of Other Current Assets within the audited consolidated balance sheet.

Property, Plant and Equipment—Property, plant and equipment 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:

F- 9

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

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, 2013, other assets primarily consist of costs associated with debt issuance costs, net of amortization, of $15.4 million; business deposits to various providers and state or regulatory agencies of $6.5 million; and investment in unconsolidated affiliates of $0.9 million. As of December 31, 2012, other assets primarily consist of costs associated with debt issuance costs, net of amortization, of $19.5 million; business deposits to various providers and state or regulatory agencies of $2.2 million; and investment in unconsolidated affiliates of $0.9 million.

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

F- 10

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.

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—Eagle Rock Energy's primary types of sales and service activities reported as operating revenue include:

• sales of natural gas, NGLs, crude oil, condensate and sulfur; 

• natural gas gathering, processing and transportation, from which Eagle Rock Energy generates revenues primarily through the compression, gathering, treating, processing and transportation of natural gas; and 

• NGL transportation from which the Partnership generates revenues from transportation fees.

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 associated with transportation and processing fees are recognized in the period when the services are provided.

For gathering and processing services, the Partnership either receives fees or commodities from natural gas producers under various types of contracts including percentage-of-proceeds, fixed recovery and percent-of-index arrangements. The Partnership also recognizes fee-based service revenues for services such as transportation, compression and processing.

The Partnership's Upstream Segment recognizes natural gas revenues 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.  For the Upstream Segment, as of December 31, 2013 and December 31, 2012, the Partnership had long-term imbalance payables of $0.3 million and $0.6 million, respectively.

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 consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the Midstream Business, as of December 31, 2013, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $1.6 million. For the Midstream Business, as of December 31, 2012, the Partnership had imbalance receivables totaling $0.9 million and imbalance payables totaling $2.1 million. 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.

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

F- 11

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 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, with the exception of certain contracts with our natural gas trading and marketing business. 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 statement of cash flows. See Note 11 for a description of the Partnership's risk management activities.

Other Reclassifications—The prior period within the audited consolidated statements of cash flows has been reclassified to conform to current period presentation. Amounts have been reclassified to new rows titled “Loss from risk management activities, net” that combines settled and mark-to-market gains/losses on derivative instruments and “Derivative settlements” that includes cash attributable to derivative instruments that settled during the periods. The revisions to the cash flow presentation had no impact on “Net cash provided by operating activities.”

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In December 2011, the FASB issued new guidance related to disclosure requirements about the nature of an entity's rights of set-off and related arrangements associated with its financial instruments and derivative instruments. The new disclosures are designed to make financial statements that are prepared under U.S. GAAP more comparable to those prepared under IFRS. To better facilitate comparison between financial statements prepared under U.S. GAAP and IFRS, the new disclosures will give financial statement users information about both gross and net exposures. The disclosure requirements are effective for annual reporting periods beginning on or after January 1, 2013, and did not have a material impact on the Partnership's financial statements for the year ended December 31, 2013. See Notes 11 and 12 for the disclosures related to the Partnership's rights of set-off and the gross and net exposure related to its derivative instruments.

In February 2013, the 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 is not expected to have a material impact on the Partnership’s consolidated financial statements.

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NOTE 4. ACQUISITIONS

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 general and administrative expenses for the year ended December 31, 2012. The Partnership incurred $0.1 million of acquisition related expenses, which are included within general and administrative expenses 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 years ended December 31, 2012 and 2011 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

Acquisition of CC Energy II L.L.C.

On May 3, 2011, the Partnership completed the acquisition (the "Mid-Continent Acquisition") of all of the outstanding membership 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"). Crow Creek Energy has oil and natural gas properties located in multiple basins across Oklahoma, north Texas and Arkansas (the "Mid-Continent" properties) and provides the Partnership with an extensive

F- 13

inventory of low-risk development prospects in established plays such as the Golden Trend field and developing plays such as the Cana Shale. The aggregate purchase price has been calculated as follows (in thousands, except unit and per unit amounts):

Number of Partnership Common Units Issued	28,753,174
Closing common unit price on May 3, 2011	$	11.69
Value of common units issued	$	336,125
Crow Creek Energy outstanding debt assumed	212,638
Cash	14,945
Total purchase price	$	563,708

The number of common units of the Partnership issued was determined based on the value of the equity issued to the sellers of $301.9 million divided by $10.50, the ceiling price of the agreed upon range in the contribution agreement between the Partnership and Crow Creek Energy. The cash portion of the acquisition consideration and the repayment of Crow Creek Energy’s outstanding debt were funded through borrowings under the Partnership’s revolving credit facility. In addition, the Partnership incurred $2.3 million of acquisition related expenses, which are included within general and administrative expenses for the year ended December 31, 2011.

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

Current assets	$	25,329
Oil and gas properties	572,097
Property, plant and equipment	4,463
Rights-of-way and easements	3,192
Other assets	450
Derivatives	3,355
Current liabilities	(37,032		)
Asset retirement obligations	(4,394		)
Deferred tax liability	(2,312		)
Other liabilities	(1,440		)
	$	563,708

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 oil and natural gas properties and asset retirement obligation were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimate of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. 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.

The amounts of Crow Creek Energy's revenue and net income included within the Partnership's audited consolidated statement of operations for the year ended December 31, 2011, and the pro forma revenue and net income of the combined

F- 14

entity had the acquisition date been January 1, 2010, are as follows:

	Revenue		Net Income		Net Income Per Diluted Common Unit
	($ in thousands)
Actual from May 3, 2011 to December 31, 2011	$	68,168	$	29,835
Supplemental pro forma from January 1, 2011 to December 31, 2011	$	1,080,964	$	78,591	$	0.62

NOTE 5. PROPERTY PLANT AND EQUIPMENT

Fixed assets consisted of the following:

	December 31, 2013			December 31, 2012
	($ in thousands)
Land	$	2,877		$	2,876
Plant	521,103			444,023
Gathering and pipeline	777,446			753,009
Equipment and machinery	53,999			39,889
Vehicles and transportation equipment	4,001			4,021
Office equipment, furniture, and fixtures	1,309			1,285
Computer equipment	14,806			11,431
Linefill	5,180			4,328
Proved properties	1,156,896			1,213,622
Unproved properties	10,022			31,823
Construction in progress	33,824			60,870
	2,581,463			2,567,177
Less: accumulated depreciation, depletion and amortization	(752,695		)	(598,971		)
Net property plant and equipment	$	1,828,768		$	1,968,206

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

	Year Ended December 31,
	2013		2012		2011
	($ in thousands)
Depreciation	$	69,449	$	61,390	$	54,606
Depletion	$	87,230	$	88,413	$	65,380
Capitalized interest costs	$	963	$	1,311	$	451
Impairment expense:
Proved properties (a)	$	207,085	$	38,943	$	11,239
Unproved properties (b)	$	7,201	$	785	$	489
Plant assets (c)	$	—	$	57,527	$	4,560
Pipeline assets (c)	$	—	$	52,537	$	—

__________________________________

(a) During the year ended December 31, 2013, the Partnership incurred impairment charges in its Upstream Business 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 in its Upstream Business 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

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associated with gas compression. During the year ended December 31, 2011, the Partnership incurred impairment charges in its Upstream Business related to certain proved properties in the Jourdanton field in South Texas, which included plans for five future drilling locations that the Partnership has determined not to pursue due to the current natural gas price environment.

(b) During the year ended December 31, 2013, the Partnership incurred impairment charges in its Upstream Business related to certain leaseholds in the Mid-Continent regions that we expect to expire undrilled in 2014. During the year ended December 31, 2012, the Partnership incurred impairment charges in its Upstream Business related to certain unproved property leaseholds expected to expire undrilled in 2013. During the year ended December 31, 2011, the Partnership incurred impairment charges related to certain drilling locations in its unproved properties which the Partnership no longer intends to develop based on the performance of offsetting wells.

(c) During the year ended December 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Midstream Segment due to (i) reduced throughput volumes as its producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment (ii) the loss of significant gathering contracts on its Panola and other systems and (iii) the substantial damage incurred at the Yscloskey processing plant as a result of Hurricane Isaac in August 2012. The value of assets for both the Panola system and the Yscloskey plant have been fully written down. During the year ended December 31, 2011, the Partnership recorded an impairment charge in its Texas Panhandle Segment to fully write-down its idle Turkey Creek plant.

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. For its producing oil and natural gas properties, 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. The Partnership recognizes asset retirement obligations for its midstream assets in accordance with the term “conditional asset retirement obligation,” which refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the Partnership's control. 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:

	2013			2012			2011
	($ in thousands)
Asset retirement obligations—January 1	$	48,755		$	33,303		$	24,711
Additional liabilities	1,140			1,721			159
Liabilities settled	(2,240		)	(2,755		)	(465		)
Revision to liabilities	7,603			11,471			2,339
Additional liability related to acquisitions	—			2,650			4,413
Accretion expense	3,706			2,365			2,146
Asset retirement obligations—December 31 (a)	$	58,964		$	48,755		$	33,303

_____________________________________

(a)    As of December 31, 2013 and 2012, $13.1 million and $3.9 million , respectively, were included within accrued liabilities in the Consolidated Balance Sheets.

NOTE 7. INTANGIBLE ASSETS

Intangible assets consist of rights-of-way and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. The amortization period for the Partnership's rights-of-way and easements is 20 years. The amortization period for contracts ranges from 5 to 20 years.  Intangible assets consisted of the following: 

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	December 31, 2013			December 31, 2012
	($ in thousands)
Rights-of-way and easements—at cost	$	131,088		$	127,375
Less: accumulated amortization	(36,228		)	(29,959		)
Contracts	22,742			38,009
Less: accumulated amortization	(11,982		)	(23,910		)
Net intangible assets	$	105,620		$	111,515

The following table sets forth the total amortization and impairment expense by type of intangible assets within the Partnership's audited consolidated statements of operations:

	Year Ended December 31,
	2013		2012		2011
	($ in thousands)
Amortization	$	10,078	$	11,205	$	11,588
Impairment expense:
Rights-of-way (a)	$	—	$	5,266	$	—
Contracts (a)	$	—	$	16,384	$	—

_____________________________________

(a) During the year endedDecember 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain rights-of-way and contracts in its East Texas and Other Midstream Segment due to (i) reduced throughput volumes as its producer customers curtailed their drilling activities due to the continued decline in natural gas prices during the first three months of 2012 and (ii) the termination of significant gathering contracts on its Panola system during the year endedDecember 31, 2012. The value of the contracts and rights-of-way related to the Panola system have been fully written down.

Estimated future amortization expense related to the intangible assets at December 31, 2013, is as follows (in thousands):

Year ending December 31,
2014	$	7,958
2015	$	7,957
2016	$	7,957
2017	$	7,956
2018	$	7,955
Thereafter	$	65,837

NOTE 8. LONG-TERM DEBT

Long-term debt consisted of the following:

	December 31, 2013			December 31, 2012
	($ in thousands)
Revolving credit facility:	$	706,800		$	608,500
Senior notes:
8.375% senior notes due 2019	550,000			550,000
Unamortized bond discount	(4,738		)	(5,397		)
Total senior notes	545,262			544,603
Total long-term debt	$	1,252,062		$	1,153,103

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Revolving Credit Facility

On June 22, 2011, the Partnership entered into an Amended and Restated Credit Agreement, as amended on December 28, 2012 (the “Credit Agreement”) with Wells Fargo Bank, National Association, as administrative and documentation agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, and the other lenders who are parties to the Credit Agreement. The Credit Agreement amended and restated the Partnership’s prior $1.2 billion Credit Agreement (the “Prior Credit Agreement”). Upon the effectiveness of the Credit Agreement, all commitments of the lenders party to the Prior Credit Agreement were terminated and all loans and other indebtedness of the Partnership under the Prior Credit Agreement were renewed and extended, inclusive of new lender commitments, on the terms and conditions of the Credit Agreement. The Credit Agreement matures on June 22, 2016.

In connection with the Credit Agreement, the Partnership incurred debt issuance costs of $9.8 million and recorded a charge of $0.4 million to write off a portion of the unamortized debt issuance costs related to the Prior Credit Agreement. As of December 31, 2013, the Partnership had unamortized debt issuance costs of $5.2 million.

On December 28, 2012, the Partnership received increased commitments from its lending group under the Credit Agreement. Aggregate commitments increased from $675 million to $820 million. The Partnership has the option to request further increases in commitments, subject to the terms and conditions of the Credit Agreement, up to an aggregate total amount of $1.2 billion. Availability under the credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. The upstream component of the borrowing base is determined semi-annually as an amount equal to the loan value of the proved oil and gas reserves of the Partnership and its subsidiaries as determined by the lenders party to the Credit Agreement. The midstream component of the borrowing base is determined quarterly as an amount equal to the lesser of (i) 55% of the total borrowing base (subject to increase for certain periods following certain material acquisitions up to 60% of the total borrowing base) and (ii) 3.75 times Consolidated EBITDA (as defined in the Credit Agreement) attributable to the midstream assets of the Partnership and its subsidiaries for the trailing four fiscal quarters. Pro forma adjustments to each component of the borrowing base, and thus total availability under the credit facility, are made upon the occurrence of certain events including material acquisitions and dispositions. Availability under the Credit Agreement is based on the lower of the current borrowing base and the total commitments. As of December 31, 2013, the Partnership had approximately $49.2 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 $150.0 million. As of December 31, 2013, the Partnership had $19.2 million of outstanding letters of credit.

At the Partnership's election, interest will accrue on the credit facility at either LIBOR plus a margin ranging from 1.75% to 2.75% (currently 2.50% per annum based on the Partnership's borrowing base utilization percentage) or the base rate plus a margin ranging from 0.75% to 1.75% (currently 1.50% 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, 2013, the weighted average interest rate (excluding the impact of interest rate swaps) on the Partnership's outstanding debt under its revolving credit facility was 2.67%.

The obligations under the Credit Agreement are secured by first priority liens on substantially all of the Partnership’s (and its material subsidiaries') material assets, including a pledge of all of the equity interests of each of the Partnership’s material subsidiaries.

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 Consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarter period ending with such fiscal quarter to Consolidated Interest Expense (as defined in the Credit Agreement) for such four fiscal quarter period (the "Interest Coverage Ratio").;

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• 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”).;

• As of the fiscal quarter-end for the fiscal quarters ending December 31, 2013 through September 30, 2014, the ratio of Senior Secured Debt (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter (the “Senior Secured 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”).

The following table presents the debt covenant levels specified in our revolving credit facility as of December 31, 2013:

Quarter Ended	Total Leverage Ratio	Senior Secured Leverage Ratio	Interest Coverage Ratio	Current Ratio
December 31, 2013	5.50	3.15	2.50	1.0
March 31, 2014	5.25	3.10	2.50	1.0
June 30, 2014	5.00	3.05	2.50	1.0
September 30, 2014	4.75	2.95	2.50	1.0
Thereafter	4.50	NA	2.50	1.0

The following table presents the Partnership's actual covenant ratios as of December 31, 2013:

Interest coverage ratio	3.1
Total leverage ratio	5.4
Senior secured leverage ratio	3.06
Current ratio	1.1

As of December 31, 2013, the Partnership was in compliance with the financial covenants under the Credit Agreement.  The Partnership expects compliance with financial covenants under the Credit Agreement through 2014 because the Midstream Business Contribution to Regency will substantially improve the Partnership’s liquidity and debt ratios through the elimination of significant debt currently outstanding under our revolving credit facility and the proposed assumption of all of it's senior unsecured notes via an exchange offer to be conducted by Regency. The completion of the Midstream Business Contribution is subject to regulatory and unitholder approvals. As a result, the Partnership can provide no assurance that the Midstream Business Contribution will be completed within its anticipated time frame, or at all. Should the Midstream Business Contribution not be consummated, the Partnership intends to explore alternative means to reduce its leverage ratios to comply with the financial covenants, which may include asset sales or purchases, equity financings, the separation of its upstream and midstream businesses or other alternatives.

On February 26, 2014, the Partnership and its lender group amended the Credit Agreement to, among other items, allow for a temporary step-up in the Total Leverage Ratio and Senior Secured Leverage Ratio, and allow for additional liquidity at its election. For a further discussion of the Credit Agreement amendment, see Note 22.

Senior Notes

On May 27, 2011, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer and certain subsidiary guarantors, issued $300.0 million of senior unsecured notes (the "Senior Notes"), that bear a coupon of 8.375%, through a private placement. The Senior Notes will mature on June 1, 2019, and interest is payable on each

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June 1 and December 1, commencing December 1, 2011. After the original discount of $2.2 million and excluding related offering expenses, the Partnership received net proceeds of approximately $297.8 million, which were used to repay borrowings outstanding under the Prior Credit Agreement.

On July 13, 2012, the Partnership, along with its subsidiary, Finance Corp, as co-issuer and certain subsidiary guarantors, completed the sale of an additional $250.0 million of 8.375% senior unsecured notes due 2019 through a private placement exempt from the registration requirements of the Securities Act of 1933. After the original issue discount of $3.7 million and excluding related offering expenses, the Partnership received net proceeds of approximately $246.3 million, which were used to repay borrowings outstanding under its revolving credit facility. This issuance supplemented the Partnership's prior $300.0 million of Senior Notes issued in May 2011, all of which are treated as a single series. As of December 31, 2013, the Partnership had unamortized debt issuance costs of $10.3 million and an unamortized debt discount of $4.7 million, which is recorded as an offset to the principal amount of the Senior Notes.

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.

The indenture governing the Senior Notes, among other things, restricts the Partnership's ability and the ability of the Partnership's restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue redeemable stock; (ii) pay dividends on stock, repurchase stock or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create liens on their assets; (vi) sell or otherwise dispose of certain assets, including capital stock of subsidiaries; (vii) restrict dividends, loans or other asset transfers from the Partnership's restricted subsidiaries; (viii) enter into new lines of business; and (ix) consolidate with or merge with or into, or sell all or substantially all of their properties (taken as a whole) to another person.

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. In addition, the Partnership may redeem up to 35% of the Senior Notes prior to June 1, 2014 under certain circumstances with the net cash proceeds from certain equity offerings at 108.375% of the principal amount of the notes redeemed.

Scheduled maturities of long-term debt as of December 31, 2013, were as follows: 

	Principal Amount
	($ in thousands)
2014	$	—
2015	—
2016	706,800
2017	—
2018	—
2019 and after	550,000
	$	1,256,800

NOTE 9. MEMBERS’ EQUITY

At December 31, 2013, there were 156,644,153 common units outstanding. In addition, there were 2,743,807 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

F- 20

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 endedDecember 31, 2012 and 20115,300,588 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. As of December 31, 2013, 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.

The Partnership has declared a cash distribution for each quarter since its initial public offering. The table below summarizes these distributions for the last three years. 

Quarter Ended	Distribution per Unit		Record Date**	Payment Date
March 31, 2011+	$	0.1500	May 9, 2011	May 13, 2011
June 30, 2011+	$	0.1875	August 5, 2011	August 12, 2011
September 30, 2011+	$	0.2000	November 4, 2011	November 14, 2011
December 31, 2011+	$	0.2100	February 7, 2012	February 14, 2012
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

_____________________________

+ The distribution per unit represents distributions made only on common units, including restricted common units issued under our Long Term Incentive Plan. 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 unit grants.

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

NOTE 10. RELATED PARTY TRANSACTIONS

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

	Year Ended December 31,
	2013		2012		2011
Affiliates of NGP:	($ in thousands)
Natural gas purchases from affiliates	$	2,938	$	2,713	$	6,097
Payable as of December 31,	$	18	$	428

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

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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.

On May 3, 2011, the Partnership completed the Mid-Continent Acquisition. Due to Crow Creek Energy being a portfolio company of NGP VIII and NGP's ownership interest in the Partnership and Board of Directors representation, the Board of Directors of the general partner of the Partnership's general partner, authorized its Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Mid-Continent Acquisition, due to the potential conflict of interest among the Partnership, the NGP and the Partnership's public unitholders. The Conflicts Committee, consisting of independent directors of the Partnership, determined that the Mid-Continent Acquisition was fair and reasonable to the Partnership and its public unitholders and recommended to the Board of Directors that the transaction be approved and authorized. In determining the consideration for the acquisition of Crow Creek Energy, the Conflicts Committee, with the assistance of a third-party, considered the valuation of the properties involved in the transaction, the valuation of the units to be offered as consideration in the transaction and the cash flows of Crow Creek Energy.

In connection with the closing of the Mid-Continent Acquisition, 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 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).

The following table sets forth certain information regarding the Partnership's various interest rate swaps as of December 31, 2013:

Effective Date	Expiration Date	Notional Amount		Fixed Rate
6/22/2011	6/22/2015	$	250,000,000	2.95	%

 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

F- 22

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.  For the Midstream Business, expected future production is based on the expected production from wells currently flowing to the Partnership's processing plants, plus additional volumes the Partnership expects to receive from future drilling activity by its producer customer base.  The Partnership's expectations for its Midstream Business volumes associated with future drilling are based on information it receives from its producer customer base and historical observations. The Partnership applies the appropriate contract terms to these projections to determine its expected future equity share of the commodities.

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, 2013, not including counterparties of its marketing and trading business, included BNP Paribas, Wells Fargo Bank, National Association, Comerica Bank, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs), ING Capital Markets LLC, BBVA Compass Bank, Royal Bank of Canada, Regions Financial Corporation and CITIBANK, N.A.

The following tables set forth certain information regarding the Partnership's commodity derivatives. Within each 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, 2013, that will mature during the years ended December 31, 2014, 2015 and 2016:

Underlying	Type	Notional Volumes (units) (a)	Floor Strike Price ($/unit)(b)		Cap Strike Price ($/unit)(b)
Portion of Contracts Maturing in 2014
Natural Gas	Swap (Pay Floating/Receive Fixed)	16,800,000	$	4.38
Crude Oil	Costless Collar	240,000	$	90.00	$	106.00
Crude Oil	Swap (Pay Floating/Receive Fixed)	2,208,000	$	96.51
Crude Oil	Swap (Pay Fixed/Receive Floating)	199,140	$	92.53
Propane	Swap (Pay Floating/Receive Fixed)	9,576,000	$	1.06
IsoButane	Swap (Pay Floating/Receive Fixed)	2,268,000	$	1.31
Normal Butane	Swap (Pay Floating/Receive Fixed)	4,132,800	$	1.30
Portion of Contracts Maturing in 2015
Natural Gas	Swap (Pay Floating/Receive Fixed)	12,000,000	$	4.10
Crude Oil	Costless Collar	480,000	$	90.00	$	97.55
Crude Oil	Swap (Pay Floating/Receive Fixed)	1,110,000	$	88.70
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)	1,416,000	$	84.60

_______________________

(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

The Partnership conducts natural gas marketing and trading activities. The Partnership engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. The Partnership's activities are governed by its risk policy.

As part of its natural gas marketing and trading activities, the Partnership enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction.

A commodity-related derivative contract may be designated as a "normal" purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as "normal" the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement. Commodity-related contracts that do not qualify for the normal designation are accounted for as derivatives and are marked-to-market each period.

Through the Partnership's natural gas marketing activity, the Partnership will have credit exposure to additional counterparties. The Partnership minimizes the credit risk associated with natural gas marketing by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, the Partnership nets the open positions of

each counterparty. See Note 12 for the impact to the Partnership's unaudited condensed consolidated balance sheets of the

netting of these contracts.

F- 24

Marketing and Trading commodity derivative instruments, as of December 31, 2013, that will mature during the years ended December 31, 2014 and 2015 and beyond:

Type	Notional Volumes (MMbtu)
Portion of Contracts Maturing in 2014
Basis Swaps - Purchases	6,955,000
Basis Swaps - Sales	2,675,000
Index Swap - Purchases	620,000
Index Swap - Sales	1,365,000
Swap (Pay Fixed/Receive Floating) - Purchases	930,000
Swap (Pay Floating/Received Fixed) - Sales	465,000
Forward purchase contract - index	13,090,332
Forward sales contract - index	18,873,397
Forward purchase contract - fixed price	2,263,000
Forward sales contract - fixed price	2,728,000
Portion of Contracts Maturing in 2015 and beyond
Basis Swaps - Purchases	13,280,000
Basis Swaps - Sales	13,280,000

Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales.

F- 25

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, 2013 and December 31, 2012:

	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	11,268			Current liabilities	1,730
Commodity derivatives - assets	Long-term assets	6,259			Long-term liabilities	1,488
Commodity derivatives - liabilities	Current assets	(2,106		)	Current liabilities	(6,543		)
Commodity derivatives - liabilities	Long-term assets	(798		)	Long-term liabilities	(2,451		)
Total derivatives		$	14,623			$	(14,871	)
	As of December 31, 2012
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	(4,844	)	Current liabilities	$	(1,201	)
Interest rate derivatives - liabilities	Long-term assets	(7,002		)	Long-term liabilities	(1,700		)
Commodity derivatives - assets	Current assets	39,182			Current liabilities	19
Commodity derivatives - assets	Long-term assets	17,338			Long-term liabilities	—
Commodity derivatives - liabilities	Current assets	(998		)	Current liabilities	(49		)
Commodity derivatives - liabilities	Long-term assets	(2,383		)	Long-term liabilities	—
Total derivatives		$	41,293			$	(2,931	)

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,
		2013			2012			2011
Interest rate derivatives	Interest rate risk management losses, net	$	(1,104	)	$	(4,727	)	$	(11,401	)
Commodity derivatives	Commodity risk management gains (losses), net	(18,533		)	57,894			32,510
Commodity derivatives -trading	Natural gas, natural gas liquids, oil, condensate and sulfur sales	315			(192		)	772
	Total	$	(19,322	)	$	52,975		$	21,881

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).

F- 26

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, 2013, 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 prior periods, the Partnership has classified the inputs to measure its NGL derivatives as Level 3 as the NGL market was considered to be less liquid and thinly traded. As of September 30, 2011, the Partnership concluded that the inputs for its NGL derivatives were considered to be more observable due to the NGL market being more liquid through the term of our contracts and has classified these inputs as Level 2. The following table discloses the fair value of the Partnership's derivative instruments as of December 31, 2013 and 2012: 

	As of December 31, 2013
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	9,804		$	—	$	(2,003	)	$	7,801
Natural gas derivatives	—		10,899			—		(4,077		)	6,822
NGL derivatives	—		42			—		(42		)	—
Total	$	—	$	20,745		$	—	$	(6,122	)	$	14,623
Liabilities:
Crude oil derivatives	$	—	$	(3,930	)	$	—	$	2,003		$	(1,927	)
Natural gas derivatives	—		(6,847		)	—		4,077			(2,770		)
NGL derivatives	—		(1,121		)	—		42			(1,079		)
Interest rate swaps	—		(9,095		)	—		—			(9,095		)
Total	$	—	$	(20,993	)	$	—	$	6,122		$	(14,871	)

____________________________

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

F- 27

	As of December 31, 2012
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	19,410		$	—	$	(1,814	)	$	17,596
Natural gas derivatives	—		27,340			—		(1,586		)	25,754
NGL derivatives	—		9,789			—		—			9,789
Interest rate swaps	—		—			—		(11,846		)	(11,846		)
Total	$	—	$	56,539		$	—	$	(15,246	)	$	41,293
Liabilities:
Crude oil derivatives	$	—	$	(1,814	)	$	—	$	1,814		$	—
Natural gas derivatives	—		(1,616		)	—		1,586			(30		)
Interest rate swaps	—		(14,747		)	—		11,846			(2,901		)
Total	$	—	$	(18,177	)	$	—	$	15,246		$	(2,931	)

____________________________

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

The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the years endedDecember 31, 2013, 2012 and 2011 (in thousands):

	Year Ended December 31,
	2013		2012		2011
Net liability beginning balance	$	—	$	—	$	(5,733	)
Settlements	—		—		15,562
Total gains or losses	—		—		(12,784		)
Transfers out of Level 3	—		—		2,955
Net liability ending balance	$	—	$	—	$	—

The Partnership values its Level 3 NGL derivatives using forward curves, interest rate curves, and volatility parameters, when applicable. In addition, the impact of counterparty credit risk is factored into the value of derivative assets, and the Partnership's credit risk is factored into the value of derivative liabilities.

Gains and losses losses 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 related to the Partnership's commodity derivatives are recorded as a component of revenue in the audited consolidated statements of operations. 

F- 28

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. 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, 2013:

	December 31, 2013		Level 1		Level 2		Level 3		Total Losses
	($ in thousands)
Proved properties	$	91,346	$	—	$	—	$	91,346	$	207,085

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 included estimates of (i) reserves, (ii) future operating and development costs (ii) forward commodity prices and (iii) a discount rate reflective of the Partnership's cost of capital. For the other assets impaired by the partnership during the year endedDecember 31, 2013, the assets were fully written down and are thus not included in the table above. See Notes 5 for a further discussion of the impairment charges.

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, 2013, 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 bears interest at a fixed rate; based on the market price of the Senior Notes as of December 31, 2013 and 2012, the Partnership estimates that the fair value of the Senior Notes is $599.5 million and $561.0 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 is subject to lawsuits which arise from time to time in the ordinary course of business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds. The Partnership had no accruals as of December 31, 2013 and 2012 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. The Partnership has been indemnified up to a certain dollar amount for two lawsuits. If there ultimately is a finding against the Partnership in these two indemnified cases, the Partnership would expect to make a claim against the indemnification up to limits of the indemnification.

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 includes: (1) commercial general liability insurance covering liabilities to third parties for bodily injury, property damage and pollution arising out of Eagle Rock Energy 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 in the Upstream Segment; 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. 

F- 29

Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, 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 planning, designing, constructing and operating pipelines, plants, and other facilities 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, 2013 and 2012, the Partnership had accrued approximately $3.2 million and $2.8 million, respectively, for environmental matters.

Retained Revenue Interest—Certain assets of the Partnership's Upstream Segment 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 2013 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, including leases with no continuing commitment, amounted to approximately $9.5 million, $8.9 million and $7.8 million for the years endedDecember 31, 2013, 2012 and 2011, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term. At December 31, 2013, commitments under long-term non-cancelable operating leases for the next five years are as follows (in thousands):

Year ending December 31,
2014	$	7,060
2015	$	6,045
2016	$	4,997
2017	$	2,848
2018	$	438

NOTE 14. SEGMENTS

Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of three segments in its Midstream Business, one Upstream Segment and one Corporate segment:

(i)Midstream—Texas Panhandle Segment: gathering, compressing, treating, processing and transporting natural gas; fractionating, transporting and marketing NGLs;

(ii)    Midstream—East Texas and Other Midstream Segment: gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in South Texas, East Texas, Louisiana, Gulf of Mexico and inland waters of Texas;

F- 30

(iii)    Midstream—Marketing and Trading Segment: crude oil and condensate logistics and marketing in the Texas Panhandle and Alabama; and natural gas marketing and trading;

(iv)    Upstream Segment: crude oil, condensate, natural gas, NGLs and sulfur production from operated and non-operated wells; and

(v)    Corporate and Other Segment: risk management, intersegment eliminations and other corporate activities such as general and administrative expenses.

The Partnership's chief operating decision maker ("CODM") currently reviews its operations using these segments. The CODM evaluates segment performance based on segment operating income or loss from continuing operations. Summarized financial information concerning the Partnership's reportable segments is shown in the following tables:

Year Ended December 31, 2013	Texas Panhandle Segment		East Texas and Other Midstream Segment		Marketing and Trading Segment			Total Midstream Business			Upstream Segment			Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	538,492	$	136,637	$	384,422		$	1,059,551		$	154,261		$	(18,533	)	(a)	$	1,195,279
Intersegment sales	226,576		37,716		(272,116		)	(7,824		)	47,048			(39,224		)		—
Cost of natural gas and natural gas liquids	594,125		131,966		64,527			790,618			—			—				790,618
Intersegment cost of natural gas, oil and condensate	200		—		38,844			39,044			—			(39,044		)		—
Operating costs and other expenses	81,186		19,943		(8		)	101,121			54,354			81,214				236,689
Depreciation, depletion, amortization	57,781		19,476		428			77,685			87,456			2,029				167,170
Impairment	—		—		—			—			214,286			—				214,286
Operating income (loss) from continuing operations	$	31,776	$	2,968	$	8,515		$	43,259		$	(154,787	)	$	(101,956	)		$	(213,484	)
Capital Expenditures	$	81,590	$	7,827	$	309		$	89,726		$	129,099		$	5,336			$	224,161
Segment Assets	$	950,092	$	243,493	$	73,918		$	1,267,503		$	842,246		$	17,801		(b)	$	2,127,550

Year Ended December 31, 2012	Texas Panhandle Segment			East Texas and Other Midstream Segment			Marketing and Trading Segment			Total Midstream Business			Upstream Segment		Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	362,902	(c)	$	156,529		$	256,772		$	776,203		$	149,862	$	57,894		(a)	$	983,959
Intersegment sales	105,759			39,099			(154,992		)	(10,134		)	53,343		(43,209		)		—
Cost of natural gas and natural gas liquids	332,792			147,493			52,434			532,719			—		—				532,719
Intersegment cost of natural gas,oil and condensate	83			—			44,317			44,400			—		(44,400		)		—
Operating costs and other expenses	60,884			21,762			2			82,648			56,612		69,994				209,254
Intersegment operations and maintenance	—			—			—			—			122		(122		)		—
Depreciation, depletion, amortization	44,451			25,771			273			70,495			88,777		1,773				161,045
Impairment	—			131,714			—			131,714			45,289		—				177,003
Operating income (loss) from continuing operations	$	30,451		$	(131,112	)	$	4,754		$	(95,907	)	$	12,405	$	(12,560	)		$	(96,062	)
Capital Expenditures	$	131,928		$	9,328		$	5,489		$	146,745		$	160,330	$	3,645			$	310,720
Segment Assets	$	922,281		$	250,916		$	43,417		$	1,216,614		$	1,018,927	$	58,675		(b)	$	2,294,216

F- 31

Year Ended December 31, 2011	Texas Panhandle Segment		East Texas and Other Midstream Segment		Marketing and Trading Segment			Total Midstream Business			Upstream Segment			Corporate and Other Segment				Total Segments
($ in thousands)
Sales to external customers	$	395,991	$	274,361	$	200,939		$	871,291		$	156,107	(d)	$	32,510		(a)	$	1,059,908
Intersegment sales	60,237		16,654		(82,378		)	(5,487		)	48,203			(42,716		)		—
Cost of natural gas and natural gas liquids	327,775		231,642		73,767			633,184			—			—				633,184
Intersegment cost of natural gas, oil and condensate	—		—		41,382			41,382			—			(41,382		)		—
Operating costs and other expenses	41,749		22,790		—			64,539			47,657			54,998				167,194
Intersegment operations and maintenance	—		—		—			—			66			(66		)		—
Depreciation, depletion, amortization	37,034		27,629		—			64,663			65,531			1,417				131,611
Impairment	4,560		—		—			4,560			11,728			—				16,288
Operating income (loss) from continuing operations	$	45,110	$	8,954	$	3,412		$	57,476		$	79,328		$	(25,173	)		$	111,631
Capital Expenditures	$	71,351	$	10,860	$	2,205		$	84,416		$	92,660		$	2,132			$	179,208
Segment Assets	$	599,688	374,030		$	40,173		$	1,013,891		$	979,331		$	52,466		(b)	$	2,045,688

______________________________

(a) Represents results of the Partnership's commodity risk management activity.

(b) Includes elimination of intersegment transactions.

(c) Sales to external customers in the Texas Panhandle Segment for the year ended December 31, 2012, includes 2.9 million of business interruption insurance recovery related to damage sustained by the Partnership's Cargray processing facility due to severe winter weather in 2011, which is recognized as part of Other Revenue in the consolidated statements of operations.

(d) Sales to external customers for the years ended December 31, 2011 includes $2.0 million, respectively, of business interruption insurance recovery related to the shutdown of the Eustace plant in 2010 in the Upstream Segment, which is recognized as part of Other revenue in the consolidated statement of operations.

NOTE 15. EMPLOYEE BENEFIT PLAN

The Partnership offers a defined contribution benefit plan to its employees. For the three years ended December 31, 2012, 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, 2013, 2012 and 2011 were approximately $2.5 million, $1.8 million and $1.0 million, respectively.

NOTE 16. 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.

F- 32

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

	For the Year Ended December 31,
	2013			2012			2011
Current:
Federal	$	(105	)	$	621		$	1,092
State	—			18			61
Total current provision	(105		)	639			1,153
Deferred:
Federal	(3,837		)	(2,776		)	(3,862		)
State	(1,172		)	434			277
Total deferred	(5,009		)	(2,342		)	(3,585		)
Total (benefit) provision for income taxes	$	(5,114	)	$	(1,703	)	(2,432		)

The effective rates for the years ended December 31, 2013, 2012 and 2011 are shown in the table below.  For 2011, the effective tax rate is attributable to the state and federal taxes being applied to their book income. In 2013 and 2012, the federal and state based income taxes were applied against book losses which resulted in effective tax rates of 1.8% and 1.1%, 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,
	2013			2012			2011
Pre-tax net book income (loss) from continuing operations	(283,093		)	(152,305		)	70,424
State income tax current and deferred	(1,172		)	452			338
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities	(4,160		)	(2,155		)	(2,232		)
Tax attributes used	218			—			(538		)
Benefit for income taxes from continuing operations	$	(5,114	)	$	(1,703	)	$	(2,432	)
Effective income tax rate on continuing operations	1.8		%	1.1		%	(3.5		)%

Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2013 and 2012 are as follows (in thousands):

	December 31, 2013			December 31, 2012
Deferred Tax Assets:
Statutory depletion carryover	$	1,438		$	1,599
AMT credit carryforward	—			57
Total Deferred Tax Assets	1,438			1,656
Deferred Tax Liabilities:
Property, plant, equipment & amortizable assets	(5,867		)	(6,585		)
Hedging transactions	—			(271		)
Book/tax differences from partnership investment	(32,086		)	(36,144		)
Total Deferred Tax Liabilities	(37,953		)	(43,000		)
Total Net Deferred Tax Liabilities	(36,515		)	(41,344		)
Current portion of total net deferred tax liabilities	—			—
Long-term portion of total net deferred tax liabilities	$	(36,515	)	$	(41,344	)

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

F- 33

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 liability 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, 2013, 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 AMT credit carryforward presented above does not have an expiration date.

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 2013, 2012 and 2011, 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): 

	2013			2012			2011
Balance at beginning of period	$	(830	)	$	(735	)	$	(569	)
Increases related to current year tax positions	(128		)	(53		)	(132		)
Increases related to tax interest and penalties	(39		)	(42		)	(34		)
Decreases related to statutory limitations	267			—			—
Decreases related to tax interest and penalties	81			—			—
Balance at end of period	$	(649	)	$	(830	)	$	(735	)

NOTE 17. 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 7,000,000 common units, to be granted either as options, restricted units or phantom units, of which, as of December 31, 2013, a total of 913,794 common units remained available for issuance. Grants under the LTIP are made at the discretion of the board and to date have only been made in the form of restricted units. 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. No options or phantom units have been issued to date.

The restricted units granted are valued at the market price as of the date issued. The weighted average fair value of the units granted during the years endedDecember 31, 2013, 2012 and 2011 was $9.16, $9.50 and $10.13, respectively. The awards generally vest over three years on the basis of one third of the award each year. 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 granted awards will be distributed to the awardees.

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A summary of the restricted common units’ activity for the year endedDecember 31, 2013 is provided below:

	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2012	2,608,035		$	9.38
Granted	1,623,939		$	9.16
Vested	(1,203,822	)	$	8.98
Forfeited	(284,345	)	$	9.90
Outstanding at December 31, 2013	2,743,807		$	9.37

For the years endedDecember 31, 2013, 2012 and 2011, non-cash compensation expense of approximately $13.4 million, $9.9 million and $5.1 million, respectively, was recorded related to the granted restricted units as general and administrative expense on the consolidated statements of operations.

As of December 31, 2013, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $17.1 million. The remaining expense is to be recognized over a weighted average of 1.6 years.

In connection with the vesting of certain restricted units during the years endedDecember 31, 2013, 2012 and 2011, 272,179, 286,716 and 137,985, respectively, of the newly-vested common units were cancelled by the Partnership in satisfaction of $1.9 million, $2.5 million and $1.4 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 18. 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, 2013, 2012 and 2011, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units will be 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.

Any warrants outstanding during the period are considered to be dilutive securities. These outstanding warrants will be considered in the diluted weighted average common units outstanding number in periods of net income, except if the exercise price of the outstanding warrants is greater than the average market price of the common units for such periods. In periods of net losses, the outstanding warrants are excluded from the diluted weighted average common units outstanding.

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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,
	2013	2012	2011
	(in thousands)
Weighted average units outstanding during period:
Common units - Basic	153,562	135,609	110,435
Effect of Dilutive Securities:
Warrants	—	—	5,727
Restricted Units	—	—	779
Common units - Diluted	153,562	135,609	116,941

The restricted common units granted under the LTIP, as discussed in Note 17, 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. For the year ended December 31, 2011, the Partnership determined that it is more dilutive to apply the two-class method versus the treasury stock method in calculating dilutive earnings per unit. Thus, the unvested restricted common units are included in the computation of the diluted weighted average common unit outstanding calculation, but the denominator in the computation of diluted earnings per common unit only includes the basic weighted average common units outstanding and weighted average warrants outstanding.

The following table presents the Partnership's basic income per unit for the year endedDecember 31, 2013:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Net loss	$	(277,979	)
Distributions	117,294			$	115,351		$	1,943
Assumed loss from continuing operations after distribution to be allocated	(395,273		)	(395,273		)	—
Assumed net (loss) income to be allocated	$	(277,979	)	$	(279,922	)	$	1,943
Basic and diluted loss per unit				$	(1.82	)

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

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(150,602	)
Distributions	124,235			$	121,504		$	2,731
Assumed loss from continuing operations after distribution to be allocated	(274,837		)	(274,837		)	—
Assumed net income to be allocated	$	(150,602	)	$	(153,333	)	$	2,731
Basic and diluted loss per unit				$	(1.13	)

The following table presents the Partnership's basic and diluted income per unit for the year endedDecember 31, 2011:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	72,856
Distributions	89,062			$	87,525		$	1,537
Assumed loss from continuing operations after distribution to be allocated	(16,206		)	(16,206		)	—
Assumed allocation of loss from continuing operations	72,856			71,319			1,537
Discontinued operations, net of tax	276			276			—
Assumed net income to be allocated	$	73,132		$	71,595		$	1,537
Basic income from continuing operations per unit				$	0.65
Basic discontinued operations per unit				$	—
Basic net income per unit				$	0.65
Diluted income from continuing operations per unit				$	0.61
Diluted discontinued operations per unit				$	—
Diluted net income per unit				$	0.62

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NOTE 19.   DIVESTITURE RELATED ACTIVITIES

The following table represents activity from divestiture related activities for the years ended December 31, 2013, 2012 and 2011:

	Barnett Shale (a)			Wildhorse System (b)			Minerals Business (c)
($ in thousands)
Year Ended December 31, 2012:
Loss from the sale	$	(4,460	)	$	—		$	—
Proceeds from sale	$	14,841		$	—		$	—
Year Ended December 31, 2011:
Revenues	$	—		$	6,859		$	—
(Loss) income from Operations	$	—		$	548		$	—
Discontinued operations, net of tax	$	—		$	(180	)	$	456
Loss from the sale	$	—		$	(718	)	—
Proceeds from sale	$	—		$	5,712		—

_____________________________

(a) On December 20, 2012, the Partnership sold its Barnett Shale properties (which was accounted for in its Upstream Segment). In 2012, the Partnership incurred a loss from sale which is included within impairment expense in the Consolidated Statement of Operations.

(b) On May 20, 2011, the Partnership sold its Wildhorse Gathering System (which was accounted for in its East Texas and Other Midstream Segment).

(c) On May 24, 2010, the Partnership completed the sale of its Minerals Business. During the year ended December 31, 2011, the Partnership received payments related to pre-effective date operations and recorded this amount as part of discontinued operations for the period.

NOTE 20. OTHER OPERATING INCOME

In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The Partnership historically sold portions of its condensate production from its Texas Panhandle and East Texas midstream systems to SemGroup. In August 2009, the Partnership sold $3.9 million of its outstanding receivables from SemGroup, which represented its 20-day administrative claims under 503(b)(9) of the United States Bankruptcy Code, for which it received a payment of $3.0 million. Due to certain repurchase obligations under the assignment agreement, the Partnership recorded the payment as a current liability within accounts payable as of December 31, 2010 and maintained the balance as a liability until it was clear that the repurchase obligations can no longer be triggered. Due to the expiration of the repurchase obligations during the year ended December 31, 2011, the Partnership released its reserve for these receivables and recorded other operating income of $2.9 million related to these reserves.

NOTE 21. SUBSIDIARY GUARANTORS

The Partnership has issued registered debt securities guaranteed by its subsidiaries.  As of December 31, 2013, 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

F- 38

• 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, 2013 and December 31, 2012, condensed consolidating statements of operations for the years endedDecember 31, 2013, 2012 and 2011, and condensed consolidating statements of cash flows for the years endedDecember 31, 2013, 2012 and 2011, 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.

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	)	$	—
Other current assets	5,868		1		157,515		—		—			163,384
Total property, plant and equipment, net	2,318		—		1,826,450		—		—			1,828,768
Investment in subsidiaries	1,133,217		—		—		908		(1,134,125		)	—
Total other long-term assets	19,833		—		115,565		—		—			135,398
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	)	$	—
Other current liabilities	17,390		—		193,876		—		—			211,266
Other long-term liabilities	9,493		—		80,850		—		—			90,343
Long-term debt	1,252,062		—		—		—		—			1,252,062
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 Balance Sheet

December 31, 2012

	Parent Issuer		Co-Issuer		Subsidiary Guarantors		Non-guarantor investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	660,898	$	—	$	—	$	—	$	(660,898	)	$	—
Other current assets	27,688		1		154,275		—		—			181,964
Total property, plant and equipment, net	2,657		—		1,965,549		—		—			1,968,206
Investment in subsidiaries	1,324,293		—		—		958		(1,325,251		)	—
Total other long-term assets	22,061		—		121,985		—		—			144,046
Total assets	$	2,037,597	$	1	$	2,241,809	$	958	$	(1,986,149	)	$	2,294,216
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	—	$	660,898	$	—	$	(660,898	)	$	—
Other current liabilities	6,734		—		174,780		—		—			181,514
Other long-term liabilities	9,386		—		81,839		—		—			91,225
Long-term debt	1,153,103		—		—		—		—			1,153,103
Equity	868,374		1		1,324,292		958		(1,325,251		)	868,374
Total liabilities and equity	$	2,037,597	$	1	$	2,241,809	$	958	$	(1,986,149	)	$	2,294,216

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	$	(4,168	)	$	—	$	1,199,447		$	—		$	—		$	1,195,279
Cost of natural gas and natural gas liquids	—			—		790,618			—			—			790,618
Operations and maintenance	(1		)	—		135,206			—			—			135,205
Taxes other than income	—			—		20,270			—			—			20,270
General and administrative	17,716			—		63,498			—			—			81,214
Depreciation, depletion and amortization	454			—		166,716			—			—			167,170
Impairment and other	—			—		214,286			—			—			214,286
Loss from operations	(22,337		)	—		(191,147		)	—			—			(213,484		)
Interest expense, net	(67,864		)	—		(898		)	—			—			(68,762		)
Other non-operating income	9,025			—		9,298			—			(18,323		)	—
Other non-operating expense	(6,904		)	—		(12,256		)	(10		)	18,323			(847		)
Loss before income taxes	(88,080		)	—		(195,003		)	(10		)	—			(283,093		)
Income tax benefit	(1,172		)	—		(3,942		)	—			—			(5,114		)
Equity in earnings of subsidiaries	(191,071		)	—		—			—			191,071			—
Net loss	$	(277,979	)	$	—	$	(191,061	)	$	(10	)	$	191,071		$	(277,979	)

F- 40

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	$	28,884		$	—	$	955,075		$	—		$	—		$	983,959
Cost of natural gas and natural gas liquids	—			—		532,719			—			—			532,719
Operations and maintenance	—			—		119,828			—			—			119,828
Taxes other than income	—			—		19,432			—			—			19,432
General and administrative	10,908			—		59,086			—			—			69,994
Depreciation, depletion and amortization	296			—		160,749			—			—			161,045
Impairment	—			—		177,003			—			—			177,003
Income (loss) from operations	17,680			—		(113,742		)	—			—			(96,062		)
Interest expense, net	(51,501		)	—		23			—			—			(51,478		)
Other non-operating income	9,039			—		10,961			—			(20,000		)	—
Other non-operating expense	(12,189		)	—		(12,558		)	(18		)	20,000			(4,765		)
Loss before income taxes	(36,971		)	—		(115,316		)	(18		)	—			(152,305		)
Income tax provision (benefit)	431			—		(2,134		)	—			—			(1,703		)
Equity in earnings of subsidiaries	(113,200		)	—		—			—			113,200			—
Net loss	$	(150,602	)	$	—	$	(113,182	)	$	(18	)	$	113,200		$	(150,602	)

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2011

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	36,095		$	—	$	1,023,813		$	—		$	—		$	1,059,908
Cost of natural gas and natural gas liquids	—			—		633,184			—			—			633,184
Operations and maintenance	—			—		93,048			—			—			93,048
Taxes other than income	—			—		19,148			—			—			19,148
General and administrative	5,299			—		52,592			—			—			57,891
Other operating income	—			—		(2,893		)	—			—			(2,893		)
Depreciation, depletion and amortization	196			—		131,415			—			—			131,611
Impairment	—			—		16,288			—			—			16,288
Income from operations	30,600			—		81,031			—			—			111,631
Interest expense, net	(29,614		)	—		(8		)	—			—			(29,622		)
Other non-operating income	8,779			—		5,607			—			(14,386		)	—
Other non-operating expense	(28,589		)	—		2,628			(10		)	14,386			(11,585		)
Income (loss) before income taxes	(18,824		)	—		89,258			(10		)	—			70,424
Income tax provision (benefit)	339			—		(2,771		)	—			—			(2,432		)
Equity in earnings of subsidiaries	92,295			—		—			—			(92,295		)	—
Income (loss) from continuing operations	73,132			—		92,029			(10		)	(92,295		)	72,856
Discontinued operations, net of tax	—			—		276			—			—			276
Net income (loss)	$	73,132		$	—	$	92,305		$	(10	)	$	(92,295	)	$	73,132

F- 41

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	$	(70,041	)	$	—	$	247,376		$	41	$	—	$	177,376
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(115		)	—		(243,315		)	—		—		(243,430		)
Proceeds from sale of asset	—			—		285			—		—		285
Purchase of intangible assets	—			—		(3,903		)	—		—		(3,903		)
Net cash flows used in investing activities	(115		)	—		(246,933		)	—		—		(247,048		)
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 derivative 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 increase (decrease) 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

F- 42

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	$	(143,444	)	$	—	$	288,888		$	57	$	—		$	145,501
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(1,551		)	—		(304,473		)	—		—			(306,024		)
Acquisitions, net of cash acquired	—			—		(230,640		)	—		—			(230,640		)
Proceeds from sale of asset	—			—		15,398			—		—			15,398
Purchase of intangible assets	—			—		(7,404		)	—		—			(7,404		)
Contributions to subsidiaries	(236,971		)	—		—			—		236,971			—
Net cash flows used in investing activities	(238,522		)	—		(527,119		)	—		236,971			(528,670		)
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	246,253			—		—			—		—			246,253
Payments of debt issuance cost	(7,132		)	—		—			—		—			(7,132		)
Proceeds from derivatives 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		)
Contributions from parent	—			—		236,971			—		(236,971		)	—
Net cash flows provided by financing activities	382,317			—		236,971			—		(236,971		)	382,317
Net (decrease) increase 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

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Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2011

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments		Consolidating Entries			Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(27,569	)	$	—	$	145,283		$	86	$	—		$	117,800
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(389		)	—		(154,527		)	—		—			(154,916		)
Acquisitions, net of cash acquired	—			—		(220,326		)	—		—			(220,326		)
Proceeds from sale of asset	—			—		5,712			—		—			5,712
Purchase of intangible assets	—			—		(4,406		)	—		—			(4,406		)
Contribution to subsidiaries	(227,583		)	—		—			—		227,583			—
Net cash flows used in investing activities	(227,972		)	—		(373,547		)	—		227,583			(373,936		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	964,279			—		—			—		—			964,279
Repayment of long-term debt	(1,012,779		)	—		—			—		—			(1,012,779		)
Proceed from senior notes	297,837			—		—			—		—			297,837
Payments of debt issuance cost	(17,466		)	—		—			—		—			(17,466		)
Proceeds from derivative contracts	6,267			—		—			—		—			6,267
Exercise of Warrants	89,745			—		—			—		—			89,745
Repurchase of common units	(1,401		)	—		—			—		—			(1,401		)
Distributions to members and affiliates	(74,512		)	—		—			—		—			(74,512		)
Contributions from parent	—			—		227,583			—		(227,583		)	—
Net cash flows provided by financing activities	251,970			—		227,583			—		(227,583		)	251,970
Net cash flows provided by discontinued operations	—			—		994			—		—			994
Net increase (decrease) in cash and cash equivalents	(3,571		)	—		313			86		—			(3,172		)
Cash and cash equivalents at beginning of year	4,890			1		(885		)	43		—			4,049
Cash and cash equivalents at end of year	$	1,319		$	1	$	(572	)	$	129	$	—		$	877

NOTE 22. SUBSEQUENT EVENTS

In February 2014, the Partnership entered into an amended credit agreement with its lender group which allowed for greater liquidity under the senior secured credit facility and for greater covenant flexibility for the first quarter of 2014. Specifically, the amendment provides for: (i) an increase in the Total Leverage Ratio and Senior Secured Leverage Ratio (as defined in the Credit Agreement) to 5.85x and 3.40x, respectively, for the quarter ended March 31, 2014; (ii) the exclusion of fees and expenses associated with the strategic review and disposition of the Partnership’s Midstream Business from the calculation of Consolidated EBITDA (as defined in the Credit Agreement); (iii) deferring the redetermination of the Upstream Borrowing Base until June 1, 2014; and (iv) the option for the Partnership, at its election, to expand the multiplier for the Midstream Borrowing Base from 3.75x to 4.00x.

On February 28, 2014, the Partnership announced that itself and Regency had received a request for additional information and documents from the Federal Trade Commission in connection with the proposed contribution of the Partnership's Midstream Business to Regency.

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NOTE 23. 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 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 2013 are based on an average of the prior twelve months first-of-month spot prices of West Texas Intermediate ($96.94 per barrel) and are adjusted for quality, transportation fees, and regional price differentials. Likewise, natural gas prices applied for 2013 are based on an average of the prior twelve months first-of-month spot prices of Henry Hub natural gas ($3.66 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 natural gas reserves in 2013. These negative revisions were due in large part to the Partnership's decision to remove a number of undeveloped locations from its Five Year Development Plan. These undeveloped locations were expected to generate lower-than-acceptable economic performance given our current outlook for commodity prices, and/or were undeveloped locations on non-operated acreage for which we lacked reasonable certainty of development. These undeveloped locations were recategorized as probable reserves. We also recategorized some undeveloped locations as contingent resources because our revised production and cost forecasts indicated these locations were non-commercial under SEC guidelines at the time of determination.

F- 45

	Proved Reserves
	Oil (MBbls)		Gas (MMcf)		Natural Gas Liquids (MBbls)
Proved reserves, January 1, 2011	8,696		38,382		6,176
Extensions and discoveries	215		14,523		903
Purchase of minerals in place	3,830		198,826		4,815
Production	(1,118	)	(12,636	)	(805	)
Revision of previous estimates	(101	)	(5,073	)	258
Proved reserves, December 31, 2011	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
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
Proved Developed Reserves
Proved developed reserves, January 1, 2011	8,299		29,686		5,758
Proved developed reserves, December 31, 2011	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 Undeveloped Reserves
Proved undeveloped reserves, January 1, 2011	397		8,696		418
Proved undeveloped reserves, December 31, 2011	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

The primary drivers behind the changes to our proved reserves for the years endedDecember 31, 2011, 2012 and 2013 are described in more detail below.

2011:

• purchases of minerals in place were significant in 2011 and were almost entirely related to the Crow Creek Acquisition;

• extensions and discoveries were related to drilling by us and other operators on our Crow Creek assets, primarily in the Cana Play and Golden Trend area in Oklahoma; and

• revisions to previous estimates were relatively small and were primarily due to reductions caused by changes in condensate and NGL yields at our Big Escambia Creek field, and well performance at our Ward Estes and Ginger fields, partially offset by higher prices which extended the economic life and reserves of some wells.

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;

F- 46

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

• revisions to 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;

• 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 to previous estimates were primarily the result of updating our Five Year Development Plan to recategorize as probable reserves those undeveloped wells that we are not reasonably certain of drilling in five years due to their expected economic performance, or because they are operated by others and we do have assurance from the operators of their intent to develop them; and because we recategorized other proved undeveloped reserves as contingent resources due to revised performance expectations and other factors. All of these revisions were primarily in the Mid-Continent Region.

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, 2013, 2012 and 2011:

	As of December 31, 2013			As of December 31, 2012			As of December 31, 2011
($ in thousands)
Proved properties	$	1,156,896		$	1,213,622		$	1,050,872
Unproved properties—excluded from depletion	10,022			31,823			91,363
Gross oil and gas properties	1,166,918			1,245,445			1,142,235
Accumulated depreciation, depletion, amortization	(353,679		)	(269,376		)	(190,833		)
Net oil and gas properties	$	813,239		$	976,069		$	951,402

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, 2013, 2012 and 2011:

	Year Ended December 31,
	2013		2012		2011
($ in thousands)
Property acquisition costs, proved	$	—	$	2,582	$	465,088
Property acquisition costs, unproved	—		—		103,337
Development costs	124,032		135,692		90,418
Total costs	$	124,032	$	138,274	$	658,843

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

F- 47

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 $8.1 million, $14.0 million and $17.8 million in 2013, 2012 and 2011, respectively. The cost of removing the sulfur is included in the future production costs in the Standardized Measure table below. In prior years, the Partnership included the expected revenues from the sale of sulfur as part of the Standardized Measure computation. The Partnership changed that practice in 2013 and now includes only the sale of hydrocarbons in the computation. The Standardized Measure presented as of December 31, 2012 and 2011 in the following table has been adjusted to reflect this change in methodology. No reserve volumes have been booked for sulfur, and the impact of sulfur revenues on the economic limit of reserves in prior years is considered immaterial.

The Standardized Measure is as follows as of December 31, 2013, 2012 and 2011:

	As of December 31, 2013			As of December 31, 2012			As of December 31, 2011
				(As Adjusted)			(As Adjusted)
($ in thousands)
Future cash inflows	$	2,423,350		$	2,279,735		$	2,516,812
Future production costs	(737,468		)	(767,004		)	(845,530		)
Future development costs	(318,778		)	(354,690		)	(315,019		)
Future net cash flows before income taxes	1,367,104			1,158,041			1,356,263
Future income tax (expense) benefit	(1,212		)	(1,086		)	(1,831		)
Future net cash flows before 10% discount	1,365,892			1,156,955			1,354,432
10% annual discount for estimated timing of cash flows	(715,386		)	(621,826		)	(711,846		)
Total standardized measure of discounted future net cash flows	$	650,506		$	535,129		$	642,586

The tables below present the Partnership’s previously-disclosed SMOG values, the revised values (which exclude sulfur revenues), and the differences between them for years ending December 31, 2012 and 2011.  The differences between the two sets of values are most pronounced in the future cash inflows and future production costs.  The change in future cash inflows is due to a shortening of the economic life of certain properties when sulfur revenues are excluded. The change in future production costs is the result of the exclusion of sulfur revenues, which were historically shown as an offset to the cost to transport and market the sulfur.  In some prior years, the cost to transport and market the sulfur exceeded the total sulfur revenues, resulting in a net cost. In other prior years, sulfur revenues exceeded the cost to transport and market the sulfur, resulting in net positive cash flows. In order to maintain consistency across periods and to show only hydrocarbon revenues as as future cash inflows, the Partnership reported the net impact from the sale of sulfur in all periods within future production costs.

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The following summarizes the revisions to the Standardized Measure for fiscal years 2012 and 2011:

	As of December 31, 2012
	As Reported			Revisions			As Adjusted
($ in thousands)
Future cash inflows	$	2,315,266		$	(35,531	)	$	2,279,735
Future production costs	(669,896		)	(97,108		)	(767,004		)
Future development costs	(359,154		)	4,464			(354,690		)
Future net cash flows before income taxes	1,286,216			(128,175		)	1,158,041
Future income tax (expense) benefit	(1,321		)	235			(1,086		)
Future net cash flows before 10% discount	1,284,895			(127,940		)	1,156,955
10% annual discount for estimated timing of cash flows	(680,855		)	59,029			(621,826		)
Total standardized measure of discounted future net cash flows	$	604,040		$	(68,911	)	$	535,129

	As of December 31, 2011
	As Reported			Revisions			As Adjusted
($ in thousands)
Future cash inflows	$	2,562,650		$	(45,838	)	$	2,516,812
Future production costs	(742,749		)	(102,781		)	(845,530		)
Future development costs	(317,405		)	2,386			(315,019		)
Future net cash flows before income taxes	1,502,496			(146,233		)	1,356,263
Future income tax (expense) benefit	(2,379		)	548			(1,831		)
Future net cash flows before 10% discount	1,500,117			(145,685		)	1,354,432
10% annual discount for estimated timing of cash flows	(778,520		)	66,674			(711,846		)
Total standardized measure of discounted future net cash flows	$	721,597		$	(79,011	)	$	642,586

F- 49

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, 2013, 2012 and 2011:

	Year Ended December 31,
	2013			2012			2011
				(As Adjusted)			(As Adjusted)
($ in thousands)
Beginning of year	$	535,129		$	642,586		$	284,687
Sale of oil and gas produced, net of production costs	(150,457		)	(132,451		)	(138,860		)
Net changes in prices and production costs	2,720			(78,247		)	143,023
Extensions, discoveries and improved recovery, less related costs	136,464			66,460			40,832
Previously estimated development costs incurred during the period	21,470			53,111			90,418
Net changes in future development costs	107,951			36,914			(119,121		)
Revisions of previous quantity estimates	(103,351		)	(76,434		)	(34,497		)
Purchases of property	—			2,811			324,652
Sales of property	—			(5,063		)	—
Accretion of discount	49,233			60,734			26,225
Net changes in income taxes	(36		)	317			(519		)
Other	51,383			(35,609		)	25,746
End of year	$	650,506		$	535,129		$	642,586

The following summarizes the revisions to the changes in the Standardized Measure for fiscal years 2012 and 2011.

	Year Ended December 31, 2012
	As Reported			Revisions			As Adjusted
($ in thousands)
Beginning of year	$	721,597		$	(79,011	)	$	642,586
Sale of oil and gas produced, net of production costs	(132,451		)	—			(132,451		)
Net changes in prices and production costs	(76,759		)	(1,488		)	(78,247		)
Extensions, discoveries and improved recovery, less related costs	66,460			—			66,460
Previously estimated development costs incurred during the period	53,111			—			53,111
Net changes in future development costs	36,503			411			36,914
Revisions of previous quantity estimates	(85,176		)	8,742			(76,434		)
Purchases of property	2,811			—			2,811
Sales of property	(5,063		)	—			(5,063		)
Accretion of discount	67,956			(7,222		)	60,734
Net changes in income taxes	564			(247		)	317
Other	(45,513		)	9,904			(35,609		)
End of year	$	604,040		$	(68,911	)	$	535,129

F- 50

	Year Ended December 31, 2011
	As Reported			Revisions			As Adjusted
($ in thousands)
Beginning of year	$	333,993		$	(49,306	)	$	284,687
Sale of oil and gas produced, net of production costs	(138,860		)	—			(138,860		)
Net changes in prices and production costs	170,917			(27,894		)	143,023
Extensions, discoveries and improved recovery, less related costs	40,832			—			40,832
Previously estimated development costs incurred during the period	90,418			—			90,418
Net changes in future development costs	(117,783		)	(1,338		)	(119,121		)
Revisions of previous quantity estimates	(26,447		)	(8,050		)	(34,497		)
Purchases of property	324,652			—			324,652
Accretion of discount	30,728			(4,503		)	26,225
Net changes in income taxes	(621		)	102			(519		)
Other	13,768			11,978			25,746
End of year	$	721,597		$	(79,011	)	$	642,586

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, 2013, 2012 and 2011:

	Year Ended December 31,
	2013			2012			2011
($ in thousands)
Revenues:
Sales to third parties	$	146,210		$	135,842		$	138,383
Intercompany sales	47,048			53,343			48,203
Total revenues	193,258			189,185			186,586
Costs and expenses:
Production costs	54,354			56,734			47,726
General and administrative	11,419			12,162			11,124
Depreciation, depletion, and amortization	87,456			88,777			65,531
Impairment and other	214,286			45,289			11,728
Total costs and expenses	367,515			202,962			136,109
Total result of operations	$	(174,257	)	$	(13,777	)	$	50,477

* * * *

F- 51

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)
2.2	Purchase and Sale Agreement by and between BP America Production Company and Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 1.1 of the registrant's Current Report on Form 8-K filed on August 10, 2012)
2.3	Membership Interest Contribution Agreement, by and among (i) CC Energy II L.L.C., Crow Creek Energy II L.L.C. and Crow Creek Operating Company II L.L.C., (ii) Natural Gas Partners VIII, L.P. and the other contributors party thereto and (iii) Eagle Rock Energy Partners, L.P., dated as of April 12, 2011 (incorporated by reference to Exhibit 2.1 to the registrant's Current Report on From 8-K filed on April 13, 2011)
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	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)
4.2	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)
4.3	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)
4.4	Registration Rights Agreement dated as of July 13, 2012 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.3 of the registrant's Current Report on Form 8-K filed on July 13, 2012)
4.5	Registration Rights Agreement dated as of May 27, 2011 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.2 to the registrant's Current Report on Form 8-K filed with the Commission on May 27, 2011)
4.6	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)
4.7	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	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)
10.2	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)
10.3	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).
10.4	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)
10.5	Purchase Agreement dated as of July 10, 2012 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 of the registrant's Current Report on Form 8-K filed on July 13, 2012)
10.6	Purchase Agreement dated as of May 24, 2011 among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the Commission on May 27, 2011)

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	Contribution Agreement, dated May 24, 2010, by and among the Partnership, Eagle Rock Holdings, L.P. and Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on May 25, 2010)
10.10†	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)
10.11	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)
10.12	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)
10.13†	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)
10.14†	Amendment to Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and Eagle Rock Field Services, L.P. (successor to ONEOK Texas Field Services, L.P.) dated April 6, 2012 (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on April 12, 2012)
10.15†	Amendment to Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P, and Eagle Rock Field Services, L.P. (incorporated by reference to Exhibit 10.1 of the registrants Current Report on Form 8-K filed with the Commission on August 23, 2011)
10.16†	Amendment to Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and Eagle Rock Field Services L.P. (successor to ONEOK Texas Field Services, L.P.) dated December 3, 2010 (incorporated by reference to Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on December 9, 2010)
10.17†	Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and ONEOK Texas Field Services, L.P. (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.5 of the registrant's registration statement on Form S-1 (File No. 333-134750))
10.18	Gas Sales and Purchase Agreement between MC Panhandle, Inc. (Chesapeake Energy Marketing Inc.) and MidCon Gas Services Corp. (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.6 of the registrant's registration statement on Form S-1 (File No. 333-134750))
10.19†	Amendment to Brookeland Gas Facilities Gas Gathering and Processing Agreement by and between Anadarko E&P Company LP and Eagle Rock Operating, L.P. (incorporated by reference to Exhibit 10.1 of the registrant's Current Report on Form 8-K filed on October 3, 2012)
10.20	Brookeland Gas Facilities Gas Gathering and Processing Agreement between Union Pacific Resources Company (Anadarko E&P Company LP) and Sonat Exploration Company (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.7 of the registrant's registration statement on Form S-1 (File No. 333-134750))
10.21	Gas Purchase Contract between Warren Petroleum Company (Eagle Rock Field Services, L.P.) and Wallace Oil & Gas, Inc. (Cimarex Energy Co.) (incorporated by reference to Exhibit 10.10 of the registrant's registration statement on Form S-1 (File No. 333-134750))
10.22	Base Contract for Sale and Purchase of Natural Gas between Eagle Rock Field Services, L.P. and Odyssey Energy Services, LLC (incorporated by reference to Exhibit 10.13 of the registrant's registration statement on Form S-1 (File No. 333-134750))
10.23**	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)
10.24**	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)
10.25**	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)
10.26**	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)
10.27**	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)
10.28**	Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Robert Hallett dated May 1, 2012
10.29**	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)
10.30**	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)
10.31**	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)

Exhibit Number	Description
10.32**	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)
10.33**	Amended and Restated Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan dated September 17, 2010 (incorporated by reference to Exhibit 10.1 of the registrant's Current Report on Form 8-K filed on September 17, 2010)
10.34**	Form of Restricted Unit Agreement for Non-Employee Directors 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 July 30, 2010)
10.35**	Form of Restricted Unit Agreement for Officers 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 December 30, 2009)
10.36**†	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)
10.37**†	Eagle Rock Energy G&P, LLC 2013 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 11, 2013)
10.38**†	Eagle Rock Energy G&P, LLC 2012 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 10, 2012)
10.39**	Amendments to certain company performance goals under the Eagle Rock Energy G&P, LLC 2011 Short Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.3 to the registrant's Current Report on Form 8-K filed with the Commission on May 3, 2011)
10.40**†	Eagle Rock Energy G&P, LLC 2011 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 14, 2011)
10.41**†	Eagle Rock Energy G&P, LLC 2010 Short Term Incentive Bonus Plan approved and adopted on December 30, 2009 (incorporated by reference to Exhibit 10.3 of the registrant's Current Report on Form 8-K filed with the Commission on December 30, 2009)
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 Jeffrey P. Wood 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 Jeffrey P. Wood 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.