Eagle Rock Energy Partners L P (EROC) 10-K 2008 FY Annual report

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, 2008

OR

¨ 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)

16701 Greenspoint Park Drive

Houston, Texas 77060

(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 ¨ No x

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

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. ¨

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  ¨	Accelerated Filer  x
Non-accelerated Filer  ¨	Smaller reporting company  ¨

(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 ¨ No x

As of June 30, 2008, the aggregate market value of the registrant’s common units held by non-affiliates of the registrant was $614,528,144 based on the closing sale price as reported on NASDAQ Global Select Market.

The issuer had ­­55,711,214 common units and 21,536,046 subordinated and general partner units outstanding as of March 6, 2009.

DOCUMENTS INCORPORATED BY REFERENCE:

None

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	53
Item 1B.	Unresolved Staff Comments	75
Item 2.	Properties	75
Item 3.	Legal Proceedings	75
Item 4.	Submission of Matters to a Vote of Security Holders	76
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	77
Item 6.	Selected Financial Data	79
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	85
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	126
Item 8.	Financial Statements and Supplementary Data	133
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	133
Item 9A.	Controls and Procedures	133
Item 9B.	Other Information	136
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	136
Item 11.	Executive Compensation	141
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	157
Item 13.	Certain Relationships and Related Transactions, and Director Independence	159
Item 14.	Principal Accountant Fees and Services	161
PART IV
Item 15.	Exhibits and Financial Statement Schedules	162

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FORWARD-LOOKING STATEMENTS

This report may include “forward-looking statements” as defined by the Securities and Exchange Commission. 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. For a complete description of these risks, please see our risk factors set forth under Item 1A of this annual report. These factors include but are not limited to:

• Drilling and exploration risks;

• Assumptions underlying oil and natural gas reserve levels;

• Commodity prices;

• Hedging activities;

• Ability to obtain credit and access capital markets;

• Conditions in the securities and/or capital markets;

• Future processing volumes and throughput;

• Loss of significant customers;

• Availability and cost of processing and transportation;

• Competition in the oil and natural gas industry;

• Relevant legislative or regulatory changes, including retroactive royalty or production tax regimes, changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations;

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

• Shortages of personnel and equipment;

• Increases in interest rates;

• Creditworthiness of our counterparties;

• Weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business; and

• Any other factors that impact or could impact the exploration of oil or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operations factors relating to the extraction of oil and natural gas.

• Tax risk associated with pass-through investment, including potential reduction in tax shield or creation of phantom income in the event distributions are not enough to support the tax burden.

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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.

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.

Boe/d:    One barrel of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil and NGLs per day.

Bbl/d:    One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons per day.

Bbtu:    One billion British thermal units.

btu:    British thermal unit.

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.

dry hole:    A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses, taxes and future capital.

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 and produce oil or natural gas reserves in an unproved area, to find new reservoir in a field previously found to be productive or oil or natural gas in another reservoir or to extend a known reservoir.

fee-based arrangements:    Under these arrangements, the oil and gas producer pays to the gatherer 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 the gatherer’s pipeline systems and is not directly dependent on commodity prices.

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.

finding and development cost (F&D):Total capital costs, including leasing and exploration expenses, spent to place reserves into production; often expressed as a unit cost, such as $/Mcfe or $/Boe, which are derived by dividing the costs by the reserves.

fixed recovery arrangements:    Under these arrangements, raw natural gas is gathered from producers at the wellhead, transported through our gathering system, and processed and sold as processed natural gas and/or NGLs at prices based on published index prices. The price paid to the producers is based on an agreed to theoretical product recovery factor to be applied against the wellhead production and then a percentage of the theoretical proceeds based on an index or actual sales prices multiplied to the theoretical production. To the extent that the actual recoveries differ from the theoretical product recovery factor, this will affect the margin.

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.

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Hp:    Horsepower.

keep-whole arrangements:    Under these arrangements, raw natural gas is processed to extract NGLs and pay to 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. The processors are generally entitled to retain the processed NGLs and to sell them for their account. Accordingly, the margin is a function of the frac spread.

LT/d:     Long tons per day.

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

MBoe:    One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil.

MBoe/d:    One thousand barrels of oil equivalent per day.

Mcf:    One thousand cubic feet of natural gas.

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

Mcfe:    One thousand cubic feet of natural gas equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil and NGLs.

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

MMBbls:    One million barrels of crude oil or other liquid hydrocarbons.

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, isobutene, 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.

percent-of-proceeds arrangements:    Under these arrangements, generally raw natural gas is gathered from natural gas producers at the wellhead, transported through the gathering system, processed and sold as processed natural gas and/or NGLs at prices based on published index prices. The price paid to producers is based on an agreed percentage of one of the following: (1) the actual sale proceeds; and (2) the proceeds based on an index price.

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.

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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 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.

Tcf:    One trillion cubic feet of natural gas.

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 reserves per unit of reserves added or transferred from undeveloped acreage non-producing acreage to proved developed producing 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.

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 report, unless the context requires otherwise, references to “Eagle Rock Energy Partners, L.P.,” “Eagle Rock,” the “Partnership,” “we,” “our,” “us,” or like terms, when used in a pre-IPO context (before October 2006), refer to Eagle Rock Pipeline, L.P. and its subsidiaries. When used in a post-IPO context, the present tense or prospectively, those terms refer to Eagle Rock Energy Partners, L.P. and its subsidiaries (after October 2006).   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 Natural Gas Partners, L.L.C. d/b/a 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 “Holdings” or “Eagle Rock Holdings” refer to Eagle Rock Holdings, L.P., the largest holder of our securities (common units and subordinated units), which is owned by the NGP Investors.

PART I

Item 1. Business.

Overview

We are based in the United States and are a domestically-focused, growth-oriented limited partnership engaged in the business of (i) gathering, compressing, treating, processing and transporting natural gas; fractionating and transporting natural gas liquids (“NGLs”); and marketing natural gas, condensate and NGLs, which collectively we call our “Midstream Business”; (ii) acquiring, developing and producing interests in oil and natural gas properties, which we call our “Upstream Business”; and (iii) acquiring and managing fee mineral, overriding royalty and royalty interests, either through direct ownership or through investment in other partnerships, which we call our “Minerals Business”.

Our objective is to generate stable, growing cash distributions for our unitholders. To do so, we focus on achieving operational excellence in our businesses and executing accretive low-risk acquisitions and organic growth opportunities. We are uniquely positioned as a publicly-traded partnership, or master limited partnership (“MLP”), that is engaged in both the midstream and upstream sectors of the oil and natural gas value chain, and one of a small group of MLPs that is engaged in the minerals business.

We have an experienced management team with expertise in gathering and processing natural gas, operating oil and natural gas properties and assets, managing mineral interests, and evaluating and executing acquisition opportunities. Generally, our MLP structure gives us a lower cost of capital than a corporation through the avoidance of double taxation of our earnings. Our diversification across our three businesses was adopted to broaden the spectrum of potential acquisition opportunities, give us an advantage in acquiring asset packages that involve both midstream and upstream assets, provide us with a natural hedge on a portion of our natural gas volumes in our Upstream Business (to the extent of the volumes of natural gas purchased by us under our natural gas purchase agreements in our Midstream Business that is not offset by our long position in our Midstream Business), and exploit vertical integration synergies and market intelligence in selected regions of our operations.

Our Midstream Business is strategically located in five significant natural gas producing regions: (i) the Texas Panhandle; (ii) East Texas/Louisiana; (iii) South Texas; (iv) West Texas; and (v) the Gulf of Mexico. These five regions are productive, mature, natural gas producing basins that have historically experienced significant drilling activity. Eagle Rock’s natural gas gathering systems within these regions represent approximately 5,200 miles of natural gas gathering pipelines with approximately 2,600 well connections, 18 natural gas processing plants with approximately 801 MMcf/d of plant processing capacity and 207,100 horsepower of compression.  Our Midstream Business averaged 450.8 MMcf/d of gathered volumes and 322.1 MMcf/d of processed volumes during 2008.

Our Upstream Business has long-lived, high working interest properties located in four significant natural gas producing regions: (i) Southern Alabama (where we also operate the associated gathering and processing assets); (ii) East Texas; (iii) South Texas; and (iv) West Texas. As of December 31, 2008, these working interest properties included 321 operated productive wells and 142 non-operated wells with net production to us of approximately 5,600 Boe/d and proved reserves of approximately 40 Bcf of natural gas, 7.2 MMBbls of crude oil, and 5.6 MMBbls of natural gas liquids, of which 85% are proved developed producing.

Our Minerals Business is a diversified set of fee mineral, overriding royalty interests and royalty interests comprised of interests in multiple trends over 5.6 million gross mineral acres (430,000 net mineral acres) and interests in over 2,800 productive wells across 17 states in the United States.  As of December 31, 2008, these interests had proved reserves of approximately 4.9 Bcf of natural gas and 2.8 MMBbls of crude oil (100% proved developed producing). These interests produced an average of approximately 1.1 MBoe/d (net to our interest).

1

We report on our businesses in seven accounting segments.   See Note 13 of our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report.

We conduct, evaluate and report on our Midstream Business within four distinct segments—the Texas Panhandle Segment, the East Texas/Louisiana Segment (previously known prior to the filing of our 2007 Annual Report as our Southeast Texas and North Louisiana Segment), the South Texas Segment, and the Gulf of Mexico Segment. These Midstream segments include our gathering, processing and related compression assets grouped geographically by major operating area.  Our South Texas Segment includes our Wild Horse system in West Texas, and our Gulf of Mexico Segment includes interests in gathering systems and related compression and processing facilities in Southern Louisiana, the Gulf of Mexico and Galveston Bay.

We conduct, evaluate and report our Upstream Business as one segment. Our Upstream Segment includes operated wells in Escambia County, Alabama as well as two treating facilities, one natural gas processing plant and related gathering systems that are inextricably intertwined with ownership and operation of the wells. The Upstream Segment also includes operated and non-operated wells that are primarily located in Rains, Van Zandt, Limestone, Freestone, Henderson, Ward, Crane, Pecos and Atascosa Counties, Texas.

We conduct, evaluate, and report our Minerals Business as one segment.  Our Minerals Segment consists of fee mineral, royalty and overriding royalty interests located in multiple producing trends in the United States.  A significant portion of the mineral interests that we own are managed by a non-affiliated private partnership that controls the executive rights associated with the minerals.

Our final reporting segment is our Corporate Segment, in which we account for our commodity hedging activity and our general corporate costs.

Relationship to Natural Gas Partners

We are affiliated with Natural Gas Partners, a leading private equity capital source for the energy industry. Natural Gas Partners owns a significant equity position in Eagle Rock Holdings, L.P., which owns 2,338,419 common units, 20,691,495 subordinated units and all of the equity interests in our general partner (directly and through ownership of all equity interests of our general partner’s general partner), which holds the incentive distribution rights in us. Historically, we have benefited from increased exposure to acquisition opportunities through our affiliation with Natural Gas Partners, including the consummation of several transactions with portfolio companies of Natural Gas Partners (the Midstream Gas Services, Montierra, Redman and Stanolind Acquisitions, as more fully described under “History” below). We expect that our relationship with Natural Gas Partners will continue to provide us with several significant benefits, including increased exposure to acquisition opportunities and access to a significant group of transactional and financial professionals with a successful track record of investing in energy assets. Founded in 1988, Natural Gas Partners represents a $7.2 billion family of investment funds organized to make direct equity investments in private energy enterprises.

Business Strategies

Our primary business objective is to increase our cash distributions per unit over time. We intend to accomplish this objective by continuing to execute the following business strategies:

• Maximizing the profitability of our existing assets. In our Midstream Business, we intend to maximize the profitability of our existing assets by marketing to, and contracting with, new customers to add new volumes of natural gas to our gathering and processing assets under economically favorable terms to us. We also strive to provide superior customer service while undertaking additional initiatives to enhance utilization, minimize excess processing capacity and improve operating margins and efficiencies across our midstream assets. In our Upstream Business, we utilize best practices and technologies to improve the recoveries of oil and natural gas from our existing wellbores, as well as focus on reducing our overall and per unit operating expenses. We manage our assets to maximize the amount of hydrocarbons and valuable by-products we can profitably extract. We pursue these opportunities at a measured pace to attempt to maintain constant or slightly growing production rates and cash flows. The performance measures we use to assess the success of our asset performance and production enhancement activities are internal rate of return and unit operating cost.

• Continuing to reduce our exposure to commodity price risk. We intend to continue to operate our business in a manner that reduces our exposure to commodity price risk in the near term and on an opportunistic basis over the long term. We manage our portfolio of equity volumes from our three lines of business as a single portfolio. As a result, the volumes of natural gas that we purchase in conjunction with our midstream keep-whole arrangements are more than offset by our long natural gas position associated with midstream percent-of-proceeds arrangements and natural gas production from our upstream and mineral assets. We use a variety of hedging instruments to accomplish our risk management objectives, and we have hedged approximately 88% of our expected hedgeable crude, condensate and natural gas liquids (heavier than propane) and 93% of our natural gas and ethane production through 2009 and, as of this filing, approximately 90% of our 2010 expected hedgeable crude, condensate and natural gas liquids (heavier than propane) volumes and 90% of our natural gas and ethane production. Our hedging strategy also includes proactively looking for opportunities to enter into additional hedges, or reset existing hedges to higher price levels, in order to meet our cash flow requirements, stay in compliance with our credit facility covenants and continue to execute on our distribution objectives.  We expect to increase our hedged volumes beyond 2010 on an opportunistic basis.

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• Maintaining a disciplined financial policy. We will continue to pursue a disciplined financial policy by maintaining a prudent capital structure, managing our exposure to interest rate and commodity price risk, and conservatively managing our cash reserves, especially in light of the current state of the financial, credit and equity markets as they now exist and may exist in the future. Maintaining a balanced capital structure may allow us to use our available capital to selectively pursue accretive investments or acquisition opportunities.

• Expanding our operations through organic growth projects. In our Midstream Business, we intend to leverage our existing infrastructure and customer relationships by expanding our existing asset base to meet new or increased demand for midstream services. In our Upstream Business, we intend to continue to identify and execute infill drilling and recompletion opportunities as the primary source of organic growth. We employ sound petroleum engineering practices to identify and quantify these opportunities, and we pursue the opportunities in a manner that reduces risk and cost. We measure the success of these projects by unit development cost and internal rate of return. We currently target an 18% internal rate of return or higher for our Midstream Business’s projects and commercial contracts and a 25% internal rate of return or higher for our Upstream Business’s infill drilling, recompletion and workover activities.

• Pursuing acquisitions. We have grown significantly through third-party acquisitions and drop-down acquisitions from Natural Gas Partners, and we will continue to employ a disciplined acquisition strategy that capitalizes on the operational experience of our management team as well as bringing new expertise to the Partnership. We believe that the extensive experience of our management team in acquiring and operating natural gas gathering and processing assets, oil and natural gas properties and mineral assets will enable us to continue to successfully identify and complete acquisitions that will enhance our profitability and increase our operating capacity. Due to our unique structure and expertise in managing midstream, upstream and mineral assets, we can pursue acquisitions that involve all three types of assets and thereby provide a seller the ability to complete a sale in a single transaction. Currently, given the state of turmoil in the credit and capital markets, we believe that procuring acquisition financing will prove difficult during 2009. However, financing may be available for highly accretive opportunities that arise when distressed companies are forced to sell assets. Strategically, we focus our acquisition efforts on assets which we believe are best-suited to accomplish our objective of delivering stable and growing distributions; specifically, we seek properties with the following characteristics:

  Midstream Business Asset Criteria:

• Serve producing areas with low decline rates—In order to provide a platform for stable and growing distributions, we seek midstream assets that have historically low production decline rates.

• Serve producing areas with high levels of drilling activity—We seek a balance of future development potential and current production rate. The current production rate is important to ensure that the acquisition will be immediately accretive (i.e., provide adequate cash flow so that distributions can be increased if appropriate), but active drilling is necessary to ensure that production declines can be offset by additional well connects or recompletions.

• Attractive contract mix—We generally seek midstream asset acquisitions that have a stable contract mix profile characterized by relatively low commodity price exposure and relatively long contract terms. In particular, we seek to increase our exposure to fixed-fee arrangements, and we look for longer term or life-of-lease contracts.

• Complementary to existing assets—We seek assets that are complementary to our existing asset base and which provide operating cost savings, diversified market outlets and a diversified customer base.

• Operator—We prefer to operate the properties we own. This allows us greater flexibility with respect to future capital investments and allows us to better manage the associated risks.

Upstream and Minerals Segments Asset Criteria:

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• Low decline rates—In order to provide a platform for stable and growing distributions, we seek upstream assets that have low production decline rates.

• Relatively high level of developed reserves—We seek a balance of future development potential and current production rate. The current production rate is important to ensure that the acquisition will be immediately accretive (i.e., provide adequate cash flow so that distributions can be increased if appropriate), but the undeveloped potential is necessary to ensure that production declines can be offset by additional drilling and recompletions.

• Relatively low-risk development— We seek properties that have multiple horizons in the substrata that are capable of producing oil and gas hydrocarbons.  Our goal is to obtain properties where we can drill an oil or natural gas well and encounter multiple productive horizons and, therefore, reduce the risk of drilling an uneconomic well.  We avoid investment opportunities that require significant exploration activities. Although we cannot guarantee future distributions, we have attempted to structure our Partnership to deliver stable distributions to our investors; thus, we do not believe that this objective is compatible with a high level of exploration activity.

• Oil/natural gas balance—We diversify our hydrocarbon mix in order to avoid exposure to excessive price swings in one commodity. Although we use financial hedges to protect the cash flows of our existing production, a significant drop in the price of a commodity could result in a significant reduction in the profitability of drilling activities which are focused on that commodity.

• Attractively priced markets—We seek upstream asset acquisitions predominantly in producing basins where the supply and demand of hydrocarbons in the consuming markets associated with such basin(s) generate a local commodity pricing environment where the basis differential to the major commodity price index is attractive.

• Wellbore diversification—We attempt to avoid situations in which a single negative well event could result in a significant impact to our cash flows.

• Operator—We prefer to operate the properties we own. This allows us greater flexibility with respect to future capital investments and allows us to better manage the associated risks.

 The primary measures we use to assess the success of our acquisition program are sustained accretion and internal rate of return. We currently target a 12% internal rate of return or higher for our acquisitions.

Competitive Strengths

We believe that we are well positioned to execute our business strategies successfully because of the following competitive strengths:

• We have a uniquely diversified business model. The combination of our Midstream, Upstream and Minerals Businesses along the oil and gas value chain provides us with significant benefits. While the Midstream Business provides us with relatively stable, and potentially growing, throughput volumes and cash flows, the performance of gathering and processing assets is tied, among other things, to our gas-producing customers’ drilling plans, well performance and financial situation.  Each of these factors is beyond our control. In contrast, in our Upstream Business we are able to manage our infill drilling plans, recompletion and workover activities to varying degrees with a company-wide view of maximizing and/or stabilizing our overall cash flow. At the same time, our highly diversified Minerals Business provides us with a stable cash flow profile due to the regeneration effect in our mineral reserves (as described in Minerals Business Overview, below) with no associated operating or capital expense requirements. Our Minerals Business is highly diversified across basins and also benefits from the statistical probability of oil and gas producers aggressively pursuing leasehold acreage acquisitions around a particular find or field, as evidenced by recent significant lease bonuses in our Minerals Business related to the Haynesville Shale play in East Texas/North Louisiana.

 An additional benefit to our diversified business model is our ability to bid for acquisition opportunities which include assets or properties in two or more of our segments and potentially in two or more of our businesses. This provides us with a competitive advantage against other potential single-focus bidders, as we are able and willing to assign value and identify potential operational improvements of all the assets included in the package. This was the case in our EAC Acquisition of upstream and midstream assets in South Alabama. We derive significant vertical integration synergies by operating both the midstream and upstream assets in a particular field. Our expertise in both midstream and upstream enables us to better manage our costs, development timing and human resources by allocating our time, resources and capital to the best and highest return projects.

 Finally, by having a diversified business model, we have the ability to capitalize on valuable market intelligence across our segments. For example, significant leasing activity in a particular field in our Minerals Business can provide us the knowledge and lead-time to pursue a commercial agreement (with the particular producer whom we know to be leasing the acreage) in our Midstream Business. Having in-house expertise in both midstream and upstream operations also allows us to better evaluate acquisition opportunities in either segment.  Oil and natural gas reserve analysis is critical for the success of a midstream acquisition, and the understanding of out-take markets and surface midstream operations are equally critical to the success of an upstream transaction.

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• We have a highly flexible, low cost and long term credit facility in place. We currently have a $980 million senior secured revolving credit facility that expires in December 2012, carries an attractive borrowing rate and offers us financial flexibility.  The credit facility accommodates, through the use of a borrowing base for our Upstream Business and traditional cash-flow based covenants for our Midstream and Minerals Businesses, the allocation of indebtedness to either our Upstream Business (to be measured against the borrowing base) or to our Midstream and Minerals Businesses (to be measured against the cash-flow based covenant). We have a well-diversified lender group consisting of 20 international and domestic financial institutions with the highest concentration in any one financial institution being 13.8% of aggregate commitments. We have the ability to upsize total commitments by an additional $20 million, in addition to the $180 million upsizing we executed during 2008. As a result of Lehman Brothers’ bankruptcy filing, the amount of available commitments was reduced by the unfunded portion of Lehman Brothers’ commitment in an amount of approximately $9.1 million.   As of December 31, 2008, we had approximately $171.5 million of available capacity under our credit facility expiring in 2012.  Availability of capital has been reduced due to recent events surrounding the crisis in the sub-prime mortgage market and its impact on lending institutions and debt and equity markets in general. Our current credit availability and our ability to draw from our credit facility may be limited by our financial results during 2009 and beyond if the energy industry endures a prolonged lower commodity price environment. We believe that once commodity prices improve and the equity and debt markets reopen for entities with characteristics similar to ours, we will have access to capital markets to raise additional funds for future acquisitions and organic growth projects.

• We have an experienced, knowledgeable management team with a proven record of performance. Our management team has a proven record of enhancing value through the investment in, and the acquisition, exploitation and integration of, natural gas midstream, upstream and mineral assets. Our senior management team has an average of approximately 20 years of industry-related experience and a substantial economic interest in us through direct ownership of our common units and, in certain cases, indirect ownership through Holdings. Our senior management team’s extensive experience and contacts within the energy industry provide a strong foundation for managing and enhancing our operations, accessing strategic acquisition opportunities and constructing new assets. We have a staff of engineers, commercial, operational and support staff who are experts at drilling and operating oil and gas wells and managing gathering and processing assets.

• We are affiliated with NGP. We expect our relationship with NGP to continue to provide us with several significant benefits, including increased exposure to acquisition opportunities and access to a significant group of transactional and financial professionals with a proven track record of investing in midstream and upstream assets.

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History

Our Partnership, formed in May 2006, is the legal successor to Eagle Rock Pipeline, L.P. (“Eagle Rock Pipeline”) which continues to exist in our organization as a subsidiary as a result of our initial public offering in October 2006.

The following is a detailed chronology of our history of significant transactions, including acquisitions, divestures, organic growth projects and equity financings.

Dry Trail Plant

• On December 5, 2003, Eagle Rock Pipeline commenced operations with the acquisition of the Dry Trail plant carbon dioxide recovery plant from Williams Field Services in the amount of approximately $18.0 million which was financed through equity of $6.0 million and debt of $12.0 million;

• On July 1, 2004, Eagle Rock Pipeline sold the Dry Trail plant to Celero Energy, L.P. for approximately $37.4 million, of which $12.0 million was used to repay the debt incurred to purchase the Dry Trial plant, and resulted in a pre-tax realized gain in the disposition of approximately $19.5 million in 2004;

Entrance into East Texas Segment with Indian Springs Processing Plant and Camp Ruby Gathering System Acquisition (Indian Springs Acquisition)

• On July 1, 2004, Eagle Rock Pipeline acquired a 25% interest in the Indian Springs processing plant and a 20% interest in the Camp Ruby gathering system, for an aggregate purchase price of approximately $20.0 million, financed with proceeds received from the sale of the Dry Trail plant;

Entrance into Texas Panhandle Segment (ONEOK Acquisition)

• On December 1, 2005, Eagle Rock Pipeline acquired ONEOK Texas Field Services, L.P (“Eagle Rock Predecessor”) for approximately $531.1 million, which was financed through an additional equity contribution of $133 million and incurrence of debt of $400 million;

Tyler County Pipeline

• On February 28, 2006, Eagle Rock Pipeline completed the first phase of construction of the 23-mile, 10 inch Tyler County Pipeline in Tyler County, Texas and Polk County, Texas, costing approximately $8 million, financed from operating cash flow, connecting the Indian Springs Plant and a significant producer in Tyler County;

Creation of East Texas/Louisiana Segment with Acquisition of Brookeland gathering system and processing plant, Masters Creek gathering system, and Jasper NGL Pipeline from Duke and Swift (Brookeland Acquisition)

• On March 27, 2006, Eagle Rock Pipeline completed a private placement of 5,455,050 common units for $98.3 million among a group of private investors;

• On March 31, 2006 and April 7, 2006, a wholly-owned subsidiary of Eagle Rock Pipeline acquired certain natural gas gathering and processing assets from Duke Energy Field Services, L.P. and Swift Energy Corporation, consisting of the Brookeland gathering system and processing plant, the Masters Creek gathering system and the Jasper NGL pipeline. This acquisition was financed with approximately $96 million out of the proceeds received from the private equity placement closed on March 27, 2006;

Expansion of Texas Panhandle Segment assets with addition of Roberts County Plant

(Midstream Gas Services Acquisition)

• On June 2, 2006, Eagle Rock Pipeline acquired all of the partnership interests in Midstream Gas Services, L.P., an NGP affiliate, which owned a plant and a small gathering system in Roberts County, Texas, for approximately $25.0 million, consisting of $4.7 million of cash flow from operations and $20.3 million in Eagle Rock Pipeline partnership units;

Creation of Quinduno Pipeline Connecting East and West Panhandle Systems in Texas Panhandle Segment

• On August 1, 2006, Eagle Rock Pipeline completed the construction of the 10-mile, 10-inch Quinduno pipeline, costing approximately $3.1 million, financed from operating cash flow, connecting our East and West Panhandle Systems in the Texas Panhandle Segment;

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Initial Public Offering

• On October 24, 2006, we completed our initial public offering with the issuance of 12,500,000 common units to the public, representing a 29.6% limited partner interest. In connection with that offering, Eagle Rock Holdings, L.P. contributed certain assets and ownership of operating subsidiaries to us and received 3,459,236 common units and 20,691,495 subordinated units;

• On November 21, 2006, 1,463,785 common units held by Eagle Rock Holdings, L.P. and certain private investors were redeemed as part of the exercise of the underwriters’ overallotment option granted in conjunction with our IPO;

Tyler County Pipeline Extension

• On March 31, 2007, we completed the construction of the 13-mile, 10-inch Tyler County Pipeline Extension in Tyler County and Jasper County, Texas, costing approximately $24.2 million, financed with proceeds from a draw on our credit facility, extending the Tyler County Pipeline to our Brookeland Gathering System;

Creation of Minerals Segment (Montierra Acquisition)

• On April 30, 2007, we acquired all outstanding equity of entities owning certain fee minerals, royalties and working interest properties, from Montierra Minerals & Production, L.P., an NGP affiliate, and we acquired certain fee minerals, royalties and working interest properties directly from NGP-VII Income Co-Investment Opportunities, L.P., another NGP affiliate, for an aggregate purchase price of $139.2 million, consisting of 6,458,946 (recorded value of $133.8 million) of our common units and $5.4 million in cash;

East Texas/Louisiana Segment Expansion and Entrance to South Texas Segment (Laser Acquisition)

• On May 3, 2007, we acquired Laser Midstream Energy, LP, including certain of its subsidiaries, for a total purchase price of $142.6 million, consisting of $113.4 million in cash and 1,407,895 (recorded value of $29.2 million) of our common units;

• On May 3, 2007, we completed the private placement of 7,005,495 common units to several institutional purchasers in a private offering resulting in gross proceeds of $127.5 million. The proceeds from this offering were used to fully fund the cash portion of the purchase price of the Laser Acquisition and the Montierra Acquisition and were used for other general company purposes;

Acquisition of Complementary Assets to Minerals Segment (MacLondon Acquisition)

• On June 18, 2007, the Partnership completed the acquisition of certain royalty and mineral assets owned by MacLondon Energy, L.P. for a purchase price of $18.2 million, consisting of 757,065 (recorded value of $18.1 million) of our common units, and cash of $0.1 million;

Construction of Red Deer Processing Plant in East Panhandle System in Texas Panhandle Segment

• On June 21, 2007, the Red Deer processing plant, with a 20 MMcf/d processing capacity, was put into service in Roberts County, Texas in the East Panhandle System in the Texas Panhandle Segment, at a cost of $16.2 million financed with proceeds from a draw on our credit facility;

Entrance into Upstream Segment with Acquisition of oil and gas producing properties in East and South Texas and in Alabama (including certain related natural gas gathering and processing assets) (Escambia and Redman Acquisitions)

• On July 31, 2007, we acquired Escambia Asset Co. LLC and Escambia Operating Co. LLC (collectively “Escambia”) for an aggregate purchase price of approximately $241.8 million, comprised of approximately $224.6 million in cash and 689,857 (recorded value of $17.2 million) in Eagle Rock common units;

• On July 31, 2007, we acquired Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P., each an NGP affiliate, and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P., and NGP affiliate, (collectively, “Redman”) for a combined value of $192.8 million, comprised of 4,426,591 (recorded value of $108.2 million) common units and $84.6 million in cash;

• On July 31, 2007, we completed the private placement of 9,230,770 common units to third-party investors for total cash proceeds of approximately $204 million. The proceeds were used to finance a portion of the cash used in the Escambia and Redman acquisitions, with the other portion being financed from a draw on our credit facility;

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Upstream Segment expansion with Acquisition of oil and gas producing properties in West Texas (Stanolind Acquisition)

• On April 30, 2008, we acquired Stanolind Oil and Gas Corp. (“Stanolind”), an affiliate of NGP, for an aggregate purchase price of approximately $81.9 million of cash;

• In 2008, subsequent to the Stanolind Acquisition, we drilled and completed five wells in the Permian Basis at a cost of $6.5 million financed through cash from operations;

Stinnett-Cargray Consolidation Project

• In July 2008, we complete the shutdown of our Stinnett Plant and began to move the natural gas to our Cargray Plant for processing.  This project cost us $6.1 million financed through cash from operations;

East Texas/ Louisiana Segment and South Texas Segment expansion and entrance into Gulf of Mexico Segment (Millennium Acquisition)

• On October 1, 2008, we acquired Millennium Midstream Partners, L.P. (“MMP”) for an aggregate purchase price of approximately $205.2 million, comprised of approximately $181.0 million in cash and 2,181,818 (recorded value of $24.2 million) common units, subject to customary post-closing purchase price adjustments and general specific indemnity claims rights.  At the closing of this acquisition, 1,818,182 common units and $0.6 million in cash were placed into an escrow account.  Prior to December 31, 2008, we recovered 40,880 common units and $0.3 million in cash from the escrow account.  As of March 6, 2009, we had recovered an additional  65,841 common units and the remaining $0.3 million in cash from the escrow account.

For a further discussion of our acquisitions, see Note 4 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report.

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The following are charts and tables that depict the foregoing history of acquisitions/dispositions and organic growth projects by date, transaction type, cost, financing sources and business:

Table of Acquisitions/Dispositions

Closing Date	Acquisition/Dispositions	Cost ($ in Millions)			Financing Sources ($ in Millions)								Business
					Cash		Debt		Equity to Sellers		Cash from private equity/ PIPEs(4)
12-05-03	Dry Trail Acquisition(1)	$	18.0			—	$	12.0		—	$	6.0	Midstream
7-01-04	Dry Trail Disposition	$	(37.4	)		—		—		—		—	NA
7-01-04	Indian Springs Acquisition(2)	$	20.0		$	20.0		—		—		—	Midstream
12-01-05	ONEOK Acquisition(1)	$	531.1			—	$	400.0		—	$	133.0	Midstream
3-31-06 & 4-07-06	Brookeland Acquisition	$	95.8			—		—		—	$	98.3	Midstream
6-02-06	Midstream Gas Services Acquisition	$	25.0		$	4.7		—	$	20.3		—	Midstream
4-30-07	Montierra Acquisition	$	139.2			—		—	$	133.8	$	5.4	Minerals
5-03-07	Laser Acquisition	$	142.6			—		—	$	29.2	$	113.4	Midstream
6-18-07	MacLondon Acquisition	$	18.2		$	0.1		—	$	18.1		—	Minerals
7-31-07	Escambia Acquisition	$	241.8			—	$	113.0	$	17.2	$	111.6	Upstream
7-31-07	Redman Acquisition	$	192.8			—		—	$	108.2	$	84.6	Upstream
4-30-08	Stanolind Acquisition	$	81.9		$	5.9	$	76.0		—		—	Upstream
10-01-08	Millennium Acquisition(3)	$	205.2		$	3.6	$	176.4	$	24.2		—	Midstream

_____________

(1) Private equity funding provided by Natural Gas Partners.

(2) Cash provided by the disposition of Dry Trail.

(3) Cost excludes 1,818,182 and $0.6 million of cash placed in an escrow account at the closing of the acquisition.

(4) Private Investment in Public Equity (“PIPE”) by institutional investors.

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Eagle Rock Energy’s Acquisition Track Record

Table of Organic Growth Projects

In-Service Date	Organic Growth Project	Cost ($ in Millions)		Business
2-28-06	Tyler County Pipeline	$	8.0	Midstream
8-01-06	Quinduno Pipeline Connecting East to West	$	3.1	Midstream
2006	Various other projects	$	16.0	Midstream
3-31-07	Tyler County Pipeline Extension	$	24.2	Midstream
6-21-07	Red Deer Processing Plant in East Panhandle	$	16.2	Midstream
2007	Various other projects	$	10.1	Midstream
7-1-08	Stinnett-Cargray Consolidation Project	$	6.1	Midstream
2008	Permian drilling projects	$	6.5	Upstream
2008	Various other projects	$	43.2	Midstream and Upstream

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Note:  All of our organic growth projects have been financed either through cash from operations or debt.

The following graph depicts our growth over time in Adjusted EBITDA and quarterly distribution rate per unit, from our initial public offering on October 24, 2006 to December 31, 2008:

Note:Q4 2006 represents a prorated distribution to the common unitholders from the IPO date of October 24, 2006 through December 31, 2006.

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

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 Three Lines of Business and Our Seven Reporting Segments

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. Processing natural gas involves the separation and treating of raw natural gas resulting in a pipeline quality natural gas, primarily methane, and mixed NGLs for sale. 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.

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The following diagram shows the process of gathering, processing, marketing and transporting natural gas and NGLs. Our Midstream Business is in all of the depicted segments other than the wellhead (which is captured in our Upstream Business Segment).

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 transport 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 through-put 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 boosted, 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 typically used to lower the wellhead pressure while maintaining the exit pressure of a gathering system to deliver natural gas into higher pressure downstream pipelines. We own and operate compression on a number of 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, such as water, sulfur compounds, carbon dioxide, or nitrogen. We own and operate natural gas processing and/or treating plants in five 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 Gulf of Mexico Segment we own a 7.74% interest in the Tebone Fractionator, a fractionation facility operated by Enterprise Products Partners L.P. in southern Louisiana, acquired as a part of our recently closed Millennium Acquisition.

Marketing. Natural gas marketing involves the sale of the pipeline-quality 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 perform a limited marketing function for our account and for the accounts of our customers based upon the location of our assets.

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 we acquired in the Millennium Acquisition, we do not own any natural gas transportation assets.

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Natural gas is gathered and processed in the industry pursuant to a variety of arrangements generally categorized (by the nature of the commodity price risk) as fee-based, percent-of-proceeds, fixed recovery and keep-whole, described in greater detail as follows:

• Fee-Based Arrangements. Under these arrangements, we generally 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, generally raw natural gas is gathered from producers at the wellhead, transported through the gathering system, and processed and sold at prices based on published index prices. We pay a portion of the sale price to the producers. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. The price paid to producers is based on an agreed percentage of the products produced multiplied by one of the following: (1) the actual sale price; or (2) the 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. Contracts in which the gatherer/processor share only in specified percentages of the proceeds from the sale of  the natural gas and in which the producer receives 100% of the proceeds from the NGL sales are referred to as a “percent-of-index” arrangements.  Under percent-of-proceeds arrangements, the margin correlates directly with the prices of natural gas and NGLs; under percent-of-liquids arrangements, the margin correlates directly with the prices of NGLs; and under percent-of-index arrangements, the margin correlates directly with the prices of natural gas (although there is often a fee-based component to all of these forms of contracts in addition to the commodity sensitive component).

• Fixed Recovery Arrangements. Under these arrangements, raw natural gas is gathered from producers at the wellhead, transported through our gathering system and processed and sold as processed natural gas and/or NGLs at prices based on published index prices.  The price paid to the producers is based on an agreed to theoretical product recovery factor to be applied against the wellhead production and then a percentage of the theoretical proceeds based on an index or actual sales prices multiplied to the theoretical production. To the extent that the actual recoveries differ from the theoretical product recovery factor, this will affect the margin. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments.

• Keep-Whole Arrangements. Under these arrangements, raw natural gas is processed to extract NGLs, and the processor pays to 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. The processors are generally entitled to retain the processed NGLs and to sell them for their account. Accordingly, the margin is a function of 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 (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 (1) 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, (2) discounts to the applicable natural gas index price under which we may reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer, or (3) fixed cash fees for ancillary services, such as gathering, treating and compressing.

Midstream Business Overview

We own strategically-positioned natural gas gathering and processing assets in five significant natural gas producing regions: the Texas Panhandle, East Texas/Louisiana, West Texas, South Texas and the Gulf of Mexico. Our gathering and processing assets are located in basins that have experienced consistent growth in natural gas land leases, drilling and production. These core basins are known as the Anadarko basin, East Texas basin, Permian and South Texas basin and the Outer Continental Shelf. While the reduction in oil, natural gas and natural gas liquids prices from their historic highs during 2008 to their current levels has resulted in a reduction in current drilling activity behind a number of our gathering systems, particularly in the Texas Panhandle, we continue to believe our strategically-positioned assets will benefit us when the drilling activity resumes in these areas.  Our focus has been on acquiring assets with strong growth prospects located in these areas or other natural gas prone acres and on developing those prospects. The Millennium Acquisition exemplifies this focus. The Millennium Acquisition added assets in the East Texas area, where we already had a presence, and helped us to achieve our additional goal of expanding into new basins, such as the Permian basin and the Gulf of Mexico, where substantial growth opportunities exist.

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Within our geographic areas of operation, we want to be the premier natural gas gatherer and processor. To achieve this end, we have structured the operations and commercial activities of our gathering and processing assets to work closely together to provide better service to our customers.  From an operations perspective, our key strategy is to provide our customers safe and reliable service at reasonable costs and to improve our competitiveness through more efficient operations to assist in securing new customers. In June 2008, we completed the shutdown of our Stinnett Plant and began to move the natural gas to our Cargray Plant for processing, resulting in improved NGL recoveries and reduced operating costs in the Texas Panhandle Segment.   From a commercial perspective, our focus is to assist our customers in maximizing the value of their production by adding additional options and capacity for the movement and marketing of their natural gas and natural gas liquids.  In July 2008, we began refurbishment of the Stinnett cryogenic plant for relocation to the site of our existing lean oil Arrington Plant.  We have not yet moved the refurbished Stinnett cryogenic plant to the Arrington plant site.  In light of the recent commodity price environment and some new developments in drilling plans of some of our significant customers, we intend to redeploy the Stinnett plant to supplement one of our existing systems.   Also in July 2008, we completed the interconnect from our East Texas Panola gathering system into the Markwest Energy Partners system, resulting in improved processing economics for us and our customers.

In October 2008, we completed the new residue gas interconnect from our Cargray Plant into the Northern Natural Pipeline high pressure interstate pipeline, affording us a more reliable delivery point for our residue gas.  The growth prospects in our core areas are driven primarily by strong commodity prices, high rig utilization rates and improvements in technology to produce natural gas from tight sand and shale formations. These require expansions to our systems in order to meet the producers’ needs and are a part of our continuing strategy to be the gatherer and processor of choice.   In December 2008, we completed the expansion of the East Texas Main Line (“ETML”) system, which we acquired as a part of the Millennium Acquisition in October 2008, adding an additional 120 MMcf/d of pipeline capacity.

We gather and process natural gas pursuant to a variety of arrangements generally categorized (by the nature of the commodity price risk) as fee-based, percent-of-proceeds, fixed recovery or keep-whole, as described more fully under “Midstream Industry Overview” above. As of December 31, 2008, the percentage of natural gas throughput volumes under various contractual arrangements were 14.5% fixed recovery, 46.6% fee-based, 30.5% percent-of-proceeds and 8.4% keep-whole. The following is a summary of the contracts that are significant to our operations.

ONEOK Hydrocarbon.

We are a party to a natural gas liquids exchange agreement with ONEOK Hydrocarbon, L.P., dated December 1, 2005. We deliver all of our natural gas liquids extracted at six of our natural gas processing plants in the Texas Panhandle to ONEOK for transportation and fractionation services. We take title to all of these volumes, and they are physically delivered to Conway, Kansas where mid-continent type natural gas liquids pricing is available, with an option to exchange certain volumes at Mont Belvieu, Texas where gulf coast type natural gas liquids pricing is available. The primary contract term expires on June 30, 2010, but an extension to June 30, 2015 may be mutually agreed to by the parties.

Chesapeake Energy Marketing

We are a party to a natural gas purchase agreement with Chesapeake Energy Marketing Inc., dated July 1, 1997, whereby we purchase raw natural gas from a number of wells on acreage dedicated to us located in Moore and Carson Counties, Texas. The natural gas from these wells is delivered into our Stinnett and Cargray gathering and processing systems. The acreage dedication under this contract is for the life of the leases from which the natural gas is produced. We pay Chesapeake an index posted gas price, less a fixed charge and fixed commodity fee and a fixed fuel percentage. Under this contract, there is an annual option to renegotiate the fuel and fees components. The original agreement was between MC Panhandle, Inc. and MidCon Gas Services Corp. and, as a result of ownership changes; the contract is now between Chesapeake and us. The volumes delivered pursuant to this contract accounts for 4.2% of all the volumes gathered by us as of December 31, 2008.  This is our single largest keep-whole arrangement by volume.

Cimarex Energy

We are a party to a natural gas purchase agreement with Prize Operating Company (Cimarex Energy Co.), dated March 28, 1994, whereby we gather and process raw natural gas from a number of wells on acreage dedicated to us located in Roberts and Hemphill Counties, Texas, delivered to our Canadian processing plant. This is a life of lease contract. We receive a percentage of the natural gas liquid value and a percentage of the natural gas residue value for gathering and processing services. The original agreement was between Warren Petroleum Company and Wallace Oil & Gas, Inc. and, as a result of ownership changes, the contract is now between Prize (Cimarex) and us.  The volume delivered pursuant to this contract accounts for 5.6% of all the volumes gathered by us as of December 31, 2008. This producer has added the most volume, year over year, of any producer-customer in our Texas Panhandle Segment.

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Anadarko Petroleum

We are a party to a natural gas purchase agreement with Anadarko E&P Company LP dated September 9, 1993, whereby we gather and process raw natural gas from a number of wells on acreage dedicated to us located in Jasper and Sabine Counties, Texas, delivered to our Brookeland processing plant. This is a life-of-lease contract. We receive a fee for gathering and processing services based upon a percentage of the natural gas liquid value and a percentage of the natural gas residue value. The volume delivered pursuant to this contract accounts for 3.4% of all the volumes gathered by us as of December 31, 2008. The producer has the largest area of mutual interest dedication to us in the East Texas/Louisiana Segment.

Midstream Business Strategies

• Maximizing the profitability of our existing assets. We strive to maximize the profitability of our existing midstream assets through organic growth opportunities, adding new volumes of natural gas, maintaining a low cost operational structure and undertaking additional initiatives to enhance utilization and improve operating efficiencies. We differentiate ourselves by taking the following steps:

• Customer service—We seek to market our midstream services and provide superior customer service to producers in our areas of operation to connect new wells to our gathering and processing systems, increase gathering volumes from existing wells and more fully utilize excess capacity on our systems.

• Asset optimization— We seek to improve the operations of our existing assets by relocating idle processing plants to areas experiencing increased processing demand, reconfiguring compression facilities and improving processing plant efficiencies.

• Low Cost Operations— We focus on controlling costs through competitive sourcing of materials and services, improving  the productivity of the workforce and reducing the uses of natural gas on our systems.

 • Acquiring midstream assets. We continue to seek opportunities to grow our midstream assets and the distributions to our unitholders through the acquisition of midstream properties. We seek assets that are either complementary to our existing assets, located in active drilling basins or complementary to our Upstream or Mineral oil and gas production assets. The primary measures we use to assess the success of our acquisition program are accretion and internal rate of return. We employ an experienced and qualified staff of engineering, commercial, operations, financial and legal experts who can effectively evaluate, negotiate and close these transactions. We focus our acquisition efforts on assets that we believe are best-suited to accomplish our objective of delivering stable and growing distributions; specifically, we seek properties with the following characteristics:

• Serve producing areas with low decline rates—In order to provide a platform for stable and growing distributions, we seek assets that have historically low production decline rates.

• Serve producing areas with relatively high levels of drilling activity—We seek a balance of future development potential and current production rate. The current production rate is important to ensure that the acquisition will be immediately accretive (i.e. provide adequate cash flow so that distributions can be increased immediately), but the active drilling is necessary to ensure that production declines can be offset by additional well connects or recompletions.

• Attractive contract mix– We generally seek midstream asset acquisitions that have a stable contract mix profile as it relates to relatively lower commodity price exposure as well as longer contract terms. We particularly seek to increase our overall fixed fee based business and look for longer term or life-of-lease contracts in potential acquisitions.

• Complementary to existing assets—We seek assets that are complementary to our existing asset base that provide operating cost savings, diversified market outlets and diversified customer base.

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• Operator—We prefer to operate the properties we own. This allows us greater flexibility with respect to future capital investments and allows us to better manage the risks associated with them.

Midstream Business Competitive Strengths

• We have an experienced, knowledgeable management team with a proven record of performance in evaluating, negotiating and closing midstream asset acquisitions.

• We have a staff of engineers, commercial, operational and support staff that are experts in the Midstream business.

• We have highly competitive asset footprints in a number of our midstream operating areas.

As of December 31, 2008, our Midstream Business consists of the following:

	Length (miles)		Compression (Horsepower)		Processing Plant Through-put Volume Capacity (MMcf/d)
Asset
Texas Panhandle Segment		3,743		125,000		157
East Panhandle System		1,100		54,500		96
Canadian cryogenic plant and gathering system		359				25
Arrington refrigerated lean oil plant and gathering system		537				40
Red Deer cryogenic plant(1)(2)	na					24
Roberts County refrigeration plant and gathering system(1)(3)		14				7
System 97 gathering system (4)		77			na
Buffalo Wallow gathering system(4)		113			na
West Panhandle System		2,643		70,500		61
Cargray cryogenic  plant and gathering system(1)		905				30
Gray cryogenic plant and gathering system(1)		615				20
Lefors cryogenic plant and gathering system		663				11
Stinnett gathering system		451			na
Turkey Creek gathering system		9			na
East Texas/Louisiana Segment		1,145		50,500		188
Brookeland cryogenic plant and gathering system		342				100
Indian Springs cryogenic plant (25% non-operated) and Camp Ruby gathering system (20% non-operated)(5)	na					36
Tyler County gathering system		75			na
Panola gathering system(1)		29			na
Quitman gathering system		51			na
Rosewood JT plant and gathering system(1)		36				10
Vixen gathering system (4)		7			na
Belle Bower JT plant and gathering system(1)		68				20
Simsboro gathering system (4)		30			na
Sligo gathering system (4)		10			na
ETML gathering system and JT Plant (4)		221				15
Douglas East gathering system (4)		14			na
BGS gathering system (4)		26			na
Robertson County gathering system (4)		34			na
North JT plant and gathering system		85				5
Central JT plant and gathering system		102				2
New Ulm gathering system		15			na
South Texas Segment		279		15,500		87
Phase 1 gathering system		70			na
Raymondville gathering system(1)		48			na
Raymondville JT plant	na					40
San Ignacio gathering system (4)		6			na
TGP McAllen JT plant and gathering system		13				40
Merit JT plant	na					7
Wildhorse gathering system		126			na
Sweeny gathering system (50% non-operated)		16			na
Gulf of Mexico Segment		40		16,100		369
Yscloskey refrigerated lean oil plant (14.26% non-operated) (6)	na					264
North Terrebonne refrigerated lean oil plant (7.74% non-operated)(6)	na					105
Tebone Fractionator (7.74% non-operated)(7)	na				na
Galveston Bay gathering (100% non-operated)		12			na
CMA Pipeline segments (non-operated)		28			na
TOTAL Midstream Segments		5,207		207,100		801

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______________

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

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

(3) The Roberts County Plant has 21 MMcf/d of capacity but currently only has installed compression to process 7 MMcf/d.

(4) The gathering systems gather natural gas that is dry gas that does not require processing to meet pipeline hydrocarbon dew point quality specifications prior to delivery to the pipeline grid.

(5) Our net plant capacity is based on the recent plant expansion to 145 MMcf/d total capacity.

(6) Our ownership capacity is subject to change each year based upon the percentage that our equity gas and/or natural gas liquids volumes represent in comparison to the total equity gas and/or natural gas liquids volumes processed and/or produced at the plant for the year. The capacity shown is net to our ownership share.

(7) 30,000 Bbl/d capacity and our ownership share is tied to our ownership percentage in the North Terrebonne Plant.

Below is a graph showing processing plant utilization. The graph shows the plant processing capacity by month and includes the Millennium Acquisition and the shutdown and consolidation of the Stinnett Plant into the Cargray Plant.  The volumes shown include only the gas volumes that were gathered and required plant processing in order to meet the interstate or intrastate gas quality specifications (we refer to such natural gas as wet gas) and excludes the gas volumes that were gathered that did not require plant processing prior to delivery to the interstate or intrastate pipeline systems (we refer to such natural gas as dry gas).

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Note.  The significant increase in processing capacity in October is due to the addition of our share of the North Terrebonne Plant and the Yscloskey Plant acquired through the Millennium Acquisition.  Both plants we impacted by hurricanes Ike and Gustav resulting in the North Terrebonne Plant returning to operations in November 2008 and the Yscloskey Plant not restarting until January 2009.

Texas Panhandle Segment

Our Texas Panhandle Segment covers ten counties in Texas and one county in Oklahoma and consists of our East Panhandle System and our West Panhandle System. The facilities are primarily located in Wheeler, Hemphill, Roberts, Moore, Potter, Hutchinson, Carson, Gray and Collingsworth Counties. Through these systems, we offer producers a complete set of midstream wellhead-to-market services, including gathering, compressing, treating, processing and selling of natural gas and fractionating and selling of NGLs. The Texas Panhandle Segment averaged gathered volumes for the fourth quarter of 2008 of approximately 144.2 MMcf/d. As of December 2008, Cimarex Energy and Chesapeake Energy represented 21.0% and 16.0%, respectively, of the total volumes of our Texas Panhandle Segment. The following is a map of our Texas Panhandle Segment.

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Below is a graph showing processing plant utilization for the Texas Panhandle Segment. The volumes include only the wet gas volumes that were gathered and processed prior to delivery to the interstate or intrastate pipeline systems.

Note:  The Stinnett Plant was consolidated into the Cargray Plant in July 2008 resulting in a reduction of 40 MMcf/d of processing capacity for the Texas Panhandle Segment.

Our Texas Panhandle Systems are located in the Texas Railroad Commission (the “TRRC”) District 10, which has experienced significant growth activity since 2002. According to the EIA, total proved natural gas reserves have grown from 5.4 Tcf at year-end 2006 to 6.3 Tcf at year-end 2007 in District 10. This area has experienced significant drilling activity during the last three years; however, with the current price environment we have seen a reduction in drilling activity in the near term.

System Description. The Texas Panhandle Segment consists of:

• approximately 3,743 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with approximately 125,000 horsepower of associated pipeline compression;

• seven active natural gas processing plants with an aggregate capacity of 157 MMcf/d;

• a propane fractionation facility with capacity of 1.0 MBbls/d;

• a condensate collection facility; and

• average gathered volumes of both wet and dry gas of approximately 152.0 MMcf/d for 2008.

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East Panhandle System

The East Panhandle System gathers and processes natural gas produced in the Morrow and Granite Wash reservoirs of the Anadarko basin in Wheeler, Hemphill and Roberts Counties, an area in the eastern portion of the Texas Panhandle.  This area has experienced substantial drilling and reserve growth since 2002; however, with the current price environment, this area has seen a reduction in drilling activity particularly in the Granite Wash play.  We anticipate producers will increase their drilling activity once either an increase in natural gas prices occurs or the cost to drill the wells declines to a point to support the producer’s drilling economics.

The processing plants in our East Panhandle System are reaching full capacity; however, with the current drilling activity, we anticipate that we will have sufficient processing capacity until drilling levels increase. In order to provide additional processing capacity to our East Panhandle System, we initiated a project to refurbish the Stinnett cryogenic processing plant, located in the West Panhandle System, and relocate it to the East Panhandle System to replace the existing Arrington lean oil processing plant, resulting in additional processing capacity and improved processing economics. This project has been temporarily postponed and will be re-evaluated based upon the need for future processing capacity once drilling activity resumes in the East Panhandle area.

System Description. The East Panhandle System consists of the following:

• approximately 1,100 miles of natural gas gathering pipelines, ranging from 4 inches to 12 inches in diameter with approximately 54,500 horsepower of associated pipeline compression;

• four active natural gas processing plants with an aggregate capacity of 96 MMcf/d; and

• average gathered volumes of both wet and dry gas of approximately 107.9 MMcf/d for 2008.

Canadian System: The system consists of 359 miles of natural gas gathering pipelines and two cryogenic natural gas processing plants referred to as the Red Deer Plant and the Canadian Plant. The Red Deer Plant, acquired by us in 2005 as a part of the ONEOK Acquisition, was refurbished and placed back in service in June 2007; capable of processing 25 MMCF/d of natural gas. The Canadian system gathers raw natural gas from producers and delivers the gas to the Canadian Plant, the Red Deer Plant, the Cargray System or the Arrington System.  The Canadian system was acquired through the ONOEK Acquisition in 2005.

Arrington System: The system consists of 537 miles of natural gas gathering pipelines and a refrigerated lean oil natural gas processing plant (Arrington Plant). The system was acquired through the ONOEK acquisition in 2005.

System 97 Gathering System: The System 97 Gathering System consists of 77 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to the interstate pipeline system. This natural gas is dry gas that does not require processing prior to delivery to the pipeline grid.  This gathering system was acquired by us through the ONEOK Acquisition in 2005.

Buffalo Wallow Gathering System: The Buffalo Wallow Gathering System consists of 113 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to the interstate pipeline system. This natural gas is dry gas that does not require processing prior to delivery to the pipeline grid; however, a portion of the natural gas does contain hydrogen sulfide that is removed prior to delivering the gas to the interstate pipeline system.  This gathering system was acquired through the ONEOK Acquisition in 2005.

Natural Gas Supply. As of December 31, 2008, approximately 575 wells and central delivery points were connected to our East Panhandle System. There are approximately 68 producers with the primary producers connected to the East Panhandle System being Bravo Natural Gas, LLC, Prize Operating Company, BP Americas and ChevronTexaco Exploration & Production. The Anadarko basin, from where this natural gas is produced, extends from the western portion of the Texas Panhandle through most of central Oklahoma. The East Panhandle System averaged gathered volumes of approximately 100.7 MMcf/d during the fourth quarter of 2008.

Natural gas from new wells located in the area served by the East Panhandle System generally have an initial annual production decline rate of approximately 75%, but after the first year of production the decline rates decreases to between 35% and 30%.  These decline rates continue to decrease over time, eventually stabilizing at 10% to 15% after several years of production.  Approximately 75% of the natural gas that is gathered on our East Panhandle System is processed to recover the NGL content, which generally ranges from 4.0 to 5.0 gpm. Approximately 25% of the natural gas gathered in the East Panhandle System is not processed but is treated for removal of carbon dioxide and hydrogen sulfide to make the natural gas marketable. This natural gas can be isolated and sent to the treating facilities while the remaining system is used to gather the natural gas into the processing plants.

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On the East Panhandle System, natural gas is contracted for at the wellhead primarily under percent-of proceeds and fee-based arrangements that range from one to five years in term. As of December 31, 2008, approximately 67%, 21%, 6% and 6 % of our total throughput in the East Panhandle System was under percent-of-proceeds, fee-based, fixed recovery and keep-whole arrangements, respectively.

Competition. With the growth in production in the Granite Wash play, a number of midstream companies have built plants in the area; however, our primary competitor in this area is Enbridge, Inc. 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 play. We expanded these systems during 2007 by approximately 24 MMcf/d of processing capacity by refurbishing and restarting the Red Deer cryogenic plant. In 2008, we have approved a project to refurbish the Stinnett Plant and move it to the Arrington Plant site to replace the existing Arrington Plant.  This project is currently on hold due to the current commodity price environment and review of drilling activity by our producer-customers.  In 2008 we added 2,700 hp of additional field compression at a cost of $1.9 MM to provide additional low pressure gathering services.  We continue to review additional projects to remain competitive in connecting new natural gas.

West Panhandle System

The West Panhandle System gathers and processes natural gas produced from the Anadarko basin in Moore, Potter, Hutchinson, Carson, Roberts, Gray, Wheeler and Collingsworth Counties located in the western part of the Texas Panhandle.

System Description. The West Panhandle System consists of:

• approximately 2,643 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with approximately 70,500 horsepower of associated pipeline compression;

• three active natural gas processing plants with an aggregate capacity of 61 MMcf/d;

• a propane fractionation facility with capacity of 1.0 MBbls/d;

• a condensate collection facility; and

• average gathered volumes of wet gas of approximately 44.1 MMcf/d for 2008.

Cargray System: Consists of 905 miles of natural gas gathering pipelines and a cryogenic natural gas processing plant (Cargray Plant). The system includes a propane fractionation facility for producing specification propane for sales into local markets. The system is a vacuum pressure gathering system gathering natural gas from very low volume wells. The Cargray System was acquired through the ONOEK Acquisition in 2005.

Gray System: Consists of 615 miles of natural gas gathering pipelines and a cryogenic natural gas processing plant (Gray Plant). The gathering system is a vacuum pressure gathering system gathering natural gas from very low volume wells. The Gray System was acquired through the ONOEK Acquisition in 2005.

Lefors System: Consists of 663 miles of natural gas gathering pipelines and a cryogenic natural gas processing plant (Lefors Plant). The gathering system is a vacuum pressure gathering system gathering natural gas from very low volume wells. The Lefors System was acquired through the ONOEK Acquisition in 2005.

Stinnett Gathering System:  Consists of 451 miles of natural gas gathering pipelines. The gathering system is a vacuum pressure gathering system gathering natural gas from very low volume wells. In July 2008, the cryogenic plant (Stinnett Plant) that was a part of the Stinnett System was shutdown and we began redirecting the Stinnett System gas to the Cargray System. The Stinnett plant has been refurbished.  We will relocated it to either the Arrington System in the East Panhandle System or to the Brookeland System in East Texas/Louisiana, unless neither system needs the additional capacity and efficiencies based on drilling plans of our producer-customers in those areas, in which case it will be sold. The Stinnett system was acquired through the ONOEK Acquisition in 2005.

Turkey Creek Gathering System: Consists of nine miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to the Cargary Plant. The gathering system is a vacuum pressure gathering system gathering natural gas from very low volume wells.  This gathering system was acquired through the ONEOK Acquisition in 2005.

Super Drip Condensate Collection Facility: The Super Drip condensate collection facility receives condensate collected from various gathering systems where it is then separated from the collected water and treated.  This facility was acquired through the ONEOK Acquisition in 2005.

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Natural Gas Supply. As of December 31, 2008, approximately 1,400 wells and central delivery points were connected to our West Panhandle System. There are approximately 180 producers with the primary producers connected to the West Panhandle System being Chesapeake Energy Marketing, Inc., Excel Production Company, and W.O. Operating Company. The West Panhandle System, from where this natural gas is produced, extends through the western and southern part of the Texas Panhandle. The West Panhandle System averaged throughput of approximately 43.3 MMcf/d during the fourth quarter of 2008.

Natural gas production from wells located within the area served by the West Panhandle System generally are low volume wells being gathered at very low pressure. Natural gas from wells located in the 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. These low volume, high gpm wells are susceptible to interruptions during freezing conditions such as can be experienced during the winter in the Texas Panhandle. Much of the natural gas in the West Panhandle System is high in nitrogen content due to the formation from which it is produced and oxygen content due to the numerous wellhead compressors being operated by the producers and the formation from which it is produced. The interstate pipelines to which the plants are connected have continued to waive their gas quality specifications requiring lower nitrogen and oxygen content in the natural gas delivered to their pipelines. Our current processing plants in the West Panhandle System are not capable of recovering and rejecting the nitrogen or removing the oxygen in the producer’s natural gas to meet the current interstate pipeline specifications. In the event that the interstate pipelines discontinue the waivers, we will be required to modify our plants at a substantial cost to meet the pipeline specifications.

On the West Panhandle System, natural gas is purchased at the wellhead primarily under keep-whole arrangements, fixed recovery and percent-of proceeds arrangements that primarily range from one to five years in term with the keep-whole arrangements being primarily life of lease term. As of December 31, 2008, approximately 44%, 38%, and 18% of our total throughput in the West Panhandle System was under keep-whole, fixed recovery and percent-of-proceeds arrangements, respectively. Our keep-whole arrangements have a significant gathering fee component.

Competition. Our primary competition in this area is Duke Energy Field Services, L.P. The key drivers in this low growth area are to continue to improve operating efficiencies, provide low pressure gathering services and to maintain equipment reliability for improved on line operations.  During July 2008, we completed our project to consolidate our Stinnett system into our Cargray system in order to achieve better overall processing plant utilization and improve our operating efficiencies. In 2008, we also refurbished the Stinnett Plant but have not yet moved it to the Arrington System, and are re-evaluating the move in light of our producer-customers drilling plans.

Texas Panhandle Markets

Our residue gas is marketed primarily to large trading companies who buy the gas at the tailgate of our plants. Our NGLs are marketed primarily to ONEOK Hydrocarbons.  The residue gas and NGL liquids are sold under month to month agreements. In addition, condensate produced on the system is exchanged by Petro Source Partners, LP to Cushing, Oklahoma where we sell it to various parties.  The condensate is sold under contract terms of one year or less.

East Texas/Louisiana Segment

Our East Texas/Louisiana operations are located primarily in Angelina, Nacogdoches, Rusk, Cherokee, Smith, Harris, Waller, Montgomery, Austin, Colorado, Robertson, Grimes, Washington, Polk, Tyler, Jasper, Newton, Upshur, Gregg, Wood and Panola Counties, Texas and Vernon, DeSoto, Lincoln, Jackson, Bienville, Caldwell and Bossier Parishes, Louisiana. Through our East Texas/Louisiana Segment, we offer producers natural gas gathering, treating, processing and transportation and NGL transportation. Our East Texas/Louisiana systems are located in the Texas Railroad Commission (the “TRRC”) District 3, 5 and 6, which has experienced significant growth activity since 2002. According to the EIA, total proved natural gas reserves have grown from 24.7 Tcf at year-end 2006 to 31.4 Tcf at year-end 2007. The following is a map of our East Texas/Louisiana Segment:

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Below is a graph showing processing plant utilization for the East Texas/Louisiana Segment. The volumes include only the wet gas volumes that were gathered and processed prior to delivery to the interstate or intrastate pipeline systems.

Note:  The September drop in volume processed is due to the impact of Hurricanes Ike and Gustav that resulted in the shut-in of production as a safety precaution and the resulting damage to third party NGL infrastructure downstream from our plants.  Volumes exceeding capacity in July and October was the result of prior period adjustments.

Systems Description. The facilities that comprise our East Texas/Louisiana operations, including those acquired through the Millennium Acquisition completed in October, 2008, consist of:

• approximately 1,145 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with approximately 50,500 horsepower of associated pipeline compression;

• a 100 MMcf/d cryogenic processing plant;

• a 145 MMcf/d cryogenic processing plant, in which we own a 25% undivided interest;

• five JT/refrigeration processing plants with an aggregate capacity of 52 MMcf/d; 

• a 19-mile NGL pipeline; and

• average gathered volumes of both wet and dry gas of approximately 198.4MMcf/d for 2008†

† Includes three months of production, the period of operation from October 2, 2008 through December 31, 2008 (the “Millennium Covered Period”) associated with the assets acquired in the Millennium Acquisition, averaged over twelve months.

Brookeland System: Consists of 342 miles of natural gas gathering pipelines and a cryogenic natural gas processing plant (Brookeland Plant). This system was acquired through the Brookeland Acquisition in 2006.

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Camp Ruby Gathering System: The system gathers raw natural gas from producers and delivers the gas to the Indian Springs Plant. We have a 20% non-operated ownership position in the gathering system.  This system was acquired through the Indian Springs Acquisition in 2004.

Indian Springs Plant: The Indian Springs plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Camp Ruby and Tyler County gathering systems.  We have a 25% non-operated ownership position in the plant. The plant is operated by Enterprise Products Partners, LP.  This system was acquired through the Indian Springs Acquisition in 2004.

Tyler County Gathering System: Tyler County Gathering System consists of 75 miles of natural gas gathering pipelines ranging in size from two inches to 10 inches in diameter. The system gathers raw natural gas from producers and delivers the gas to the Brookeland Plant and to the Indian Springs Plant.  We completed construction on this system in 2007.

Panola Gathering System: This system consists of 29 miles of natural gas gathering pipelines. In July 2008, the Panola JT plant that was a part of the system was shutdown and a connection to Markwest Energy Partners, LP was made to deliver the natural gas for processing prior to delivery to the interstate pipeline grid. This system was acquired through the Laser Acquisition in 2007.

Rosewood System: This system consists of 36 miles of natural gas gathering pipelines and a refrigeration natural gas processing plant that processes the raw natural gas to meet the minimum interstate pipeline gas quality specifications. The system gathers raw natural gas from producers and delivers the gas to the Rosewood refrigeration plant. This system was acquired through the Laser Acquisition in 2007.

Belle Bower System: This system consists of 68 miles of natural gas gathering pipelines and a JT natural gas processing plant (Belle Bower JT Plant) that processes the raw natural gas to meet the minimum interstate pipeline gas quality specifications. This system was acquired through the Laser Acquisition in 2007.

Vixen Gathering System: The Vixen Gathering System consists of seven miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid. This system was acquired through the Laser Acquisition in 2007.

Sligo Gathering System: The Sligo Gathering System consists of ten miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.  This system was acquired through the Laser Acquisition in 2007.

Simsboro Gathering System: The Simsboro Gathering System consists of 30 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid. This system was acquired through the Laser Acquisition in 2007.

Quitman Gathering System: The Quitman Gathering System consists of 51 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.  This system was acquired through the Laser Acquisition in 2007.

ETML Gathering System: The ETML Gathering System consists of 221 miles of natural gas gathering pipelines and a 15 MMcf/d refrigeration plant that processes a small portion of wet gas prior to delivery to the ETML Gathering System. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid. This gathering system was acquired through the Millennium Acquisition in 2008.

Douglas East Gathering System: The Douglas East Gathering System consists of 14 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.  This gathering system was acquired through the Millennium Acquisition in 2008.

BGS Gathering System: The BGS Gathering System consists of 26 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.  This gathering system was acquired through the Millennium Acquisition in 2008.

Robertson County Gathering System: The Robertson County Gathering System consists of 34 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is delivered to third parties for further treating and processing.  This gathering system was acquired though the Millennium Acquisition in 2008.

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North Gathering System: The North Gathering System consists of 85 miles of natural gas gathering pipelines and a 5 MMcf/d JT plant that processes a small portion of wet gas prior to delivery to the North Gathering System. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.  Sections of the system are subject to FERC 311 jurisdiction. There are a number of city gate deliveries from this system.  This gathering system was acquired through the Millennium Acquisition in 2008.

Central Gathering System: The Central Gathering System consists of 102 miles of natural gas gathering pipelines and a 2 MMcf/d refrigeration plant that processes a small portion of wet gas prior to delivery to the Central Gathering System. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid. Sections of the system are subject to FERC 311 jurisdiction. There are a number of city gate deliveries from this system.  This gathering system was acquired through the Millennium Acquisition in 2008.

New Ulm Gathering System: The New Ulm Gathering System consists of 15 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is delivered to a third party for processing.  This gathering system was acquired through the Millennium Acquisition in 2008.

Natural Gas Supply. As of December 31, 2008, approximately 510 wells and central delivery points were connected to our systems in the East Texas and Louisiana regions. Our East Texas and Louisiana operations are located in an area experiencing an increase in drilling activity and production. Our Tyler County and Brookeland Systems are situated in an active Austin Chalk drilling play in Polk, Tyler and Jasper Counties, Texas. Our ETML system is situated in an active drilling area called the Angelina River Trend complex that has active development in the James Lime and Travis Peak formations of Angelina and Nacogdoches Counties, Texas.   Recently there has been active Haynesville Shale drilling nearby to our Belle Bower System and we anticipate gathering some of this gas in the future.    The East Texas/Louisiana segment averaged gathered volumes of approximately 275.6 MMcf/d during the fourth quarter of 2008. As of December 2008, Ergon Exploration Inc. Goodrich Petroleum Corporation,  Encana Oil & Gas Inc., and Anadarko Petroleum, represented 12.3% 12.1% , 11.2 and 7.6%%, respectively, of the total volumes of our East Texas/Louisiana Segment.

The natural gas supplied to us under our East Texas/Louisiana Systems is generally dedicated to us under individually negotiated long-term and life-of-lease contracts. Contracts associated with this production are generally percent-of-proceeds, which includes percent-of-liquids and percent-of-index, fixed recovery, well head purchases or fee-based arrangements.  As of December 31, 2008, the percentage of natural gas under the contract structures were 23.4% fixed recovery, 48.7% fee-based, 19.6% percent of proceeds and 8.3% purchased at the wellhead.

Markets. Residue gas remaining after processing or gathering is primarily taken-in-kind by the producer customers into the markets available at the tailgates of the plants or pipeline interconnects.  Some of the available markets are 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 with Duke Energy Field Services, L.P. representing the largest purchaser.

Competition. Our primary competition in this area includes Anadarko Petroleum, Crosstex Energy, L.P., Duke Energy Field Services L.P., Energy Transfer Partners, LP and Enterprise Products Partners, L.P. The key drivers are high run-time rates of the assets, connections to premium markets and low pressure gathering services. In December 2008, we completed the expansion of the ETML System to increase the pipeline capacity by an additional 120 MMcf/d.  During 2008 we continued to expand the Brookeland Gathering System and Tyler County gathering system to gather the expanding Austin Chalk Drilling activity by 12.7 miles of 4 inch to 10 inch pipeline at a cost of $5.4 million.

South Texas Segment

As a result of the Millennium Acquisition on October 1, 2008, we expanded the footprint of our South Texas segment.  Our South Texas operations are primarily located in Hidalgo, Willacy, Brooks, Zapata, Starr, Cameron, Colorado, Fort Bend, McMullen, Crockett, and San Patricio Counties. The South Texas Segment systems primarily gather natural gas and recovers NGLs and condensate from natural gas produced in the Frio, Vicksburg, Miocene, Canyon Sands and Wilcox formations in Hidalgo, Willacy, Brooks, Zapata, Starr, Cameron, Crockett and Colorado Counties in South Texas and in the Permian Basin. The South Texas Segment also provides producer services by purchasing natural gas at the wellhead for sale into third-party pipeline systems.  Our South Texas systems are located in the Texas Railroad Commission (the “TRRC”) District 4 and 8, which has experienced significant growth activity since 2002. According to the EIA, total proved natural gas reserves have grown from 14.2 TCF at year-end 2006 to 14.5 TCF at year-end 2007.  The following is a map of our South Texas Segment.

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Below is a graph showing processing plant utilization for the South Texas Segment. The volumes include only the wet gas volumes that were gathered and processed prior to delivery to the interstate or intrastate pipeline systems.

System Description. The South Texas Segment consists of:

• approximately 279 miles of natural gas pipeline ranging in size from two inches to 20 inches in diameter;

• compressor stations with approximately 15,500 aggregate horsepower;

• three processing stations consisting of 11 active skids and related facilities for an aggregate capacity of 87 MMcf/d;

• utilization of our pipelines and third-party pipelines for the purchase and sale of wellhead natural gas (“Producer Services”); and

• average gathered volumes of both wet and dry gas of approximately 88.5 MMcf/d for 2008.†

† Includes three months of production (during the Millennium Covered Period) associated with the assets acquired in the Millennium Midstream Acquisition averaged over twelve months.

Phase 1 Gathering System: The Phase 1 Gathering System consists of 70 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to multiple market outlets.  This gathering system was acquired through the Laser Acquisition in 2007.

Raymondville System: The Raymondville System consists of 48 miles of natural gas gathering pipelines and a JT natural gas processing plant (Raymondville JT Plant).  A JT plant typically recovers less NGL production than a cryogenic plant. The system gathers both raw and treated natural gas from producers and delivers the gas to multiple market outlets. This system was acquired through the Laser Acquisition in 2007.

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San Ignacio Gathering System: The San Ignacio Gathering System consists of six miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to Tennessee Gas Pipeline. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.  This gathering system was acquired through the Laser Acquisition in 2007.

TGP McAllen Gathering System: The TGP McAllen Gathering System consists of 13 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to Tennessee Gas Pipeline. The raw natural gas is of such quality that it does not require processing prior to delivery to the pipeline grid.  This gathering system was acquired through the Laser Acquisition in 2007.

Merit JT Plant: The Merit JT plant is a JT natural gas processing plant that processes raw natural gas to meet the minimum interstate pipeline gas quality specifications. A JT plant typically recovers less NGL production than a cryogenic plant. The gas from the plant is delivered to the Tennessee Gas Pipeline. This plant was acquired through the Laser Acquisition in 2007.

Wildhorse Gathering System: The Wildhorse Gathering System consists of 126 miles of natural gas gathering pipelines located in Crockett County, Texas, in the prolific Permian Basin. The system gathers raw natural gas from producers and delivers the gas to a third party plant for processing.  This gathering system was acquired through the Millennium Acquisition in 2008.

Sweeny Gathering System: The Sweeny Gathering System consists of 16 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to a third party plant for processing.  We own a 50% non-operated ownership in the system. We acquired our 50% non-operated ownership in this gathering system through the Millennium Acquisition in 2008.

Producer Services:  This is a low-margin business where we negotiate new well connections on behalf of small producers, to pipelines other than our own. We receive a fee for this service of between one to four cents per MMbtu of the gas volumes delivered to the pipelines. In some instances we buy the gas from the producers and net out the fee while in other instances we receive only the fee.  The contracts for this service are typically for a term of one year or less.  We acquired this business through the Laser Acquisition in 2007.

Natural Gas Supply. As of December 31, 2008, the South Texas Segment provides gathering and/or marketing services to approximately 180 producers. The South Texas Segment operates approximately 94 meter stations for receipt or delivery of producer gas. The primary producers on the South Texas Segment systems are Chesapeake Energy Corporation (“Chesapeake Energy”), XTO Energy Inc. (“XTO”) and FIML Natural Resources LLC (“FIML”).  The three largest producers in the South Texas Segment’s producer services business are Century Exploration Company, Kebo Oil & Gas Inc., and Rincon Petroleum Corporation. Natural gas production from wells located in the area served by the South Texas Segment’s systems generally have steep rates of decline during the first few years of production, therefore throughput must be maintained by the addition of new wells. The South Texas Segment averaged gathered volumes of approximately 111.1 MMcf/d during the fourth quarter of 2008. As of December 2008, Chesapeake Energy, XTO, FIML and Cody Energy represented 38.8%, 10.0%, 7.9%, and 7.4%, respectively, of the total volumes of our South Texas Segment.

On the South Texas Segment’s systems, natural gas is transported, compressed, dehydrated, and/or processed under fee based arrangements. The 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. Our South Texas Segment’s producer services business either acts as an agent for producers or purchases natural gas at the wellhead for sale into interstate or intrastate pipelines on a percentage netback or fee basis with the producers.

Markets. The majority of natural gas deliveries from the South Texas systems go to Tennessee Gas Pipeline Company or Enterprise Texas Pipeline. The natural gas is sold primarily at the delivery points into the interstate or intrastate pipeline systems to various customers. Our South Texas Segment’s producer services three largest markets were Cypress Pipeline Company, Houston Pipeline Company, and Total Gas & Power North America Company.

Competition. Our primary competition in our South Texas Segment is Duke Energy Field Services, L.P. and Enterprise Products Partners, L.P. The key drivers in this area are low pressure gathering and multiple market outlets for the 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 interstate pipelines in the 1000 psig range; 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. Many of the interstate pipelines in our area are constrained from time to time. Offering multiple market outlets is important to our customers to insure that they can produce their natural gas. Our South Texas Segment’s producer services business competes against various natural gas marketing companies for the purchase of wellhead production. We focus on working with the small independent producers that are in need of someone to help them evaluate their various pipeline options and then to handle the contracting services or buy the natural gas from them. By focusing on the smaller producers, we are able to establish the personal relationships necessary to maintain this business. A customer service focus is critical for our producer services business.

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Gulf of Mexico Segment

As a result of the Millennium Acquisition, which closed October 1, 2008, we expanded the footprint of our Midstream Business into the Gulf of Mexico. Our Gulf of Mexico Segment’s operations are non-operated ownership interests in a number of pipelines and onshore plants which are all located in southern Louisiana. The Gulf of Mexico Segment’s systems primarily process natural gas from the Transco, Gulf South and Tennessee interstate pipelines and recovers NGLs and condensate from natural gas produced in the Outer Continental Shelf of the Gulf of Mexico.  The Gulf of Mexico Segment’s operations also provides producer services by arranging for the processing of producer’s natural gas into third-party processing plants, which we describe as our Mezzanine Processing Services in the Gulf of Mexico Segment.  Our Gulf of Mexico Segment’s systems have experienced decreased activity since 2002. According to the EIA, total proved natural gas reserves have decreased from 11.8 TCF at year-end 2006 to 11.1 TCF at year-end 2007.  The following is a map of our Gulf of Mexico Segment.

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Below is a graph showing processing plant utilization for the Gulf of Mexico Segment.  The volumes include only the wet gas volumes that were gathered and processed prior to delivery to the interstate or intrastate pipeline systems.

Note.  The Gulf of Mexico Segment processing utilization was impacted by Hurricanes Ike and Gustav.  The North Terrebonne Plant returned to limited operations in November 2008 and the Yscloskey plant did not restart until January 2009.

Systems Description. The facilities that comprise our Gulf of Mexico Segment, acquired through the Millennium Acquisition which closed October 1, 2008, consist of:

• approximately 40 miles of natural gas gathering pipelines located in the Gulf of Mexico or Galveston Bay, ranging from four inches to 20 inches in diameter. The pipelines are operated by others.

• a 1.85 Bcf/d cryogenic processing plant in which we own a 14.26% interest;

• a 1.35 Bcf/d cryogenic processing plant, in which we own a 7.74% interest;

• a 30 MBbl/d NGL fractionator in which we own a 7.74% interest; and

• average processed volumes of both wet and dry gas of approximately 12.0 MMcf/d for 2008.†

† Includes three months of production (during the Millennium Covered Period) associated with the assets acquired in the Millennium Acquisition averaged over twelve months.

CMA Pipelines: The CMA Pipelines consist of various interests in 28 miles of offshore natural gas and condensate gathering pipeline segments in the Gulf of Mexico acquired from Trunkline Pipeline Company. The pipeline segments gather raw natural gas and condensate generally from a single offshore platform and deliver the gas to various pipeline interconnects with Trunkline Pipeline Company. The CMA Pipelines are operated by Trunkline Pipelines Company and Enterprise Products Partners, LP.  The CMA Pipelines were acquired through the Millennium Acquisition in 2008.

Yscloskey Plant: TheYscloskey Plant is a refrigerated lean oil natural gas processing plant located in Saint Bernard Parish, Louisiana that processes raw natural gas transported on the Tennessee Pipeline. This plant was acquired through the Millennium Acquisition in 2008.  We have a 14.26% non-operated ownership interest in the plant.   Targa Resources Inc. operates the plant.

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North Terrebonne Plant: The North Terrebonne plant is a refrigerated lean oil natural gas processing plant located in Terrebonne Parish, Louisiana that processes raw natural gas transported on the Transco Pipeline and the Gulf South Pipeline. This plant was acquired through the Millennium Acquisition in 2008.  We have a 7.74% non-operated ownership interest in the plant.   Enterprise Products Partners, LP operates the plant.

Tebone Fractionator: The Tebone Fractionator is a NGL fractionation plant located in Terrebonne Parish, LA that separates a y-grade NGL stream into its specification products of ethane, propane, isobutane, normal butane and natural gasoline which are then sold to various markets.  The Tebone Fractionator substantially fractionates the y-grade NGL stream produced from the North Terrebonne Plant.  We have a 7.74% non-operated ownership interest in the fractionator which was acquired through the Millennium Acquisition in 2008.   Enterprise Products Partners, LP operates the Tebone Fractionator.

Galveston Bay Gathering System: The Galveston Bay gathering system consists of 12 miles of natural gas, water and condensate gathering pipeline segments located in Galveston Bay, Texas. The pipeline segments gather a water and condensate mixture from a single platform located in state waters and deliver the natural gas to a downstream pipeline for further transportation and the water and condensate mixture to an onshore separation facility owned by others.  We have a 100% non-operated ownership interest in the Galveston Bay Gathering system, but we are subject to a reduction of our ownership to 50% once certain investment criteria are met.  This system is operated by Layton Energy, the producer on the system.  This system was acquired through the Millennium Acquisition in 2008.

Mezzanine Processing Services:  Our Mezzanine Processing Services arranges for the processing of producers’ natural gas into third-party processing plants.  This is accomplished by us entering into contracts with various processing plants in south Louisiana in which we have no ownership position and then contracting with various producers to have their gas processed in these plants.  Producers enter into these arrangements with us as we provide the management of the processing of their natural gas for them. Typically, these are smaller producers without staffing to handle the management of the processing themselves.  The fee we receive for these services is typically a percentage of the NGLs recovered from their natural gas.  We have no keep-whole exposure under our contracts with the producers.

Natural Gas Supply. The supply of natural gas is highly dependent upon the drilling activity that occurs on the offshore to feed the offshore pipelines in which we have no ownership or control.  These offshore pipelines deliver natural gas to plants that we have an ownership or a contract with to process natural gas.  As of December 31, 2008, the Gulf of Mexico Segment provides processing services to approximately 13 producers. Our processing contracts with the producers are specific to their ownership interests in certain blocks located in the Gulf of Mexico or state waters. The producers have entered into rights agreements with us whereby they have dedicated those interests to us under a life-of-lease term.  We, in turn, enter into processing agreements with the producers whereby we receive a portion of the NGLs as a fee for the services we provide. We have no keep-whole exposure under our direct processing agreements with the producers.  In addition to the natural gas which we have under direct contract, we also receive an economic benefit from stranger’s gas as an owner in the Yscloskey and North Terrebonne Plants.  Stranger’s gas is the natural gas that a plant contracts for the benefit of all the plant owners.  This may be contracted for directly with various producers or with the pipeline delivering gas to the plant.  The primary producers in our Gulf of Mexico Segment systems in which we have an ownership share in Yscloskey and North Terrebonne are Stone Energy Corporation, McMoRan Exploration Company and ExxonMobil Corporation.

The Yscloskey and North Terrebonne Plants suffered significant damage from hurricanes Gustav and Ike, respectively.  The damage resulted in significant downtime for both facilities.  North Terrebonne Plant restarted operations in November 2008 and the Yscloskey Plant restarted operations in January 2009.  The cost to repair the facilities and the cost of business interruption will be covered by either insurance proceeds or by the sellers under the Millennium Acquisition purchase and sale agreement.  In addition to damage to the facilities, the third-party pipelines delivering gas to the plants and the producer platforms suffered damage that has resulted in reduced volumes for processing.  We anticipate that following the repair of the pipelines and platforms that the volumes that we have under contract will return to pre-hurricane levels.  The hurricanes also had impacts to our Mezzanine Processing Services due to the shut-in of production in the Gulf of Mexico and the impact on third-party plants.  Our Mezzanine Processing Services have returned to near pre-hurricane levels.

Tennessee Gas Pipeline has acquired the Bluewater lateral from Columbia Gulf Pipeline and is in the process of redirecting the gas toward the Yscloskey Plant.  The impact of this will be to increase the natural gas we have under contract for processing at the Yscloskey Plant while reducing the volume of gas in our Mezzanine Processing Business.  This is due to shifting gas under contract in the Mezzanine Processing Services to the Yscloskey Plant.  The result will be increased margin for us due to reduced costs for processing the gas.

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Our three largest producers in the Mezzanine Processing Services business are Stone Energy Corporation, Apex Oil & Gas, Inc. and Dynamic Offshore Resources LLC.

Natural gas production from wells located in the area served by the Gulf of Mexico Segment generally have steep rates of decline during the first few years of production, therefore throughput must be maintained by the addition of new wells. The Gulf of Mexico Segment averaged processed volumes of approximately 47.8 MMcf/d during the fourth quarter of 2008. As of December 2008, Stone Energy Corporation represented 90% of the total volumes of our Gulf of Mexico Segment.  Other major producers under contract had their volumes of gas shut-in during the fourth quarter due to the impact of hurricanes Ike and Gustav. With the Yscloskey Plant back in operation in January 2009, we anticipate the producer volumes returning.  On the Gulf of Mexico Segment’s gathering systems, natural gas and condensate is transported under fee based arrangements. We do not purchase any natural gas or condensate from producers for purposes of reselling in the Gulf of Mexico Segment’s systems.

Markets. The majority of natural gas liquids produced from the Gulf of Mexico Segment’s systems are transported by pipelines for fractionation at the Norco, Toca and Tebone fractionators.  Once fractionated, the specification products are sold to Enterprise Products Partners L.P. under a year-to-year contract.

Competition. Our competition in the Gulf of Mexico at the Yscloskey Plant and 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.  The owners most active in contracting directly for new supplies of natural gas are Enterprise Products Partners, L.P., as the operator of the North Terrebonne Plant, Targa Resources, Inc., as the operator of the Yscloskey Plant,  and DCP Midstream, L.P.  In our Mezzanine Processing Services, the primary competition comes from  the plant operators at the various third party plants in which we have contracts and from Louis Dreyfus Energy Services, L.P. who provides a similar service as to ours.

Upstream Business

Upstream Business Overview

Our Upstream Business has long-lived, high working interest properties located primarily in Southern Alabama (where we also operate the associated gathering and processing assets), East Texas, South Texas and West Texas regions. As of December 31, 2008, these working interest properties included 321 operated productive wells and 142 non-operated wells with net production of approximately 5,600 Boe/d and proved reserves of approximately 40 Bcf of natural gas, 7.2 MMBbls of crude oil, and 5.6 MMBbls of natural gas liquids, of which 85% are proved developed producing. The reserve life index is approximately 11 years.

We entered the Upstream Business in August 2007 through the Redman and EAC acquisitions that included operated properties in East Texas, South Texas, Mississippi and Alabama, as well as non-operated properties in East Texas and Louisiana.    In April 2008 we closed on the Stanolind Acquisition, which provided our entry to the prolific Permian Basin of West Texas.   Each of these acquisitions are consistent with our focus to acquire assets with a relatively high percentage of proved developed producing reserves, characterized by low production decline rates, and located in areas providing low risk infill drilling and recompletion opportunities.  We pursue operated assets with generally high working interests to better control the development of our reserves and maximize the efficiency of our cost structure.  The average working interest of our producing operated properties is 92%.   Our properties are diversified in multiple fields and producing basins.  Our largest fields, comprising 75% of net production, are the Big Escambia Creek field in Escambia County, Alabama, the Jourdanton field in Atascosa County, Texas, the Ward Estes field in Ward County, Texas, the Ginger/Ginger S.E. fields in Rains County, Texas and the Flomaton and Fanny Church fields in Escambia County, Alabama.  The remaining 25% of our fields are located in East Texas, West Texas and Mississippi.

The production in our East Texas and Alabama fields is predominantly from the Smackover formation which contains significant percentages of hydrogen sulfide and carbon dioxide which must be extracted prior to sales.  The Alabama assets include two operated treating plants to facilitate the extraction of these contaminants and elemental sulfur, and one operated processing plant to process and sell natural gas liquids. The Alabama field assets also include gathering pipelines, saltwater disposal wells and other equipment to conduct efficient operations.  The production from our East Texas assets is treated and processed by Regency Field Services at their Eustace Plant.  Regency provides gathering, compression, and treating to extract hydrogen sulfide and carbon dioxide prior to residue gas sales.   In addition, the gas stream is processed to extract natural gas liquids for sales, and elemental sulfur is recovered for sales at Regency’s Eustace Plant.   The Jourdanton field in Atascosa County, Texas produces from the Edwards formation and contains a significantly lower percentage of hydrogen sulfide (2%) and is treated at Regency Field Services Tilden Plant.

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The Permian assets acquired in the Stanolind acquisition are characterized by long life oil and gas reserves produced from multiple pay horizons with low decline rates.  Production from these assets averaged 858 Boe/d in 2008, significantly above the initial rate of 760 Boe/d at the close of the acquisition.  Since May 2008, we have drilled and completed five wells on these Permian assets with a success rate of 100%.   The growth prospects in our core areas are driven primarily by infill drilling, low risk recompletions and workovers of existing formations or shut-in wells located on our properties.

Upstream Business Strategies

• Enhancing the production and profitability of our existing assets—We endeavor to manage our assets in a manner to maximize the amount of hydrocarbons we can profitably extract. We accomplish this by employing sound petroleum engineering practices to identify opportunities to improve production rates and recoveries and to reduce our operating costs. Examples of these types of opportunities are the installation of additional surface compression, recompletions, well workovers and stimulations, and the installation of artificial lift and other production equipment modifications. We pursue these opportunities at a measured pace to attempt to maintain constant or slightly growing production rates and cash flows. The performance measures we use to assess the success of our production enhancement activities are accretion, internal rate of return, and unit development and operating cost.

• Pursuing organic growth opportunities—In our Upstream Business, drilling our proved undeveloped and probable locations are the sources of organic growth. We employ sound petroleum engineering and geological practices to identify and quantify these opportunities, and we pursue them in a manner that seeks to reduce risk and cost.   We have identified numerous proved undeveloped and probable locations on our existing assets and we prudently drill these locations to add reserves and production to maintain our growth production.    We measure the success of these projects by their accretion, internal rate of return, and unit development cost.

• Acquiring oil and natural gas assets—Our goal is to grow our assets and the distributions to our unitholders, in part, through the acquisition of oil and gas properties. We employ an experienced and qualified staff of engineers, geoscientists, and financial and legal experts who can effectively evaluate, negotiate and close these transactions. We focus our acquisition efforts on properties that we believe are best-suited to accomplish our objective of delivering stable and growing distributions; specifically, we seek properties with the following characteristics:

• Low decline rates—In order to provide a platform for stable and growing distributions, we seek assets that have historically low production decline rates.

• Relatively high level of developed reserves—We seek a balance of future development potential and current production rate. The current production rate is important to ensure that the acquisition will be immediately accretive (i.e., provide adequate cash flow so that distributions can be increased immediately), but the undeveloped potential is necessary to ensure that production declines can be offset by additional drilling and recompletions.

• Relatively low-risk development—We seek properties that have multiple horizons in the substrata that are capable of producing oil and gas hydrocarbons.    Our goal is to obtain properties where we can drill an oil or gas well and encounter multiple productive horizons and therefore reduce the risk of drilling an uneconomic well.   We avoid investment opportunities that require significant exploration activities. Although we cannot guarantee future distributions, we have attempted to structure our Partnership to deliver stable distributions to our investors; we do not believe that this objective is compatible with a high level of exploration activity.

• Oil/natural gas balance—We diversify our hydrocarbon mix in order to avoid exposure to excessive price swings in one commodity. Although we use commodity hedges to protect the cash flows of our existing production, a significant drop in the price of a commodity could result in a significant reduction in the profitability of drilling activities that are focused on that commodity.

• Attractively priced markets—We seek to make acquisitions in our Upstream Business predominantly in producing basins where the supply and demand of hydrocarbons in the consuming markets associated with such basin(s) generate a local commodity pricing environment where the basis differential to the major commodity price index is attractive.

• Wellbore diversification—We attempt to avoid situations in which a single well negative event could result in a significant impact to our cash flows.

• Operator—We prefer to operate the properties we own. This allows us greater flexibility with respect to future capital investments and allows us to better manage the associated risks.

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The primary measures we use to assess the success of our acquisition program are sustained accretion and internal rate of return.

Upstream Business Competitive Strengths

• We have an experienced knowledgeable management team with a proven record of performance in evaluating, negotiating and closing upstream oil and gas transactions.

• We have a staff of engineers and support staff who are highly proficient at drilling and operating oil and gas wells in the areas in which we operate production.

• We derive market intelligence from our Midstream and Minerals Businesses that improve our ability to acquire Upstream assets that meet our investment criteria.

Upstream Significant Properties

Our Upstream business consists of operated and non-operated working interests located in Alabama, Texas, Louisiana and Mississippi. The following table summarizes our holdings as of December 31, 2008.

Field	Location	Average net daily production rate in December 2008						Gross producing wells in December 2008
		Oil, Bbl/d		Natural gas, Mcf/d		Natural gas liquids, Bbl/d		Operated		Non- Operated
Big Escambia Creek	Escambia County, Alabama		1,186		2,514		748		15		1
Jourdanton	Atascosa County, Texas		25		2,847				11
Ward Estes	Ward County, Texas		252		913		83		123
Ginger/Ginger SE	Rains County, Texas		73		345		213		7		1
Fanny Church	Escambia County, Alabama		273		285				3
Flomaton	Escambia County, Alabama		153		785				4
Southern Unit	Crane County, Texas		50		604		23		29
Edgewood/Edgewood NE	Van Zandt County, Texas		48		258		70		4
Fruitvale/Fruitvale E	Van Zandt County, Texas		42		370		53		6
Eustace	Henderson County, Texas		55		24		64		6
All others	Various		203		2,791		68		113		140
Total			2,360		11,736		1,322		321		142

Big Escambia Creek.  The Big Escambia Creek field, located in Escambia County, Alabama, encompasses approximately 11,520 gross and 7,128 net Eagle Rock operated acres.  The field was discovered in 1971 and produces from the Smackover formation at depths ranging from approximately 15,000 to 16,000 feet.  Eagle Rock operates fifteen wells with an average ownership of 62% working interest and 51% net revenue interest.  The reservoir is a sour, gas condensate reservoir in which produced gas and fluids contain a high percentage of hydrogen sulfide and carbon dioxide. These impurities are extracted at the Eagle Rock operated Big Escambia Creek Treating Facility, and the effluent gas is further processed in the Big Escambia Gas Processing Facility for the removal of natural gas liquids. The operation of the wells and the two facilities are intimately connected, and Eagle Rock is the largest owner and operator of the combined assets. In addition to selling condensate, natural gas, and natural gas liquids, we also market elemental sulfur. The sulfur market was highly volatile during 2008, with prices ranging from $150 to $617 per long ton before price netbacks.  The current market for sulfur is vastly oversupplied resulting in a negative price after netbacks to the Big Escambia Creek field.  If we are unable to either sell or dispose of the sulfur we produce due to the oversupplied market, we may be forced to curtail our oil and gas production.  We acquired our interest in the Big Escambia Creek field through the Escambia Acquisition in 2007.

Jourdanton.  The Jourdanton field, located in Atascosa County, Texas, was originally discovered in 1945 by Humble Oil Company.  Eagle Rock’s 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.  The Jourdanton field originally produced from the “oil leg” at the bottom of the Edwards interval with subsequent production from the higher porosity gas sections at the top of the Edwards.  In recent years, production has been established from some of the lower permeability and porosity sections in the middle Edwards interval.   Eagle Rock operates eleven wells with 100% working interest and 87.5% net revenue interest.  Net leasehold ownership in the field is 1,422 acres.  Gas content is relatively dry and contains approximately 7% carbon dioxide and 2% hydrogen sulfide.   Production flows from the wellhead full well stream to a central production facility where the liquids are separated and the gas is compressed to pipeline pressures.  The gas is transported via pipeline to Regency Field Services’ Tilden Gas Plant where it is sold to Louis Dreyfus.  The oil is transported from our central production facility by truck and sold to Flint Hills Resources, LP.  We acquired our interest in the Jourdanton field through the Redman Acquisition in 2007.

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Ward-Estes. The Ward-Estes Area is located on the western edge of the prolific Central Basin Platform within the Permian Basin.  The Central Basin Platform extends from central Lea County in New Mexico to central Pecos County in Texas and encompasses hundreds of individual fields with multiple productive intervals from the Yates-Seven Rivers-Queen through the Ellenburger formations.  Eagle Rock operates multiple fields consisting of stacked multi-pay horizons that produce from depths of 2300 feet (Yates) to 9100 feet (Pennsylvanian).  The Yates-Queen production is primarily oil production associated with secondary waterflood operations with discovery dates dating back to the late 1920s.  The San Andres, Holt, Glorieta, Tubb / Clearfork intervals produce oil with associated casinghead gas.  The Wichita Albany, Wolfcamp and Pennsylvanian intervals typically are gas wells that produce some associated oil.  Our ownership in these wells average 99.8% net working interest and 79.4% net revenue interest.  Gas production from the leases are gathered and processed by Southern Union Gas and Targa Gas under various percent-of- proceeds (POP) contracts.  Crude oil is sold to Navajo and Plains Petroleum.  Water production from the Yates – Queen secondary recovery operations is treated and re-injected into water injection wells to provide reservoir pressure maintenance. Eagle Rock acquired its interest in the Ward Estes field through the Stanolind Acquisition in 2008.

Ginger/Ginger Southeast.   The Ginger/Ginger Southeast fields are located in eastern Rains County, Texas encompassing approximately 2,346 gross and 1,835 net Eagle Rock operated acres.  The fields are positioned on the flanks of a northeast-southwest trending salt-cored anticline that culminates in a graben at its crest.  The fields were discovered in 1951 and 1982 respectively and produce from the Smackover formation at depths of approximately 12,000 feet.   We operate seven producing wells in these fields which produce gas that contains approximately 32% hydrogen sulfide and 3.5% carbon dioxide.  Eagle Rock’s ownership in the wells average 77% working interest and 62% net revenue interest.  The full well stream production is gathered by Regency Field Services and delivered to Regency’s Ginger Station where it is compressed before flowing to Regency’s Myrtle Springs compressor station for condensate separation and sales.  Flow continues to Regency’s Eustace Plant where it is treated for impurities, and natural gas liquids and sulfur is extracted for a combination of fees and percent-of-proceeds.   The residue gas is sold to Regency.  Natural gas liquids are sold to Regency through a marketing arrangement with Targa Midstream Services LP (“Targa”) and condensate is sold to CIMA Energy.  The extracted sulfur is sold to International Chemical Company (“Inter-Chem”).  The sulfur market was highly volatile during 2008, with prices ranging from $150 to $617 per long ton before price netbacks.  The current market for sulfur is vastly oversupplied resulting in a negative price after netbacks to our Big Escambia Creek field.  If we are unable to either sell or dispose of the sulfur we produce due to the oversupplied market, we may be forced to curtail our oil and gas production.  We acquired our interest in the Ginger/Ginger Southeast fields through the Redman Acquisition in 2007

Fanny Church.  The Fanny Church field is located 2 miles east of Big Escambia Creek and produces from the Smackover formation at depths from approximately 15,000 to 16,000 feet.  Eagle Rock’s ownership includes approximately 1,923 gross and 1,506 net operated acres that include three operated wells with an average ownership of 87% working interest and 68% net revenue interest.  Similar to those in the Big Escambia Creek Field, the produced fluids contain a high concentration of hydrogen sulfide and carbon dioxide. The production is treated for the removal of these impurities at the Flomaton Treating Facility, and the treated natural gas is sent to the Jay Field Processing Facility (of which the Partnership owns approximately a 23% non-operating interest) for the extraction of natural gas liquids.  The Jay Field Processing Facility is operated by Quantum Management Resources MGT LLC.  Beginning as of late December 2008, the Jay Field Processing Facility has ceased operating, and we began selling natural gas without extracting the NGLs.  We acquired our interest in the Fanny Church field through the Escambia Acquisition in 2007.

Flomaton. The Flomaton field is adjacent to and partially underlies the Big Escambia Creek field.   The field encompasses approximately 3,200 gross and 3,143 net Eagle Rock operated acres and produces from the Norphlet formation at depths from approximately 15,000 to 16,000 feet.  Eagle Rock operates four wells with an approximate average 98% working interest and 86% net revenue interest.   Production from the Flomaton Field contains significant quantities of hydrogen sulfide and carbon dioxide. The produced fluids from Flomaton are treated in the same manner as those from the Fanny Church Field.  We acquired our interest in the Flomaton field through the Escambia Acquisition in 2007.

Southern Unit.  The Southern Unit field is located in the middle of the Central Basin Platform of the Permian Basin, specifically in Crane County, Texas.  Production is primarily associated with the Ordovician-aged Waddell Sand formation that is faulted and sub crops against the younger Permian aged carbonates.  The Southern Unit is located in the Running “W” Waddell field discovered in the mid-1930s and produces predominantly oil at depths from approximately 5,750 to 5,900 feet.  Eagle Rock operates approximately 6,100 net acres in this area.  In addition to the Waddell Sand in the Southern Unit, production is also associated with the shallower McKee Sand gas bearing interval which sub crops similar to the Waddell Sand west of the Southern Unit.  Our ownership average in these wells average 85.4% net working interest and 66.7% net revenue interest.  Gas production from the Southern Unit field is gathered and processed by Targa under a percent-of-proceeds contract.  The oil is purchased by Plains Marketing, L.P..  Produced water on the Southern Unit is re-injected into the Waddell Sand to provide reservoir pressure maintenance.  Eagle Rock acquired its interest in the Southern Unit from the Stanolind Acquisition in 2008.

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Northeast Edgewood.   The Northeast Edgewood field is located in Van Zandt County, Texas along the Smackover Trend of East Texas.  The reservoir is a northeast-southwest oriented anticline that produces from the Upper Smackover formation at approximately 12,700 feet.   Eagle Rock’s leasehold includes 4,531 gross acres and 3,691 net acres and we operate four wells which produce gas that contains approximately 30% hydrogen sulfide.  Eagle Rock’s ownership in the wells averages 81% working interest and 69% net revenue interest.   The full well stream production is gathered by Regency Field Services and compressed at Regency’s Edgewood compressor station.  The gas proceeds to Regency’s Myrtle Springs compressor station for additional compression and separation of condensate before arriving at Regency’s Eustace Plant.   At the Eustace Plant the gas stream is separated, treated for impurities and natural gas liquids and sulfur is extracted for a combination of fees and percent of proceeds.  The residue gas is sold to Regency. Natural gas liquids are sold to Regency through a marketing arrangement with Targa, and the condensate is sold to CIMA Energy.  The extracted sulfur is sold to Inter-Chem. The sulfur market was highly volatile during 2008, with prices ranging from $150 to $617 per long ton before price netbacks.  The current market for sulfur is vastly oversupplied resulting in a negative price after netbacks to our Big Escambia Creek field.  If we are unable to either sell or dispose of the sulfur we produce due to the oversupplied market, we may be forced to curtail our oil and gas production.  We acquired our interest in the Northeast Edgewood filed through the Redman Acquisition in 2007.

Fruitvale / E. Fruitvale.  The Fruitvale and East Fruitvale fields are located in Van Zandt County, Texas and encompass approximately 4,037 gross and 3,925 net Eagle Rock operated acres. The fields were discovered in 1976 and produce from the Smackover at 12,500 feet.  The reservoir is on a northeast-southwest oriented anticline that produces from the Upper Smackover formation at approximately 12,700 feet.  Eagle Rock operates six wells which produce gas that contains approximately 6.5% hydrogen sulfide, 7.5% carbon dioxide and 17% nitrogen.  Eagle Rock’s ownership in the wells averages 97% working interest and 81% net revenue interest.  The full well stream production is gathered by Regency Field Services and flows to Regency’s Myrtle Springs compressor station for condensate separation and sales.  The gas proceeds to Regency’s Eustace Plant for separation, treating for impurities, and extraction of natural gas liquids and sulfur for a combination of fees and percentage of proceeds.   Residue gas is sold to Regency, Natural gas liquids are sold to Regency through a marketing arrangement with Targa, and condensate is sold to CIMA Energy.  The extracted sulfur is sold to Inter-Chem.  The sulfur market was highly volatile during 2008, with prices ranging from $150 to $617 per long ton before price netbacks.  The current market for sulfur is vastly oversupplied resulting in a negative price after netbacks to the Big Escambia Creek field.  If we are unable to either sell or dispose of the sulfur we produce due to the oversupplied market, we may be forced to curtail our oil and natural gas.  We acquired our interest in the Fruitvale/E. Fruitvale field through the Redman Acquisition in 2007.

Eustace.  The Eustace field is located in northwestern Henderson County, Texas and includes approximately 2,800 gross and net acres operated by Eagle Rock.  The wells produce from the Smackover formation at approximately 12,700 feet.  The field was originally discovered in 1973 and began producing in 1981 after Shell Oil Company purchased the field and constructed the Eustace sour gas treating and gas processing plant (that is currently owned and operated by Regency Field Services).  The reservoir is an elongated anticlinal feature located along the East Texas Smackover Trend.  Eagle Rock operates six wells in this field that produce gas containing approximately 37% hydrogen sulfide and 5% carbon dioxide.  Eagle Rock’s ownership in the wells is 100% working interest and 87% net revenue interest.  The full well stream production flows through Eagle Rock’s flow lines  to Regency’s Eustace Plant for separation of condensate, removal of impurities, and extraction of natural gas liquids and sulfur for a combination of fees and percentage of proceeds..  The residue gas is sold to Regency, Natural gas liquids are sold to Regency through a marketing arrangement with Targa, and condensate is sold to CIMA Energy.  The extracted sulfur is sold to Inter-Chem.  The sulfur market was highly volatile during 2008, with prices ranging from $150 to $617 per long ton before price netbacks.  The current market for sulfur is vastly oversupplied resulting in a negative price after netbacks to our Big Escambia Creek field.  If we are unable to either sell or dispose of the sulfur we produce due to the oversupplied market, we may be forced to curtail our oil and gas production.  We acquire our interest in the Eustace field through the Redman Acquisition in 2007.

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Proved Reserves

The following table presents the Partnership’s estimated net proved natural gas and oil reserves in the Upstream Business on December 31, 2008. These values are based on independent reserve reports prepared by Cawley, Gillespie & Associates, Inc.

	As of December 31, 2008
Reserve Data: Upstream Segment
Estimated net proved reserves:
Natural gas (Bcf)		39.7
Oil (MMBbls)		7.2
Natural Gas Liquids (MMBbls)		5.6
Total (Bcfe)		116.9
Proved developed (Bcfe)		99.1
Proved developed reserves as % of total proved reserves		85	%

(source: CGA Proved Reserves Estimates)

Productive Wells

On December 31, 2008 we had under operation 249 gross (237 net) productive oil wells and 72 gross (58 net) productive natural gas wells. On December 31, 2008, we owned non-operated working interests in an additional 120 gross (3.5 net) productive natural gas wells and 22 gross (1.5 net) productive oil wells.

Developed and Undeveloped Acreage

The following table describes the leasehold acreage we owned as of December 31, 2008.

	Developed Acreage(1)				Undeveloped Acreage(2)				Total Acreage
	Gross(3)		Net(4)		Gross(3)		Net(4)		Gross		Net
Operated		66,971		54,672		1,134		924		68,105		55,596
Non-operated		29,930		1,650		—		—		29,930		1,650
Total		96,901		56,322		1,134		924		98,035		57,246

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(1) Developed acres are acres pooled or assigned to productive wells.

(2) 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.

(3) A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres.

Drilling and Recompletion Activity

In 2008, we completed the drilling of 21 wells (5.8 net), of which 15 wells drilled were operated by others.  All six wells operated by us were successful.  Five operated, successful Permian Basin wells were drilled and completed on leasehold acquired from the Stanolind Acquisition in 2008.  Four of these wells were drilled in the Ward-Estes field area on the Louis Richter and American National leases testing the San Andres, Holt and Penn formations.  The fifth Permian Basin well was a successful completion in the Penn Sand on our American National lease in the Southern Unit field area.  In addition to the Permian program, a successful Smackover test we drilled and completed a successful Smackover test in our Big Escambia Creek field.  As of December 31, 2008, two additional wells are in the process of completion operations.  The total finding and development cost of the operated program was $1.47/Mcfe.

The fifteen non-operated wells drilled in 2008 were drilled by Stroud Petroleum in various fields of East Texas and North Louisiana.  Our average working interest in the Stroud Petroleum program is 3.8%.  Two of the non-operated wells were plugged and abandoned, the rest were successful.

Recompletions and capital workovers were conducted on eight operated wells across our South Texas, West Texas and Alabama regions during 2008.   Five recompletions were executed in our Jourdanton field to complete additional Edwards formation intervals.  Three of the five Edwards recompletions were successful.  Three successful capital workovers were completed in our Alabama and West Texas operations resulting in significant reserve additions during 2008.  The unit development cost for these operations was $1.77/Mcfe.

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Minerals Business

Minerals Business Overview

The Minerals Business is comprised almost entirely of mineral, royalty and overriding royalty interests. These interests represent ownership in over 430,000 net mineral acres and royalties and overriding royalties in over 2,800 producing wells in 17 states in the United States and the Gulf of Mexico. Our ownership in our minerals or royalties is a direct ownership of the mineral estate and ownership of partnership interests in other limited partnerships that were created to own and manage mineral and royalty interests.  Our minerals and royalty holdings are very well diversified and span multiple geological basins and geographical areas.  We have limited concentration of operators or wellbores in a single play type or exploration activity.    Successful management of minerals entails actively leasing and promoting the mineral estate to active oil and gas producers to entice them to lease and develop the oil and gas potential.   We do not operate the substantial majority of these properties, but we do have small mineral interests underlying our Big Escambia Creek, Flomaton and Fanny Church Upstream assets.

Our fee mineral, royalty and overriding royalty interests are significantly different than working interests, and we believe they have very attractive features to a master limited partnership. Ownership of mineral and royalty interests do not bear any of the costs of drilling or production (other than certain production taxes) which are borne by the Operator or producer but the mineral owner usually does not control any of the relevant decisions associated with the operation of existing wells or the drilling of future ones. Despite this lack of control, we believe the following characteristics make mineral and royalty interests an ideal asset for a master limited partnership.

• They do not bear drilling or production costs—Mineral interests are leased to working interest owners who bear all of the cost and financial risk associated with operating the existing wells and drilling future ones. The mineral interest owner receives a negotiated portion of the revenues from the sale of the products of the wells.

• Mineral ownership may be perpetual—Mineral interests are a real property interest and they are usually owned in perpetuity. Overriding royalty interests are derived from the leasehold estate (the oil and gas lease rights), and are only valid so long as the underlying oil and gas lease is valid. Many leases last for decades, however.

• They have the potential for “regeneration”—This refers to the fact that although the current wells usually have declining production rates, the operator of the lease will often conduct activities to create new sources of production (by drilling new wells, working on old ones, or employing various forms of advanced technology to enhance production). In a well-diversified portfolio of mineral and royalty interests, it is not uncommon to observe stable or inclining production over the course of many years as a result of the regeneration effect.

The income we receive from these assets consists of lease bonus payments, delay rentals, and royalty payments from the sale of production. We do not bear any of the costs associated with drilling or operating the wells, other than ad valorem and production taxes.

Minerals Business Strategies

• Pursuing acquisition of mineral, royalty and overriding royalty interests – We intend to grow the Minerals Business, and the cash flow it generates, through acquisitions of mineral, royalty and overriding royalty interests.

• Actively manage and promote the leasing of our mineral estate - We intend to actively promote the leasing and development of our mineral estate by attracting active oil and gas producers to explore and develop drilling plays and prospects across our diversified mineral holdings.

Because our Minerals Business consists of non-operated interests, our business strategy is focused on the accurate engineering and geologic evaluation of properties that are available for acquisition. Specifically, we conduct a thorough evaluation of the existing wells to determine their production decline characteristics, and we assess whether the interests have the characteristics we believe indicate a high likelihood that future regeneration will occur.

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Minerals Business Competitive Strengths

• We have an experienced knowledgeable management team with a proven record of performance in evaluating, negotiating and closing minerals transactions.

• We have a staff of engineers and support staff who are experts at evaluating minerals interests across a large majority of the geological basins and trends in the United States. .

Minerals Proved Reserves

The following table presents the Partnership’s estimated net proved natural gas and oil reserves in the Minerals Business on December 31, 2008. These volumes are based on independent reserve reports prepared by Cawley, Gillespie & Associates, Inc.

Reserve Data: Minerals Segment
Estimated net proved reserves:
Natural gas (Bcf)	4.9
Oil (MMBbls)	2.8
Total (Bcfe)	21.6
Proved developed (Bcfe)	21.6
Proved developed reserves as % of total proved reserves	100	%

(source: CGA Proved Reserves Estimates)

Brea Olinda Royalty

Our most significant royalty interest is a 12.5% non-participating royalty interest in the oil production from three units of the Brea Olinda Field (Stearns, West Brea, and East Naranjal) and a 3.75% non-participating royalty interest in a fourth unit (Columbia). The field is located in Orange County, California and all of the units are operated by Linn Western Energy.

Production from the field is medium gravity crude oil and has a very low decline rate due to ongoing secondary recovery, infill drilling and workover operations. Our net production is approximately 220 Bbl/d, which represents about half of the crude oil and condensate production in the Minerals Business.

The surface lands are currently undergoing residential development which has the potential for limited, temporary impact on the field’s operations and production rate.  Also, in November 2008, wildfires passed though the field.  The wells and facilities were not damaged, but the electrical distribution system was.  This system has been repaired and the field is now operating at full capacity.

Fruitland Coal Bed Methane (CBM) Overriding Royalty, New Mexico

Another significant asset in the Minerals Business is overriding royalty interests in certain wells in two units in the Fruitland CBM Field: the Northeast Blanco and San Juan 30 6 Units. Our net production of natural gas is approximately 220 Mcf/d, which represents approximately 9% of the gas production in the Minerals Business.

Ivory Acquisitions Partners, L.P. and Ivory Working Interests, L.P.

We hold the majority of our mineral interests (all but approximately 10,000 net mineral acres) as a co-investor in an acquisition agreement signed in 2004 with respect to a set of mineral interests from the Pure Resources Company: these interests were previously owned by International Paper, and are often referred to as the “Pure Minerals” or the “IP Minerals.”  The transaction was led by a private company (the “Minerals Manager”), who serves as the manager of the mineral interests.  As part of the transaction, we received direct title to approximately 13.2% of 92% of the mineral interests (the “direct title minerals”); the remaining 8% of the mineral interests was placed into Ivory Acquisition Partners, L.P. (��IAP”), a private partnership of which we owned approximately 13.2% of the limited partner units.  We account for the direct title minerals using the consolidation method while our interest in IAP is accounted for under the equity method.  We acquired these interests through the Montierra Acquisition in 2007.

The Minerals Manager is the general partner of IAP, and also serves as the manager of the mineral interests.  In these roles, the Mineral Manager has a number of rights and obligations; for instance, the Mineral Manager holds the executive rights of the mineral interests.  The executive rights grants the Minerals Manager the sole authority to negotiate and execute mineral leases on behalf of the mineral owners.  The Minerals Manager also collects all bonus and royalty payments from the operators, and disburses them to the mineral owners monthly.  The Minerals Manager has a large staff of land, engineering, geological and accounting professionals who conduct extensive activities to lease the minerals on competitive terms and to encourage their exploration and development.  As described in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Year Ended December 31, 2008 Compared with Year Ended December 31, 2007 – Mineral Segment, during 2008, the efforts of the Minerals Manager resulted in a substantial amount of bonus income related to leases in the Haynesville shale play.

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In June 2008, we were notified by the Minerals Manager that certain payout hurdles specified in the IAP partnership agreement had been reached.  As a result, pursuant to the partnership agreement, we were required to assign our limited partnership interest in IAP to the Minerals Manager for $1, and we no longer own an interest in IAP.  This reversion of interest in IAP does not affect the direct title minerals, nor does it affect our proved reserve quantities.  We had not previously included the IAP portion of the minerals in our proved reserves because we knew the reversion would occur (although we were uncertain when).

Also in our Minerals Business is a 13.2% limited partnership interest in Ivory Working Interests, L.P. (“IWI”). This entity owns non-operating working interests in some of the wells in which we own a mineral interest, and its general partner is the Minerals Manager. We do not own direct title to the working interests of IWI, so it is accounted for under the equity method.

IWI was formed at the same time as IAP, and its purpose was to hold title to current and future working interests related to the Pure minerals.  These working interests derive from certain leases on the minerals that the Minerals Manager executed which, under certain conditions, gave the mineral owners the right to participate collectively as a working interest owner (in addition to their participation as royalty owners).  Under the various agreements that exist between the co-investors, IAP, IWI and the Minerals Manager, IWI has the right to use the revenues generated in IAP or from the direct title minerals as a source of funding for its drilling and production costs, in the event and only to the extent that IWI’s internal cash flow is insufficient to cover these costs.  This event did occur during 2008.  Approximately $3.9 million was retained by the Minerals Manager for investment in IWI.

Regulation of Our Operations

Safety and Maintenance Regulation

Midstream Business

Our Midstream Business, other than our pipelines, is subject to federal safety standards developed under the Occupational Health and Safety Act of 1970, as amended (“OSHA”). The OSHA standards focus on protection of employee health and safety and the maintenance and safe operation of our facilities.  The facilities covered by these safety regulations in our Midstream Business are our natural gas plants, compressor stations, and natural gas treatment facilities. Safety matters associated with our pipelines are regulated by the U.S. Department of Transportation (“DOT”), Office of Pipeline Safety (“OPS”).  We incur costs related to all of these regulations for monitoring and maintaining our facilities in safe operating conditions.  We also have costs associated with training our workforce in safety, record keeping, reporting, and inspecting our operations.  Consequences of non-compliance with these regulations are potential fines from the federal or state government agencies and disruption of operations due to injuries or equipment failure.

OSHA process safety management (“PSM”) standards apply to our natural gas plants, compressor stations, and natural gas treatment facilities.  The PSM standards address ways in which our Midstream Business maintains process safety information, evaluates the hazards associated with these operations, develops procedures for ensuring their safe operation, maintains the integrity of our operations, and manages contractors on-site.  PSM standards apply because each of these sites processes and stores (under pressure) flammable liquids or gas in excess of 10,000 pounds.  In addition, those of our facilities that handle hydrogen sulfide in quantities exceeding 1,500 pounds are subject to further PSM requirements. The PSM standard also requires us to conduct compliance audits every three years. We are on schedule to timely complete these audits.

More general OSHA standards also apply to these operations.  These include regulations governing safety sensitive issues, such as means of egress, fire protection, materials handling and storage, confined space entry, servicing and maintaining machines and equipment, and electrical, that have more application to our Midstream Business than our Upstream Business due to the nature of our Midstream Business facilities.

Our pipeline operations within our Midstream Business, specifically the gathering and transportation of natural gas and hazardous liquids, are subject to DOT regulatory requirements as promulgated by the OPS, specifically 49 CFR 192 (natural gas) and 49 CFR 195 (hazardous liquids). The extent to which our gathering pipelines are regulated primarily depends on their location.  There is a sliding scale of regulation ranging from basic safety precautions to more rigorous inspection and reporting depending upon the population density and other factors within proximity of the specific pipeline.  Where applicable, these DOT regulations direct our activities with respect to design and construction of pipelines, corrosion control, testing requirements, operations, maintenance, emergency response, and qualification of pipeline personnel.

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The safety of our pipelines is also regulated by the states in which we operate. These regulations in general, focus on reporting, recordkeeping, and notification obligations.

Upstream and Minerals Business

Our Upstream and Minerals Business implicates safety matters with respect to the exploration and production of hydrocarbons and carries consequences of non-compliance consistent with those discussed above under the safety matters for the Midstream Business.  This segment of our business is also subject to OSHA standards.  The actual production of oil and gas is subject to OSHA PSM requirements but through agency internal policy, PSM standards are not currently enforced. OSHA has specifically exempted oil and gas well drilling and servicing from standards covering the control of hazardous energy and the PSM standard as they relate to highly hazardous chemicals.If agency policy changes, additional compliance, reporting, and training costs could be incurred in our Upstream and Minerals Business.

Our Upstream and Minerals Business is also subject to safety rules and regulations promulgated by state agencies, such as the Alabama State Oil and Gas Board, Louisiana Department of Conservation, Mississippi Oil and Gas Board, New Mexico Oil Conservation Division, and Texas Railroad Commission. While these agencies have established some regulations designed to protect worker and community health and safety, their primary focus is on environmentally sound well drilling, servicing, and production operations.

FERC and Similar State Regulations

Under the Natural Gas Act of 1938, or NGA, as amended by the Energy Policy Act of 2005, or EPA 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.  FERC also regulates intrastate pipelines that engage in interstate transportation activities under Section 311 of the Natural Gas Policy Act, or NGPA.

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

FERC exercises authority over the rates, terms and conditions of service of intrastate pipelines to the extent that such pipelines transport gas in interstate commerce under Section 311 of the 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. The rates for Section 311 service are generally subject to review every three years by the FERC or by an appropriate state agency. Our Eagle Rock DeSoto Pipeline, L.P., (“DeSoto Pipeline”) an intrastate pipeline acquired in October 2008 as part of the Millennium Acquisition, 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.  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 the DeSoto Pipeline or the imposition of civil and/or criminal penalties.

EPA 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.  In January 2006, FERC issued rules implementing the anti-manipulation provision of EPA 2005. These rules make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC or the purchase or sale of transportation services subject to the jurisdiction of FERC: (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-manipulation rules apply to activities of natural gas pipelines and storage companies that provide interstate transportation services, and to otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases, or transportation subject to FERC jurisdiction, but do not apply to activities that relate only to non-jurisdictional sales or gathering. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines.

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In 2008, FERC took additional steps to enhance its market oversight and monitoring of the natural gas industry.  Order No. 704, as clarified on rehearing in 2008, 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.  The first such report is due on May 1, 2009 for calendar year 2008 activities.  Order No. 720, issued in late November 2008, requires “major non-interstate” pipelines (defined as pipelines with annual deliveries of more than 50 million MMBtu) to post on the internet the daily volumes scheduled for each receipt and delivery point on their systems with a design capacity of 15,000 MMBtu per day or greater.  Order No. 720 also increases the posting obligations of interstate pipelines.  Numerous parties have requested modification or reconsideration of this rule, and it remains to be seen whether the requirements will be modified on rehearing.  Our DeSoto Pipeline does not at this time meet the criteria to be considered a “major non-interstate pipeline,” but it may become subject to posting requirements in the future, depending on market conditions and depending on whether FERC modifies the criteria on rehearing.   In November 2008, FERC also issued a Notice of Inquiry to the industry soliciting comments regarding whether “Hinshaw” pipelines and intrastate pipelines that transport natural gas in interstate commerce pursuant to Section 311 of the NGPA should be required to post on the internet certain details of their transactions with individual shippers in a manner comparable to the reporting requirements applicable to interstate pipelines.  Once the FERC evaluates the comments filed in response to the Notice of Inquiry, it may choose to engage in the formal rulemaking process to propose additional reporting requirements on such pipelines.

In 2008 FERC also took action to ease restrictions on the capacity release market, in which shippers on interstate pipelines can transfer to one another their rights to pipeline and/or storage capacity.  Among other things, Order No. 712 removed the price ceiling on short-term capacity releases of one year or less, and facilitated Asset Management Agreements, or AMAs, by exempting releases under qualified AMAs from: the competitive bidding requirements for released capacity; FERC’s prohibition against tying releases to extraneous conditions; and the prohibition on capacity brokering.

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 the jurisdiction of FERC, but does not define or provide any guidance as to what constitutes “gathering.” FERC has developed tests for determining which facilities constitute gathering facilities exempt from FERC jurisdiction under the NGA. From time to time, FERC may reconsider the elements of such tests. In recent years, FERC has permitted jurisdictional pipelines to “spin-down” exempt facilities out of a jurisdictional entity into affiliated entities not subject to FERC jurisdiction, although FERC continues to examine the factual circumstances under which a spin-down is appropriate. 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 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.

The jurisdictional status of DeSoto Pipeline’s East Texas System has been reviewed by the FERC.  DeSoto Pipeline filed a petition for a declaratory order in October 2008, in connection with the Millennium Acquisition, requesting the FERC to determine that the East Texas System is engaged in natural gas gathering services under Section 1(b) of the NGA, and is not engaged in jurisdictional transportation services, pursuant to FERC’s traditional tests used to establish a pipeline’s jurisdictional status.  DeSoto Pipeline filed the petition based on changed system circumstances, including expanded producer interconnections and the fact that the East Texas System had ceased taking gas from an intrastate pipeline.  On February 6, 2009, FERC granted DeSoto Pipeline’s request for a declaratory order and determined that DeSoto Pipeline’s East Texas facilities perform a gathering function.  As a result, the East Texas System operations are deemed to be exempt from FERC jurisdiction under Section 1(b) of the NGA.

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. Historically, apart from pipeline safety, it has not acted to exercise this jurisdiction respecting gathering facilities.

The majority of our gathering systems in Texas have been deemed non-utilities by the TRRC. Under Texas law, non-utilities are not subject to rate regulation by the TRRC. Should the status of these non-utility facilities change, they would become subject to rate regulation by the TRRC, which could adversely affect the rates that our facilities are allowed to charge their customers.  Texas also administers federal pipeline safety standards under the Pipeline Safety Act of 1968. The “rural gathering exemption” under the Natural Gas Pipeline Safety Act of 1968 presently exempts most of our gathering facilities from jurisdiction under that statute, including those portions located outside of cities, towns or any area designated as residential or commercial, such as a subdivision or shopping center. The “rural gathering exemption,” however, may be restricted in the future. With respect to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation, or DOT, have passed or are considering heightened pipeline safety requirements. We operate our facilities in full compliance with local, state and federal regulations, including the DOT regulations found at 49 C.F.R. Parts 192 and 195.

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The DOT also 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 our pipeline facilities. The HLPSA covers petroleum and petroleum products. The HLPSA 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 believe that we are in material compliance with these HLPSA regulations.

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 believe that we are in material compliance with these DOT regulations.

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. The regulation requires the development and implementation of 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. The regulation also requires periodic review of HCA pipeline segments to ensure adequate preventative and mitigative measures exist and that companies take prompt action to address integrity issues raised by the assessment and analysis. In compliance with these DOT regulations, we identified our HCA pipeline segments and have developed an IMP. We believe that the established IMP meets the requirements of these DOT regulations.

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 required us 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. We believe we are operating in material compliance with our risk management program.

Eleven miles of our Turkey Creek gathering system are regulated as a utility by the TRRC. To date, there has been no adverse affect to our system due to this regulation. In addition, our Hesco Pipeline Company, LLC, which we purchased in 2007, and our recently purchased DeSoto Pipeline are regulated by the TRRC. Our purchasing and gathering operations are subject to ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Texas and Louisiana have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.  The 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.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also 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. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

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Intrastate Pipeline Regulation.  Our DeSoto Pipeline, acquired in October 2008 as part of the Millennium Acquisition, transports natural gas both in intrastate commerce and in interstate commerce on its North and Central Texas Systems.  The TRRC has authority over the rates, terms and conditions of service for DeSoto Pipeline’s intrastate transportation activities.  FERC exercises authority over the rates, terms and conditions of service for DeSoto Pipeline’s interstate transportation activities.  Pursuant to Section 311 of the NGPA, rates for such transportation must be “fair and equitable”, and amounts collected in excess of “fair and equitable” rates are subject to refund with interest.  DeSoto recently 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.   FERC has not yet acted on this application.  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 or the imposition of civil and/or criminal penalties.

Sales of Natural Gas. 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 those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation, although FERC has recently promulgated regulations to implement the increased market oversight ability conferred by Congress in EPA 2005.  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.    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 Future Trading Commission.  These agencies hold substantial enforcement authority, including the ability to assess 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.

Intrastate NGL Pipeline Regulation. We do not own any NGL pipelines subject to FERC’s 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 you 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.

Upstream Business and Minerals 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 under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. 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.

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

Drilling and Production. The activities conducted by us and by the operators on our properties are subject to various types of regulation at the federal, state and local levels. These types of regulation 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 method of drilling and casing 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 some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally 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.

Federal Regulation. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the rates, terms and conditions of service for interstate transportation, storage and various other matters, primarily by the FERC. Our sale of gas in interstate markets is subject to FERC authority and rules prohibiting market manipulation.  Further, FERC has imposed new reporting requirements on entities engaged in wholesale physical natural gas transactions as part of FERC’s initiatives to facilitate price transparency.  Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

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. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

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. We do not believe that compliance with these laws will have a material adverse effect upon the unitholders.

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Environmental Matters

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. These laws and regulations can adversely affect our capital expenditures, earnings and competitive position in many ways, such as requiring the acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, including accidental releases and spills; and imposing substantial liabilities on us for pollution resulting from our operations. The costs of planning, designing, constructing, operating and decommissioning 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 result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or prohibiting our activities.

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, and 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 into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances, and therefore subject to CERCLA.  However, we have not to date received notification that we are or may be potentially responsible for cleanup costs under CERCLA.

We also 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. Although RCRA contains an exclusion from the definition of solid and hazardous wastes for certain materials generated in the exploration, development, or production of crude oil and natural gas, in the course of our operations we may generate petroleum product wastes and ordinary industrial wastes such as paint wastes, waste solvents, and waste compressor oils 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 was 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 decontaminate previously disposed wastes or contaminated environmental media, or to perform activities to prevent future contamination.

The Federal Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including processing plants and compressor stations. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of facilities, obtain and comply with the terms of operating permits that may include stringent limitations on air emissions, capacity utilization, and hours of facility operations, or utilize specific equipment or technologies to control emissions. Please refer to our discussion under the heading Legal Proceedings for further information on this subject.

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. These laws also regulate the discharge of stormwater in process areas. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater and stormwater and develop and 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—prevention, containment and cleanup, and 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 also result in fines or penalties. 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. We believe, but cannot assure, that our exposure to loss from groundwater contamination will not have a material adverse effect on our financial position.

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The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases. The United States is not currently a participant in the Protocol. The U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. Congress recently passed, and the President signed, an omnibus spending bill that contains a provision requiring the U.S. Environmental Protection Agency (“EPA”) to promulgate, within 18 months of December 2007, regulations requiring certain facilities as yet to be defined to measure and report their greenhouse gas emissions to the EPA and to maintain this information in a greenhouse gas registry The Senate Environment and Public Works Committee recently passed a bill out of committee that would impose certain requirements on natural gas processing plants and producers or importers of natural gas. The House of Representatives is considering similar legislation. As a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. At the state level, several states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants, and other states are considering such legislation. The natural gas and oil industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane and future restrictions on such emissions could impact our future operations. Our assets are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

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.

Upstream Business and Minerals Business

Our Upstream Business involves acquiring, developing and producing oil and natural gas working interests.  Our Minerals Business involves acquiring and managing fee minerals and royalty interests.

Our and our lease operators’ operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These operations are subject to the same environmental laws and regulations as other companies in the natural gas and oil industry. These laws and regulations may:

• require the acquisition of various permits before drilling commences;

• require the installation of expensive pollution control equipment;

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

• limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

• require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;

• impose substantial liabilities for pollution resulting from our operations;

• with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement; and

• restrict the rate of natural gas and oil production below the rate that would otherwise be possible.

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 may adversely affect our capital expenditures, earnings and competitive position.

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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.  The Partnership has recorded liabilities for these asset retirement obligations in accordance with FASB Statement No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”). SFAS 143 applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. SFAS 143 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.

A portion of our Upstream Business and Minerals Business is derived from non-cost bearing minerals, royalties, and overriding royalty interests. Because we are not the owner or operator of the facilities associated with these  interests we believe that we would not be liable or responsible for non-compliance with environmental laws or any environmental damage caused by the operator or other parties as a result of drilling or production activities.

We believe but cannot assure that compliance with existing environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings and competitive position.

Title to Properties and Rights-of-Way

Midstream Business

Our midstream real property falls into two categories: (1) parcels that we own in fee and (2) 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 ground 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, 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.

Some of our leases, easements, rights-of-way, permits, licenses and franchise ordinances require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.

Upstream Business and Minerals 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 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 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 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.

Employees

To carry out our operations, as of December 31, 2008, Eagle Rock Energy G&P, LLC or its affiliates employed approximately 348 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

Eagle Rock provides access free of charge to all of its Securities and Exchange Commission (“SEC”) filings, as soon as reasonably practicable after filing or furnishing it, on its internet site located at www.eaglerockenergy.com. The Partnership will also make available to any unitholder, without charge, copies of its 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, 16701 Greenspoint Park Drive, Suite 200, Houston, TX 77060, or call 281-408-1200.

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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 an internet site (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.

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 the minimum quarterly distribution, or any distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Certain risks apply to both our midstream business and our upstream business. To the extent any risk applies to one or the other, we have indicated the specific risk in the appropriate risk factor.

Risks Related to Our Business

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 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.

Our gathering systems are connected to or dependent on the level of production from natural gas wells, from which production will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering systems and NGL pipelines and the asset utilization rates at our natural gas processing plants, we must continually obtain new supplies of natural gas. The primary factors affecting our ability to obtain new supplies of natural gas and NGLs and attract new customers to our assets include: (1) the level of successful drilling activity by producers near our systems and (2) our ability to compete for volumes from successful new wells.

The level of drilling activity is dependent on economic and business factors beyond our control. The primary factor that impacts drilling decisions is natural gas prices. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in our fields and 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. If we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells due to reductions in drilling activity or competition, throughput on our pipelines and the utilization rates of our treating and processing facilities would decline, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.

In our upstream business, we have additional risks inherent with declining reserves. Producing reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our decline rate may change when additional wells are drilled, 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.

Natural gas, NGLs, crude oil and other commodity prices are volatile, and a reduction in these prices could adversely affect our cash flow and our ability to make distributions.

We are subject to risks due to frequent and often substantial fluctuations in commodity prices. NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas 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 crude oil and natural gas prices have a significant impact on the value of our reserves and on our cash flows. The NYMEX contract month end settlement price for natural gas for the prompt month contract in 2008 ranged from a high of $11.29 per MMBtu to a low of $6.47 per MMBtu. The NYMEX daily average settlement price for crude oil for the prompt month contract in 2008 ranged from a high of $134.60 per barrel to a low of $45.51 per barrel. The markets and prices for oil, natural gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:

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• the impact of weather or other force majeure events;

• the level of domestic oil and natural gas production and demand;

• the level of imported oil and natural gas availability and demand;

• the level of consumer product demand;

• political and economic conditions and events in, as well as actions taken by foreign oil and natural gas producing nations;

• overall domestic and global economic conditions;

• the availability of local, intrastate and interstate transportation systems including natural gas pipelines and other transportation facilities to our production;

• 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 oil or natural gas prices may not only decrease our revenues and net proceeds, but also reduce the amount of oil or natural gas that we, and other producers using our midstream assets, can economically produce. As a result, the operator of any of the properties could decide during periods of low commodity prices to shut in or curtail production, or to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. This may result in substantial downward adjustments to our estimated proved reserves. If this occurs, or 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 for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. Given the significant drop in commodity prices in the fourth quarter of 2008, we evaluated our businesses for potential impairment.  This evaluation resulted in a total impairment charge of $174.9 million taken in the fourth quarter of 2008.  We may incur additional impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our credit facility, which may adversely affect our ability to make cash distributions to our unitholders.

Our natural gas gathering and processing businesses operate under three types of contractual arrangements that expose our cash flows to increases and decreases in the price of natural gas and NGLs: percentage-of-proceeds, fixed recovery and keep-whole arrangements. Under percentage-of-proceeds arrangements, we generally purchase natural gas from producers and retain an agreed percentage of the proceeds (in cash or in-kind) from the sale at market prices of pipeline-quality gas and NGLs or NGL products resulting from our processing activities. Under fixed recovery arrangements, we generally gather raw natural gas from producers at the wellhead, transport the natural gas through our gathering system, process the natural gas and sell the processed natural gas and/or NGLs at prices based on published index prices. The price paid to the producers is based on an agreed to theoretical product recovery factor to be applied against the wellhead production and then a percentage of the theoretical proceeds based on an index or actual sales prices multiplied to the theoretical production. To the extent that the actual recoveries differ from the theoretical product recovery factor, this will affect the margin. Under keep-whole arrangements, we receive the NGLs removed from the natural gas during our processing operations as the fee for providing our services in exchange for replacing the thermal content removed as NGLs with a like thermal content in pipeline-quality gas or its cash equivalent. Under these types of arrangements our revenues and our cash flows increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and NGL prices may also affect our profitability. When natural gas prices are low relative to NGL prices, under keep-whole arrangements it is more profitable for us to process natural gas. When natural gas prices are high relative to NGL prices, it is less profitable for us and our customers to process natural gas both because of the higher value of natural gas and of the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce our processing margins or reduce the volume of natural gas processed at some of our plants.

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In addition, the sulfur market was very volatile during 2008, with received prices ranging from $150 to $617 per long ton, before price netbacks.  Currently, the sulfur market is vastly oversupplied resulting in negative price after netbacks in our Big Escambia Creek field.  If we are unable to either sell or dispose of the sulfur we produce during the oversupplied market, we may be forced to curtail our oil and gas production within that and other fields.

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. Nevertheless, it is possible that these 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 position is presented in Part II, Item 7A. Qualitative and Quantitative Disclosure About Market Risk.

To the extent we hedge our commodity price and interest rate risk, we may forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. Furthermore, because we have entered into derivative transactions related to only a portion of the volume of our expected oil and natural gas production, natural gas supply and production of NGLs and condensate from our processing plants, we will continue to have direct commodity price risk to 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 derivative transactions for that period. If the actual amount is higher than we estimated, we will have less 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 the underlying physical commodity, resulting in a reduction of our liquidity.

As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, even though our management monitors our hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not 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 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.

As a result of our hedging activities and our practice of marking to market the value of our hedging instruments, we will also experience significant variations in our unrealized derivative gains/ (losses) from period to period. These variations from period to period will follow variations in the underlying commodity prices and interest rates. As this item is of a non-cash nature, it will not impact our cash flows or our ability to make our distributions. However, it will impact our earnings and other profitability measures. To illustrate, during the twelve months ended December 31, 2008, we experienced negative movements in our underlying commodities’ prices which led to an unrealized derivative gain of $221.1 million. This $221.1 million gain had a direct impact on our net income (loss) line resulting in net income of $87.5 million. For additional information regarding our hedging activities, please read Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

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. Our estimates of our net proved reserve quantities are based upon reports of petroleum engineers. 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, and these reports rely upon various assumptions, including assumptions regarding 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 timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. In addition, our wells are characterized by low production rates per well. As a result, changes in future production costs assumptions could have a significant effect on our proved reserve quantities.

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The standardized measure of discounted future net cash flows of our estimated net proved reserves is not necessarily 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 prices and costs in effect on the day of the estimate. 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 interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the 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.

Furthermore, due to the nature of ownership of royalties, overriding royalties and fee minerals, we will not usually be able to control the timing of drilling by the operators who have taken an oil and gas lease on our lands. This leads to uncertainty in the timing of future reserve additions and production increases resulting from new drilling across our assets. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the 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.

Our operations will 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, which could lead to a decline in our cash flows.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the maintenance, construction and acquisition of midstream assets and oil and natural gas reserves. 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 oil and natural gas 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; 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 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 relating to development of our capital projects, 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, which could adversely effect our business, results of operation, financial conditions and ability to make distributions to our unitholders. In addition, we may lose opportunities to acquire oil and natural gas properties and businesses.

To fund our capital expenditures, we will be required to use cash generated from our operations, additional borrowings or the issuance of additional partnership interests, or some combination thereof.

In 2009, our capital program is expected to be approximately $40 million, excluding acquisitions. Use of cash generated from operations to fund future capital expenditures will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings to fund future capital expenditures may be limited by our financial condition at the time of any such financing or offering and the covenants in our debt agreements, as well as by oil and natural gas prices, the value and performance of our equity securities, and adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control. Over the recent months, the capital markets have limited the availability of funds due to distressed conditions in the sub-prime securities market, economic conditions in general, and other factors. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, results of operations, financial condition and ability to pay distributions. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution thereby increasing the aggregate amount of cash required to maintain the then-current distribution rate, which could have a material adverse effect on our ability to pay distributions at the then-current distribution rate.

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We may not be able to fully execute our business strategy if we encounter illiquid capital 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 will impair our ability to execute this component of our growth strategy. If the cost of such capital 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 market conditions and offering or borrowing costs such as interest rates or underwriting discounts.

The global financial crisis may have impacts on our business and financial condition that we currently cannot predict.

The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, which could have an impact on our flexibility to react to changing economic and business conditions. The economic situation could have an impact on our lenders, derivative counterparties or customers, causing them to fail to meet their obligations to us. Additionally, market conditions could have an impact on our commodity hedging arrangements if our counterparties are unable to perform their obligations or seek bankruptcy protection. Additionally, the current economic situation could lead to reduced demand for oil and natural gas, or lower prices for oil and natural gas, or both, which could have a negative impact on our revenues.

We typically do not obtain independent evaluations of other producers’ natural gas reserves dedicated to our gathering and processing systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate.

We typically do not obtain independent evaluations of other producers’ natural gas reserves connected to our systems due to the unwillingness of producers to provide reserve information as well as the typically high cost of such evaluations. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas on our systems in the future could be less than we anticipate. A decline in the volumes of natural gas on our systems could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions.

Failure of the gas, NGLs, condensate or other products that we produce from our plants or ship 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 gas, NGLs, condensate or other products typically establish specifications for the products that they are willing to accept, which include requirements such as hydrocarbon dewpoint, compositions, temperature, and foreign content including water, sulfur, carbon dioxide, and hydrogen sulfide. 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 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 gas that is causing the products to be out of specifications, potentially reducing our through-put volumes or revenues.

We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.

The marketability of our production will depend in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and other transportation facilities owned by third parties. The amount of oil, gas and NGL 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 or transportation system, 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. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas, the value of our units and our ability to pay distributions on our units.

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The loss of any of our significant customers could result in a decline in our volumes, revenues and cash available for distribution.

Midstream. We rely on certain natural gas producer customers for a significant portion of our natural gas and NGL supply. The make-up of gas suppliers can change from time to time based upon a number of reasons, some of which include success of the producer’s drilling programs, additions or cancellations of new agreements and acquisition of new systems. We may be unable to negotiate long-term contracts or extensions or replacements of existing contracts, on favorable terms, if at all. The loss of all or even a portion of the natural gas volumes supplied by these customers, as a result of competition or otherwise, could have an adverse effect on our business, results of operations and financial condition, unless we were able to acquire comparable volumes from other sources.

Upstream and Minerals. To the extent any significant customer reduces the volume of its oil or natural gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our oil and natural gas production and our revenues and cash available for distribution could decline which could adversely affect our ability to make cash distributions to our unitholders.

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

Risks of nonpayment and nonperformance by our counterparties are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and other hedge counterparties. Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. In connection with the recent economic downturn, commodity prices have declined sharply, and the credit markets and availability of credit have been constrained. Additionally, many of our customers’ equity values have declined substantially, increasing their cost of equity capital. The combination of lower cash flow due to commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of available debt or equity financing may result in a significant reduction in our customers’ liquidity and 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 nonpayment and 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.

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 customers 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 marketers and 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.

Our business depends on gathering and transportation facilities. Any limitation in the availability of those facilities would interfere with our ability to market the oil, gas and NGL we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil, gas and NGL production from our drilling program.

The marketability of our oil, gas and NGL production depends in part on the availability, proximity and capacity of gathering and pipeline systems. The amount of oil, gas and NGL 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 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 and transportation pipelines, 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 and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, would interfere with our ability to market the oil, gas and NGL we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil and gas production from our drilling program."

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If third-party pipelines and other facilities interconnected to our 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 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 access to transportation options may affect our revenues and cash available for distribution.

Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. These factors and the availability of markets are beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas, the value of our units and our ability to pay distributions on our units.

Our industry is highly competitive, and increased competitive pressure 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 natural gas and NGLs than we do.

Midstream. Some of these competitors may expand or construct gathering, processing and transportation systems that would create additional competition for the services we provide to our customers. In addition, our customers who are significant producers of natural gas may develop their own gathering, processing and transportation systems in lieu of using ours. Likewise, our customers who produce NGLs may develop their own processing facilities in lieu of using ours. Our 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. 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.

Upstream. 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 carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for 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.

In both the midstream and upstream businesses, competition has been strong in hiring experienced personnel, particularly in the engineering, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive midstream assets as well as oil and natural gas producing properties, oil and natural gas companies and undeveloped leases and drilling rights. We may be often outbid by competitors in our attempts to acquire 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.

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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 natural gas gathering and intrastate transportation operations are generally exempt from Federal Energy Regulatory Commission, or FERC, regulation under the Natural Gas Act of 1938, or NGA; however, FERC has regulatory influence over certain aspects of our business through its jurisdiction over natural gas markets and intrastate pipelines that engage in interstate transportation services, including Eagle Rock DeSoto Pipeline, L.P., and thus  FERC regulation affects our natural gas gathering and intrastate transportation operations and the markets for products derived from these businesses. FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, 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 pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, FERC may not continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by FERC and the courts.

Other state and local regulations also affect our business. Common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport 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, including state regulation of production rates and maximum daily production allowable from gas wells. While our proprietary gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge proprietary status of a line, or the rates, terms and conditions of a gathering line providing transportation service. Please read Part I, Item 1. Business—Regulation of Operations.

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

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise to environmental protection. These laws and regulations may impose numerous obligations that are applicable to 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 protection or correlative rights affect our operations by limiting the quantity of oil and natural gas that may be produced and sold.

Numerous governmental authorities, such as the U.S. Environmental Protection Agency, also known as the “EPA,” and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits 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.

These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

• the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;

• the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

• the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and

• the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal.

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Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, 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 inherent risk of incurring significant environmental costs and liabilities in connection with our operations due to 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. Joint and several, strict liability may be incurred under these environmental laws and regulations in connection with discharges or releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties 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. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations or financial position. 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.

Regulation of greenhouse gas emissions could adversely affect our revenues and costs of operation.

The natural gas and oil industry is a source of emissions of certain greenhouse gases, namely carbon dioxide and methane.  Although there are still significant uncertainties regarding future federal regulation in the U.S., a reasonably broad-based consensus for federal legislation, involving either a cap-and-trade program or a carbon tax or both, is forming.  A cap-and-trade program could require major sources of emissions, including but not limited to producers of hydrocarbon-based fuels, such as refineries and gas processing plants, to incur additional costs for capital improvements or for the acquisition of greenhouse gas emission allowances.  Under various proposed cap-and-trade programs, we could be required to purchase emission allowances for greenhouse gas emissions resulting from our operations (e.g., processing plants and compressor stations) or from combustion of fuels by consumers of natural gas we produce and process.  A carbon tax could increase our costs and reduce demand for our products and services.  Although it is not possible at this time to predict the specific nature of possible future federal legislation to control greenhouse gas emissions, any such program could have an adverse effect on our cost of doing business and could reduce demand for the natural gas and oil we produce, process, and transport.

Our construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which 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. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a pipeline, the construction may occur over an extended period of time, and we will not receive any material increases in revenues until the project is completed. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. We often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in such area. 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 because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new 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. In addition, 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.

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If we do not 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 result in an increase in the cash generated from operations per unit. If we are unable to make these accretive acquisitions either because we are: (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) 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.

In our Upstream Business in particular, properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities, which could adversely affect our cash available for distribution. One of our growth strategies is to capitalize on opportunistic acquisitions of oil and natural gas reserves. Any future acquisition will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities and other liabilities and similar factors. Ordinarily, our review efforts are focused on the higher valued properties and are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material liabilities and costs that negatively impact our financial conditions and results of operations and our ability to make cash distributions to our unitholders.

Any acquisition, midstream, upstream or minerals, involves 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;

• an inability to integrate successfully the businesses we acquire;

• inadequate expertise for new geographic areas, operations or products and services;

• inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including their markets;

• the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;

• limitations on rights to indemnity from the seller;

• 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;

• a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition;

• the diversion of management’s and employees’ attention from other business concerns;

• unforeseen difficulties operating in new product areas or new geographic areas;

• customer or key employee losses at the acquired businesses; and

• establishment of internal controls and procedures that we are required to maintain under the Sarbanes-Oxley Act of 2002.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and the limited partners will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

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Our ability to derive benefits from our acquisitions will depend on our ability to integrate operations to achieve the benefits of the acquisitions.

Achieving the anticipated benefits from acquisitions depends in part upon whether we are able to integrate the assets or businesses of these acquisitions, in an efficient and effective manner. We may not be able to accomplish the integration process smoothly or successfully. 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;

• differences in the disclosure systems, accounting systems, and accounting controls and procedures of the two companies, which may interfere with our ability to make timely and accurate public disclosure; and

• the demands of managing new lines of business acquired.

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.

We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

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 and/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.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. 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, pipelines and plants, 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;

• 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;

• fires and explosions; and

• other hazards that could also result in personal injury and loss of life, pollution and suspension of operations, such as the uncontrollable flow of oil or natural gas or well fluids.

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.

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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.

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines and certain gathering lines 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 will incur costs of $885,000 between 2009 and 2010 to implement pipeline integrity management program testing along certain segments of our pipeline, as required by existing DOT regulations. 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.

Our current debt levels 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.

In December 2007, we entered into an $800.0 million senior secured credit facility.  During the year ended December 31, 2008, we exercised $180 million of our $200 million accordion feature under the credit facility, which increased the total commitment to $980 million.  Our level of debt could have important consequences to us, including the following:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

• we will need a portion of our cash flow to make interest payments on our debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders;

• our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

• our debt level may limit our flexibility in responding to changing business and economic conditions.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness or comply with our financial covenants under our existing credit facility, we will be forced to take actions such as 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.

Our Upstream Business requires a significant amount of capital expenditures to maintain and grow production levels. If commodity prices were to decline for an extended period of time, if the costs of our acquisition and drilling and development operations were to increase substantially, or if other events were to occur which reduced our revenues or increased our costs, we may be required to borrow significant amounts in the future to enable us to finance the expenditures necessary to replace the reserves we produce. The cost of the borrowings and our obligations to repay the borrowings will reduce amounts otherwise available for distributions to our unitholders.

Low commodity price levels may result in a decrease of our borrowing base under our credit facility, impacting our covenant compliance.

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Our credit facility accommodates, through the use of a borrowing base for our Upstream Business and traditional cash-flow based covenants for our Midstream and Minerals Businesses, the allocation of indebtedness to either our Upstream Business (to be measured against the borrowing base) or to our Midstream and Minerals Businesses (to be measured against the cash-flow based covenant).  As of December 31, 2008, our borrowing base for our Upstream Business was determined at $206 million.  A decrease in our borrowing base would result in a higher allocation of indebtedness to our Midstream and Minerals Businesses and a rise in our leverage ratio which may impact our availability under our credit facility and, potentially, put us at risk of breach covenants.

Restrictions in our credit facility limit our ability to make distributions in certain circumstances and limit our ability to enter into certain types of acquisitions and other business opportunities.

Our credit facility contains covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates. Furthermore, our credit facility contains covenants requiring us to maintain certain financial ratios and tests. Any subsequent replacement, restatement or amendment of our credit facility or any new indebtedness could impose similar or greater restrictions.

Increases in interest rates, which have recently experienced record lows, 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 recently have experienced record lows in interest rates. As the overall economy recovers from the current recessionary environment, it is likely that monetary policy will gradually tighten, resulting in higher interest rates to counter possible inflation. 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.

Shortages of drilling rigs, equipment and crews could delay our operations and reduce our cash available for distribution.

Under normal market conditions, higher oil and natural gas prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our and other operators’ ability to drill the wells and conduct the operations currently planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash available for distribution.

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;

• shortages or delays in the availability of drilling rigs 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; and

• uncontrollable flows of oil or natural gas or well fluids.

Any curtailment to the gathering systems used by operators could also require such operators to find alternative means to transport the oil and natural gas production from the underlying properties, which alternative means could require such operators to incur additional costs. We do not provide midstream services to all of our upstream activities.

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Any such curtailment, delay or cancellation may limit our ability to make cash distributions to our unitholders.

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. In 2008, we incurred total impairment charges of $174.9 million primarily as a result of lower expected commodity prices.  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.

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

We rely on the revenues generated from our midstream and upstream energy businesses, and as a result, our financial condition depends upon prices of, and continued demand for, natural gas, NGLs and condensate. While our fee mineral and royalty upstream properties are well diversified geographically, all of our midstream assets are located in the Texas Panhandle, East, West and South Texas and Louisiana and all of our upstream operated properties are located in West, East and South Texas and Alabama. 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.

We are exposed to the credit risks of our key sales customers, and any material nonpayment or nonperformance by our key sales customers could reduce our ability to make distributions to our unitholders.

We are subject to risks of loss resulting from nonpayment or nonperformance by our sales customers. Any material nonpayment or nonperformance by our key sales customers could reduce our ability to make distributions to our unitholders. Furthermore, some of our sales customers may be highly leveraged and subject to their own operating and regulatory risks, which could increase the risk that they may default on their obligations to us.

Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on our industry in general, and on us in particular, is not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

Risks Inherent in an Investment in Us

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units (including unvested restricted units under our Long Term Incentive Plan), subordinated units and general partner units at the initial distribution rate under our cash distribution policy.

In order to make our cash distributions at our initial distribution rate of $0.3625 per unit per complete quarter, or $1.45 per unit per year, we will require available cash of approximately $28.0 million per quarter, or $112.0 million per year, based on the common units (including restricted units under our Long Term Incentive Plan), subordinated units and general partner units outstanding as of December 31, 2008. We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

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• the fees we charge and the margins we realize for our services;

• the prices and level of production of and demand for, oil, natural gas, NGLs and condensate that we and others produce;

• the volume of natural gas we gather, treat, compress, process, transport and sell, the volume of NGLs we transport and sell, and the volume of oil and natural gas we and others produce;

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

• the level of competition from other upstream and midstream energy companies;

• the level of our operating and maintenance and general and administrative costs;

• the relationship between oil, natural gas and NGL prices; and

• prevailing economic conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

• the level of capital expenditures we make;

• the cost of acquisitions;

• our debt service requirements and other liabilities;

• fluctuations in our working capital needs;

• our ability to borrow funds and access capital markets;

• restrictions contained in our debt agreements; and

• the amount of cash reserves established by our general partner.

The amount of cash we have available for distribution to holders of our common units and subordinated 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.

Assuming our ownership structure as of December 31, 2008, the amount of available cash we need to pay the minimum quarterly distribution for four quarters on our outstanding common units and restricted units under our Long Term Incentive Plan is approximately $80.8 million. In addition, $1.2 million is a full four-quarter distribution on our general partner units, and a full distribution on our subordinated units is $30.0 million, totaling $112.0 million with the full distribution on outstanding common units and restricted units. The amount of our available cash generated during the year ended December 31, 2005 and the year ended December 31, 2006 would not have been sufficient to allow us to pay the full minimum quarterly distribution on our common units and subordinated units for those periods; however, it would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units.

We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy.

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 make short term borrowings 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 working capital 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.

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Eagle Rock Holdings, L.P., owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has conflicts of interest, which may permit it to favor its own interests.

Eagle Rock Holdings, L.P. (“Holdings”), owns and controls our general partner. Holdings is owned and controlled by the NGP Investors. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners, the NGP Investors. Conflicts of interest may arise between the NGP Investors and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

• neither our partnership agreement nor any other agreement requires the NGP Investors to pursue a business strategy that favors us;

• our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest;

• the NGP Investors and its affiliates are not limited in their ability to compete with us;

• our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

• our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;

• our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;

• our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

• our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

• our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

• our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

• our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

• our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets, drilling opportunities or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

Affiliates of our general partner are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, affiliates of our general partner may acquire, construct or dispose of additional midstream, upstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets.

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

We depend on the continuing efforts of our executive officers. The departure of any of our executive officers could have a significant negative effect on our business, operating results, financial condition, and on our ability to compete effectively in the marketplace. Additionally, the General Partner’s employees operate our business. Our General Partner's ability to hire, train, and retain qualified personnel will continue to be important and will become more challenging as we grow and if energy industry market conditions are positive. When general industry conditions are good, the competition for experienced operational and field technicians increases as other energy and manufacturing companies’ needs for the same personnel increases. Our ability to grow and perhaps even to continue our current level of service to our current customers will be adversely impacted if our General Partner is unable to successfully hire, train and retain these important personnel.

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Cost reimbursements due to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution.

Prior to making distribution on our common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us, including costs for rendering corporate staff and support services to us, and there is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that other parties have recourse only to our assets, and not against our general partner or its assets. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it. The partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

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 or our credit facility 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.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units.

Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise free of fiduciary duties to us and our unitholders, including determining how to allocate corporate opportunities among us and our affiliates. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include:

• its limited call right;

• its voting rights with respect to the units it owns;

• its registration rights; and

• its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

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Our partnership agreement restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:

• provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action in good faith, and our general partner will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation or at equity;

• provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, and our partnership agreement specifies that the satisfaction of this standard requires that our general partner must believe that the decision is in the best interests of our partnership;

• provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

• provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if the resolution of a conflict is:

• approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval;

• approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

• fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its

directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors, and will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of Eagle Rock Energy G&P, LLC, the general partner of our general partner, chosen by the members of Eagle Rock Energy G&P, LLC. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

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.

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Control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner or Eagle Rock Energy G&P, LLC, from transferring all or a portion of their respective ownership interest in our general partner or Eagle Rock Energy G&P, LLC to a third party. The new owners of our general partner or Eagle Rock Energy G&P, LLC would then be in a position to replace the board of directors and officers of Eagle Rock Energy G&P, LLC with its own choices and thereby influence the decisions taken by the board of directors and officers.

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;

• because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

• 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.

Affiliates of our general partner, certain private investors and employees, may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

Management of Eagle Rock Energy G&P, LLC, the general partner of our general partner and the NGP Investors and their affiliates (both through their interests in Eagle Rock Holdings and Montierra) and certain employees of Eagle Rock Energy G&P, LLC hold, as of December 31, 2008, an aggregate of 14,365,198 common units, including 905,486 common units which are still subject to a vesting requirement and 20,691,495 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period but may convert earlier.  In addition, we have issued 16,236,265 common units since our initial public offering to certain institutional investors through private investments in public equity (“PIPEs”). Based on recent amendments to Rule 144 as promulgated under the Securities Act of 1933, as amended, all common units issued by us in acquisitions other than the Millennium Acquisition and issued by us in certain private equity offerings are freely transferable, whereas the common units issued in the Millennium Acquisition are subject to resale only six months after the issuance date (i.e., six months from October 1, 2008 – April 1, 2009). Certain of the NGP Investors, as “control persons,” are not able to resell their securities without a valid registration statement.  Some of the common units held by certain of the NGP Investors are currently covered by an effective resale registration statement. 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. We also have entered into a registration rights agreement with Holdings and Montierra, which requires us to file with the SEC a registration statement registering for resale to the public Holdings’ and Montierra’s units.

Our general partner has a limited call right that may require limited partners to sell their units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, the limited partners may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Limited partners may also incur a tax liability upon a sale of units. As of December 31, 2008, our general partner and its affiliates owned approximately 25.8% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 45.9% of our outstanding common units.

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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.

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.

Filing of a free writing prospectus may result in certain purchasers of common units having a right to seek refunds or damages.

Prior to the effectiveness of our registration statement No. 333-144938, we participated in a business conference whereby we made available a slideshow presentation covering our current operating business through the third quarter of 2007, which was filed as a free writing prospectus to registration statement No. 333-144938 with the Commission. However, we later determined that we are an “ineligible issuer” and were not permitted to use a free writing prospectus in connection with an offering by selling unitholders. Subsequently, we furnished a current report on Form 8-K informing the public of our ineligible status for the free writing prospectus in this situation. We filed the slideshow as an exhibit to that registration statement.

A purchaser of our common units under the ineligible free writing prospectus could claim that the sale was in violation of Section 5 of the Securities Act of 1933, and in that specific circumstance, we could be required to grant rescission rights to such purchaser. Although, we have not sold any of our common units under the ineligible free writing prospectus and do not intend to sell any of our common units under the ineligible free writing prospectus, if proven that we did, we could have a potential liability arising out of this situation. We would vigorously defend any claim made in this regard. The amount of this liability, if any, is not known or determinable at this time and would depend, in part, upon the number of common units sold under the ineligible free writing prospectus and the trading price of our common units.

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Tax Risks to Common Unitholders

The tax efficiency of our partnership structure 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 were to treat us as a corporation or if we become subject to a material amount of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution.

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. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer to as the IRS, on this 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 distributions, 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 distribution 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.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation.  Any such changes could negatively impact the value of an investment in our common units. In addition, 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 a new entity level tax on the portion of our income that is generated in Texas during our tax year ending December 31, 2008.  Imposition of such a tax on us by any state, will reduce the cash available for distribution. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

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

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this report or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

We may adopt certain valuation methodologies that could result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may successfully challenge this treatment, which could adversely affect the value of the Common Units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of Common Units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders' sale of Common Units and could have a negative impact on the value of the Common Units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

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.

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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 use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. 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 loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, 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 to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Limited partners 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, limited partners 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.  Limited partners may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

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

If a limited partner sells common units, the limited partner 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 limited partner in excess of the total net taxable income allocated for a common unit, which decreased the limited partner’s tax basis in that common unit, will, in effect, become taxable income to the limited partner 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. In addition, if a limited partner sells units, the limited partner may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and foreign 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 (known as 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 reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If a limited partner is a tax-exempt entity or a foreign person, the limited partner 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 actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the limited partners. 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 limited partners.

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

We will be considered to have 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. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

Limited partners 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 limited partner 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 do business or own property, even if the limited partner does not live in any of those jurisdictions. A limited partner 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 limited partner may be subject to penalties for failure to comply with those 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 limited partner’s responsibility to file all United States federal, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

Item 1B. Unresolved Staff Comments.

We have no unresolved staff comments.

Item 2. Properties.

For a complete description of our significant properties, see Item 1. Business, which descriptions are incorporated into this item by this 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 have been subordinated to the rights-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.

Some of our leases, easements, rights-of-way, permits, licenses and franchise ordinances require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.

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 nor 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 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 Three Lines of Business and Our Seven Reporting Segments – Midstream Business.

Item 3. Legal Proceedings.

Our operations are subject to a variety of risks and disputes normally incident to our business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds.  As a result, we are and may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business.  However, we are not currently a party to any material litigation.  For several of our legal proceedings and litigation, we have been indemnified in whole or in part, as the result of a negotiated arrangement at the time of our acquisition of the assets to which those proceedings and/or litigation relate.  We also 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, assure you 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.

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In June 2008, the Texas Commission on Environmental Quality (“TCEQ”) issued a Notice of Enforcement (“NOE”) to one of our subsidiaries, TCEQ ID No.: CF-0068-J (the “First NOE”) and another NOE to another of our subsidiaries (TCEQ ID No.: CF-0070-W) (the “Second NOE”).  Both the First NOE and the Second NOE were the result of findings made by the TCEQ’s Amarillo Region Office as a result of routine inspections of our Cargray facilities in the Texas Panhandle.  These NOEs were consolidated into one docket during negotiations between the Company and TCEQ. On October 28, 2008, we executed an Agreed Order resolving with the TCEQ the two NOE matters by, among the things, payment of an administrative penalty and Supplemental Environmental Project payment which, in the aggregate, were less than $10,000. We consider these matters concluded.

On September 29, 2008, the TCEQ issued another NOE to one of our subsidiaries concerning the environmental compliance of our Red Deer Gas Plant; TCEQ ID No.: RH-0004-B (the “Third NOE”). The allegations in the Third NOE are also the result of findings made by the TCEQ’s Amarillo Region Office as a result of a routine inspection.  In response, our subsidiary took certain steps to come into compliance, and provided substantial documentation, some of which is corrective in nature, to the TCEQ. We also contested certain allegations. On December 5, 2008, TCEQ issued a proposed Agreed Order to us, offering settlement by, among other things, payment of an administrative penalty. On February 13, 2009, we executed this Agreed Order, paying an administrative penalty and Supplemental Environmental Project payment which, in the aggregate, were $46,072. We consider this matter concluded.

We have voluntarily undertaken a self-audit of our compliance with air quality standards, including permitting in the Texas Panhandle Segment as well as a majority of our other Midstream Business locations and some of our Upstream Business locations. This auditing has been and is being undertaken pursuant to the Texas Environmental, Health and Safety Audit Privilege Act, as amended. We have begun making the disclosures to the TCEQ as a result of the completion of the first of these self audits, and we are addressing in due course the deficiencies that we disclosed therein.  We do not foresee at this time any impediment to our successful conclusion of these audits and the resulting corrective effort.

Since 2008, we have received additional NOEs and a notice of violation from the TCEQ related to air compliance matters in the Texas Panhandle Segment.  One of the NOEs has been resolved for $2,575. We expect to receive additional NOEs or NOVs from the TCEQ from time to time throughout 2009.  Though the TCEQ has the discretion  to adjust penalties and settlements upwards based on a compliance history containing multiple, successive NOEs, we do not expect  that the resolution  of any existing NOE or any future similar  NOE will vary significantly from the administrative penalties and agreed settlements experienced by us to date.

Item 4. Submission of Matters to a Vote of Security Holders.

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 paid per quarter.

Quarter Ended	High		Low		Distribution per Unit		Record Date	Payment Date
March 31, 2007	$	20.88	$	18.56	$	0.3625	May 7, 2007	May 15, 2007
June 30, 2007	$	25.62	$	20.50	$	0.3625	Aug. 8, 2007	Aug. 14, 2007
September 30, 2007	$	27.64	$	19.75	$	0.3675	Nov. 8, 2007	Nov. 14, 2007
December 31, 2007	$	23.23	$	16.71	$	0.3925	Feb. 11, 2008	Feb. 14, 2008
March 31, 2008	$	18.71	$	12.90	$	0.4000	May 9, 2008	May 15, 2008
June 30, 2008	$	17.96	$	14.26	$	0.4100	Aug. 8, 2008	Aug. 14, 2008
September 30, 2008	$	16.56	$	10.00	$	0.4100	Nov. 7, 2008	Nov. 14, 2008
December 31, 2008	$	10.90	$	4.00	$	0.4100	Feb. 10, 2009	Feb. 13, 2009

_____________

We have also issued 20,691,495 subordinated units, for which there is no established market. There is one holder of record of our subordinated units as of the date of this Form 10-K.

The last reported sale price of our common units on the NASDAQ Global Select Market on February 27, 2009, was $4.65. As of that date, there were 178 holders of record and approximately 10,034 beneficial owners of our common units.

Cash Distribution Policy

We will 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;

• 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.

In addition to distributions on its 1.09% general partner interest, our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, our general partner is entitled, without duplication and in addition to its 1.09% general partner interest, to 13% of amounts we distribute in excess of $0.4169 per unit, 23% of the amounts we distribute in excess of $0.4531 per unit and 48% of amounts we distribute in excess of $0.5438 per unit.

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.

Sales of Unregistered Securities

On October 1, 2008, we issued 4,000,000 unregistered common units as partial consideration for our acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P.

Purchase of Common Units by Affiliates

On November 13, 2008, we announced that certain of our affiliates, Eagle Rock Holdings, L.P. and Montierra Minerals & Production, L.P., which are owned by certain members of Eagle Rock management, certain other individuals, and certain Natural Gas Partners investment funds,  authorized the purchase of up to an aggregate of $2,000,000 of our common units.  The purchases were authorized to occur between November 14, 2008 and December 5, 2008.  During this period, Eagle Rock Holdings, L.P. purchased 150,548 common units and Montierra Minerals & Production, L.P. purchased 47,978 common units  The common units were purchased through a systematic program of open market purchases in accordance with Rule 10b-18 under the Securities Exchange Act of 1934, as amended.  The total amount invested by Eagle Rock Holdings, L.P. and Montierra Minerals & Production, L.P. was $1.1 million and $0.3 million, respectively, inclusive of brokerage commissions.

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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, 2008 to October 31, 2008		—		—		—		—
November 1, 2008 to November 30, 2008		198,526	$	7.05		198,526	$	599,840.70
December 1, 2008 to December 31, 2008		—		—		—		—
Total		198,526	$	7.05		198,526	$	—

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Item 6. Selected Financial Data.

The following table shows selected historical financial data of our predecessor, ONEOK Texas Field Services L.P., and of Eagle Rock Pipeline, L.P. and Eagle Rock Energy Partners, L.P. ONEOK Texas Field Services, L.P. is treated as our and Eagle Rock Pipeline, L.P.’s predecessor and is referred to as “Eagle Rock Predecessor” throughout this report because of the substantial size of the operations of ONEOK Texas Field Services, L.P. as compared to Eagle Rock Pipeline, L.P. and the fact that all of Eagle Rock Pipeline, L.P.’s operations at the time of the acquisition of ONEOK Texas Field Services, L.P. related to an investment that was managed and operated by others. References in this report to “Eagle Rock Pipeline” refer to Eagle Rock Pipeline, L.P., which is the acquirer of Eagle Rock Predecessor and the entity contributed to us  in connection with our initial public offering.

Our historical results of operations for the periods presented below may not be comparable either from period to period or going forward, for the following reasons:

• On December 5, 2003, Eagle Rock Pipeline commenced operations by acquiring the Dry Trail plant from Williams Field Service Company for approximately $18.0 million, and in July 2004, Eagle Rock Pipeline sold the Dry Trail Plant to Celero Energy, L.P. for approximately $37.4 million, resulting in a pre-tax realized gain in the disposition of approximately $19.5 million in 2004. The Dry Trail operations are reflected as discontinued operations for Eagle Rock Pipeline for 2004.

• The purchase price paid in connection with the acquisition of Eagle Rock Predecessor on December 1, 2005 was “pushed down” to the financial statements of Eagle Rock Energy Partners, L.P. As a result of this “push-down” accounting, the book basis of our assets was increased to reflect the purchase price, which had the effect of increasing our depreciation expense.

• In connection with our acquisition of the Eagle Rock Predecessor, our interest expense subsequent to December 1, 2005 increased due to the increased debt incurred.

• After our acquisition of Eagle Rock Predecessor, we initiated a risk management program comprised of puts, costless collars and swaps for crude oil, natural gas and NGLs, as well as interest rate swaps that we account for using mark-to-market accounting. The amounts related to commodity hedges are included in unrealized/realized gain (loss) derivatives gains (losses) and the amounts related to interest rate swaps are included in interest expenses (income).

• The historical results of Eagle Rock Predecessor only include the financial results of ONEOK Texas Field Services L.P..

• Our historical financial results for periods prior to December 31, 2005 do not include the full financial results from the operation of the Tyler County pipeline.

• On March 27, 2006, Eagle Rock Pipeline completed a private placement of 5,455,050 common units for $98.3 million.

• On March 31, 2006 and April 7, 2006, a wholly-owned subsidiary of Eagle Rock Energy Partners, L.P. acquired certain natural gas gathering and processing assets from Duke Energy Field Services, L.P. and Swift Energy Corporation, consisting of the Brookeland gathering system and processing plant, the Masters Creek gathering system and the Jasper NGL pipeline. We refer to this acquisition as the Brookeland Acquisition. As a result, our historical financial results for the periods prior to March 31, 2006 do not include the financial results from the operation of these assets.

• On June 2, 2006, we purchased all of the partnership interests in Midstream Gas Services, L.P., which we refer to as the MGS Acquisition, an NGP affiliate, for approximately $4.7 million in cash and 809,174 (recorded value of $20.3 million) common units in Eagle Rock Pipeline. As a result, financial results for the periods prior to June 2006 do not include the financial results from the operation of these assets.

• On April 30, 2007, we acquired certain fee minerals, royalties and working interest properties through purchases directly from Montierra Minerals & Production, L.P. and through purchases directly from NGP-VII Income Co-Investment Opportunities, L.P., which we refer to as the Montierra Acquisition, for 6,458,946 (recorded value of $133.8 million) of our common units and $5.4 million in cash. As a result, financial results for the periods prior to May 2007 do not include the financial results from these assets.

• On May 3, 2007, we acquired Laser Midstream Energy, L.P. and certain of its subsidiaries, which we refer to as the Laser Acquisition, for $113.4 million in cash and 1,407,895 (recorded value of $29.2 million) of our common units. As a result, financial results for the periods prior to May 2007 do not include the financial results from these assets.

79

• On May 3, 2007, we completed the private placement of 7,005,495 common units for $127.5 million.

• On June 18, 2007, we acquired certain fee minerals and royalties from MacLondon Energy, L.P., which we refer to as the MacLondon Acquisition, for $18.2 million, financed with 757,065 (recorded value of $18.1 million) of our common units and cash of $0.1 million. As a result, financial results for the periods prior to July 2007 do not include the financial results from these assets.

• On July 31, 2007, we completed the acquisition of Escambia Asset Co. LLC and Escambia Operating Co. LLC, which we refer to as the EAC Acquisition, for approximately $224.6 million in cash and 689,857 (recorded value of $17.2 million) of our common units, subject to post-closing adjustment. As a result, financial results for the periods prior to July 31, 2007 do not include the financial results from these assets.

• On July 31, 2007, we completed the acquisition 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. (a Natural Gas Partners affiliate) which we refer to as the Redman Acquisition, for 4,428,334 (recorded value of $108.2 million) common units and $84.6 million. As a result, financial results for the periods prior to July 2007 do not include the financial results from these assets.

• On July 31, 2007, we completed the private placement of 9,230,770 common units for approximately $204.0 million.

• On April 30, 2008, we completed the acquisition of Stanolind Oil and Gas Corp., which we refer to as the Stanolind Acquisition, for an aggregate purchase price of $81.9 million in cash.  As a result, financial results for the periods prior to May, 2008 do not include the financial results from these assets.

• On October 1, 2008 we completed the acquisition of Millennium Midstream Partners, L.P., which we refer to as the Millennium Acquisition, for approximately $181.0 million in cash and 2,181,818 (recorded value of $24.2 million) of our common units. Additionally, 1,818,182 common units and $0.6 million in cash were placed into an escrow account. Prior to December 31, 2008, we recovered 40,880 common units and $0.3 million in cash from the escrow account.  As a result, financial results for the periods prior to October 2008 do not include the financial results from these assets.

The selected historical financial data as of and for the year ended December 31, 2004 and as of and for the eleven month period ended November 30, 2005 are derived from the audited financial statements of Eagle Rock Predecessor and as of and for the years ended December 31, 2004, and 2005 are derived from the audited financial statements of Eagle Rock Pipeline, L.P. The selected historical financial data as of and for the years ended December 31, 2006, 2007, and 2008 are derived from the audited financial statements of Eagle Rock Energy Partners, L.P.

The following table includes the non-GAAP financial measure of Adjusted EBITDA. We define Adjusted EBITDA as net income (loss) plus or (minus) income tax provision (benefit); interest-net, including realized interest rate risk management instruments 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; unrealized (gains) losses on commodity and interest rate risk management related instruments; and other (income) expense. Adjusted EBITDA is used as a supplemental financial measure by external users of Eagle Rock’s financial statements such as investors, commercial banks and research analysts. 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 reflects more accurately 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, by excluding unrealized derivative gains (losses), also describes more accurately the underlying performance of our operating assets by isolating the performance of our operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of our financial statements a more accurate picture of our current assets’ cash generation ability, independently from that of assets which are no longer a part of our operations. Eagle Rock’s 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 Eagle Rock. For example, we include in Adjusted EBITDA the actual settlement revenue created from our commodity hedges by virtue of transactions undertaken by us to reset commodity hedges to higher prices or purchase put 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.For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP (accounting principles generally accepted in the United States), please read “Summary—Non-GAAP Financial Measures.”

80

	Eagle Rock Predecessor						Eagle Rock Pipeline, L.P.						Eagle Rock Energy Partners, L.P.
	Year Ended December 31, 2004			Period from January 1, 2005 to November 30, 2005			Year Ended December 31, 2004			Year Ended December 31, 2005(1)			Year Ended December 31, 2006			Year Ended December 31, 2007			Year Ended December 31, 2008
Statement of Operations Data:
Sales to external customers	$	335,519		$	396,953		$	10,636		$	66,382		$	502,394		$	910,632		$	1,581,556
Unrealized derivative gains/(losses)		—			—			—			7,308			(26,306	)		(130,773	)		207,824
Realized derivative gains/(losses)		—			—			—			—			2,302			(3,061	)		(46,059	)
Total revenues		335,519			396,953			10,636			73,690			478,390			776,798			1,743,321
Cost of natural gas and NGLs		263,840			316,979			8,811			55,272			377,580			686,882			1,154,707
Operating and maintenance expense		25,219			25,326			34			2,955			32,905			52,793			73,620
Non-income based taxes		2,208			2,192			—			149			2,301			8,340			19,936
General and administrative expense		—			—			2,406			4,616			10,860			27,799			45,701
Other operating		—			—			—			—			—			2,847			10,699
Advisory termination fee		—			—			—			—			6,000			—			—
Depreciation, depletion and amortization expense		8,268			8,157			619			4,088			43,220			80,559			116,754
Impairment expense																	5,749			174,851
Operating income (loss)		35,984			44,299			(1,234	)		6,610			5,524			(88,171	)		147,053
Interest (income) expense		(646	)		(859	)		—			4,031			28,604			49,764			65,022
Other (income) expense		(23	)		(17	)		(24	)		(171	)		(996	)		7,530			(4,373	)
Income (loss) before income taxes		36,653			45,175			(1,210	)		2,750			(22,084	)		(145,465	)		86,404
Income tax provision		12,731			15,811			—			—			1,230			169			(1,116	)
Income (loss) from continuing operations		23,922			29,364			(1,210	)		2,750			(23,314	)		(145,634	)		87,520
Discontinued operations		—			—			22,192			—			—			—			—
Cumulative effect of change in accounting principle		—			—			—			—			—			—			—
Net income (loss)	$	23,922		$	29,364		$	20,982		$	2,750		$	(23,314	)	$	(145,634	)	$	87,520
Loss (income)  per common unit - diluted	$	—		$	—		$	—		$	—		$	(1.26	)	$	(2.11	)	$	1.20
Balance Sheet Data (at period end):
Property plant and equipment, net	$	243,939		$	242,487		$	19,564		$	441,588		$	554,063		$	1,207,130		$	1,357,609
Total assets		304,631			376,447			28,017			700,659			779,901			1,609,927			1,773,061
Long-term debt		—			—			—			408,466			405,731			567,069			799,383
Net equity		204,344			233,708			27,655			208,096			291,987			726,768			727,715
Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	41,813		$	47,603		$	3,652		$	(1,667	)	$	54,992		$	106,945		$	181,151
Investing activities		(5,567	)		(6,708	)		16,918			(543,501	)		(134,873	)		(475,790	)		(334,603	)
Financing activities		(36,246	)		(40,895	)		(13,955	)		556,304			71,088			426,816			102,816
Other Financial Data:
Cash distributions per Common Unit (declared)	$	—		$	—		$	—		$	—		$	0.2679		$	1.455		$	1.6125
Adjusted EBITDA(2)	$	44,275		$	52,473		$	(591	)	$	3,561		$	81,192		$	133,357		$	249,227

_____________________________________

(1) Includes historical financial and operating data for Eagle Rock Predecessor for the period from December 1, 2005 to December 31, 2005. Prior to the December 1, 2005 acquisition of the Eagle Rock Predecessor, the operations of Eagle Rock Pipeline, L.P. were minimal.

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

81

Non-GAAP Financial Measures

We include in this filing the following non-GAAP financial measure: Adjusted EBITDA (as defined on page 80). We provide reconciliations of this non-GAAP financial measure to its most directly comparable financial measures as calculated and presented in accordance with GAAP.

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

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 determined under GAAP, as well as Adjusted EBITDA, to evaluate our liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.  For example, we include in Adjusted EBITDA the actual settlement revenue created from our commodity hedges by virtue of transactions 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.

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	Eagle Rock Predecessor						Eagle Rock Pipeline, L.P.						Eagle Rock Energy Partners, L.P.
	Year Ended December 31, 2004			Period from January 1, 2005 to November 30, 2005			Year Ended December 31, 2004			Year Ended December 31, 2005(1)			Year Ended December 31, 2006			Year Ended December 31, 2007			Year Ended December 31, 2008
Reconciliation of “Adjusted EBITDA” to net cash flows provided by (used in) operating activities and net income (loss):
Net cash flows provided by (used in) operating activities	$	41,813		$	47,603		$	3,652		$	(1,667	)	$	54,992		$	106,945		$	181,151
Add (deduct):
Depreciation, depletion, amortization and impairment		(8,268	)		(8,157	)		(1,174	)		(4,088	)		(43,220	)		(86,308	)		(291,605	)
Amortization of debt issue cost		—			—			—			(76	)		(1,114	)		(1,777	)		(958	)
Risk management portfolio value changes		—			—			—			5,709			(23,531	)		(136,132	)		199,339
Reclassing financing derivative settlements		—			—			—			—			978			(1,667	)		(11,063	)
Other		(7,325	)		(1,559	)		—			(6	)		(7,566	)		(8,235	)		(4,433	)
Gain on sale of Dry Trail plant		—			—			19,465			—			—			—			—
Accounts receivable and other current assets		30,905			56,599			(901	)		43,179			1,432			16,579			(41,814	)
Accounts payable, due to affiliates and accrued liabilities		(34,705	)		(64,320	)		(169	)		(40,197	)		(8,777	)		(34,374	)		57,762
Other assets and liabilities		1,502			(802	)		109			(104	)		3,492			(665	)		(859	)
Net income (loss)		23,922			29,364			20,982			2,750			(23,314	)		(145,634	)		87,520
Add:
Interest (income) expense, net		(646	)		(859	)		—			2,432			30,383			44,587			38,260
Depreciation, depletion, amortization and impairment		8,268			8,157			619			4,088			43,220			86,308			291,605
Income tax provision (benefit)		12,731			15,811			—			—			1,230			169			(1,116	)
EBITDA		44,275			52,473			21,601			9,270			51,519			(14,570	)		416,269
Add:
Income from discontinued operations		—			—			(22,192	)		—			—			—			—
Risk management portfolio value changes		—			—			—			(5,709	)		23,531			144,176			(180,107	)
Restricted unit compensation expense		—			—			—			—			142			2,395			7,694
Other income		—			—			—			—			—			(696	)		(5,328	)
Other operating expense		—			—			—			—			6,000			2,847			10,699
Non-recurring operating items		—			—			—			—			—			(795	)		—
ADJUSTED EBITDA	$	44,275		$	52,473		$	(591	)	$	3.561		$	81,192		$	133,357		$	249,227

__________________

(1) Includes historical financial and operating data for Eagle Rock Predecessor for the period from December 1, 2005 to December 31, 2005.

(2) Includes $6.0 million to terminate an advisory fee for the year ended December 31, 2006, a settlement of arbitration for $1.4 million, severance to a former executive for $0.3 million and $1.1 million for liquidated damage related to the late registration of our common units during the year ended December 31, 2007 and $10.7 million related to bad debt expense taken against our outstanding accounts receivable from SemGroup during the year ended December 31, 2008.

83

The following table summarizes our quarterly financial data for 2008.

	For the Quarters Ended
	December 31, 2008			September 30, 2008(1)			June 30, 2008(1)			March 31, 2008(1)
	($ in thousands, except earnings per unit)
Sales of natural gas, NGLs and condensate	$	268,841		$	421,346		$	451,769		$	357,019
Gathering and treating services		11,130			12,513			8,085			7,143
Minerals and royalty income		8,388			17,393			10,255			6,958
Realized commodity derivative gains (losses)		18,329			(24,105	)		(27,708	)		(12,575	)
Unrealized commodity derivative gains (losses)		241,205			255,956			(256,265	)		(33,072	)
Other revenues		106			428			122			60
Total operating revenues		547,999			683,531			186,258			325,533
Cost of natural gas and NGLs		208,530			316,788			353,558			275,831
Operating and maintenance expense		23,809			21,475			17,731			15,566
General and administrative expense		14,540			15,258			15,289			15,589
Other operating expense		565			3,920			6,214			—
Depreciation, depletion, amortization and impairment expense		210,806			28,597			26,457			25,745
Interest—net including realized risk management instrument		9,499			9,856			9,418			9,205
Unrealized risk management interest related instrument		27,245			501			(13,689	)		13,660
Income tax (benefit) provision		366			(494	)		(886	)		(102	)
Other expense (income)		(2,158	)		(441	)		(814	)		(1,633	)
Net income (loss)	$	54,797		$	288,071		$	(227,020	)	$	(28,328	)
Earnings per unit—diluted
Common units	$	0.61		$	2.31		$	(3.14	)	$	(0.39	)
Subordinated units	$	0.61		$	2.31		$	(3.14	)	$	(0.39	)
General partner	$	0.61		$	2.31		$	(3.14	)	$	(0.39	)

_______________

(1) Prior quarterly periods’ financial data has been reclassified to conform to current period presentation.

The following table summarizes our quarterly financial data for 2007.

	For the Quarters Ended
	December 31, 2007(1)			September 30, 2007(1)			June 30, 2007(1)			March 31, 2007(1)
	($ in thousands, except earnings per unit)
Sales of natural gas, NGLs and condensate	$	312,275		$	254,084		$	191,621		$	110,121
Gathering and treating services		8,148			8,103			6,883			4,283
Minerals and royalty income		5,803			6,009			3,192			—
Realized commodity derivative gains (losses)		(7,385	)		(177	)		1,502			2,999
Unrealized commodity derivative gains (losses)		(100,240	)		8,865			(28,757	)		(10,641	)
Other revenues		130			(20	)		—			—
Total operating revenues		218,731			276,864			174,441			106,762
Cost of natural gas and NGLs		235,042			196,839			164,365			90,636
Operating and maintenance expense		20,754			19,629			12,124			8,626
General and administrative expense		11,212			7,196			5,171			4,220
Other operating expense		916			220			—			1,711
Depreciation, depletion, amortization and impairment expense		35,424			25,105			14,149			11,630
Interest—net including realized risk management instrument		10,826			10,075			8,025			7,435
Unrealized risk management interest related instrument		9,848			8,429			(6,485	)		1,611
Income tax (benefit) provision		(603	)		352			256			164
Other expense (income)		6,866			(352	)		619			397
Net (loss) income	$	(111,554	)	$	9,371		$	(23,783	)	$	(19,668	)
Earnings per unit—diluted
Common units	$	(1.55	)	$	0.25		$	(0.28	)	$	(0.28	)
Subordinated units	$	(1.55	)	$	(0.09	)	$	(0.71	)	$	(0.64	)
General partner	$	(1.55	)	$	(0.09	)	$	(0.71	)	$	(0.64	)

_______________

(1) Prior quarterly periods’ financial data has been reclassified to conform to current period presentation.

84

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. The following discussion of our financial condition and results of operations 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 three businesses:

• Midstream Business—gathering, compressing, treating, processing and transporting of natural gas; fractionating and transporting of natural gas liquids (“NGLs”); and the marketing of natural gas, condensate and NGLs;

• Upstream Business—acquiring, developing and producing oil and natural gas property interests; and

• Minerals Business—acquiring and managing fee minerals and royalty interests, either through direct ownership or through investment in other partnerships.

We report on our businesses in seven accounting segments.

We conduct, evaluate and report on our Midstream Business within four distinct segments—the Texas Panhandle Segment, the East Texas/Louisiana Segment, the South Texas Segment and the Gulf of Mexico Segment. Our Texas Panhandle Segment consists of gathering and processing assets in the Texas Panhandle. Our East Texas/Louisiana Segment consists of gathering and processing assets in East Texas/Northern Louisiana. Our South Texas Segment consists of gathering systems and related compression and processing facilities in South Texas, Central Texas, and West Texas.   Our Gulf of Mexico Segment consists of gathering and processing assets in Southern Louisiana, the Gulf of Mexico and Galveston Bay.  During the year ended December 31, 2008, our Midstream Business generated operating income of $58.2 million, compared to operating income of $57.0 million generated during the year ended December 31, 2007, an increase of 2.1%.  The operating income generated during the year ended December 31, 2008 was offset by an impairment charge to certain assets of $35.1 million.

We conduct, evaluate and report on our Upstream Business as one segment. Our Upstream Segment includes operated wells in Escambia County, Alabama as well as two treating facilities, one natural gas processing plant and related gathering systems that are inextricably intertwined with ownership and operation of the wells. The Upstream Segment also includes operated and non-operated wells that are primarily located in West, East and South Texas in Ward, Crane, Pecos, Henderson, Rains, Van Zandt, Limestone, Freestone and Atascosa Counties.  During the year ended December 31, 2008, our Upstream Business generated an operating loss of $47.5 million, compared to operating income of $19.6 million generated during the year ended December 31, 2007.  The operating loss generated during the year ended December 31, 2008 was primarily due to impairment charges of $107.0 million and $31.0 million to write down the value of certain fields and goodwill, respectively.  Of important note, during 2008, our Upstream Business had eight months of operations from the assets acquired in the Stanolind Acquisition and a full year of the other assets acquired in acquisition during 2007 and our Upstream Business generated revenue of $37.8 million from the sale of sulfur during the year ended December 31, 2008 compared to revenue of $2.6 million during the year ended December 31, 2007.

We conduct, evaluate, and report our Minerals Business as one segment.  Our Minerals Segment consists of fee mineral, royalty and overriding royalty interests located in multiple producing trends in the United States.  A significant portion of the mineral interests that we own are managed by a non-affiliated private partnership (the “Minerals Manager”) that controls the executive rights associated with the minerals.  For a more detailed discussion of this relationship, see Part I, Item 1. Business – Minerals Business.  During the year ended December 31, 2008, our Minerals Segment generated operating income of $31.8 million, compared to $0.5 million generated during the year ended December 31, 2007.  Included within these numbers is $16.8 million of lease bonus revenue generated during the year ended December 31, 2008 compared to $1.3 million of lease bonus revenue generated during the year ended December 31, 2007.  During the year ended December 31, 2008, as a result of the regeneration phenomenon we received an initial royalty payment for 304 new wells.  During the year ended December 31, 2008, we recorded an impairment charge of $1.7 million compared to an impairment charge of $5.7 million recorded during the year ended December 31, 2007.

The final segment that we report on is our Corporate Segment, which is where we account for our commodity derivative/hedging activity and our general and administrative expenses.   During the year ended December 31, 2008, our Corporate Segment generated operating income of $104.6 million compared to an operating loss of $165.2 million generated during the year ended December 31, 2007.  Within these numbers were gains, realized and unrealized, on commodity derivatives of $161.8 million during the year ended December 31, 2008 compared to a loss, realized and unrealized, on commodity derivatives of $133.8 million during the year ended December 31, 2007.  The gain generated by our commodity derivatives during the year ended December 31, 2008 was the result of the decline in commodity prices during the fourth quarter of 2008.

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Impairment

In connection with preparation and audit of our Consolidated Financial Statements for the year ended December 31, 2008, which are included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report, we determined that we needed to record an impairment charge for certain plants and pipelines within our Midstream Business and certain fields within our proved properties within our Upstream and Minerals Segments.  These impairment charges were necessary due to the substantial decline in commodity prices during the fourth quarter of 2008, as well as declining drilling activity.  As a result, we incurred impairment charges of $35.1 million in our Midstream Business, $107.0 million in our Upstream Segment and $1.7 million in our Minerals Segment.  Due to the impairment charge recorded in our Upstream Segment, we assessed our goodwill balance for impairment and recorded an impairment charge of $31.0 million.

Pursuant to generally accepted accounting principles in the United States, 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.

Acquisitions

Historically, we have grown through acquisitions.  With the Stanolind Acquisition, described below, completed at the beginning of the second quarter of 2008, we expanded our Upstream Business. At the beginning of the fourth quarter we completed the Millennium Acquisition, described below, which expanded our Midstream Business.

Going forward, we will continue to assess acquisition opportunities, regardless of whether such opportunity is in the Midstream, Upstream, or Minerals Business, for their potential accretive value. Our ability to complete acquisitions will depend on our ability to finance the acquisitions, either through the issuance of additional securities, debt or equity, or the incurrence of additional debt under our credit facilities, on terms acceptable to us.

Below is a summary of our important acquisition transactions completed during 2008.

Stanolind Acquisition - On April 30, 2008, we completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (“Stanolind”), for an aggregate purchase price of $81.9 million, subject to working capital and other purchase price adjustments (the “Stanolind Acquisition”).  We funded the transaction from existing cash from operations, as well as with borrowings under our existing secured revolving credit facility.  Stanolind operated crude oil and natural gas producing properties in the Permian Basin of West Texas, primarily in Ward, Crane and Pecos Counties.

Millennium Acquisition - On October 1, 2008, we completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”) for an aggregate purchase price of $225.9 million, comprised of approximately $181.0 million in cash and 2,181,818 (recorded value of $24.2 million) common units and subject to post-closing purchase price adjustments (the “Millennium Acquisition”).  Additionally, 1,818,182 common units and $0.6 million in cash were placed into an escrow account. The cash portion of the consideration was funded through borrowings of $176.4 million under our secured revolving credit facility made prior to September 30, 2008 and through cash on hand.  MMP is in the natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana.  With respect to the South Louisiana assets acquired in the Millennium Acquisition, both the Yscloskey and North Terrebonne facilities were flooded with three to four feet of water as a result of the storm surges caused by Hurricanes Ike and Gustav.  We have reported, are preparing to file claims for, and expect to receive payment on our business interruption insurance coverage related to hurricanes Ike and Gustav’s damage to these two facilities. The timing of collection of such insurance claims is unknown at this time.  The North Terrebonne Plant restarted service in November 2008 and the Yscloskey Plant restarted service in January 2009.  The former owners of MMP provided us indemnity coverage for Hurricanes Ike and Gustav to the extent losses are not covered by insurance and established an escrow account of 1,818,182 common units and $0.6 million in cash available for us to recover against for this purpose.  Prior to December 31, 2008, we recovered 40,880 units and $0.3 million in cash from this escrow account.  Subsequent to December 31, 2008, we recovered 65,841 common units and the remaining $0.3 million in cash from the escrow account and we expect to recover additional amounts in the future.

Below is a summary of the important acquisition transactions we completed during the year ended December 31, 2007.   A more complete description of these acquisitions is contained in Note 4 of our consolidated financial statements included in Part II, Item 8, Financial Statements and Supplementary Data starting on page F-1 of this Annual Report.

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Montierra Acquisition - On April 30, 2007, we completed the acquisition of (by direct acquisition or acquisition of certain entities) certain fee minerals, royalties, working interest properties and certain investments in partnerships from Montierra Minerals & Production, L.P. and NGP-VII Income Co-Investment Opportunities, L.P. (the “Montierra Acquisition”).

Laser Acquisition - On May 3, 2007, we acquired all of the non-corporate interests of Laser Midstream Energy, LP and certain subsidiaries (the “Laser Acquisition”).

MacLondon Acquisition - On June 18, 2007, we completed the acquisition of certain fee mineral and royalties owned by MacLondon Energy, L.P.

Escambia Acquisition - On July 31, 2007, we completed the acquisition of Escambia Asset Co. LLC and Escambia Operating Co. LLC (the “Escambia Acquisition”).

Redman Acquisition - On July 31, 2007, we completed the acquisition 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. (the “Redman Acquisition”).

Prior to the above 2007 acquisitions the Partnership was solely a midstream company.  The Montierra Acquisition, (followed quickly by the MacLondon Acquisition) provided the Partnership’s entry into the Minerals Business and the EAC and Redman acquisitions provided the Partnership’s entry into the Upstream Business.

Other Matters

Hurricanes Ike and Gustav - Hurricane Ike, which made landfall in Texas on September 13, 2008, caused no direct damage to our offices or facilities except for certain assets acquired in the Millennium Acquisition, as described above; however, the storm did cause temporary operational disruption to our operations located in East Texas, North Louisiana and South Texas due to third-party downstream infrastructure issues. Operations were either temporarily interrupted or curtailed during and immediately after the storm due to power disruptions suffered by third parties causing natural gas and natural gas liquids supply and market issues. All of our operations returned to pre-hurricane levels within ten days after the storm.  Our assets, except for certain assets acquired in the Millennium Acquisition, as described above, were not impacted by Hurricane Gustav.

Recent Transactions

On January 8, 2009, we executed a series of hedging transactions that involved the unwinding of a portion of existing “in-the-money” 2011 and 2012 WTI crude oil swaps and collars, and the unwinding of two “in-the-money” 2009 WTI crude oil collars. With these transactions, and an additional $13.9 million of cash, we purchased a 2009 WTI crude oil swap on 60,000 barrels per month beginning January 1, 2009 at $97 per barrel. Both the unwound hedges and new hedges relate to expected volumes in our Midstream and Minerals segments.  These transactions were executed to enhance our expected 2009 cash flows and our ability to maintain our current distribution level of $1.64 per unit on an annual basis and our ability to remain in compliance with our credit facility financial covenants. The actual distributions we will declare will be subject to our operating performance, prevailing market conditions (including forward oil, natural gas and sulfur commodity prices), the impact of unforeseen events and the approval of our Board of Directors and the actual distributions will be pursuant to our distribution policy described in Part II, Item 5 Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities – Cash Distribution Policy.

In addition to the hedging transactions discussed above, we also entered into a 125,000 MMBtu per month Henry Hub natural gas swap at $6.65/MMBtu on January 19, 2009 for our 2009 fiscal year, a 170,000 MMBtu per month Henry Hub natural gas swap at $6.14/MMBtu on February 17, 2009 for our 2010 fiscal year, a 45,000 barrel per month WTI crude oil swap at $53.55 per barrel on February 17, 2009 for our 2010 fiscal year and a 40,000 barrel per month WTI crude oil swap at $51.40 per barrel on February 19, 2009 for our 2010 fiscal year.

How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements to analyze our performance. We view these measurements as important factors affecting our profitability and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, margin, operating expenses and Adjusted EBITDA (defined on page 80) on a company-wide basis.

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Volumes (by Business)

Midstream Volumes. In our Midstream Business, 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) the level of workovers or recompletions of existing connected wells and successful drilling activity 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.

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.

Minerals Volumes. Our Minerals Segment assets are comprised of royalty, overriding royalty, non-producing mineral, and  therefore, we do not operate any of these properties. In order to maintain or increase our cash flows from our Minerals Segment, we rely upon the efforts of the operators of our interests. We do not control whether or when additional drilling or recompletion activity will be conducted on the properties in which we have an interest; however, when these activities do occur, we do not bear any of their costs.  Nevertheless, at any time, there is often a significant amount of drilling and recompletion activity occurring on the properties in which we own an interest yielding us a cost-free “regeneration effect” on mineral and royalty interests. We monitor the additional production volumes that we realize from regeneration, and we use this information to make adjustments to our reserves estimates on a regular basis. These adjustments to our reserves (as a result of the regeneration effect) are important measures of the performance of our Minerals Segment.  During the year ended December 31, 2008, as a result of the regeneration phenomenon we received an initial royalty payment for 304 new wells.

Commodity Pricing

Our margins in our Midstream Business may be positively impacted to the extent the price of NGLs increase in relation to the price of natural gas and may be adversely impacted to the extent the price of NGLs decline 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 both our Upstream and Minerals Segments, increases in crude oil, natural gas and NGL prices will generally have a favorable impact our revenues, conversely, decreases in crude oil, natural gas and NGL prices will generally unfavorably impact on our revenue.

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. To execute and evaluate the performance of these activities, we have formed a Risk Management Committee which is comprised of several members of our senior management team and other key employees. In addition to establishing the procedures and controls associated with risk management activities, the Risk Management Committee meets regularly to review the hedge portfolio and make recommendations for additional hedges. The Risk Management Committee routinely estimates the potential effect of price and interest rate fluctuations on the expected future cash flows associated with our operations, and the Risk Management Committee evaluates whether the hedges sufficiently mitigate the effect of these fluctuations. The impact of our risk management activities are captured in our Corporate Segment.

Operating Expenses

Midstream Operating Expenses. Midstream operating expenses are a separate measure we use to evaluate the performance of our field operations. Direct labor, insurance, 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.

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 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, materials, and insurance.

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Minerals Operating Expenses. We do not incur any operating costs associated with our Minerals Segment due to the non-cost-bearing nature of the mineral and royalty assets.

Adjusted EBITDA

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

General Trends and Outlook

We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

The most significant external events impacting our business are the worldwide credit crisis that was precipitated by the United States subprime mortgage market collapse, and the resulting global economic recession.  The recession has led to a significant reduction in demand for the commodities that we produce, transport and/or process.

The government of the United States and the governments of many other developed and developing nations have already taken, and are contemplating additional, significant actions to stabilize their banking systems and to increase consumption to stimulate economic growth.  Although these actions are of unprecedented size and scope, we do not believe that they will restore demand for our products in 2009 to the levels that we observed in early 2008.

Natural Gas Supply and Demand

Natural gas is a significant source of energy and raw materials in the United States.  Over the last several years, supply of natural gas remained fairly steady, while demand gradually increased.  In the early part of the current decade, supply and demand came into balance and natural gas prices began to rise.

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However, over the last half of 2008, the global economic recession resulted in greatly reduced demand for natural gas.  This reduction in demand has occurred at the same time that large amounts of additional natural gas supply are being developed in various shale gas plays in the United States.  The development of some of these shale gas plays has been so successful that the decline in United States per well natural gas production has been reversed for the first time in many years. The confluence of reduced demand and increased domestic supply caused natural gas prices to fall dramatically in the United States.  Natural gas is currently about $4.50/mmbtu at Henry Hub.

We do not expect that significant economic growth will occur in the United States and global economies during 2009, and we believe it will be at least several months before reduced levels of drilling activity will lead to lower production rates.  Therefore, with demand low and unlikely to increase quickly, and with supply strong and unlikely to decline quickly, we believe that natural gas prices will be low (relative to the last couple of years) throughout 2009 and at least throughout the first portion of 2010.

Other factors which we do not believe will affect the price of natural gas in the near term, but potentially could, are liquified natural gas (LNG) imports and the development of alternative energy sources.  With respect to LNG imports, we have noted that the amount of LNG delivered to United States terminals has declined significantly, to the point where it can not be considered a meaningful source of supply.  Nevertheless, despite the low prices we anticipate in the United States natural gas market, LNG exporters may find that prices in other markets have suffered, as well.  Atlantic Basin LNG suppliers may view the United States as their most attractive market, and the additional supply they could bring would put additional downward pressure on prices.

Alternative energy sources are generally more expensive than fossil fuels and are unlikely to displace fossil fuels at their current prices.  It is possible, however, that the expected investment in alternative energy sources contemplated in the United States economic stimulus legislation could result in either lower costs for these technologies (through successful research) or could result in economic subsidies intended to make these fuels more competitive.  We do not think these scenarios are likely in 2009, however.

Petroleum Supply, Demand and Outlook

Petroleum, primarily in the form of crude oil, condensate, and NGLs, plays a critical role in the United States and world economies. It is a primary source of energy, especially for transportation, and its components are used in an extensive number of manufacturing processes. Many of the characteristics of modern civilization, particularly in the industrialized countries, are a result of the abundance, utility, and relatively low cost of petroleum. The supply and demand of petroleum is a very complex matter; however, we have made the following observations about current trends.

As was the case for many commodities in 2008, demand for crude oil reached all-time highs, and record high prices (both real and nominally) were observed.  Much of the growth in demand for crude oil was fueled by the continued strong growth of several developing economies, particularly China, Russia, India, and certain countries in the Middle East.  Nevertheless, the global economic recession has resulted in substantially lower demand for crude oil, and the price for the prompt month NYMEX futures contract has fallen from nearly $150/bbl in July 2008 to about $40/bbl in February 2009.  As shown below, spot prices have experienced a similar rise and fall.

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We expect crude oil demand to remain below last year’s levels until economic growth resumes.  With respect to supply, however, we have observed that the members of the Organization of Petroleum Exporting Countries (“OPEC”) have made several recent reductions in their production quotas.  We are uncertain how well OPEC’s members will adhere to their quotas, and how successful they will be in reducing crude oil supply to a level that will support higher prices.  We believe that their efforts have had some measure of success, and that without their actions prices would be lower.  Because OPEC’s members have had a mixed record of adhering to their production quotas, we are not optimistic that enough supply will be removed from the market to result in a significant price increase during 2009.  We believe there is a reasonable probability that prices will decline below current prices before prices begin to strengthen.

Sulfur Supply, Demand and Outlook

Much of the natural gas that we produce in 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 before it can be processed for NGL extraction or sale.  The process of removing the hydrogen sulfide yields a large amount of elemental sulfur, and we can sell this co-product or otherwise dispose of it.  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.  Phosphoric acid is a key raw material in the manufacture of phosphate fertilizers, so 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 port for sulfur.  For many years, the supply of sulfur was greater than the available demand, such that Tampa prices fluctuated within a narrow band of $20 to $40 per long ton.  Some North American sources of sulfur are large distances from Tampa, so those sellers might have received very little revenue for their sulfur, or actually had a net expense to move their sulfur co-product.

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Beginning in the second half of 2007, demand for fertilizer increased significantly, and the Tampa prices also rose to record levels.  By the fourth quarter of 2008, sulfur prices at Tampa were over $600 per long ton.  The global economic recession has greatly reduced fertilizer demand, however, and consequently, demand for sulfur is also much lower than it was only a few months ago.  By the end of 2008, Tampa sulfur prices had fallen to $0 (zero dollars) per long ton, resulting in a net expense for sellers to move their sulfur.

Our expectations are for sulfur demand to increase back to historical levels as fertilizer manufacturers deplete their excess inventories.  Nevertheless, if the global economic recession worsens, sulfur prices could stay depressed throughout the year.

Outlook for Interest Rates and Inflation

The turmoil in worldwide capital markets makes it difficult to formulate a clear outlook of future interest and inflation rates.  We have observed that many key benchmark interest rates are at very low levels, despite heavy borrowing by the U.S. Treasury.  We believe this reflects a high degree of risk aversion by all types of investors due to the great uncertainty regarding the likely returns of virtually all other investment types.  Despite this, we have observed that many interest rates of riskier securities (consumer and corporate debt, for instance) are very high by historical standards and these types of credit are difficult to obtain.  We expect that both of these conditions will persist during 2009.

Nevertheless, we believe as order is restored in the financial system, and economic growth resumes, investors will seek opportunities to generate higher returns.  This could lead to increased interest rates as the U.S. Treasury finds it harder to sell bonds at the current low rates.  Also, a potential excess of dollars in the economy as a result of spending related to economic stimulus efforts may cause an increase in inflation.  If this were to occur, the government may find that monetary policy actions are needed to reduce inflation, which would also lead to higher interest rates.  It is difficult for us to predict if and when such a scenario might occur, and during the near term, we believe that the threat of inflation is very low.  In fact, if the U.S. government’s efforts to restore the banking system and stimulate the economy are unsuccessful, deflation will be a possibility.

Impact of Credit and Capital Market Turmoil

As a direct consequence of the collapse of the sub-prime mortgage and housing markets that began in the summer of 2007 and their corollary impact on the banking and financial industry in general, bank lending and capital markets have experienced a significant contraction. This generalized and world-wide condition of reduced credit availability and downward pressure on the value of debt obligations and equity prices has persevered throughout 2008 and into 2009. Specifically among Master Limited Partnerships, which rely on credit and capital markets to finance their acquisition and organic growth projects, this diminished availability of external capital, made worse by a low commodity price environment has in the short term, effectively closed access to traditional external financing sources for all but the largest investment grade partnerships.

As governments around the world enact policies designed to restore the health of the banking industry and promote growth in their respective economies, we believe that credit and access to capital markets will gradually return. When such favorable conditions become prevalent again, we believe we will be able to obtain external financing in the credit and capital markets which will allow us to resume our growth strategy through acquisitions and organic growth projects. In the meantime, we have reduced our growth and maintenance capital expenditure budget for 2009 and are only pursuing highly accretive potential acquisitions which could be financed in the current financial market environment.

Impact of Regulation of Greenhouse Gas Emissions

The natural gas and oil industry is a source of emissions of certain greenhouse gases, namely carbon dioxide and methane  Regulation of greenhouse gas emissions has not had an impact on our operations in the past and regulation of our greenhouse gas emissions as such has not occurred.   However, there is a trend towards government-imposed limitations on greenhouse gas emissions at the state, regional, and federal level.  Although there are still significant uncertainties regarding future federal regulation in the U.S., a reasonably broad-based consensus for federal legislation, involving either a cap-and-trade program or a carbon tax, is forming.  Many significant uncertainties remain about the timing, nature, and effect of any such action.  Consequently, at this time, we are unable to forecast how future regulation of greenhouse gas 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.

Critical Accounting Policies

Conformity with accounting principles generally accepted in the United States requires management to make estimates and judgments that affect the amounts reported in the financial statements and notes. On an on-going basis, we make and evaluate estimates and judgments based on management’s best available knowledge of previous, current, and expected future events. Given that a substantial portion of our operations were acquired within the past 12 to 24 months, 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. We have selected the following critical accounting policies that currently affect our financial condition and results of operations for discussion.

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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, including dry holes, 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. Statement of Financial Accounting Standards (“SFAS”) No. 19, Financial Accounting and Reporting for Oil and Gas Producing Companies 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.  In the case of our Minerals Segment, we only claim proved, producing reserves because, as a mineral interest owner, we lack sufficient engineering and geological data to estimate the proved undeveloped and non-producing reserve quantities and because we cannot control the occurrence or the timing of the activities that would cause such reserves to become productive. Since our units of production depletion and amortization rate is 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.

In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, 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. During the year ended December 31, 2008, we incurred impairment charges related to certain fields of $107.0 million and $1.7 million in our Upstream and Minerals Segments, respectively, due to the substantial decline in commodity prices during the fourth quarter of 2008.  During the year ended December 31, 2007, we incurred an impairment charge in our Minerals Segment of $5.7 million as a result of steeper decline rates in certain fields.

Unproved properties that are individually insignificant are amortized. Unproved properties that are individually significant are assessed for impairment on a property-by-property basis. If considered impaired, costs are charged to expense when such impairment is deemed to have occurred.

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

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described 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.

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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.

Revenue and Cost of Goods Sold Recognition. In our Midstream Business, we record revenue and cost of goods sold on the gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that is purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating or transportation we record the fees separately in revenues.

Risk Management Activities. We have structured our hedging activities in order to minimize our commodity pricing and interest rate risks. 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.  We have currently hedged approximately 88% of our forecasted 2009 hedgeable crude, condensate and natural gas liquids (heavier than propane) and 93% of our net natural gas and ethane production.  We have currently hedged approximately 90% of our anticipated 2010 hedgeable crude, condensate and natural gas liquids (heavier than propane) and 90% of our net natural gas and ethane production.

From the inception of our hedging program, we used mark-to-market accounting for our commodity hedges and interest rate swaps. There were no derivatives for the periods before September 30, 2005. We record monthly realized gains and losses on hedge instruments based upon cash settlements information. The settlement amounts vary due to the volatility in the commodity market prices throughout each month. We also record unrealized gains and losses monthly based upon the future value on mark-to-market hedges through their expiration dates. The expiration dates vary but are currently no later than December 2012 for our interest rate hedges and for our commodity hedges. Option premiums and costs incurred to reset contract prices or purchase swaps are amortized during the contract period through the unrealized risk management instruments in total revenue. We monitor and review hedging positions regularly.

Depreciation and Depletion 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 costs of funds used in construction. The cost of funds used in construction represents 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 included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report, 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 based on SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

Examples of long-lived asset impairment indicators 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.

During the year ended December 31, 2008, we incurred impairment charges related to certain processing plants and contracts within our Midstream Business of $35.1 million due to the substantial decline in commodity prices during the fourth quarter of 2008.

Goodwill Impairment. We assess our goodwill for impairment annually or whenever events indicate impairment may have occurred based on SFAS No. 142, Goodwill and Other Intangible Assets..  We performed our annual assessment in May 2008 and no impairment was evident at that point in time.  As a result of the impairment charge recorded in our Upstream Segment, we performed an assessment of our goodwill during the fourth quarter and recorded an impairment charge of $31.0 million, or our entire goodwill balance, during the fourth quarter of 2008.

Environmental Remediation. Current accounting guidelines require us to recognize a liability and expense associated with environmental remediation if (i) government agencies mandate such activities or one of our properties were added to the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) database, (ii) the existence of a liability is probable and (iii) the amount can be reasonably estimated. As of December 31, 2008, we have recorded an $8.6 million liability for remediation expenditures. If governmental regulations change, we could be required to incur additional remediation costs which may have a material impact on our profitability.

Asset Retirement Obligations. Eagle Rock has recorded liabilities of $19.9 million for future asset retirement obligations in its midstream and upstream operations. Related accretion expense has been recorded in operating expenses, as discussed in Note 5 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report.

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, 2008 Compared with Year Ended December 31, 2007

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the years ended December 31, 2008 and December 31, 2007. Operating results for our individual operating segments are presented in tables in this Item 7.

	Year Ended December 31,
	2008			2007
	($ in thousands)
Revenues:
Sales of natural gas, NGLs, oil, condensate and sulfur	$	1,498,975		$	868,101
Gathering, compression, processing and treating fees		38,871			27,417
Minerals and royalty income		42,994			15,004
Realized commodity derivative gains (losses)		(46,059	)		(3,061	)
Unrealized commodity derivative gains (losses)		207,824			(130,773	)
Other		716			110
Total revenues		1,743,321			776,798
Cost of natural gas and natural gas liquids		1,154,707			686,882
Costs and expenses:
Operating and maintenance		73,620			52,793
Taxes and other income		19,936			8,340
General and administrative		45,701			27,799
Other operating expense		10,699			2,847
Depreciation, depletion and amortization		116,754			80,559
Impairment expense		143,857			5,749
Goodwill impairment expense		30,994			—
Total costs and expenses		441,561			178,087
Total operating income (loss)		147,053			(88,171	)
Other income (expense):
Interest income		793			1,160
Other income		5,328			696
Interest expense, net		(32,884	)		(38,936	)
Unrealized interest rate derivatives gains (losses)		(27,717	)		(13,403	)
Realized interest rate derivative gains (losses)		( 5,214	)		1,415
Other expense		(955	)		(8,226	)
Total other income (expense)		(60,649	)		(57,294	)
Income (loss) before taxes		86,404			(145,465	)
Income tax (benefit) provision		(1,116	)		169
Net income (loss)	$	87,520		$	(145,634	)
Adjusted EBITDA(a)	$	249,227		$	133,357

_____________

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

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Midstream Business (Four Segments)

Significant Acquisitions and Organic Growth Projects in 2008

The Millennium Acquisition, completed in October 2008 (hereinafter, the period of operation from October 2 through December 31, 2008, (the “Millennium Covered Period”), contributed a number of gathering and processing assets to the Midstream Business. The assets expanded the East Texas/Louisiana Segment and the South Texas Segment and created the Gulf of Mexico Segment. The assets acquired consisted of:

• Approximately 679 miles of natural gas gathering pipelines ranging in size from four inches to 20 inches in diameter.

• Compression stations with approximately 12,500 aggregate horsepower.

• Two cryogenic processing plants (non-operated), in which we own a 14.26% and 7.74% interest, respectively, consisting of processing and related facilities for an aggregate capacity of 369 MMcf/d.

• A 30,000 Bbl/d NGL fractionation plant (non-operated), in which we own a 7.74% interest.

We also completed a number of capacity expansion projects during 2008.  In the Texas Panhandle Segment, we installed an additional 2600 horsepower of compression at two sites to provide additional capacity of approximately 7 MMcf/d and lower gathering pressures for the producers.  In addition we completed the shut-down of the Stinnett Plant and the consolidation of the volumes from the Stinnett Plant into the Cargray Plant resulting in increased operating efficiencies.  In the East Texas/Louisiana Segment, we completed the connection of our Panola system to a processing plant owned by a third party, increasing the recovered NGLs on the Panola system;  we expanded the capacity of the ETML system by 120 MMcf/d; and we expanded the Brookeland and Tyler County systems by 12.7 miles to continue to keep pace with drilling activity in the Austin Chalk play.  In the South Texas Segment, we completed the expansion of the Kelsey Compressor station, adding an additional 12 MMcf/d of outlet capacity to our Phase 1 20” pipeline system.

Texas Panhandle Segment

	Twelve Months Ending December 31,
	2008			2007
	($ in thousands, except for realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	592,997		$	479,120
Gathering and treating services		10,069			8,910
Total revenues		603,066			488,030
Cost of natural gas and natural gas liquids		459,064			372,205
Operating costs and expenses:
Operations and maintenance		34,269			32,494
Depreciation and amortization		43,688			42,308
Total operating costs and expenses		77,957			74,802
Operating income	$	66,045		$	41,023
Capital expenditures	$	30,738		$	34,865
Realized prices:
Oil and condensate (per Bbl)	$	94.27		$	63.51
Natural gas (per Mcf)	$	7.44		$	6.08
NGLs (per Bbl)	$	58.34		$	51.24
Production volumes:
Gathering volumes (Mcf/d)(a)		151,964			151,260
NGLs and condensate (net equity gallons)		86,514,543			88,973,133
Natural gas short position (MMbtu/d)(a)		(5,607	)		(7,184	)

_____________

(a) 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 Natural Gas Liquids. For the year ended December 31, 2008, the revenues minus cost of natural gas and natural gas liquids for our Texas Panhandle Segment operations totaled $144.0 million compared to $115.8 million for the year ended December 31, 2007. There were three primary contributors to this increase: (i) higher NGL and condensate pricing, as compared to pricing in 2007, (ii) a lower natural gas short position as compared to 2007 and (iii) the downtime at our Arrington Plant which resulted in a negative impact in 2007 of approximately $2.7 million.

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The slightly higher gathering volumes in 2008 as compared to 2007 were primarily due to a full year of Red Deer Plant operations in 2008 compared to only six months in 2007, colder than normal weather in that area and downtime to repair the Arrington plant during 2007, which reduced gathering volumes during the year ended December 31, 2007.  These were partially offset by reduced drilling activity during 2008 that was not sufficient to replace the natural volume declines in the West Panhandle System and the East Panhandle System.

The drilling activity in the West Panhandle System is not sufficient to offset the natural declines experienced on the System. While our contract mix in the West Panhandle System provides us with a higher equity share of the production, the overall decline will continue, and we expect to recover smaller amounts of equity production in the future on the West Panhandle System. The East Panhandle System experienced increased drilling activity in the active Granite Wash play located in Roberts and Hemphill Counties, Texas through much of 2008; however, due to lower commodity values during the fourth quarter of 2008, we saw a significant reduction in drilling activity during the fourth quarter of the year ended December 31, 2008 by the producers in Roberts and Hemphill Counties. The liquids content of the natural gas is lower in the East Panhandle System, and our contract mix provides us with a smaller share of equity production as compared to the West Panhandle System. Due to this difference in contract mix and liquid content between our West and East Panhandle Systems, while we have grown aggregate volumes during 2008 as compared to 2007, our equity share of liquids production declined in 2008 as compared to 2007. Our current goal is to grow volumes aggressively in the East Panhandle System to offset the decline in volumes in the West Panhandle System (and resulting decline in our share of equity production). The start-up of the Red Deer Plant in June 2007 provided an additional 20 MMcf/d of processing capacity in our East Panhandle System that was immediately utilized by our customers.  We expanded our Red Deer Plant facility during 2008 to handle additional volumes of 5 MMcf/d, bringing total capacity to 25 MMcf/d.  We completed the shut-down of the Stinnett Plant and the consolidation of the volumes from the Stinnett Plant to the Cargray Plant.  We initiated a project to relocate the Stinnett Plant to the Arrington Plant, with the goal of replacing the older refrigerated lean oil plant, resulting in additional processing capacity and improved product recovery efficiencies.  This project has been postponed due to the reduction in drilling activity and the reduction in commodity prices.  We intend to reevaluate the project in the near future and either resume the project, relocate the plant to the East Texas area or sell the plant.

Operating Expenses. Operating expenses, including taxes other than income, for the year ended December 31, 2008 were $34.3 million compared to $32.5 million for the year ended December 31, 2007.  The major items impacting the $1.8 million increase in operating expenses for the year ended December 31, 2008 were a combination of the operations of the Red Deer plant for the full year in 2008 compared to only six months in 2007 and higher materials, supplies and labor costs.  These increases in operating expenses were slightly offset by the fact that the year ended December 31, 2007 included additional maintenance costs for repairing the Arrington plant.

Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2008 were $43.7 million compared to $42.3 million for the year ended December 31, 2007. The major items impacting the $1.4 million increase were the depreciation on the Red Deer Plant for a full year in 2008 compared to only six months in 2007 and beginning depreciation expense associated with the other capital expenditure projects.

Capital Expenditures. Capital expenditures for the year ended December 31, 2008 were $30.7 million as compared to $34.9 million for the year ended December 31, 2007.   During 2008, of our capital spending in this segment, we spent $21.4 million on growth capital and $9.3 million on maintenance capital.  We classify capital expenditures as either maintenance capital which represents routine well connects and capitalized maintenance activities or as growth capital which represents organic growth projects. Our decrease of $4.2 million in capital spending for 2008 was driven by less growth capital due to expenditures in 2007 on the new Red Deer Plant, which was offset by capital expenditures related to our Stinnett – Cargray plant consolidation projects during 2008.

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East Texas/Louisiana Segment

	Twelve Months Ending December 31,
	2008(c)			2007(b)
	($ in thousands, except for realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	298,720		$	153,660
Gathering and treating services		23,320			13,547
Other		—			(21	)
Total revenues		322,040			167,186
Cost of natural gas and natural gas liquids		269,030			133,350
Operating costs and expenses:
Operations and maintenance		16,569			10,929
Depreciation and amortization		13,559			10,781
Impairment		26,994			—
Total operating costs and expenses		57,122			21,710
Operating income	$	(4,112	)	$	12,126
Capital expenditures	$	17,391		$	25,560
Realized prices:
Oil and condensate (per Bbl)	$	101.62		$	73.33
Natural gas (per Mcf)	$	8.75		$	6.54
NGLs (per Bbl)	$	54.66		$	44.94
Production volumes:
Gathering volumes (Mcf/d)(a)		198,365			134,007
NGLs and condensate (net equity gallons)		28,619,378			18,320,082
Natural gas short position (MMbtu/d)(a)		1,427			1,077

______________

(a) 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.

(b) Includes operations related to the Laser Acquisition starting on May 3, 2007.

(c) Includes operations related to the Millennium Acquisition starting on October 2, 2008.

Revenue and Cost of Natural Gas and Natural Gas Liquids. For the year ended December 31, 2008, revenues minus cost of natural gas and natural gas liquids for our East Texas/Louisiana Segment totaled $53.0 million compared to $33.8 million for the year ended December 31, 2007.

We were positively impacted from higher NGL and condensate pricing during 2008 as compared to 2007. We were also positively impacted by a 48% growth in daily gathering volumes during 2008, as compared to 2007. Increased volumes were due to both a full year of the Laser Acquisition during 2008 compared to approximately eight months 2007; three months of the Millennium Acquisition during 2008; and continued successful drilling in the Austin Chalk play in Tyler and Jasper Counties, Texas. Excluding the Laser Acquisition and the Millennium Acquisition, our gathering volumes increased by 26.6% during 2008 compared to 2007.  We have also constructed a new seven mile lateral from our Brookeland gathering system into an active Austin Chalk drilling area where we have a large dedicated acreage position under a life-of-lease contract with an active significant producer. The production rates of wells drilled in the Austin Chalk play are characterized by high initial decline rates; therefore, operators must conduct active drilling programs if they are to maintain or grow their production in this play.  Depending upon the continued success of the producer’s drilling activities on this acreage; this area may continue to provide added volume growth to our East Texas/Louisiana Segment in the future.

The Laser Acquisition positively impacted the East Texas/Louisiana Segment’s revenues minus cost of natural gas and natural gas liquids by $15.0 million during the year ended December 31, 2008, compared to $8.6 million during the same time period in the prior year.  The increase is primarily the result of twelve months of operations during the year ended 2008 compared to approximately eight months during the same period in the prior year.  The daily gathering volumes of the assets acquired in the Laser Acquisition during 2008, as compared to the time period of ownership of those assets in 2007, are down due to reduced drilling activity around the Belle Bower system.

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The Millennium Acquisition positively impacted the East Texas/Louisiana Segment’s revenue minus cost of natural gas and natural gas liquids by $5.0 million.

Operating Expenses. Operating expenses for the year ended December 31, 2008 were $16.6 million compared to $10.9 million for the year ended December 31, 2007. The major items impacting the $5.6 million increase in operating expense for 2008 were (i) the additional months in 2008 that we have owned the assets acquired in 2007 as part of the Laser Acquisition (twelve months compared to approximately eight months); (ii) incremental expenses for additional compression costs due to increased gathered volumes on the Tyler County Pipeline and Brookeland system; (iii) preparation costs for hurricanes Ike and Gustav; (iv) expenses associated with operating the assets acquired as part of the Millennium Acquisition; and (v) higher  materials, supply and labor expenses.

Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2008 were $13.6 million compared to $10.8 million for the year ended December 31, 2007. The major items impacting the increase were (i) the additional months in 2008 that we owned the assets acquired as part of the Laser acquisition (twelve months compared to approximately eight months); (ii) placing the Tyler County Pipeline Extension into service and beginning the depreciation expense associated therewith; (iii) beginning the depreciation expense associated with other capital expenditure projects; and (iv) three months of depreciation and amortization of the assets acquired as part of the Millennium Acquisition.

Impairment.  During the year ended December 31, 2008, we incurred impairment charges related to certain processing plants, gathering systems and contracts within our East Texas/Louisiana Segment of $27.0 million due to the substantial decline in commodity prices during the fourth quarter of 2008.  No impairment charges were incurred during the year ended December 31, 2007.

Capital Expenditures. Capital expenditures for the year ended December 31, 2008 were $17.4 million compared to $25.6 million for the year ended December 31, 2007. During 2008, of our capital spending in this segment, we spent $14.5 million on growth capital and $2.9 million on maintenance capital.  We classify capital expenditures as either maintenance capital, which represents routine well connects and capitalized maintenance activities, or as growth capital, which represents organic growth projects. Our decrease in capital spending for 2008 was due primarily to the high costs associated with the construction and start-up of the Tyler County Pipeline Extension in March 2007.

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South Texas Segment

	Twelve Months Ending December 31,
	2008(c)			2007(b)
	($ in thousands,  except for realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	433,978		$	184,634
Gathering and treating services		4,779			4,012
Other		15			1
Total revenues		438,772			188,647
Cost of natural gas and natural gas liquids		425,237			181,327
Operating costs and expenses:
Operations and maintenance		2,924			1,058
Depreciation and amortization		4,428			2,453
Impairment		8,105			—
Total operating costs and expenses		15,457			3,511
Operating income	$	(1,922	)	$	3,809
Capital expenditures	$	1,145		$	3,449
Realized volumes:
Oil and condensate (per Bbl)	$	92.10		$	78.89
Natural gas (per Mcf)	$	8.99		$	6.38
NGLs (per Bbl)	$	52.66		$	55.44
Production volumes:
Gathering volumes (Mcf/d)(a)		88,488			63,435
NGLs and condensate (net equity gallons)		2,413,483			463,490
Natural gas short position (MMbtu/d)(a)		500			250

_____________

(a) 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.

(b) Includes operations related to the Laser Acquisition starting on May 3, 2007.

(c) Includes operations related to the Millennium Acquisition starting on October 2, 2008.

Revenue and Cost of Natural Gas and Natural Gas Liquids. During the year ended December 31, 2008 the South Texas Segment contributed revenues minus cost of natural gas and natural gas liquids of $13.5 million, as compared to $7.3 million for the year ended December 31, 2007.   The increase during 2008, as compared to 2007 was due to a full year of operating the assets acquired as part of the Laser Acquisition as compared to approximately eight months in 2007 and also due to the additional assets acquired as part of the Millennium Acquisition.  The assets acquired as part of the Millennium Acquisition positively impacted the South Texas Segment’s revenue minus cost of natural gas and natural gas liquids by $1.1 million.  Also contributing to the increase in revenues minus cost of natural gas and natural gas liquids is the expansion during the fourth quarter of 2008 of the Kelsey Compressor Station on our Phase 1 20-inch Pipeline, which provides access to Exxon’s King Ranch processing facility, which added an additional 12 MMcf/d of capacity.

There are two primary activities related to the assets acquired as part of the Laser Acquisition in this segment: (i) volumes of natural gas gathered on our own assets, which represents approximately 87.1% of revenues minus cost of natural gas and natural gas liquids for this segment for the year ended December 31, 2008 compared to 86.0% for the time period we owned these assets in 2007 and (ii) producer services, i.e. providing marketing and pipeline connection services to small independent producers and to third party pipeline systems, which accounted for approximately 12.9% of revenues minus cost of natural gas and natural gas liquids for the year ended December 31, 2008 as compared to 14.0% for approximately eight months we provided these producer services in 2007.

Operating Expenses. Operating expenses for the year ended December 31, 2008 were $2.9 million, as compared to $1.1 million for the year ended December 31, 2007.Operating expenses are higher due to (i) the additional months in 2008 that we have owned the assets acquired in 2007 as part of the Laser Acquisition (twelve months compared to approximately eight months); (ii) expenses associated with operating the assets acquired as part of the Millennium Acquisition; and (ii) higher material and labor expenses.

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Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2008 were $4.4 million, as compared to $2.5 million for the year ended December 31, 2007.  Depreciation and amortization increased due to: (i) a full year of depreciation and amortization of the assets acquired in 2007 as part of the Laser Acquisition in 2008 as compared to approximately eight months in 2007; and (ii) depreciation and amortization associated with the assets acquired as part of the Millennium Acquisition.

Impairment. During the year ended December 31, 2008, we incurred impairment charges related to certain processing plants, gathering systems and contracts within our South Texas Segment of $8.1 million due to the substantial decline in commodity prices during the fourth quarter of 2008.  No impairment charges were incurred during the year ended December 31, 2007.

Capital Expenditures. Capital expenditures for the year ended December 31, 2008 were $1.1 million as compared to $3.4 million for the year ended December 31, 2007.  During the year ended December 31, 2008, we spent $0.8 million on growth capital and $0.3 million on maintenance capital.  The decrease in capital expenditures in 2008 compared to 2007 was the result of the spending incurred in 2007 to add capacity and new supply to our Phase 1 20” pipeline.

Gulf of Mexico Segment

	Three Months Ending December 31,
	2008(b)			2007
	($ in thousands, except for realized prices)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	952		$	—
Gathering and treating services		703			—
Other					—
Total revenues		1,655			—
Cost of natural gas and natural gas liquids		1,376			—
Operating costs and expenses:
Operations and maintenance		605			—
Depreciation and amortization		1,521			—
Total operating costs and expenses		2,126,			—
Operating income (loss)	$	(1,847	)	$	—
Realized average prices:
Natural gas (per Mcf)	$	6.64		$	—
NGLs (per Bbl)	$	20.58		$	—
Production volumes:
Gathering volumes (Mfc/d)(a)		12,014			—
NGLs and condensate (net equity gallons)		176,962			—

_____________

(a) 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.

(b) Includes operations related to the Millennium Acquisition starting on October 2, 2008.

Revenues and Cost of Natural Gas and Natural Gas Liquids. The Gulf of Mexico Segment is a new segment and new area of operations for us in 2008.  We entered into this segment as a result of the Millennium Acquisition, effective October 1, 2008.During 2008, the Gulf of Mexico Segment contributed $0.3 million in revenues minus cost of natural gas and natural gas liquids.  Revenues minus the cost of natural gas and natural gas liquids were impacted in this segment as the result of damage inflicted on the Yscloskey and North Terrebonne plants by hurricanes Gustav and Ike.  During the time period we owned these assets in 2008, the Yscloskey plant did not come back online and the North Terrebonne plant only came back online during mid November 2008.

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Operating Expenses.  Operating expenses for 2008 were $0.6 million for the Millennium Covered Period.  We continued to incur operating expenses associated with the Yscloskey and North Terrebonne plants while the plants were undergoing repair for the hurricane damage.  We anticipate that the costs for the repair of the two plants will either be covered by insurance proceeds or by the previous owners pursuant to the Millennium Acquisition purchase and sale agreement.  In fact, we made our first claim against the sellers for such repair costs at the end of 2008 and received payment from the acquisition escrow on December 28, 2008 in the amount of $0.3 million.  We have since made a claim for the balance of the $0.6 million in cash held in escrow (i.e. $0.3 million) and have begun canceling common units held in escrow to satisfy our claims.  We may elect to cancel common units or wait to receive cash payment from the insurer for future amounts at our discretion.

Depreciation and Amortization. Depreciation and amortization expenses for 2008 were $1.5 million for the three months in 2008 that we owned the assets acquired in the Millennium Acquisition.

Capital Expenditures. We did not incur anycapital expenditures related to the Gulf of Mexico Segment in 2008.

Upstream Segment

	Twelve Months Ending December 31,
	2008 (b)			2007 (a)
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Oil and condensate	$	72,526		$	24,874
Sulfur		37,759			2,588
Natural gas		32,513			11,210
NGLs		29,530			12,015
Income fees and other		—			948
Other		701			130
Total revenues		173,029			51,765
Operating Costs and expenses:
Operations and maintenance		37,481			15,881
Depletion, depreciation and amortization		44,997			16,235
Impairment		107,017			—
Goodwill impairment		30,994			—
Total operating costs and expenses		220,489			32,116
Operating income	$	(47,460	)	$	19,649
Capital expenditures	$	20,655		$	2,242
Realized average prices:
Oil and condensate (per Bbl)	$	87.21		$	74.02
Natural gas (per Mcf)	$	7.89		$	7.08
NGLs (per Bbl)	$	61.36		$	56.66
Sulfur (per Long ton)	$	360.31		$	58.55
Production volumes:
Oil and condensate (Bbl)		831,631			336,028
Natural gas (Mcf)		4,122,997			1,584,279
NGLs (Bbl)		481,259			212,061
Total (Mcfe)		12,000,337			4,872,813
Sulfur (Long ton)		104,795			44,201

_____________

(a) Includes operations from the Escambia and Redman acquisitions beginning on August 1, 2007.

(b) Includes operations from the Stanolind Acquisition beginning on May 1, 2008.

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Acquisitions. On April 30, 2008, we acquired Stanolind Oil and Gas Corporation.  All of the assets acquired in this transaction are located in the Permian Basin, primarily in Ward, Crane and Pecos counties, Texas.  As of December 31, 2008, the transaction has added 252 operated producing wells, 21 non-operated producing wells and 44 injection wells to the Upstream Segment.  During the eight month period ended December 31, 2008, these assets averaged approximately 1,906 Mcf/d, 372 Bop/d and 168 Bbls of NGL’s of production, net to our interest after deducting royalties.   Also during the eight month period ended December 31, 2008, we drilled and completed five successful wells on the acquired leasehold acreage.  One additional well was drilled during the period and is currently in its completion phase.

Revenue. For the year ended December 31, 2008, the Upstream Segment contributed $173.0 million of revenue as compared to $51.8 million for the year ended December 31, 2007.  The increase in revenues in 2008 was due to higher realized prices for oil, natural gas, NGLs and sulfur, as well as eight months of operations related to the assets acquired in the Stanolind Acquisition, and a full year’s contribution from the assets acquired in the Escambia and Redman Acquisitions compared to only five months of operations in 2007.   During the year ended December 31, 2008, production averaged 11.2 MMcf/d, 2.3 MBO/d, 1.3 MB/d of NGL’s and 286 LT/d of sulfur.   The period included eight months of production from the assets acquired in the Stanolind acquisition properties which averaged 858 BOE/d.  These increases in revenue in 2008 were offset by: (i) shut-in production at the Big Escambia Creek field associated with a 20 day planned turnaround of the BEC treating facility in April 2008; (ii) BEC experiencing 31 days and 18 days of partial curtailment associated with sulfur recovery limitations and facility damage caused by a lightning strike, respectively; and (iii) gas production from Flomaton and Fanny Church fields being restricted from sales for 25 days associated with a third party’s gas quality issue at the point of sale (Oil and sulfur sales from both Flomaton and Fanny Church fields continued during this period of curtailment).

During the year ended December 31, 2008, sulfur sales contributed $37.8 million of the total $173.0 million for the Upstream Segment.  Historically, sulfur was viewed as a low value by-product in the production of oil and natural gas.  Due to an increase in demand in the global fertilizer market during the first nine months of 2008, the price per long ton peaked at over $600 at the Tampa, Florida market (before effects of net-backs).  During the last three months of 2008, demand in the global fertilizer market began to decline and the price per long ton at the Tampa, Florida market was $150 as of December 31, 2008.   Further deterioration in the sulfur market and pricing has continued into the first quarter 2009.  Sulfur pricing at the Tampa, Florida market in the first quarter 2009 is $0 per long ton.  We anticipate sulfur disposal costs during the first quarter 2009 to be $50 to $60 per long ton, and we anticipate this pricing will continue in future quarters of 2009.  During 2008, we attempted to identify and negotiate a long term contract to lock in some of the price upside, but we were unable to find a suitable counterparty.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, totaled $37.5 million for the Upstream Segment during the year ended December 31, 2008, as compared to $15.9 million for the year ended December 31, 2007.  The operating expenses in 2008 include eight months of expenses related to the assets acquired in the Stanolind Acquisition, as well as a full year of operating expense from the assets acquired in the Escambia and Redman Acquisitions compared to five months of expenses related to these assets in 2007.  During the eight month period of the operation of the assets acquired in the Stanolind Acquisition, these assets accounted for $5.1 million of the total $37.5 million of operating expenses including severance and ad valorem taxes.  Excluding severance and ad valorem taxes, the most significant portion of operating expenses were associated with operating the BEC and Flomaton treating and processing facilities, including operating expenses related to the planned turnaround at the BEC treating facility during April 2008.  The remaining operating expenses are attributed to base lease operating expenses and well workovers.  For 2008, our unit operating expense totaled $1.86 / Mcfe in the Upstream Business.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense for the year ended December 31, 2008 was $45.0 million, as compared to $16.2 million for the year ended December 31, 2007.  This increase is due to us owning the assets acquired in the Escambia and Redman Acquisitions for twelve months in 2008 compared to only five months in 2007 and owning the assets acquired in the Stanolind Acquisition for eight months of 2008 compared to zero months in 2007.

Impairment.  During the year ended December 31, 2008, we incurred an impairment charge of $107.0 million related to certain fields within our Upstream Segment as a result of the substantial decline in commodity prices during the fourth quarter of 2008.  As a result of this impairment charge, we assessed our goodwill balance for impairment and recorded an impairment charge to goodwill of $31.0 million.  We did not incur any impairment charges related to any of our fields or to goodwill during the year ended December 31, 2007.

Capital Expenditures.  The Upstream Segment’s maintenance capital expenditures for the year ended December 31, 2008 totaled $14.2 million.  The maintenance capital expenditures during 2008 were associated with the planned turnaround at the BEC treating facility, drilling, recompletions and workover activities.  One successful Smackover test was drilled and completed in our Big Escambia Creek (BEC) field in 2008, while one additional BEC well is in the process of completion operations as of December 31, 2008.  Maintenance capital was expended in fifteen non-operated wells drilled by a third party operator in various fields of East Texas and North Louisiana.  Eagle Rock’s average working interest in this non operated drilling program is 3.8%.  Recompletions and capital workovers were also conducted on eight operated wells across our South Texas, West Texas and Alabama regions during 2008.   Five recompletions were executed in our Jourdanton field to complete additional Edwards formation intervals.  Three of the five Edwards recompletions were successful.  Three successful capital workovers were completed in our Alabama and West Texas operations resulting in significant reserve additions during 2008.  The unit development cost for these recompletions and workover operations was $1.77/Mcfe.  During 2009, we are not expecting to perform any turnarounds at the BEC treating facility.

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Growth capital expenditures during 2008 totaled $6.5 million and were associated with five successful wells drilled and completed on leaseholds acquired from the Stanolind Acquisition in 2008.  Four wells were drilled in the Ward-Estes field area on the Louis Richter and American National leases testing the San Andres, Holt and Penn formations.  The fifth Permian Basin well was a successful completion in the Penn Sand on our American National lease in the Southern Unit field area.

 For the total capital drilling program in 2008, we completed the drilling of 21 wells (5.8 net), of which 15 wells drilled were operated by others.  As of December 31, 2008, two additional wells are in the process of completion operations.  The total finding and development cost of the operated program was $1.47/Mcfe.

Minerals Segment

	Twelve Months Ending December 31,
	2008		2007(a)
	(Amounts in thousands, except volumes and realized prices)
Revenues:
Oil and condensate	$	14,337	$	7,529
Natural gas		10,451		5,493
NGLs		1,376		693
Lease bonus, rentals and other		16,830		1,289
Total revenues		42,994		15,004
Operating Costs and expenses:
Operating		1,708		771
Depreciation and depletion		7,774		8,028
Impairment		1,741		5,749
Total operating costs and expenses		11,223		14,548
Operating Income	$	31,771	$	456
Realized average prices:
Oil and condensate (per Bbl)	$	91.83	$	70.84
Natural gas (per Mcf)	$	8.18	$	6.30
NGLs (per Bbl)	$	52.32	$	46.63
Production volumes:
Oil and condensate (Bbl)		156,118		106,275
Natural gas (Mcf)		1,277,046		872,176
NGLs (Bbl)		26,298		14,862
Total (Mcfe)		2,371,542		1,599,001

_____________

(a) Includes operations from the Montierra Acquisition beginning on May 1, 2007 and from the MacLondon Acquisition beginning on July 1, 2007.

Revenue.  For the year ended December 31, 2008 our revenue was $43.0 million compared to $15.0 million for the year ended December 31, 2007.  The increase in revenue was due to (i) increases in commodity prices, (ii) increases in production rates during 2008, which was the result of drilling, recompletion and workover operations conducted by the various operators of the properties and (iii) owning these properties for the full year in 2008.

Additionally, we received approximately $16.8 million in bonus and delay rental payments during the year ended December 31, 2008. Substantially all of this was derived from our ownership in the minerals. The majority of this bonus revenue ($12.8 million) was derived from new leases executed during the third and fourth quarters in 2008 on our behalf by the Minerals Manager in the emerging Haynesville shale play.  As a result of these leases, we now have the opportunity to receive future royalty revenues from wells drilled on approximately 75,000 gross acres in Desoto and Sabine Parishes, Louisiana and San Augustine and Sabine Counties, Texas.  In addition, we made a capital contribution to Ivory Working Interest Partners who then used the funds (along with other funds contributed by the remaining partners) to purchase a working interest position in approximately 60,000 gross acres in the Haynesville shale play, in San Augustine and Sabine Counties, Texas.  We also own a mineral interest in approximately 32,000 of these acres (included in the 75,000 acres mentioned above).

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The amount of revenue we receive from bonus and rental payments varies significantly from month to month; therefore, we do not believe a meaningful set of conclusions can be drawn by observing changes in leasing activity over small time periods. Commodity prices may affect the amount of leasing that will occur on the minerals in future periods, and it is impossible to predict the timing or amount of future bonus payments.  We do expect to receive some level of bonus payments in the future, however.

Operating Expenses. Operating expenses of $1.7 million for the year ended December 31, 2008 as compared to $0.8 million for the year ended December 31, 2007 are predominately production and ad valorem taxes. These taxes are levied by various state and local taxing entities.  For the year ended December 31, 2008, operating expenses include a full year of production and ad valorem taxes for the assets acquired in the Montierra and MacLondon Acquisition, while 2007 includes only approximately eight months for the assets acquired in the Montierra Acquisition and six months for the assets acquired in the MacLondon Acquisition.

Impairment.  During the year ended December 31, 2008, we incurred an impairment charge of $1.7 million related to certain fields within our Minerals Segment as a result of the substantial decline in commodity prices during the fourth quarter of 2008.  During the year ended December 31, 2007, we recorded an impairment charge of $5.7 million as a result of steeper decline rates in certain fields.

Depletion. Our depletion during the year ended December 31, 2008 was $7.8 million as compared to $8.0 million for the year ended December 31, 2008.

Corporate Segment

	Twelve Months Ending December 31,
	2008			2007
	($ in thousands)
Revenues:
Realized commodity derivatives	$	(46,059	)	$	(3,061	)
Unrealized commodity derivatives		207,824			(130,773	)
Total revenues		161,765			(133,834	)
General and administrative		45,701			27,799
Depreciation and amortization		787			754
Other expense		10,699			2,847
Operating income		104,578			(165,234	)
Other income (expense):
Interest income		793			1,160
Other income		5,328			696
Interest expense, net		(32,884	)		(38,936	)
Unrealized interest rate derivative gains (losses)		(27,717	)		(13,403	)
Realized interest rate derivative gains (losses)		(5,214	)		1,415
Other income (expense)		(955	)		(8,226	)
Total other income (expense)		(60,649	)		(57,294	)
Gain (loss) before taxes		43,929			(222,528	)
Income tax provision		(1,116	)		169
Segment gain (loss)	$	45,045		$	(222,697	)

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Revenue. As a master limited partnership, we distribute available cash (as defined in our partnership agreement) every quarter to our unitholders.  Our distribution policy, including a description of the right to make reserves against available cash, is discussed in greater detail in Part II, Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities - Cash Distribution Policy.

The volatility inherent in commodity prices generates uncertainty in future levels of available cash. We enter into derivative transactions to reduce our exposure to commodity price risk and reduce the uncertainty of future cash flows.

Our Corporate Segment’s revenue, which solely includes our commodity derivatives activity, increased to a gain of $161.8 million for the year ended December 31, 2008, from a loss of $133.8 million for the year ended December 31, 2007. As a result of our commodity hedging activities, revenues include total realized losses of $46.1 million on risk management activity settled during the year ended December 31, 2008 and unrealized mark-to-market gains of $207.8 million for the year ended December 31, 2008, as compared to realized losses of $3.1 million and unrealized losses of $130.8 million for the year ended December 31, 2007.  During the year ended December 31, 2008, our realized losses were partially offset by realized gains as a result of the hedge resets performed in the fourth quarter of 2008.  In addition, we recorded amortization related to put premiums and costs associated with the resetting of derivative contract prices of $13.3 million during the year ended December 31, 2008 as compared to $8.2 million for the year ended December 31, 2007.

As the forward price curves for our hedged commodities shift in relation to the caps, floors, and swap strike prices, the fair value of such instruments changes.  We capture this change as unrealized, non-cash, mark-to-market changes during the period of the change. The unrealized mark-to-market changes for the year ended December 31, 2008 and 2007 had no impact on cash activities for those periods and, as such, are excluded from our calculation of Adjusted EBITDA.  The realized commodity derivatives results during the year ended December 31, 2008 reflect the difference between the strike prices and settlement prices for derivative volumes settled during the year.  As such, the realized amounts impact our cash flows and are included in our calculation of Adjusted EBITDA.

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. Conversely, negative commodity price movements affecting our revenues and costs are expected to be partially offset by our executed derivative instruments.

General and Administrative Expenses. General and administrative expenses were $45.7 million for the year ended December 31, 2008 as compared to $27.8 million for the year ended December 31, 2007. This growth in general and administrative expenses was mostly driven by an increase in the number of employees in our corporate office as a result of: our midstream acquisitions in both 2008 and 2007; our expansion into the minerals and upstream businesses related to the Montierra, Redman, EAC and Stanolind acquisitions in both 2008 and 2007; and recruiting efforts in accounting, engineering, land and operations. As a result of the acquisitions and recruiting efforts, corporate-office payroll expenses increased by $11.9 million for the year ended December 31, 2008 as compared to the same period in the prior year.  In addition, other professional fees, including our public partnership expenses related to audit, tax, Sarbanes-Oxley compliance and other contract labor increased by $2.5 million for the year ended December 31, 2008.  We also experienced increased miscellaneous general and administrative expenses of $1.0 million for the year ended December 31, 2008.  At the present time, we do not allocate our general and administrative expenses to our operational segments. The Corporate Segment bears the entire amount.

For the years ended December 31, 2008 and 2007, non-cash compensation expense of approximately $6.0 million and $2.4 million, respectively, was recorded as general and administrative expense related to restricted units granted under the Partnership’s long-term incentive plan (“LTIP”).

General and administrative expenses also increased by $1.7 million in 2008 due to non-cash compensation expense allocated to us related to the issuance of Tier I incentive units by Eagle Rock Holdings, L.P.  During 2008, Holdings granted 417,000 Tier I incentive interests in the aggregate to six Eagle Rock employees.  One of these employees subsequently forfeited 200,000 of the interests upon his resignation from Eagle Rock in 2008.  The Tier I incentive interests entitle the holder to immediately begin to share in the cash distributions of Holdings because the associated payout target was reached in 2006.  Grants of Tier I incentive units by Holdings to employees working on our behalf are intended to provide additional motivation for those employees to create value at Holdings, in part through their actions to create value in the equity Holdings holds in us.  Because the incentive interests represent an interest in the future profits of Holdings, and receive distributions only from the cash flow at Holdings, the value the incentive interests creates accrues to the benefit of our unitholders without any associated burden on, or dilution to, the returns on our common units.  On the contrary, the incentive units are solely a burden on, and dilutive to, the returns of the equity owners of Holdings, including NGP as the substantial majority equity owner of Holdings. We have determined to record a portion of the value of the incentive units as compensation expense in our financial statements based on our estimate of the total value of the incentive unit grant and based on our estimate of the grantee’s portion of time dedicated to us.

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Other Operating Expenses.  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.  We historically sold portions of our condensate production from our Texas Panhandle and East Texas midstream systems to SemGroup.  During July 2008, we sold pre-bankruptcy, and continued to sell post-bankruptcy, condensate to SemGroup.  As of August 1, 2008, we ceased all deliveries/sales of condensate to SemGroup. As a result of the bankruptcy we recorded a $10.7 million bad debt charge during the year ended December 31, 2008 which is included in “Other Operating Expense” in the consolidated statement of operations.  Although we sought payment of our $10.7 million receivable for condensate sales as a critical supplier to SemGroup under its Supplier Protection Program (“SPP”), we were not successful in being recognized as a critical provider by SemGroup and thus were not admitted to the SPP.

For the year ended December 31, 2007, other operating expenses included a settlement of arbitration of $1.4 million, severance to a former executive of $0.3 million, and $1.1 million for liquidated damages related to the late registration of our common units.

Total Other Expense.  Total other expense, which includes both realized and unrealized gains and losses from our interest rate swaps, increased to $61.5 million for the year ended December 31, 2008 as compared to $57.3 million for the year ended December 31, 2007.  During 2008, we incurred realized losses from our interest rate swaps of $5.2 million as compared to realized gains of $1.4 million during the year ended December 31, 2007.  We also incurred unrealized mark-to-market losses from our interest rate swaps of $28.6 million during the year ended December 31, 2008 as compared to unrealized mark-to-market losses of $13.4 for the same period in 2007.  These unrealized mark-to-market losses did not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.

Interest expense, net, decreased to $32.9 million for the year ended December 31, 2008 as compared to $38.9 million during the same period in the prior year.  The decrease in interest expense, net, is due to the decrease in interest rates from December 31, 2007 to December 31, 2008 as well as lower interest rate margin under the new senior revolving credit facility, partially offset by higher debt balances.

Other income includes our equity in earnings of the partnerships described in Part I, Item 1. Business – Minerals Business (Ivory Working Interests, L.P and Ivory Acquisition Partners, L.P.).  During the year ended December 31, 2008, we recorded income of $8.2 million.  This income was partially offset by a loss on the sale of investments of $2.1 million due to the reversion of our interest in the IAP partnership.   During the year ended December 31, 2007, we recorded income of $0.7 million related to the equity in earnings of the partnerships.  In addition, other income for the year ended December 31, 2008 includes a $1.3 million gain on the sale of assets related to properties we sold.

Income Tax (Benefit) Provision. Income tax benefit recorded during the year ended December 31, 2008 reflects the Texas Margin Tax as recorded during the current year and offset by the reduction of the deferred tax liability created by the book/tax differences as a result of the federal income taxes associated with the Redman and Stanolind Acquisitions.  For further discussion of our income tax (benefit) provision, see Note 15 to our consolidated financial statements included in Part II, Item 8, Financial Statements and Supplementary Data staring on page F-1 of this Annual Report.

Adjusted EBITDA.

Adjusted EBITDA, as defined under Part II, Item 6. Selected Financial Data - Non-GAAP Financial Measures, increased by $115.9 million from $133.4 million for the year ended December 31, 2007, to $249.2 million for the year ended December 31, 2008.

As described above, revenues minus cost of natural gas and natural gas liquids for the Midstream Segment (including the Texas Panhandle, East Texas/Louisiana, South Texas and Gulf of Mexico Segments) grew by $53.8 million during the year ended December 31, 2008, as compared to the comparable period in 2007. The acquisitions which led to our entry into our Upstream and Mineral Segments contributed an additional $149.3 million to revenues during the year ended December 31, 2008, as compared to the comparable period in 2007. Our Corporate Segment’s realized commodity derivatives loss decreased by $43.0 million during the year ended December 31, 2008 as compared to the comparable period in 2007. This resulted in $160.1 million of total incremental revenues minus cost of natural gas and natural gas liquids during the year ended December 31, 2008, as compared to the comparable period in 2007.  The incremental revenue amounts are adjusted to exclude the impact of unrealized commodity derivatives not included in the calculation of Adjusted EBITDA.

Operating expenses (including taxes other than income) for our Midstream Segment increased by $9.9 million for the year ended December 31, 2008, as compared to the same period in 2007, while the acquisitions which created the Upstream and Minerals Segments in 2007 and 2008 contributed additional Operating Expenses (including taxes other than income) of $22.5 million for the year ended December 31, 2008, as compared to the comparable period in 2007.

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General and administrative expense, excluding the impact of non-cash compensation charges related to our long-term incentive program, Holding’s Tier I incentive units and other non-recurring items and captured within our Corporate Segment, increased during the year ended December 31, 2008 by $11.8 million, as compared to the respective period in 2007.

As a result, revenues (excluding the impact of unrealized commodity derivative activity) minus cost of natural gas and natural gas liquids for the year ended December 31, 2008, as compared to the same period in 2007 increased by $160.1 million, operating expenses increased by $32.4 million and general and administrative expenses increased by $11.8 million.  The increases in revenues minus the cost of natural gas and natural gas liquids, offset by increases in operating costs and general and administrative expenses resulted in an increase to Adjusted EBITDA during the year ended December 31, 2008, as compared to the year ended December 31, 2007.

Year Ended December 31, 2007 Compared with Year Ended December 31, 2006

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the years ended December 31, 2007 and December 31, 2006. Operating results for our individual operating segments are presented in tables in this Item 7.

	Year Ended December 31
	2007			2006
	($ in thousands)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	868,101		$	486,911
Gathering and treating services		27,417			14,862
Minerals and royalty income		15,004			—
Commodity derivatives		(133,834	)		(24,004	)
Other		110			621
Total revenues		776,798			478,390
Cost of natural gas and natural gas liquids		686,882			377,580
Costs and expenses:
Operating		52,793			32,905
Taxes and other income		8,340			2,301
General and administrative		27,799			10,860
Other expense		2,847			6,000
Depreciation, depletion and amortization		80,559			43,220
Impairment		5,749			—
Total costs and expenses		178,087			95,286
Total operating income (loss)		(88,171	)		5,524
Other income (expense):
Interest income		1,160			996
Other income		696			—
Interest expense		(37,521	)		(29,759	)
Unrealized interest rate derivatives		(13,403	)		2,774
Other income (expense)		(8,226	)		(1,619	)
Total other income (expense)		(57,294	)		(27,608	)
Income (loss) before taxes		(145,465	)		(22,084	)
Income tax provision		169			1,230
Net income (loss)	$	(145,634	)	$	(23,314	)
Adjusted EBITDA(a)	$	133,357		$	81,192

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

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For the year ended December 31, 2007, based on operating income of our non-Corporate segments, our Midstream Business comprised approximately 73.9% of our business (with the Texas Panhandle Segment accounting for 53.2% of our business, the South Texas Segment accounting for 4.9% of our business, and the East Texas/Louisiana Segment accounting for 15.7% of our business), our Upstream Business comprised approximately 25.5% of our business, and our Minerals Business comprised approximately 0.6% of our business.

Midstream Business (Three Segments)

Significant Acquisitions and Organic Growth Projects in 2007

The Laser Acquisition, completed in May 2007 (hereinafter, the period of operation from May 3 through December 31, 2007, the “Laser Covered Period”), contributed a number of gathering and processing assets to the Midstream Business. The assets were split between the East Texas/Louisiana Segment and established the new South Texas Segment. The assets acquired consisted of:

• Approximately 137 miles of natural gas gathering pipelines ranging in size from two inches to 20 inches in diameter.

• Approximately 8100 aggregate horsepower.

• Three processing stations consisting of processing and related facilities for an aggregate capacity of 87 MMcf/d.

• Producer Services utilizing our pipelines and third-party pipelines for the purchase and sale of wellhead natural gas.

We also completed two significant organic growth capital projects, one in the Texas Panhandle Segment (refurbishment and start-up of the Red Deer Plant) and the other in the East Texas/Louisiana Segment (completion of the Tyler County Pipeline Extension), both of which contributed to the results in 2007.

Texas Panhandle Segment

	Twelve Months Ending December 31
	2007		2006
	($ in thousands)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	479,120	$	415,331
Gathering and treating services		8,910		7,382
Other		—		339
Total revenues		488,030		423,052
Cost of natural as and natural gas liquids		372,205		317,626
Operating costs and expenses:
Operations and maintenance		30,635		28,318
Taxes other than income		1,859		1,758
Depreciation and amortization		42,308		36,270
Total operating costs and expenses		74,802		66,346
Operating income	$	41,023	$	39,080

Revenues and Cost of natural gas and natural gas liquids. For the year ended December 31, 2007, the revenues minus cost of natural gas and natural gas liquids for our Texas Panhandle Segment operations totaled $115.8 million compared to $105.4 million for the year ended December 31, 2006. There were two primary contributors to this increase: (i) higher NGL and condensate pricing, as compared to pricing in 2007, and (ii) flat natural gas pricing, as compared to pricing in 2007.

Due to the large component of keep-whole contracts in our West Panhandle System, we are a net buyer of natural gas in the Texas Panhandle Segment. Given this short position in natural gas, we were positively impacted in 2007 from a flat natural gas price from 2006 to 2007, essentially maintaining our cost of gas at a constant rate, and rising NGL and condensate prices in the same period, which resulted in a higher fractionation spread in 2007 as compared to 2006.

During 2007, this Segment gathered an average of 151.3 MMcf/d of natural gas on its pipelines and processed an average of 122 MMcf/d of natural gas as compared to gathering an average of 146.4 MMcf/d of natural gas on its pipelines and processing an average of 112.7 MMcf/d of natural gas during 2006. During 2007, we recovered an average of 11,896 Bbls/d of NGLs of which our equity share was 3,678 Bbls/d compared to an average of 11,322 Bbls/d of NGLs recovered during 2006, of which our equity share was 3,828 Bbls/d during 2006. During 2007 we recovered an average of 2,200 Bbls/d of condensate from our gathering systems of which our equity share was 2,125 Bbls/d as compared to 2,619 Bbls/d of condensate from our gathering systems of which our equity share was 2,549 Bbls/d during 2006.

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The positive pricing impact was partially offset by a reduction of our equity share of production. This is primarily due to a continued decline in volumes in our West Panhandle System and partially due to the colder than normal weather in that area during the first quarter. The drilling activity in the West Panhandle System is not sufficient to offset the natural declines experienced on the System. While our contract mix in the West Panhandle System provides us with a higher equity share of the production, the overall decline will continue and we expect to recover smaller equity production in the future on the West Panhandle System.

The East Panhandle System continues to experience strong growth in volumes and equity production due to the active Granite Wash drilling play located in Roberts and Hemphill Counties, Texas. The liquids content of the natural gas is lower in the East Texas Panhandle System and our contract mix provides us with a smaller share of equity production as compared to the West Panhandle System. Due to this difference in contract mix and liquid content between our West and East Panhandle Systems, while we have grown aggregate volumes during 2007 as compared to 2006, our equity share of liquids production has been reduced. Our goal is to grow volumes aggressively in the East Panhandle System to offset the decline in volumes and our share of equity production in the West Panhandle System. The start-up of the Red Deer Plant in June 2007 provided an additional 20 MMcf/d of processing capacity in our East Panhandle System that was immediately utilized by our customers.

Other significant events during 2007 included the Arrington Plant downtime during the second quarter resulting in a negative impact of approximately $2.7 million.

Operating Expenses. Operating expenses for 2007 were $30.6. million compared to $28.3 million in 2006. The major items impacting the $2.3 million increase in operating expense were (i) $1.0 million associated with the start-up and operations of the Red Deer Plant, (ii) $0.5 million for the unscheduled Arrington shutdown, (iii) $0.4 million for additional rental compression due to increased natural gas volumes on the East Panhandle System, (iv) $0.1 million study to review moving the Tonkawa Plant to a new location and (v) $0.1 million incremental costs for scheduled shutdowns as compared to 2006.

Depreciation and Amortization. Depreciation and amortization expenses for 2007 were $42.3 million compared to $36.3 million in 2006. The major items impacting the $6.0 million increase were (i) a full year for the MGS Acquisition and (ii) placing the Red Deer Plant into service and beginning the depreciation expense associated with the capital spend.

Capital Expenditures. Capital expenditures for 2007 were $34.9 million compared to $12.2 million in 2007. We classify capital expenditures as either maintenance capital which represents routine well connects and capitalized maintenance activities or as growth capital which represents organic growth projects. In 2007, growth capital represented 71% of our capital expenditures as compared to 52% in 2006. Our increase in growth capital of $18.2 million and routine well connects of $3.1 million in this area were driven by the continued heavy drilling activity in the Granite Wash play. Growth capital expenditures focused on adding additional capacity to our systems as reflected by the Red Deer Plant project and compressor station expansions. We anticipate continued growth capital expenditures as we have announced the replacement of our existing Arrington Plant with a cryogenic plant to provide more capacity for our customers in the Granite Wash play. In addition to growth capital, we continued to spend on maintenance capital to make up for the lack of maintenance performed by the previous owners of the assets. We spent an additional $1.7 million on overhauls of compression during 2007 compared to 2006 in order to improve runtimes and service to our customers.

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East Texas/Louisiana Segment

	Twelve Months Ending December 31
	2007			2006
	($ in thousands)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	153,660		$	71,580
Gathering and treating services		13,547			7,480
Other		(21	)		282
Total revenues		167,186			79,342
Cost of natural gas and natural gas liquids		133,350			59,954
Operating costs and expenses:
Operations and maintenance		9,773			4,587
Taxes other than income		1,156			543
Depreciation and amortization		10,781			5,915
Total operating costs and expenses		21,710			11,045
Operating income	$	12,126		$	8,343

Revenues and Cost of natural gas and natural gas liquids. For the year ended December 31, 2007, revenues minus cost of natural gas and natural gas liquids for our East Texas/Louisiana Segment totaled $33.8 million compared to $19.4 million for the year ended December 31, 2006. During 2007, this segment gathered an average of 134.0 MMcf/d of natural gas on its pipelines and processed an average of 108.4 MMcf/d of natural gas as compared to gathering an average of 72.2 MMcf/d of natural gas on its pipelines and processing an average of 70.7 MMcf/d of natural gas during 2006. During 2007, we produced an average of 5,380 Bbls/d of NGLs of which our equity share was 1,118 Bbls/d compared to 3,624 Bbls/d of NGLs of which our equity share was 841 Bbls/d during 2006. We recovered during 2007 an average of 112 Bbls/d of condensate from our gathering systems of which our equity share was 77 Bbls/d compared to an average of 84 Bbls/d of condensate from our gathering systems of which our equity share was 37 Bbls/d during 2006.

The Laser Acquisition positively impacted the East Texas/Louisiana Segment by $8.6 million during 2007. For the approximate eight months of the Laser Covered Period, the assets acquired in the Laser Acquisition added 52.5 MMcf/d average volume and 177 Bbls/d of NGL production. The Laser Acquisition contract mix is weighted to fee-based contracts. Fees we received from these contracts represented $5.0 million of the $8.6 million.

We were positively impacted from higher NGL and condensate pricing during 2007 as compared to 2006. Due to the large component of fixed recovery contracts, we are from time to time a net buyer of natural gas in the East Texas/Louisiana area. During those times where we were net short natural gas, we were positively impacted from a flat natural gas price from 2006 to 2007. The flat natural gas price and rising NGL and condensate prices resulted in a higher fractionation spread in 2007 as compared to 2006 which positively impacted the fixed recovery contract mix. During those times where we were a net seller of natural gas, the flat natural gas pricing environment had no negative financial impact to us.

We were positively impacted by a 78% gathering volume growth during 2007 compared to 2006. Volumes increased due to both the Laser Acquisition and continued drilling in the Austin Chalk play in Tyler and Jasper Counties, Texas. Excluding the Laser Acquisition, our gathering volumes increased by 32%. The Tyler County Pipeline Extension completed in March 2007, connected the Tyler County Pipeline to our Brookeland gathering system providing an additional 50 MMcf/d of outlet capacity for the Tyler County Pipeline. The Tyler County Pipeline has greatly benefited from the active drilling in the Austin Chalk play. The Austin Chalk’s production profile is characterized by steep initial declines in new wells requiring active drilling programs by producers to maintain or grow volumes. We have also constructed a new seven mile lateral from our Brookeland gathering system into an active Austin Chalk drilling area where we have a large dedicated acreage position under a life-of-lease contract with Anadarko Exploration and Production Company.

Operating Expenses. Operating expenses for 2007 were $9.8 million compared to $4.6 million in 2006. The major items impacting the $5.2 million increase in operating expense were (i) $3.9 million for the eight months that we have owned the assets in 2007 that were a part of the Laser Acquisition, (ii) $0.8 million for a full year of operations in 2007 compared to only 9 months of ownership in 2006 of the assets acquired in the Brookeland Acquisition, (iii) $0.4 million expenses for operating compression due to increased natural gas volumes on the Tyler County Pipeline, and (iv) $0.3 million our share for unscheduled downtime and repair work at the non operated Indian Springs Plant.

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Depreciation and Amortization. Depreciation and amortization expenses for 2007 were $10.8 million compared to $5.9 million in 2006. The major items impacting the $4.9 million increase were (i) the inclusion of eight months of the Laser Acquisition, (ii) a full year for the Brookeland Acquisition and (iii) placing the Tyler County Pipeline Extension into service and beginning the depletion and amortization expense associated with the capital spend.

Capital Expenditures. Capital expenditures for 2007 were $25.6 million compared to $0.7 million in 2006. We classify capital expenditures as either maintenance capital which represents routine well connects and capitalized maintenance activities or as growth capital which represents organic growth projects. In 2006 and 2007 growth capital represents over 90% of the capital expenditures in the area. Growth capital expenditures focused on adding additional capacity to our systems to meet the active Austin Chalk play in the Jasper and Tyler Counties in Texas. Major projects completed in 2007 were the Tyler County Pipeline Extension and the Brookeland Gathering System expansion. In addition to capital expenditures incurred to support the Austin Chalk play, growth capital expenditures increased by an additional $2.0 due to the Laser Acquisition and supporting growth in those areas. Maintenance capital expenditures for 2007 increased by $1.3 million due to the Laser Acquisition.

South Texas Segment

	Twelve Months Ending December 31
	2007		2006
	($ in thousands)
Revenues:
Sales of natural gas, NGLs, oil and condensate	$	184,634	$	—
Gathering and treating services		4,012		—
Other		1		—
Total revenues		188,647		—
Cost of natural gas and natural gas liquids		181,327		—
Operating costs and expenses:
Operations and maintenance		911		—
Taxes other than income		147		—
Depreciation and amortization		2,453		—
Total operating costs and expenses		3,511		—
Operating income	$	3,809	$	—

Revenues and Cost of natural gas and natural gas liquids.  This segment was a new area of operations for us in 2007.  We entered into this segment as a result of the Laser Acquisition, effective May, 2007.During the Laser Covered Period, the South Texas Segment contributed $7.3 million in revenues minus cost of natural gas and natural gas liquids.  There are two primary activities in this segment: (i) volumes of natural gas gathered on our own assets, which represented 86% of revenues minus cost of natural gas and natural gas liquids for this segment and (ii) producer services, providing marketing and pipeline connection services to small independent producers and to third party pipeline systems, which accounted for 14% of revenues minus cost of natural gas and natural gas liquids.

Two significant items that will continue to add value to this area are (i) a pipeline extension to connect Chesapeake Energy Corporation’s and other operator’s production to our Phase 1 20” Pipeline and (ii) the construction of the Kelsey Compressor Station on our Phase 1 20” Pipeline which will provide access to Exxon’s King Ranch processing facility, resulting in an incremental 24 MMcf/d of capacity. The construction of this station will enable us to continue to increase volumes on our Phase 1 20” Pipeline providing that drilling activity and our commercial success to contract for the natural gas continues in 2008.

Operating Expenses.  Operating expenses for 2007 were $0.9 million in for the Laser Covered Period.

Depreciation and Amortization. Depreciation and amortization expenses for 2007 were $2.5 million for the eight months in 2007 that we have owned the assets part of the Laser Acquisition.

Capital Expenditures. Capital expenditures for 2007 were $3.4 million for the eight months in 2007 that we have owned the assets part of the Laser Acquisition in 2007. This spending was primarily growth capital focused on adding capacity and new supply to our Phase 1 20” pipeline.

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Upstream Segment

	Twelve Months Ending December 31
	2007		2006
	($ in thousands)
Revenues:
Oil and condensate	$	24,874	$	—
Natural gas		11,210		—
NGLs		14,603		—
Income fee and other		948		—
Other		130		—
Total revenues		51,765		—
Operating Costs and expenses:
Operations and maintenance		11,474		—
Taxes other than income		4,407		—
Depreciation, depletion and impairment		16,235		—
Total operating costs and expenses		32,116		—
Operating Income	$	19,649	$	—

Overview. On July 31, 2007, the Partnership became engaged in the Upstream Segment with the acquisition of Escambia Asset Co., LLC (EAC) and Redman Energy Holdings, L.P., Redman Energy Holdings II, L.P., and NGP Income Co-Investment Opportunities Fund II, L.P. (collectively Redman). The EAC and Redman operated properties consist of 108 wells (producing and non-producing) located in Alabama, Texas and Mississippi. From those transactions, the Partnership also acquired 106 non-operated wells (producing and non-producing) with minor working interests and overriding royalty interests in Texas and Louisiana. Our Upstream Segment assets produced 4.9 Bcfe, net to our interest after deducting royalties, during the five months of 2007 from July 31, 2007 to December 31, 2007 (the “Upstream Covered Period”).

EAC Assets. Substantially all of the assets acquired in this transaction are located in or near Escambia County, Alabama. We own and operate 30 producing wells in three primary fields: Big Escambia Creek, Flomaton and Fanny Church in the Smackover and Norphlett formations. During the Upstream Covered Period, these wells averaged approximately 21 MMcfe/d of production, net to our interest after deducting royalties. Production from these formations contains significant percentages of hydrogen sulfide and carbon dioxide and must be extracted prior to sales. In addition to the wells, the EAC assets included two treating plants (100 MMcf/d capacity, to facilitate the extraction of these contaminants, and one processing plant (40 MMcf/d capacity) to process and sell natural gas liquids. These facilities are included within our Upstream Segment predominately because these facilities exist to service the equity owners in the wells in the field and not to service third-party gas. The field assets also include gathering pipelines, saltwater disposal wells and other equipment to conduct efficient operations. The Partnership owns an 18.8% interest in the Jay field plant that processes natural gas liquids from the Flomaton and Fanny Church field.

Redman Assets. The East Texas assets acquired in this transaction are located in the Smackover trend extending from Rains County to Henderson County, Texas. On account of the Redman Acquisition, we own and operate 31 producing wells in nine fields which averaged approximately 7.6 MMcfe/d of production, net to our interest after deducting royalties, from the Smackover formation during the Upstream Covered Period. Production from these wells is mostly gathered and compressed by Regency Field Services and transported to Regency’s Eustace plant for separation, hydrogen sulfide treating and NGL processing. Production from the Smackover contains significant percentages of hydrogen sulfide requiring treating at the wellhead and extraction prior to sales.

The Redman transaction also included the acquisition of operated assets in South Texas and Mississippi as well certain non-operated wells in Texas and Louisiana. The South Texas assets include 10 producing wells in Jourdanton field in Atascosa County which averaged approximately 2.8 MMcfe/d of production, net to our interest after deducting royalties, from the Edwards formation during the Upstream Covered Period. These wells are gathered and compressed by Eagle Rock Operating Co., LLC and are transported to the Regency Field Services Tilden plant for treating prior to sales. In Mississippi, the Partnership operates 3 producing wells which averaged approximately 165 Mcf/d of production, net to our interest after deducting royalties, from the Smackover formation during the Upstream Covered Period. The production is treated for hydrogen sulfide and processed by Enbridge. In addition to the operated assets, the Partnership acquired minor non-operated working interests in 81 producing wells, as well as 13 producing wells with small overriding royalty interests. The primary operator of the Partnership’s non-operated interests is Stroud Petroleum Inc. Stroud operates 78% of these non-operated properties.

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Revenues.  For the year ended December 31, 2007, revenues for our Upstream Segment contributed $51.8 million of revenues.   Production rates during the period were essentially flat to slightly increasing. Exiting 2007, the average December production rate of 34.9 MMcfe/d was slightly above the August average production rate of 33 MMcfe/d due to the completion of two wells (i.e., the Huddleston 1-3, associated with Redman assets, and the Manning 4-9 #1, in Big Escambia Creek field), certain wellbore cleanouts, and flush production following the unscheduled shutdown of the Big Escambia Creek plant’s sulfur treating facility in November, 2007. Revenues during the Upstream Covered Period were negatively impacted by approximately $ 3.6 million, according to management’s estimate, from the production downtime at Big Escambia Creek field required for maintenance and repair of the plant’s sulfur treating facilities. Following the Big Escambia Creek downtime, production rates were restored to levels equivalent to those at the beginning of the fourth quarter of 2007. Prices received for all products improved through the Upstream Covered Period and contributed significantly to revenues. In particular, oil and sulfur prices improved 24% and 46%, respectively, comparing August to December 2007.

Operating Expenses. Operating expenses during the period, including severance and ad valorem taxes, which totaled $15.9 million for the Upstream Segment. Excluding the severance and ad valorem taxes, the most significant portion of the operating expenses were associated with operating the Big Escambia Creek and Flomaton treating and processing facilities. The incremental net operating expense associated with the unscheduled Big Escambia Creek shutdown was offset by the reduction in severance taxes due to the reduced volume. These facilities are required to extract the H2S and CO2 to achieve pipeline sales quality specifications, as well as beneficially extracting natural gas liquids and sulfur for sale. The remaining operating expenses are attributed to base lease operating expenses and well workovers. The most significant workovers were conducted on three wells with coiled tubing units to cleanout scale plugging the production tubulars. All three wells were returned to normal producing rates following the cleanouts. The remaining workover expenses were associated with wireline operations to remove scale from wells or improve natural gas flow.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense for 2007 was $16.2 million for the five months in 2007 that we have owned the Upstream assets acquired from EAC and Redman.

Capital Expenditures. All Upstream Segment capital expenditures during the period, totaling $2.2 million, were categorized as maintenance capital. The majority of the capital (approximately 50%) was associated with completing three wells drilled by EAC and Redman prior to the transaction close date. In addition to the operated completions, an unsuccessful recompletion in Jourdanton field was conducted, as well as various facility upgrades in each of the newly acquired asset areas. The Partnership participated in small non-operated working interest projects consisting of ten drilling wells and two recompletions.

Minerals Segment

	Twelve Months Ending December 31
	2007		2006
	($ in thousands)
Revenues:
Oil and condensate	$	7,529	$	—
Natural gas		5,493		—
NGLs		693		—
Lease bonus, rentals and other		1,289		—
Total revenues		15,004		—
Operating Costs and expenses:
Operations and maintenance		—		—
Taxes other than income		771		—
Depreciation, depletion and impairment		13,777		—
Total operating costs and expenses		14,548		—
Operating Income	$	456	$	—

Revenues.  Our Minerals Segment consists of properties we acquired in the Montierra Acquisition on April 30, 2007 and in the MacLondon Acquisition on June 18, 2007. The figures and events discussed below relate only to the period after our acquisition of the properties (the “Minerals Covered Period”).

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During the Minerals Covered Period, we produced an average of approximately 440 barrels of oil, 3.6 MMcf of natural gas, and 62 Bbls of natural gas liquids per day. The production rate during the period remained essentially flat due to drilling, recompletion and workover operations conducted by the various operators of the properties. We did not incur any expense for these activities.

A mineral owner typically experiences a delay of two to six months between the time a new well is completed and receipt of the initial royalty payment. Because of these delays we are generally not aware of new sources of production until many months after the drilling has occurred. For this reason, we did not include any extensions and discoveries in our Minerals Segment and cannot quantify the level of drilling activity that occurred on the interests since we purchased them.

Our realized average prices during the Minerals Covered Period in the Minerals Segment (excluding the effect of hedging) were $70.85/Bbl of oil, $6.30/Mcf of natural gas, and $46.62/Bbl of natural gas liquids. Prices for these commodities rose during the period.

The prices we receive for our production are influenced by a number of factors including their location, quality, and external market forces. At our largest oil producing field, Brea Olinda the crude oil production is sold under a long term contract that is tied to NYMEX WTI. Under the terms of the contract we receive approximately 83% of the NYMEX WTI price.

We received approximately $1.3 million in bonus and delay rental payments in 2007. Substantially all of this was derived from our ownership in the Pure Minerals. The amount of revenue we receive from bonus and rental payments varies significantly from month to month. Therefore, we do not believe a meaningful set of conclusions can be drawn by observing changes in leasing activity over small time periods. Nevertheless, due to high commodity prices, we expect leasing activity to remain robust and expect to see similar levels of bonus income in future periods.

Operating Expenses.  Operating expenses for the Minerals Segment are predominately production expenses. We paid $0.8 million in production expenses, which was substantially all production and ad valorem taxes. These taxes are levied by various state and local taxing entities and were approximately 5.6% of our production revenue.

Depletion, depreciation, amortization and impairment. Under the Successful Efforts method of accounting, we calculate depletion, depreciation and amortization using the units of production method. In the case of our Minerals Segment, we only claim proved, producing reserves because, as a mineral interest owner, we lack sufficient engineering and geological data to estimate the proved undeveloped and non-producing reserve quantities, and because we cannot control the occurrence or the timing of the activities that would cause such reserves to become productive. Since our units of production depletion and amortization rate is 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. Our depletion, depreciation and amortization rate during 2007 was $4.89/Mcfe, and our depletion, depreciation and amortization expenses were $8.0 million in 2007. In addition in 2007, we recorded an impairment change of $5.7 million as result of steeper decline rates in certain fields.

One of the distinctive characteristics of our large, diversified mineral position is that operators are continually conducting exploration and development drilling, recompletion, and workover operations on our interests. We do not pay for these operations, but we do receive a share of the production they generate. This mode of operation has resulted in relatively constant production rates from our mineral interests in the last several years, and we expect that this will continue. We refer to this phenomenon as “regeneration.” The new sources of production that we expect to materialize due to regeneration will also be the source of future extensions and discoveries, and positive revisions to our reserve estimates, which may effect out future depletion and amortization rates.

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Corporate Segment

	Twelve Months Ending December 31
	2007			2006
	($ in thousands)
Revenues:
Realized commodity derivatives	$	(3,061	)	$	2,302
Unrealized commodity derivatives		(130,773	)		(26,306	)
Total revenues		(133,834	)		(24,004	)
General and administrative		27,799			10,860
Depreciation and amortization		754			1,035
Other expense		2,847			6,000
Operating income		(165,234	)		(41,899	)
Other income (expense):
Interest income		1,160			996
Other income		696			—
Interest expense, net		(37,521	)		(29,759	)
Unrealized interest rate derivatives		(13,403	)		2,774
Other income (expense)		(8,226	)		(1,619	)
Total other income (expense)		(57,294	)		(27,608	)
Loss before taxes		(222,528	)		(69,507	)
Income tax provision		169			1,230
Segment loss	$	(222,697	)	$	(70,737	)

Revenues. As a master limited partnership, we distribute Available Cash (as defined in our partnership agreement) every quarter to our unitholders. The volatility inherent in commodity prices generates uncertainty around achieving a steady flow of available cash. We counter this by entering into certain derivative transactions to reduce our exposure to commodity price risk and reduce uncertainty surrounding our cash flows.

Our Corporate Segment’s revenues, which solely include the Partnership’s commodity derivatives activity, for the year decreased to a loss of $133.8 million for the year ended December 31, 2007, from a loss of $24.0 million for the year ended December 31, 2006.  As a result of our commodity hedging activities, revenues include a total realized  loss of $3.1 million on risk management activity that was settled during the year ended December 31, 2007, and an unrealized mark-to-market  loss of $130.8 million for the year ended December 31, 2007, as compared to a realized gain of $2.3 million on risk management activity that was settled for the year ended December 31, 2006 and an unrealized mark-to-market net loss of $26.3 million for the year ended December 31,2006.

As the forward price curves for our hedged commodities shift in relation to the caps, floors, swap and strike prices at which we have executed our derivative instruments, the fair market value of such instruments changes through time. The unrealized, non-cash mark-to-market net gain in 2006 as compared to our  loss in 2007 reflects overall favorable forward curve price movements as they relate to our physical volumes sales during the twelve month period for commodities underlying the derivative instruments. The unrealized mark-to-market loss for 2007 of $130.8 million reflects $122.5 million in losses related to our crude oil, NGL and natural gas positions as the forward curve prices in these commodities increased during the year, as well as $8.2 million loss related to amortization of put premiums during the term of the underlying options.  The unrealized mark-to-market net loss for 2006 is comprised of a $18.6 million gain related to our NGL position and crude oil as the forward curve prices in these commodities decreased during the year, $25.7 million loss related to our natural gas position as the forward curve price increased during the year, and the $19.2 million loss related to amortization of put premiums during the term of the underlying options. Neither the unrealized mark-to-market net loss of $26.3 million for 2006   nor the unrealized mark-to-market loss of $130.7 million for 2007 had an impact on cash activities for the 2006 period and 2007 period, as applicable, and as such are excluded from our calculation of Adjusted EBITDA.

Given the uncertainty surrounding future commodity prices, and the general inability to predict these as they relate to the caps, floors, swaps and 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. Conversely, negative commodity price movements affecting our revenues and costs are expected to be partially offset by our executed derivative instruments.

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General and Administrative Expenses. General and administrative expenses increased by $16.9 million from $10.9 million for the year ended December 31, 2006 to $27.8 million for the year ended December 31, 2007. This growth in general and administrative expenses was mostly driven by increased head-count in our corporate office as a result of our 2006 acquisitions, our expansion into the minerals and upstream businesses related to the Montierra, Redman and EAC acquisitions, and to  recruiting efforts in accounting, back-office, engineering, land and operations-related corporate personnel associated with being a public partnership. Corporate-office payroll expenses increased by $4.8 million as a result. Also as a result of being a public partnership, our public partnership expenses related to audit, tax, Sarbanes-Oxley compliance and others increased by $4.3 million. Also, expenses related to outside professional services, including those related to the registration of common units related to our private placements of equity and funding of acquisitions with our common units, impacted our general and administrative expenses expense by $1.9 million. Insurance costs increased by $1.2 million as we insured our acquired assets. In addition, contract labor on an interim basis as we integrated acquisitions contributed to this increase in our general and administrative expenses by $0.6 million, while IT infrastructure increased by $0.9 million and we recorded other miscellaneous expense of $3.2 million. At the present time, we do not allocate our general and administrative expenses cost to our operational Segments. The Corporate Segment bears the entire amount.

Total other income (expense). Which includes both realized and unrealized gains/losses from our interest rate swaps, increased to $57.3 million for the year ended December 31, 2007 as compared to $27.6 million for the year ended December 31, 2006. This increase is a result of an increase in our debt outstanding from $405.7 million at the end of 2006, to $567.1 million at the end of 2007. This increase in funded debt results from our debt financing of several organic projects and acquisitions during the year, including the Tyler County Pipeline Expansion, Red Deer processing plant project and the acquisitions of Redman and EAC, partially financed by a $106 million draw from our credit facility. In addition, increased base interest rate and a higher interest rate margin also decreased our interest expense. We entered into a new Senior Revolving Credit Facility on December 13, 2007 (as discussed in greater detail in Item 7. “—Liquidity and Capital Resources” below and Item 7A. Quantitative and Qualitative Disclosures About Market Risk), which carries a lower interest rate margin than our previous credit facility. However, this only impacted our interest expense for a two-week period.

Total other income (expense), includes interest rate swap realized gain of $1.4 million. We also recorded an unrealized mark-to-market loss of $13.4 million related to our interest rate risk management position reflected in Interest Expense—net. The unrealized gain relates to our future periods interest swaps and from changes during the year in the underlying interest rate associated with the derivatives. The unrealized mark-to-market gain did not have any impact on cash activities for the 2006 period and 2007 period, as applicable, and is excluded by definition from our calculation of Adjusted EBITDA.

Adjusted EBITDA. Adjusted EBITDA, as defined in Part II, Item 6. Selected Financial Data – Non GAAP Financial Measures, increased by $52.2 million from $81.2 million for the year ended December 31, 2006 to $133.4 million for the year ended December 31, 2007. The components of adjusted EBITDA are revenues minus cost of natural gas and natural gas liquids, offset by operating expenses, taxes other than income and general and administrative expenses.

As described above, revenues minus cost of natural gas and natural gas liquids for the Midstream Segment (including the Texas Panhandle, East Texas / Louisiana, including the acquired Laser Assets, and the newly created South Texas Segment) grew by $32.2 million as compared to the year ended December 31, 2006.  The acquisitions leading to our entry into our Upstream and Mineral Segments contributed $51.8 million and $15.0 million, respectively, to revenues while our Corporate Segment’s realized commodity derivatives loss increased by $5.4 million as compared to the year ended December 31, 2006. This resulted in $93.6 million of total incremental revenues minus cost of natural gas and natural gas liquids, adjusted to exclude the impact of un-realized commodity derivatives not included in the calculation of Adjusted EBITDA, with respect to 2006.

Operating expenses (including Taxes Other Than Income), increased by $9.3 million for our Midstream Segment with respect to 2006, while the acquisitions which created the Upstream and Minerals Segments contributed incremental operating Expenses (including Taxes Other Than Income) of $15.9 million and $0.8 million, respectively.  This resulted in total incremental Operating Expenses of $26.0 million.

General and administrative expense, captured in the Corporate Segment, increased by $14.7 million adjusted to exclude non-cash compensation charges related to our LTIP program, while Other Expense decreased by $3.2 million, with respect to 2006.

As a result, revenues (excluding the impact of unrealized commodity derivative activity) minus cost of natural gas and natural gas liquids increased by $93.6 million, operating expenses increased by $26.0 million and general and administrative expenses increased by $14.7 million, resulting in an increase to Adjusted EBITDA of $52.2 million from 2006 to 2007.

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Other Expense. Other expense reflects the arbitration award recorded during 2007 of approximately $1.4 million related to a dispute on the Panhandle operations for periods before the Partnership’s ownership. In addition, approximately $0.3 million relates to a separation expense accrual recorded during 2007.

In addition, other expense includes the non-cash write-off of $6.2 million in unamortized debt issuance costs related to our previous credit facility.

Related to registration rights granted to our March 2006 pre-IPO investors and investors in our May 2007 private equity placement, the Partnership incurred $1.0 million in liquidated damages as the effective registration of these investors’ common units was not achieved within the timeframe specified in such registration statements.

Income Tax Provision. Income taxes recorded during the year ended December 31, 2007 of approximately $0.2 million reflects the Texas Margin Tax recorded during the current year offset by the reduction of the deferred tax liability created by the book/tax differences as a result of the acquisition of Redman Energy Corporation.

Liquidity and Capital Resources

Historically, our sources of liquidity have included cash generated from operations, equity investments by our owners, borrowings under our existing credit facilities and the private placement of our common units among institutional investors.  During 2008, however, our sources of cash were limited to cash generated from operations and borrowings under our existing credit facility.

We believe that the cash generated from these sources will continue to be sufficient to meet our minimum quarterly cash distributions and our requirements for short-term working capital and long-term capital expenditures for at least the next twelve months.  The actual distributions we will declare will be subject to our operating performance, prevailing market conditions (including forward oil, natural gas and sulfur commodity prices), the impact of unforeseen events and the approval of our Board of Directors and will be done pursuant to our distribution policy described in Part II, Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

In the event that we acquire additional midstream assets or natural gas or oil properties that exceed our existing capital resources, we expect that we will finance those acquisitions with a combination of expanded or new debt facilities and, if necessary, new equity issuances.  The continued credit crisis and related turmoil in the global financial system has caused restricted access to the capital markets, particularly for non-investment grade companies like us.  If these conditions continue, we expect our level of acquisition activity to be lower going forward than that which we experienced in 2007 and 2008.  The ratio of debt and equity issued, if any, will be determined by our management and our board of directors as deemed appropriate.

Cash Flows

From January 1, 2007 through December 31, 2008, there have been several key events that have had major impacts on our cash flows. They are:

• the completion of the Tyler County Pipeline Extension into our Brookeland System on March 31, 2007 at a cost of approximately $24.2 million, which we financed with proceeds from a draw on our credit facility;

• the acquisition of certain fee minerals, royalties and non-operated working interest properties, directly and by entity acquisition, from Montierra Minerals & Production, L.P., and NGP-VII Income Co-Investment Opportunities, L.P. on April 30, 2007 for an aggregate purchase price of $139.2 million, including cash of $5.4 million;

• the acquisition of Laser Midstream Energy, LP, on May 3, 2007, including its subsidiaries Laser Quitman Gathering Company, LP, Laser Gathering Company, LP, Hesco Gathering Company, LLC, and Hesco Pipeline Company, LLC, for $142.6 million, including $113.4 million in cash;

• the acquisition of certain fee minerals, royalties and non-operated working interest properties from MacLondon Energy, L.P. on June 18, 2007 for $18.2 million, including cash of approximately $0.1 million;

• the private placement of 7,005,495 common units to several institutional purchasers in a private offering resulting in gross proceeds of $127.5 million, on May 3, 2007. The proceeds from this offering were used to fully fund the cash portion of the purchase price of the Laser Acquisition and other general company purposes;

• the refurbishment and installation of a 20 MMcf/d processing facility located in Roberts County, Texas called our Red Deer Processing Plant, at a cost of $16.2 million and put in service on June 21, 2007;

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• the acquisition of Escambia Asset Co, LLC and Escambia Operating Co, LLC on July 31, 2007 for $241.8 million, including $224.6 million in cash;

• the acquisition 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. on July 31, 2007 for $192.8 million, including $84.6 million in cash;

• the private placement of 9,230,770 common units among a group of institutional investors for total cash proceeds of approximately $204.0 million on July 31, 2007. The proceeds from the private offering were used to partially fund the cash portion of the purchase price of the Escambia and Redman Acquisitions;

• the acquisition of Stanolind Oil and Gas Corp. on April 30, 2008, for which we paid $81.9 million in cash drawn from our revolver and cash on hand; and

• the acquisition of Millennium Midstream Partners, L.P. on October 1, 2008 for $205.2 million, including $181.0 million in cash drawn from our revolver and cash on hand, excluding amounts placed into an escrow account.

Cash Distributions. On February 7, 2007, we declared a cash distribution of $0.3625 per common unit for the fourth quarter of 2006, prorated to $0.2679 per common unit for the timing of the initial public offering on October 24, 2006. The distribution to the common units was paid on February 15, 2007. No distribution was made to the general partner or Holdings (on the general partner units or subordinated units) for the quarter.

On May 4, 2007, we declared a cash distribution of $0.3625 per common unit for the first quarter ending March 31, 2007. The distribution was paid May 15, 2007, for common unitholders of record as of May 7, 2007, not including common unitholders who acquired common units in either the Montierra Acquisition or the Laser Acquisition. No distribution was made to the general partner or Holdings (on the general partner units or subordinated units) for the quarter.

On August 6, 2007, we declared a cash distribution of $0.3625 per common unit for the second quarter ending June 30, 2007. The distribution was paid August 14, 2007 to common unitholders of record as of August 8, 2007, not including common unitholders who acquired common units in the MacLondon, EAC or Redman Acquisitions. No distribution was made to the general partner or Holdings (on the general partner units or subordinated units) for the quarter.

On November 8, 2007, we declared a cash distribution of $0.3675 per unit for the third quarter ended September 30, 2007. The distribution was paid November 14, 2007 to all unitholders of record as of November 8, 2007, including the general partner and Holdings (on the general partner units and subordinated units, respectively).

On February 6, 2008, we declared a cash distribution of $0.3925 per unit for the fourth quarter ended December 31, 2008.  The distribution was paid February 15, 2008 to all unitholders of record as of February 11, 2008, including the general partner and Holdings (on the general partner units and subordinated units, respectively).

On April 30, 2008, we declared a cash distribution of $0.40 per unit for the first quarter ended March 31, 2008. The distribution was paid May 15, 2008 to all unitholders of record as of May 9, 2008, including the general partner and Holdings (on the general partner units and subordinated units, respectively).

On July 29, 2008, we declared a cash distribution of $0.41 per unit for the second quarter ended June 30, 2008.  The distribution was paid on August 14, 2008, to all unitholders of record as of August 8, 2008, including the general partner and Holdings (on the general partner units and subordinated units, respectively).

On October 29, 2008, we declared a cash distribution of $0.41 per unit for the third quarter ended September 30, 2008.  The distribution was  paid on November 14, 2008, to all unitholders of record as of November 7, 2008, including the general partner and Holdings (on the general partner units and subordinated units, respectively), but not including common unitholders who acquired common units in the Millennium Acquisition.

On February 4, 2009, we declared a $0.41 per unit distribution on all outstanding units (including common units, general partner units, and subordinated units) for the fourth quarter of 2008, payable on February 13, 2009 to the unitholders of record on February 10, 2009. The distribution to the common units, general partner units and subordinated units was paid on February 13, 2009.

Working Capital. Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. As of December 31, 2008, working capital was $57.5 million as compared to $15.1 million as of December 31, 2007.

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The net increase in working capital of $42.4 million from December 31, 2007 to December 31, 2008, resulted primarily from the following factors:

• cash balances and marketable securities, net of due to affiliates, decreased overall by $38.1 million and was impacted primarily from the working capital balances acquired in the acquisitions during the year, from the results of operations, timing of capital expenditures payments, financing activities including our debt activities as well as members’ equity distributions;

• the Due to Affiliate liability of $4.3 million as of December 31, 2008 is owed to Eagle Rock Energy G&P, LLC;

• trade accounts receivable decreased by $19.7 million primarily due to an increase in our allowance for bad debt of $10 million related to SemCrude, and from a decline in commodity prices during the last three months of the year ended December 31, 2008;

• risk management net working capital balance increased by a net $29.9 million as a result of the changes in current portion of the mark-to-market unrealized positions and the purchase of option premiums;

• accounts payable decreased by $15.9 million from December 31, 2007 primarily as a result the decline in commodity prices during the last three months of the year ended December 31, 2008 compared to the same time period in the prior year and timing of payments, including capital expenditures activities; and

• accrued liabilities increased by $9.8 million primarily reflecting unbilled expenditures, timing of payments related to compensation and activities from the acquisitions during the year.

Cash Flows Year Ended 2008 Compared to Year Ended 2007

Cash Flow from Operating Activities. The increase of $80.1 million during the current year is the result of increased income from the acquired assets, the growth capital expenditure projects and rising commodity prices during the first half of 2008.

Cash Flows from Investing Activities. Cash flows used by investing activities for the year ended December 31, 2008, as compared to the year ended December 31, 2007, decreased by $135.3 million. The investing activities for the current year reflect the net cash consideration for acquisition assets of $262.2 million, versus net cash consideration for acquisition assets of $407.6 million for the previous year. In addition, investing activities for the current year reflect a slightly higher capital expenditure level of $66.7 million versus $66.1 million for the year ended 2007.

Cash Flows from Financing Activities. Cash flows provided by financing activities for the year ended December 31, 2008 decreased by $324.0 million over the year ended December 31, 2007. Key differences between years include $331.5 million less in net proceeds from equity issuance, a $71.0 million increase in net debt balances and increased distributions of $58.1 million.

Cash Flows Year Ended 2007 Compared to Year Ended 2006

Cash Flows from Operating Activities. Increase of $52.0 million during 2007 compared to 2006 is the result of increased income from both the acquired assets and the growth capital expenditure projects.

Cash Flows from Investing Activities. Cash flows used by investing activities for the year ended December 31, 2007, as compared to the year ended December 31, 2006, increased by $340.9 million. The investing activities for 2007 reflect the net cash consideration for acquisition assets, $407.6 million, versus net cash consideration for acquisition assets, $101.2 million for 2006. In addition, investing activities for 2007 reflect a higher capital expenditure level of $66.1 million versus $38.4 million for the year ended 2006. In addition, cost for acquiring intangibles, primarily pipeline rights-of-way decreased by $0.9 million.

Cash Flows from Financing Activities. Cash flows provided by financing activities for the year ended December 31, 2007, increased by $355.7 million, over the year ended December 31, 2006. Key differences between years include higher net proceeds from equity issuance of $331.5 million and increase in net debt balances of $161.3 million, offset by lower member contribution of $98.5 million and increased distribution of $37.5 million. Distributions, not including the IPO-related distributions, were a cash outflow of $59.4 million in 2007, as compared to $22.0 million in 2006.

Capital Requirements

The energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as either:

• acquisition-related capital expenditures, which are made to acquire additional assets, properties or companies to increase the scope of our business;

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• growth capital expenditures, which are made to expand and upgrade existing systems and facilities or to construct similar systems or facilities, or to grow our production in our Upstream Business; or

• maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to meet regulatory requirements, to maintain the existing operating capacity of our assets and extend their useful lives, or to connect wells to maintain existing system volumes and related cash flows; in our Upstream Business, maintenance capital is defined as capital which is expended to maintain our production and cash flow levels in the near future.

Our 2008 capital budget anticipated that we would spend approximately $54.3 million in total in 2008 on our existing assets. We actually spent approximately $70.7 million in total in 2008, including the Stinnett to Cargray consolidation, Stinnett plant relocation and numerous capacity expansion, well connection and maintenance projects within our Midstream Business and the turnaround at our BEC Plant and drilling, recompletion and workover activities within our Upstream Segment.

Our 2009 capital budget anticipates that we will spend approximately $40 million in total for the year on our existing assets. This budget includes capital expenditures for growth, maintenance and well connect projects in both our Midstream and Upstream Segments.  We reduced our 2009 capital budget in late 2008 to reflect more conservative assumptions on capital availability during 2009 as a result of the continued global credit crisis.  We intend to finance our maintenance capital expenditures (including well connect costs) with internally generated cash flow, and our growth capital expenditures with draws from our Revolving Credit Facility.

Since 2004, we have made substantial growth capital expenditures.  We anticipate we will continue to make growth capital expenditures and acquisitions as opportunities arise and as long as we can secure equity or debt financing at levels and costs satisfactory to us.  We continually review opportunities for both organic growth projects and acquisitions which will enhance our financial performance. Because we will distribute most of our available cash to our unitholders, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives.  We will depend on borrowings under our Revolving Credit Facility and the issuance of debt and equity securities to finance any future growth capital expenditures or acquisitions.  We do not believe the equity or debt markets are currently available to us at levels and costs satisfactory to us.

Hedging Strategy

We use a variety of hedging instruments to accomplish our risk management objectives.  At times our hedging strategy may involve entering into hedges with strike prices above current futures prices or resetting existing hedges to higher price levels in order to meet our cash flow requirements, stay in compliance with our credit facility covenants and continue to execute on our distribution objectives.  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. 

Revolving Credit Facility

On December 13, 2007, we entered into a credit agreement with Wachovia Bank, National Association, as administrative agent and swing line lender, Bank of America, N.A., as syndication agent; HSH Nordbank AG, New York Branch; the Royal Bank of Scotland, plc; and BNP Paribas, as co-documentation agents, and the other lenders who are parties to the agreement with aggregate commitments of up to $800 million.  During the year ended December 31, 2008, we exercised $180 million of our $200 million accordion feature under the credit facility, which increased the total commitment to $980 million.  In connection with exercising the accordion feature of our credit facility, we incurred debt issuance costs of $0.8 million.  We exercised the accordion feature to provide for adequate funding associated with our growth strategy.    Pursuant to the credit facility we may, at our request and subject to the terms and conditions of the credit facility, increase our commitments by an additional $20 million to an aggregate of $1 billion.  As a result of Lehman Brothers’ bankruptcy filing, the amount of available commitments was reduced by the unfunded portion of Lehman Brothers’ commitment in an amount of approximately, $9.1 million.   As of December 31, 2008, unused capacity available to us under the new credit agreement, based on financial covenants, is approximately $171.5 million.  The credit agreement is scheduled to mature on December 13, 2012.

Given the current state of the banking industry worldwide, we have endeavored to diversify our lender group as much as possible. As such, after the upsizing of our credit facility as described above, our credit facility now includes the participation of 20 financial institutions. As of today, all of our banks’ commitments, with the exception of Lehman Brothers’ commitment, remain in place and have funded in response to our borrowing notices.  A Lehman Brothers subsidiary has an approximately 2.6% participation in the Partnership’s credit facility.  We believe that based on the expected positive effects of the passing of the Emergency Economic Stabilization Act of 2008, and similar initiatives around the world, credit will continue to be available under our credit facility.

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Off-Balance Sheet Obligations.

We have no off-balance sheet transactions or obligations.

Debt Covenants.

Our credit facility accommodates, through the use of a  borrowing base for our Upstream Business and traditional cash-flow based covenants for our Midstream and Minerals Businesses, the allocation of indebtedness to either our Upstream Business (to be measured against the borrowing base) or to our Midstream and Minerals Businesses (to be measured against the cash-flow based covenant).  At December 31, 2008, we were in compliance with our covenants under the credit facility. Our interest coverage ratio, as defined in the credit agreement (i.e., Consolidated EBITDA divided by Consolidated Interest Expense), was 6.6 as compared to a minimum interest coverage covenant of 2.5, and our leverage ratio, as defined in the credit agreement (i.e., Total Funded Indebtedness divided by Adjusted Consolidated EBITDA), was 3.7 as compared to a maximum leverage ratio of 5.0 times (5.25 times until March 31, 2009 due to the Millennium Acquisition).  As of December 31, 2008, the borrowing base for our Upstream Business was determined at $206 million.  As a result of the current commodity price environment and depressed economic activity, which will negatively impact our financial results going forward, we expect that our borrowing base will be re-determined in early April 2009 to a lower amount (resulting in a higher allocation of indebtedness to our Midstream and Minerals Businesses) and a rise in our leverage ratio in 2009.  This may cause us to take steps to reduce our leverage or enhance our Adjusted Consolidated EBITDA, as defined in our credit facility, (e.g., through further hedge resets). As a result of our hedging transactions executed on January 8, 2009, which enhanced our expected 2009 EBITDA, as defined under our credit facility, as described above and in Note 19 to our Consolidated Financial Statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report, however, we believe that, assuming that our producers volumes through our systems are in line with our expectations, we will remain in covenant compliance for the remainder of 2009.

Total Contractual Cash Obligations.

The following table summarizes our total contractual cash obligations as of December 31, 2008.

	Payments Due by Period
Contractual Obligations	Total		2009		2010		2011			2012- 2013	Thereafter
	($ in millions)
Long-term debt (including interest)(1)	$	982.6	$	46.1	$	46.1	$	46.1	$	844.3	$	—
Operating leases		12.1		1.7		0.8		0.7		1.2		7.7
Purchase obligations(2)		—		—		—		—		—		—
Total contractual obligations	$	994.7	$	47.8	$	46.9	$	46.8	$	845.5	$	7.7

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(1) Assumes our fixed swapped average interest rate of 3.76% plus the applicable margin under our amended and restated credit agreement, which remains constant in all periods.

(2) Excludes physical and financial purchases of natural gas, NGLs, and other energy commodities due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.

Recent Accounting Pronouncements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). This statement defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. The statement was effective for financial statements issued for fiscal years beginning after November 15, 2007. We adopted SFAS No. 157 on January 1, 2008, and it did not have a material impact on our consolidated results of operations and financial position.

In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”), which delays the effective date of SFAS 157 for all nonfinancial assets and non financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on at least an annual basis, until fiscal years beginning after November 15, 2008.  We do not expect the adoption of FSP FAS 157-2 to have a material impact on our consolidated financial statements.

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In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”), which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 was effective for us as of January 1, 2008 and had no impact as we elected not to measure additional financial assets and liabilities at fair value.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS No. 141R”), which replaces SFAS No. 141.  SFAS 141R requires that all assets, liabilities, contingent consideration, contingencies and in-process research and development costs of an acquired business be recorded at fair value at the acquisition date; that acquisition costs generally be expensed as incurred; that restructuring costs generally be expensed in periods subsequent to the acquisition date; and that changes in accounting for deferred tax asset valuation allowances and acquired income tax uncertainties after the measurement period impact income tax expense.  SFAS No. 141R is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, with the exception for the accounting for valuation allowances on deferred tax assets and acquired tax contingencies associated with acquisitions.  SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes, such that adjustments made to valuation allowances on deferred taxes and acquired tax contingencies associated with acquisitions that closed prior to the effective date of SFAS No. 141R would also apply the provisions of SFAS No. 141R.  The impact of the adoption of SFAS No. 141R on our consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 requires that accounting and reporting for minority interests will be re-characterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This Statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. We do not expect the adoption of SFAS No. 160 to have a material impact on our consolidated financial statements.

In March 2008, the FASB issued Statement No. 161, Disclosures About Derivative Instruments and Hedging Activities (“SFAS No. 161”). SFAS No. 161 requires enhanced disclosures to help investors better understand the effect of an entity’s derivative instruments and related hedging activities on its financial position, financial performance, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We do not expect the adoption of SFAS No. 161 to have a material impact on our consolidated financial statements.

In March 2008 the FASB approved EITF Issue No. 07-4,  Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships, which requires that master limited partnerships use the two-class method of allocating earnings to calculate earnings per unit. EITF Issue No. 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008. We do not expect the adoption of EITF Issue No. 07-4 to have a material impact on our earnings per unit calculation and consolidated financial statements. 

In April 2008, the FASB issued FASB Staff Position (“FSP”) No. SFAS 142-3, Determination of the Useful Life of Intangible Assets (“FSP SFAS 142-3”).  FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS 142”).  The intent of FSP SFAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R (revised 2007), Business Combinations (“SFAS 141R”) and other applicable accounting literature.  FSP SFAS 142-3 is effective for financial statements issued forfiscal years beginning after December 15, 2008 and must be applied prospectively to intangible assets acquired after the effective date.  The impact of the adoption of FSP SFAS 142-3 on our consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009.

In May 2008, the FASB issued SFAS No. 162, Hierarchy of Generally Accepted Accounting Principles (“SFAS 162”).  This statement is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with GAAP.  This statement will be effective 60 days following the U.S. Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board amendment to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.  We do not expect the adoption of SFAS 162 to have a material impact on our consolidated financial statements. 

In June 2008, the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”).  FSP EITF 03-6-1 affects entities that accrue cash dividends on share-based payment awards during the awards’ service period when dividends do not need to be returned if the employees forfeit the awards.  FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008 and earnings-per-unit calculations would need to be adjusted retroactively.  We are currently evaluating the effect that FSP EITF 03-6-1 will have on our earnings per unit calculation and consolidated financial statements.

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In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling will become effective for disclosures in our Annual Report on Form 10-K for the year ended December 31, 2009.

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

Risk and Accounting Policies

We are exposed to market risks associated with adverse changes in commodity prices, interest rates and counterparty credit. We may use financial instruments such as puts, calls, swaps 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, or sulfur prices, or interest rates could adversely impact our ability to make distributions to our unitholders, meet debt service obligations, fund required capital expenditures and fulfill 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. The Risk Management Committee 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 Risk Management Committee is responsible for the overall management of commodity price risk, interest rate risk and credit risk, including monitoring exposure limits.

See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Critical Accounting Policies and Estimates — Risk Management Activities and Note 11 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 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.

The Risk Management Committee (“RMC”) is the entity responsible for creating and implementing a sound approach to managing our commodity price 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 risk;

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

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

• Establish controls for risk management activities, including hedging transactions and financial reporting;

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

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

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

The Risk Management Committee is charged with the following:

• Establishing an organizational structure for risk management controls;

• Developing and enforcing policies related to setting and following acceptable risk parameters and risk limits;

• Establishing clearly-defined segregation of duties and delegations of authority;

• Identifying permitted transaction and product types;

• Establishing and enforcing counterparty credit limitations; and

• Developing and executing policies for risk reporting.

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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 frequently use financial derivatives (“hedges”) to reduce our exposure to commodity price risk. We have implemented a Risk Management Policy which allows management to execute crude oil, natural gas liquids and natural gas hedging instruments, which may include swaps, collars, options and other derivatives, in order to reduce exposure to substantial adverse changes in the prices of these commodities. These hedges are only intended to mitigate the risk associated with our natural physical position. We monitor and ensure compliance with this 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 80% 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 in the fourth quarter of 2008 and have obtained for 2009.

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.

See Note 11 to our consolidated financial statements included in Part II, Item 8 Financial Statements and Supplementary Data starting on page F-1 of this Annual Report for additional discussion of our commodity hedging activities.

We have not designated our contracts as accounting hedges under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. 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.

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The following table, as of December 31, 2008, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2009:

Underlying	Period	Notional Volumes (units)	Type	Floor Strike Price ($/unit)		Cap Strike Price ($/unit)		Fair Value
	($ in thousands except volumes and $/unit)
Natural Gas:
IF Waha	Jan-Mar 2009	60,000 mmbtu	Costless Collar	$	9.00	$	9.85	$	249
IF Waha	Apr-Jun 2009	60,000 mmbtu	Costless Collar		7.50		7.95		153
IF Waha	Jul-Sep 2009	60,000 mmbtu	Costless Collar		7.50		8.60		120
IF Waha	Oct-Dec 2009	60,000 mmbtu	Costless Collar		7.50		8.90		100
NYMEX Henry Hub	Jan-Mar 2009	185,400 mmbtu	Costless Collar		7.00		13.75		378
NYMEX Henry Hub	Jan-Mar 2009	(185,400) mmbtu	Costless Collar		8.80		13.75		(834	)
NYMEX Henry Hub	Jan-Dec 2009	220,000 mmbtu	Costless Collar		6.25		11.20		181
NYMEX Henry Hub	Jan-Dec 2009	935,000 mmbtu	Costless Collar		7.85		9.25		1,898
NYMEX Henry Hub	Jan-May 2009	160,000 mmbtu	Put		7.00				282
NYMEX Henry Hub	Jan-Dec 2009	935,000 mmbtu	Swap		8.35				2,269
NYMEX Henry Hub	Jan-Dec 2009	770,000 mmbtu	Swap		6.685				481
NYMEX Henry Hub	Jan-Dec 2009	490,000 mmbtu	Swap		6.885				265
Crude Oil:
NYMEX WTI	Jan-May 2009	35,000 bbls	Costless Collar		60.00		80.75		423
NYMEX WTI	Jan-Dec 2009	72,000 bbls	Costless Collar		60.00		77.00		669
NYMEX WTI (1)	Jan-May 2009	240,000 bbls	Costless Collar		50.00		66.25		390
NYMEX WTI (1)	Jan-Dec 2009	240,000 bbls	Costless Collar		50.00		66.55		408
NYMEX WTI	Jan-Dec 2009	120,000 bbls	Costless Collar		93.00		100.85		4,594
NYMEX WTI	Jan-Dec 2009	60,000 bbls	Put		90.00				3,949
NYMEX WTI	Jan-Dec 2009	84,000 bbls	Put		100.00				3,448
NYMEX WTI	Jan-Dec 2009	300,000 bbls	Swap		71.25				5,004
NYMEX WTI	Jan-Dec 2009	600,000 bbls	Swap		100.00				38,695
Natural Gas Liquids:
OPIS Ethane Mt Belv non TET	Jan-Dec 2009	5,040,000 gallons	Costless Collar		0.48		0.58		391
OPIS Ethane Mt Belv non TET	Jan-Dec 2009	5,040,000 gallons	Swap		0.53				558
OPIS Ethane Mt Belv non TET	Jan-Dec 2009	12,600,000 gallons	Swap		0.6361				2,734
OPIS IsoButane Mt Belv non TET	Jan-Dec 2009	1,260,000 gallons	Costless Collar		0.935		1.035		175
OPIS IsoButane Mt Belv non TET	Jan-Dec 2009	1,260,000 gallons	Swap		0.985				205
OPIS IsoButane Mt Belv non TET	Jan-Dec 2009	1,532,034 gallons	Swap		1.295				720
OPIS NButane Mt Belv non TET	Jan-Dec 2009	2,772,000 gallons	Costless Collar		0.935		1.035		466
OPIS NButane Mt Belv non TET	Jan-Dec 2009	2,772,000 gallons	Swap		0.985				540
OPIS NButane Mt Belv non TET	Jan-Dec 2009	3,045,000 gallons	Swap		1.2775				1,478
OPIS Propane Mt Belv non TET	Jan-Dec 2009	5,292,000 gallons	Costless Collar		0.765		0.815		661
OPIS Propane Mt Belv non TET	Jan-Dec 2009	5,292,000 gallons	Swap		0.815				788
OPIS Propane Mt Belv non TET	Jan-Dec 2009	7,560,000 gallons	Swap		1.0925				3,175
OPIS Propane Mt Belv non TET	Jan-Dec 2009	2,765,028 gallons	Swap		1.0775				1,136
OPIS Propane Mt Belv non TET	Jan-Dec 2009	1,489,236 gallons	Swap		1.0775				620
Total								$	76,769

(1) This costless collar was “unwound” as part of the January 8, 2009 hedge transactions.  See Note 19 of our consolidated financial statements included in Item II, Part 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report.

On January 8, 2009, the Partnership executed a series of hedging transactions that involved the unwinding of a portion of existing “in-the-money” 2011 and 2012 WTI crude oil swaps and collars, and the unwinding of two “in-the-money” 2009 WTI crude oil collars. With these transactions, and an additional $13.9 million of cash, the Partnership purchased a 2009 WTI crude oil swap on 60,000 barrels per month beginning January 1, 2009 at $97 per barrel. Both the unwound hedges and new hedges relate to expected volumes in the Partnership’s Partnership's Midstream and Minerals segments.

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The following table, as of December 31, 2008, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2010:

Underlying	Period	Notional Volumes (units)	Type	Floor Strike Price ($/unit)		Cap Strike Price ($/unit)		Fair Value
	($ in thousands except volumes and $/unit)
Natural Gas:
NYMEX Henry Hub	Jan-Dec 2010	1,320000 mmbtu	Costless Collar	$	7.70	$	9.10	$	1,200
Crude Oil:
NYMEX WTI	Jan-Dec 2010	60,000 bbls	Costless Collar		50.00		67.50		(275	)
NYMEX WTI	Jan-Dec 2010	60,000 bbls	Costless Collar		50.00		68.00		(289	)
NYMEX WTI	Jan-Dec 2010	108,000 bbls	Costless Collar		90.00		99.80		2,828
NYMEX WTI	Jan-Dec 2010	180,000 bbls	Costless Collar		50.00		67.50		(805	)
NYMEX WTI	Jan-Dec 2010	180,000 bbls	Costless Collar		50.00		68.00		(855	)
NYMEX WTI	Jan-Dec 2010	60,000 bbls	Put		100.00				3,149
NYMEX WTI	Jan-Dec 2010	72,000 bbls	Put		90.00				3,038
NYMEX WTI	Jan-Dec 2010	120,000 bbls	Swap		78.35				1,705
NYMEX WTI	Jan-Dec 2010	300,000 bbls	Swap		70.00				1,821
Natural Gas Liquids:
OPIS Ethane Mt Belv non TET	Jan-Dec 2010	4,536,000 gallons	Costless Collar		0.43		0.53		(28	)
OPIS Ethane Mt Belv non TET	Jan-Dec 2010	4,536,000 gallons	Swap		0.58				13
OPIS IsoButane Mt Belv non TET	Jan-Dec 2010	2,520,000 gallons	Costless Collar		0.82		1.02		10
OPIS NButane Mt Belv non TET	Jan-Dec 2010	5,544,000 gallons	Costless Collar		0.82		1.02		156
OPIS Propane Mt Belv non TET	Jan-Dec 2010	5,040,000 gallons	Costless Collar		0.705		0.81		83
OPIS Propane Mt Belv non TET	Jan-Dec 2010	5,040,000 gallons	Swap		0.755				134
Total								$	11,885

In addition to the hedging transactions discussed above, we also entered into a 125,000 MMBtu per month Henry Hub natural gas swap at $6.65/MMBtu on January 19, 2009 for our 2009 fiscal year, a 170,000 MMBtu per month Henry Hub natural gas swap at $6.14/MMBtu on February 17, 2009 for our 2010 fiscal year, a 45,000 barrel per month WTI crude oil swap at $53.55 per barrel on February 17, 2009 for our 2010 fiscal year and a 40,000 barrel per month WTI crude oil swap at $51.40 per barrel on February 19, 2009 for our 2010 fiscal year.

The following table, as of December 31, 2008, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2011:

Underlying	Period	Notional Volumes (units)	Type	Floor Strike Price ($/unit)		Cap Strike Price ($/unit)		Fair Value
	($ in thousands except volumes and $/unit)
Natural Gas:
NYMEX Henry Hub	Jan-Dec 2011	1,200,000 mmbtu	Costless Collar	$	7.50	$	8.85	$	646
Crude Oil:
NYMEX WTI(1)	Jan-Dec 2011	600,000 bbls	Costless Collar		75.00		85.70		5,341
NYMEX WTI(2)	Jan-Dec 2011	540,000 bbls	Swap		80.00				5,773
Total								$	11,760

(1) 460,848 barrels of this costless collar were “unwound” as part of the January 8, 2009 hedge transactions.  See Note 19 of our consolidated financial statements included in Part II, Item 8.  Financial Statements and Supplementary Data starting on page F-1 of this Annual Report for further information.

(2) 414,744 barrels of this swap were “unwound” as part of the January 8, 2009 hedge transactions.  See Note 19 of our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report for further information.

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The following table, as of December 31, 2008, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2012:

Underlying	Period	Notional Volumes (units)	Type	Floor Strike Price ($/unit)		Cap Strike Price ($/unit)		Fair Value
	($ in thousands except volumes and $/unit)
NYMEX Henry Hub	Jan-Dec 2012	1,080,000 mmbtu	Costless Collar	$	7.35	$	8.65	$	490
NYMEX WTI(1)	Jan-Dec 2012	600,000 bbls	Costless Collar		75.30		86.30		4,222
NYMEX WTI(2)	Jan-Dec 2012	480,000 bbls	Swap		80.30				4,094
Total								$	8,806

(1) 464,424 barrels of this costless collar were “unwound” as part of the January 8, 2009 hedge transactions.  See Note 19 of our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report for further information.

(2) 371,532 barrels of this swap were “unwound” as part of the January 8, 2009 hedge transactions. See Note 19 of our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report for further information.

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 and including the transactions we entered into in 2009 (see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview- Recent Transactions”), 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 2009 Adjusted EBITDA of $4.4 million and $0.1 million, respectively.

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.

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, the Partnership has 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 December 4, 2008, we executed a series of interest rate hedge transactions by which we extended the term on our existing interest rate swaps with a then notional amount of $450 million. The expiration dates on these swaps were extended from December 31, 2010 (for swaps with a notional value of $150 million), and January 3, 2011 (for swaps with a notional value of $300 million) to December 31, 2012. In addition, we blended the existing swap rates with the then prevailing interest rate swap rate for the period January 2011 through December 2012 (“blend and extend” strategy). This resulted in our weighted average three month LIBOR swap rate on our existing swaps decreasing from approximately 4.84% to approximately 4.16%.

In addition, on December 5, 2008, we executed an incremental interest rate swap on a notional amount of $150 million with an expiration of December 31, 2012 at a three month LIBOR swap rate of 2.56%. This additional transaction further reduced our weighted average three month LIBOR swap rate to approximately 3.76%. Including the impact of this transaction and the transactions discussed in the paragraph above, we estimate that for 2009, a 10% increase or decrease in the interest rates for our credit facility and interest rate hedge transactions as of December 31, 2008, will impact our interest expense by $2.3 million.

See Note 11 of our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report for additional discussion of our interest rate hedging activities.

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The table below summarizes the terms, amounts received or paid and the fair values of the various interest swaps:

Roll Forward Effective Date	Expiration Date	Notional Amount		Fixed Rate			Fair Market Value December 31, 2008
	($ in thousands except notional amount)
09/30/2008	12/31/2012	$	150,000,000		4.020	%	$	(11,398	)
09/30/2008	12/31/2012		150,000,000		4.295			(12,900	)
10/03/2008	12/31/2012		150,000,000		4.170			(12,199	)
12/31/2008	12/31/2012		150,000,000		2.560			(3,448	)
							$	(39,945	)

The table below summarizes the changes in commodity and interest rate risk management assets for the applicable periods:

	Year Ended 12/31/2008			Year Ended 12/31/2007
	($ in thousands)
Net risk management assets at beginning of period	$	(127,289	)	$	9,628
Investment premium payments (amortization), net		5,880			814
Acquired contracts in acquisitions		(2,710	)		350
Cash received from settled contracts		51,271			1,647
Settlements of positions		(51,271	)		(1,647	)
Unrealized mark-to-market valuations of positions		193,394			(138,081	)
Balance of risk management assets at end of period	$	69,275		$	(127,289	)

Credit Risk

Our principal natural gas sales customers are large gas marketing companies that, in turn, typically sell to large end users such as local distribution companies and electrical utilities. 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, 2008, ONEOK Hydrocarbon and ONEOK Energy Services, our two largest customers, represented 15.7% and 11.1% of our total sales revenue (including realized and unrealized gains on commodity derivatives.  All of our natural gas sales are under 30 day term deals, with credit based upon 60 days of deliveries and almost all other product sales contracts are under 30 day 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.

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.    We historically sold portions of our condensate production from our Texas Panhandle and East Texas midstream systems to SemGroup.  The abrupt bankruptcy of SemGroup caught us, the energy business and the financial community by surprise.  We are not aware of any other measures that we could have taken to identify this risk at an earlier time.  During the year ended December 31, 2008, we recorded a bad debt provision of $10.7 million related to our outstanding receivables from SemGroup.  We discontinued all sales to SemGroup as of August 1, 2008, and as a result, we do not anticipate recording any additional bad debt charges in future periods.

131

Our derivative counterparties include BNP Paribas, Wells Fargo Bank, N.A. / Wachovia Bank N.A Comerica Bank, Barclays Bank PLC, The Royal Bank of Scotland plc and its agent Sempra Energy Trading LLC, Bank of America N.A., J Aron & Company (an affiliate of Goldman Sachs) and British Petroleum North America Inc.

132

Item 8. Financial Statements and Supplementary Data.

Our consolidated financial statements, together with the independent registered public accounting firm’s report of Deloitte & Touche LLP (“Deloitte & Touche”), begin on page F-1 of this Annual Report.

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

None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

The Partnership maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Partnership’s reports under the 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 and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2008. Based on that evaluation, management concluded that, as of that date, the Partnership’s disclosure controls and procedures were effective.

2008 Acquisitions

Because the Stanolind and Millennium acquisitions were completed in the second and fourth quarters of 2008, respectively, management did not include the internal control processes for these entities in its assessment of internal control over financial reporting as of December 31, 2008.   Additionally, these acquisitions are excluded from the certifications required under section 302 of the Sarbanes-Oxley Act of 2002, which are attached as exhibits to this Annual Report.  Management will include all aspects of internal controls for these acquisitions in its 2009 assessment.

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 2008.  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” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).  Management excluded from its assessment the internal control over financial reporting of the Stanolind Acquisition and the Millennium Acquisition, which were completed in the second and fourth quarters of 2008, respectively, and whose total assets and revenues constitute 6.7% and 13.1% of total assets, respectively, and 0.8% and 1.9% of revenues, respectively of the consolidated financial statement amounts as of and for the year ended December 31, 2008.  Our evaluation and testing was conducted as of the year ended December 31, 2008, 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.

133

Remediation of 2007 Material Weaknesses

As previously reported, there were three material weaknesses in our internal control over financial reporting as of December 31, 2007. The remediation of these material weaknesses during fiscal 2008 is described as follows:

• Internal Control Environment. Additional qualified financial reporting and accounting personnel were hired and trained, and turnover was reduced.  Many of the additional staff were charged with and responsible for performing supervisory reviews and other monitoring activities over financial reporting matters and controls.  Management also provided COSO training, which included clear communication of management and the employee’s roles and responsibilities related to internal controls over financial reporting, across the Partnership. Remediation of this material weakness was initially disclosed in the Partnership’s second quarter Form 10-Q of 2008.  Management has determined that this material weakness continued to be remediated at December 31, 2008.

• Period-end Financial Reporting. Management enhanced preventative control activities and monitoring controls surrounding account reconciliations, hedging activities, non-routine transactions, and variance analyses which remediated the material weakness surrounding the overall Period End Financial Reporting process effective December 31, 2008.

• Midstream Cost of Natural Gas and Natural Gas Liquids.  Management implemented additional controls related to the loading and maintenance of monthly index pricing in the revenue system associated with the Midstream Business. Remediation of this material weakness was initially disclosed in the Partnership’s second quarter Form 10-Q of 2008.  Management has determined that this material weakness continued to be remediated at December 31, 2008.

Except as set forth above, there have been no changes in our internal control over financial reporting that occurred during the last quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

The Partnership’s independent registered public accounting firm has issued an attestation report based on their assessment of the Partnership’s internal control over financial reporting, which appears below.

134

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P. Houston, Texas

We have audited the internal control over financial reporting of Eagle Rock Energy Partners, L.P. and subsidiaries (the “Partnership”) as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management’s Annual Report on Internal Control Over Financial Reporting, management excluded from its assessment the internal control over financial reporting at Stanolind and Millennium (the “Acquired Entities”), which were acquired during the second and fourth quarter of 2008 and whose total assets and revenues constitute 6.7% and 13.1% of total assets, respectively, and 0.8% and 1.9% of revenues, respectively, of the consolidated financial statement amounts as of and for the year ended December 31, 2008. Accordingly, our audit did not include the internal control over financial reporting at the Acquired Entities. 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, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and 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 by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the 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, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2008, of the Partnership and our report dated March 12, 2009 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 12, 2009

135

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Management and Board of Directors of Eagle Rock Energy Partners, L.P.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business. Our general partner typically must act in “good faith” when making decisions on behalf of the Partnership, and our partnership agreement further provides that in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in the best interests of the Partnership; provided, however, our partnership agreement also allows our general partner to make certain decisions which are in the best interest of its owners.  See “Risk Factors” and our partnership agreement for a more detailed description.

Our general partner owes a fiduciary duty to our unitholders; however, this duty has been modified by our partnership agreement. See “Risk Factors” for a description of the provisions that modify our general partner’s fiduciary duties. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to our general partner. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to our general partner.

Because our general partner is a limited partnership, its general partner, Eagle Rock Energy G&P, LLC, makes all determinations on behalf of our general partner, including determinations related to the conduct of our business and operations. As a result, the executive officers of Eagle Rock Energy G&P, LLC, under the direction of the board of directors of Eagle Rock Energy G&P, LLC, make all decisions on behalf of our general partner with respect to the conduct of our business and operations. Neither our general partner, nor the general partner of our general partner, is elected by our unitholders, and neither entity will be subject to re-election on a regular basis in the future. Unitholders are not entitled to elect the directors of Eagle Rock Energy G&P, LLC, the general partner of our general partner, nor are unitholders otherwise entitled to directly or indirectly participate in our management or operation. Our general partner may be removed by the unitholders, subject to the satisfaction of various conditions which will be difficult to meet.

The directors of Eagle Rock Energy G&P, LLC, the general partner of our general partner, oversee our operations. Eagle Rock Energy G&P, LLC has seven directors, three of whom are independent as defined under the independence standards established by the NASDAQ Global Select Market. The NASDAQ Global Select Market does not require a listed limited partnership like us to have a majority of independent directors on the Board of Directors of our general partner, or to establish a compensation committee or a nominating and governance committee. Nevertheless, we have established a compensation committee, and two of its three members are independent. All of our board members served during the entire calendar year of 2008.  Our board of directors met 10 times during 2008 with each board member attending at least 80% of our board meetings. Additionally, our board of directors took action by written consent 10 times during 2008.

We have an audit committee of three directors, Philip B. Smith, William K. White and William A. Smith, all of whom meet the independence and experience standards established by the NASDAQ Global Select Market and the Securities Exchange Act of 1934, as amended. Mr. White served as chairman of our audit committee during 2008 and currently serves as our audit committee chairman for 2009. We have determined that Mr. White meets the standards of and has been designated as our “financial expert” on the audit committee in compliance with the SEC standards and the NASDAQ Global Select Market standards. The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee.  Additionally, the audit committee has the sole authority to retain and terminate our independent reservoir engineering firm.

Our audit committee met 16 times during 2008 with all three members of the audit committee attending at least 87% of the meetings. Our audit committee regularly meets with our independent registered public accounting firm, Deloitte & Touche LLP, outside the presence of our management most often at the conclusion of regularly scheduled audit committee meetings.

We also have a compensation committee, comprised of William A. Smith, William J. Quinn and Philip B. Smith.  Mr. W. Smith served as chairman of our compensation committee since February 2008 and currently serves as our compensation committee chairman for 2009. Before February 2008, Mr. William Quinn served as chairman of the compensation committee.  Among other things, the compensation committee oversees the compensation plans and determination of the overall compensation for officers and employees. The compensation committee met seven times during 2008 with all three members of the compensation committee attending at least 71% of the meetings.  Our compensation committee also took action by unanimous written consent four times during 2008.

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Additionally, we have a standing conflicts committee, which currently consists of the three members of our board of directors who meet the independence described above for members of the audit committee, Messrs. P. Smith, W. White, and W. Smith. Mr. P. Smith served as chairman of our conflicts committee during 2008, and currently serves as our conflicts committee chairman for 2009. The conflicts committee reviews specific matters that the board believes may involve conflicts of interest, including acquisitions or other transactions with an affiliate. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.

Our conflicts committee met formally two times during 2008, primarily to approve the Stanolind acquisition with all members attending at least 50% of the meetings.  Our conflicts committee also took action by unanimous written consent one time during 2008, to approve the Stanolind acquisition and recommend approval to the full Board of Directors.

Committee Charters and Code of Ethics

Each of our committees has a written charter that can be found on our website, www.eaglerockenergy.com, under the “Investor Relations—Corporate Governance” tab. Additionally, we have a “Code of Ethics for Chief Executive Officer and Senior Financial Officers” and a “Code of Business Conduct and Ethics,” both of which also can be found on our website under the “Investor Relations—Corporate Governance” tab.  Each committee charter was reviewed by the applicable committee during the first part of 2009 and was revised by the board of directors, based on the recommendation of the applicable committee at the conclusion of such committee’s review, effective February 4, 2009.  Each of the charters, as amended and restated, for the Audit Committee, the Compensation Committee and the Conflicts Committee is included as an exhibit to this Annual Report on Form 10-K.

Non-Management Executive Sessions and Unitholder Communications

Non-management directors periodically meet in executive session in connection with regular meetings of the board of directors or at regular meetings of our audit committee or conflicts committee.

Interested parties can communicate directly with non-management directors by mail in care of the General Counsel and Secretary, Eagle Rock Energy G&P, LLC, 16701 Greenspoint Park Drive, Suite 200, Houston, Texas 77060. Such communications should specify clearly inside the body of the communication itself (and not simply the outside of the envelope) the intended recipient or recipients.

Report of the Audit Committee

The audit committee of Eagle Rock Energy G&P, LLC oversees the Partnership’s financial reporting process on behalf of the board of directors. Management has the primary responsibility for the financial statements and the reporting process, including the systems of internal control over financial reporting and disclosure.

In fulfilling its oversight responsibilities, the audit committee reviewed and discussed with management the audited financial statements contained in this Annual Report on Form 10-K.

Eagle Rock’s independent registered public accounting firm, Deloitte & Touche LLP, is responsible for expressing an opinion on the conformity of the audited financial statements with accounting principles generally accepted in the United States of America and opinions on management’s assessment and on the effectiveness of Eagle Rock’s internal control over financial reporting. The audit committee reviewed with Deloitte & Touche LLP its judgment as to the quality, not just the acceptability, of Eagle Rock’s accounting principles and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards.

The audit committee discussed with Deloitte & Touche LLP the matters required to be discussed by SAS 61 (Codification of Statement on Auditing Standards, AU § 380), as modified or supplemented. The audit committee has received the written disclosures and the letter from Deloitte & Touche LLP required by applicable requirements of the Public Company Accounting Oversight Board regarding the independent accountant’s communications with the audit committee concerning independence, and has discussed with Deloitte & Touche LLP its independence from management and Eagle Rock.

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Based on the reviews and discussions referred to above, the audit committee recommended to the board of directors that the audited financial statements be included in the Annual Report on Form 10-K for the year ended December 31, 2008 for filing with the SEC.

William K. White, Chairman

Philip B. Smith

William A. Smith

Directors and Executive Officers

The following table sets forth certain information with respect to the current members of our board of directors and our executive officers (for purposes of Item 401(b) of Regulation S-K under the Securities Exchange Act of 1934).

Name	Age	Position with Eagle Rock Energy G&P, LLC
Joseph A. Mills	49	Chairman and Chief Executive Officer, Director
Jeffrey P. Wood	38	Senior Vice President, Chief Financial Officer and Treasurer
Alfredo Garcia	43	Senior Vice President, Corporate Development
Charles C. Boettcher	35	Senior Vice President, General Counsel, Chief Compliance Officer and Secretary
Steven G. Hendrickson	47	Senior Vice President, Technical Evaluations
William E. Puckett	53	Senior Vice President, Midstream Business
Joseph E. Schimelpfening	47	Senior Vice President, Upstream and Minerals Business
William J. Quinn	38	Director
Kenneth A. Hersh	46	Director
Philip B. Smith	56	Director
William A. Smith	64	Director
John A. Weinzierl	40	Director
William K. White	65	Director

Because of its control of the general partner of, and ownership of a majority interest in, Eagle Rock Holdings L.P., Natural Gas Partners controls the election of all of the members of the board of directors of Eagle Rock Energy G&P, LLC. Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal by Eagle Rock Holdings L.P., as the sole member of Eagle Rock Energy G&P, LLC. The executive officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers. The directors of Eagle Rock Energy G&P, LLC will devote a commercially reasonable amount of time to our business and operations, given the nature and scope of their duties as directors, but may devote a substantial amount of time to commercial activities unrelated to our business and operations. The executive officers of Eagle Rock Energy G&P, LLC will devote a majority of their time, and will strive to devote substantially all of their time, to our business and operations. With that understanding, the executive officers of Eagle Rock Energy G&P, LLC may devote a portion of their time to the business and operations of Holdings, Eagle Rock Energy GP, L.P., Eagle Rock Energy G&P, LLC, Montierra Minerals & Production, LP or other affiliates of Eagle Rock Energy G&P, LLC. Although the amount of time spent by the executive officers of Eagle Rock Energy G&P, LLC on matters other than our business and operations should be insignificant in comparison to the time spent on our business and operations, it may from time–to–time rise to a level that is not insignificant.

Joseph A. Mills was elected Chairman of the Board and Chief Executive Officer of Eagle Rock Energy G&P, LLC in May 2007. Additionally, Mr. Mills has served since April 19, 2006, and will continue to serve for the foreseeable future, as Chief Executive Officer and as a manager of Montierra Management LLC, which is the general partner of Montierra Minerals & Production, LP. From January 2006 to April 2006, Mr. Mills took some personal time off to spend time with his family. From September 2003 to January 2006, Mr. Mills was the Senior Vice President of Operations for Black Stone Minerals Company, LP, a privately held company. From March 2001 to August 2003, Mr. Mills was a Senior Vice President of El Paso Production Company, a wholly-owned subsidiary of El Paso Corporation.

Jeffrey P. Wood was elected Senior Vice President and Chief Financial Officer of Eagle Rock Energy G&P, LLC in January 2009.  On March 11, 2009, Mr. Wood was appointed Treasurer of Eagle Rock Energy G&P, LLC.  From August 2006 to December 2008, Mr. Wood was a senior vice president and portfolio manager in the private equity division of Lehman Brothers Holdings, Inc.  From July 2001 through August 2006, Mr. Wood worked for Lehman Brothers in its natural resources investment banking practice.  Mr. Woods primary focus area during his tenure at Lehman Brothers was the energy industry and specifically the master limited partnership sector.

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Alfredo Garcia was elected Senior Vice President, Corporate Development of Eagle Rock Energy G&P, LLC in August 2006, and has served in that capacity ever since. In addition to his service in this role, Mr. Garcia has served as Interim Chief Financial Officer of Eagle Rock Energy G&P, LLC most recently from August 15, 2008 until January 5, 2009 and previously from December 29, 2007 until May 15, 2008, and Mr. Garcia served as Acting Chief Financial Officer of Eagle Rock Energy G&P, LLC from July 16, 2007 until November 9, 2007. Prior to August 2006, Mr. Garcia served as Senior Vice President and Chief Financial Officer of Eagle Rock Energy G&P, LLC from March 2006 until August 2006, Chief Financial Officer of Eagle Rock Pipeline, L.P. from December 2005 until August 2006 and Chief Financial Officer of Eagle Rock Energy, Inc. from February 2004 through December 2005. From March 1999 until February 2004, Mr. Garcia was founder and director of Investment Analysis & Management, LLC, a financial advisory and consulting firm. During this period, he also acted as Chief Financial Officer of TrueCentric, LLC, a software start-up company. Prior to this, Mr. Garcia was a Latin American Associate for HM Capital Partners, a private equity firm formerly known as Hicks Muse Tate & Furst.

Charles C. Boettcher was elected Senior Vice President, General Counsel and Secretary of Eagle Rock Energy G&P, LLC in August 2007. Additionally, Mr. Boettcher serves as the Chief Compliance Officer. Prior to joining Eagle Rock, Mr. Boettcher was a partner in the law firm of Thompson & Knight, LLP, primary outside counsel to Eagle Rock. During his eight years at Thompson & Knight, Mr. Boettcher practiced law in the Corporate and Securities department and focused his practice on mergers and acquisitions in the oil and gas industry and securities compliance and disclosure for public companies.

Steven G. Hendrickson was elected Senior Vice President of Technical Evaluations of Eagle Rock Energy G&P, LLC in May 2007. From May 2006 to May 2007, Mr. Hendrickson was Vice President of Engineering for Montierra Minerals & Production, L.P. From April 2005 to May 2006, he was in private engineering practice. From March 1999 to April 2005, Mr. Hendrickson was Director of Reservoir Engineering and other various management positions with El Paso Corporation. Mr. Hendrickson is a licensed Petroleum Engineer in the State of Texas.

William E. Puckett was elected Senior Vice President, Midstream Business of Eagle Rock Energy G&P, LLC in October 2008.  From March 2006 to October 2008, Mr. Puckett has served as Senior Vice President, Midstream Commercial Operations of Eagle Rock Energy G&P, LLC. Mr. Puckett has served as Vice President, Midstream Commercial Operations of Eagle Rock Pipeline, L.P. from December 2005 to March 2006. From September 1999 until November 2005, Mr. Puckett was Vice President, Technical Services for Dynegy, Inc., a natural gas gathering and processing company. During the month of November 2005, Mr. Puckett served as Vice President of Technical Services for Targa Resources. Mr. Puckett has also served in a variety of positions in marketing, processing and operations.

Joseph E. Schimelpfening was elected Senior Vice President, Upstream and Minerals Business of Eagle Rock Energy G&P, LLC in October 2008.  From May 2007 to October 2008, Mr. Schimelpfening served as Senior Vice President of E&P Operations and Development. From May 2006 to May 2007, Mr. Schimelpfening was Vice President of Operations and Development for Montierra Minerals & Production, L.P.  Prior to May 2006, Mr. Schimelpfening was Division Operations Manager for El Paso Corporation. (Mr. Schimelpfening is also a licensed engineer in Texas)

Kenneth A. Hersh was elected Director of Eagle Rock Energy G&P, LLC in March 2006. Mr. Hersh served as a director of Eagle Rock Pipeline, L.P. from December 2005 to March 2006 and Eagle Rock Energy, Inc. from December 2003 through December 2005. Mr. Hersh is the Chief Executive Officer of NGP Energy Capital Management and is a managing partner of the Natural Gas Partners private equity funds and has served in those or similar capacities since 1989. He currently serves as a director of NGP Capital Resources Company, a business development company that focuses on the energy industry. Mr. Hersh has served as a director of Energy Transfer Partners, L.L.C., the indirect general partner of Energy Transfer Partners, L.P., a natural gas gathering and processing and transportation and storage and retail propane company, since February 2004 and has served as a director of LE GP, LLC, the general partner of Energy Transfer Equity, L.P., since October 2002.

William J. Quinn was elected Director of Eagle Rock Energy G&P, LLC in March 2006.  Mr. Quinn served as Chairman of the Board of Eagle Rock Energy G&P, LLC from January 2007 to May 2007. Mr. Quinn has served as a member of the compensation committee since March 2006, and served as chairman of the committee from March 2006 to February, 2008. Mr. Quinn served as a director of Eagle Rock Pipeline, L.P. from December 2005 to March 2006 and Eagle Rock Energy, Inc. from December 2003 through December 2005. Mr. Quinn is the Executive Vice President of NGP Energy Capital Management and is a managing partner of the Natural Gas Partners private equity funds and has served in those or similar capacities since 1998. He currently serves on the investment committee of NGP Capital Resources Company, a business development company that focuses on the energy industry.

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Philip B. Smith was elected Director of Eagle Rock Energy G&P, LLC in October 2006 and serves as chairman of the conflicts committee and as a member of the audit committee and the compensation committee of the board of directors of Eagle Rock Energy G&P, LLC. From April 2002 to September 2006, Mr. Smith has been administering estates and managing private investments. From January 1999 until March 2002, Mr. Smith was Chief Executive Officer and Chairman of the Board of Directors of Prize Energy Corp. in Grapevine, Texas. From 1996 until 1999, Mr. Smith served as a director of HS Resources, Inc. and of Pioneer Natural Resources Company and its predecessor, MESA, Inc.

William A. Smith was elected Director of Eagle Rock Energy G&P, LLC in September 2007 and serves as chairman of the compensation committee since February 2008 and as a member of the audit committee and conflicts committee of the board of directors of Eagle Rock Energy G&P, LLC since September 2007. Mr. Smith is managing director and partner in Galway Group, L.P., a position he has held since August 2002. From October 1999 to June 2002, Mr. Smith was executive vice president of El Paso Corporation. Prior to the merger of Sonat Inc. with El Paso Corporation in 1999, Mr. Smith was executive vice president and general counsel of Sonat. Mr. Smith currently serves as a member of the Board of Directors and audit committee of the Board of Directors of El Paso Pipeline GP Company, LLC, the general partner of El Paso Pipeline Partners, L.P.

John A. Weinzierl was elected Director of Eagle Rock Energy G&P, LLC in March 2006. Mr. Weinzierl served as a director of Eagle Rock Pipeline, L.P. from December 2005 to March 2006 and Eagle Rock Energy, Inc. from December 2003 through December 2005. Mr. Weinzierl is a managing director of the Natural Gas Partners private equity funds and has served in that capacity since 2005. Upon joining Natural Gas Partners in 1999, Mr. Weinzierl served as a senior associate until 2000 and as a principal until he became a managing director in December 2004. He presently serves as a director for several of Natural Gas Partners’ private portfolio companies.

William K. White was elected Director of Eagle Rock Energy G&P, LLC in October 2006 and serves as Chairman of the audit committee and as a member of the conflicts committee of the board of directors of Eagle Rock Energy G&P, LLC. Mr. White also serves as the audit committee financial expert. Mr. White is President of Amado Energy Management, LLC, a private, wholly-owned LLC, a position he has held since December 2002. He formerly served as a member of the board of directors of Teton Energy Corporation. From September 1996 to November 2002, Mr. White was Vice President, Finance and Administration and Chief Financial Officer for Pure Resources, Inc.

Section 16(A) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our directors and officers, and persons who beneficially own more than 10% of Eagle Rock’s common units, to file with the SEC initial reports of ownership and reports of changes in ownership of the common units. Directors, officers and more than 10% unitholders are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file.

To our knowledge, based solely on review of the copies of such reports furnished to us and written representations that no other reports were required, we are not aware of any director, executive officer, or 10% unitholder who has not timely filed reports required by Section 16(a) of the Exchange Act during or following the end of the year ended December 31, 2008, except that one Form 4 filing for William E. Puckett, reporting his acquisition on October 1, 2008 of 20,000 restricted common units by grant under our Long Term Incentive Plan, was filed on Form 5 on January 22, 2009.

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Item 11. Executive Compensation.

The following discussion of executive compensation contains references to our employee benefit plans and an Omnibus Agreement. These descriptions are qualified in their entirety by reference to the full text of the plans and Omnibus Agreement, which have been filed by us as exhibits or are incorporated by reference as exhibits to this report on Form 10-K with the U.S. Securities and Exchange Commission.

Overview of Executive Officer Compensation

As a publicly-traded limited partnership, we do not have directors, officers or employees. Instead, our operations are managed by our general partner, Eagle Rock Energy GP, L.P., which in turn is managed by its general partner, Eagle Rock Energy G&P, LLC, which we refer to in this Item 11 as “G&P.” When we refer to “our employees,” “our officers,” or similar statements, we are referring to individuals who are employed by G&P and serve us or who hold officer positions for G&P and serve us. Employee costs, such as salaries, bonuses, benefits, reimbursements and other cash payments, are funded by payments received by G&P through an Omnibus Agreement, which G&P entered into with us, along with other of our affiliates, in connection with our initial public offering on October 24, 2006. We recognize and record these expenses in our financial statements on an accrual basis and in the same period as G&P or its affiliates incur them on our behalf.

Prior to our initial public offering, as a private company, compensation arrangements were determined on an individual basis and resulted primarily from negotiations between our management group and our private equity investors. These private equity investors are funds of Natural Gas Partners, which we refer to in this Item 11 as “NGP.”

Upon becoming a publicly-traded limited partnership, we altered our internal organization to follow the guidelines and processes of the appropriate governance standards for a publicly-traded limited partnership, including standards that apply to executive compensation decisions. As of the date of filing this Form 10-K, G&P has seven members of the Board of Directors, three of whom are independent board members as determined in accordance with the NASDAQ Global Select Market standards for independence. Three members of the Board of Directors, William A. Smith, William J. Quinn, and Philip B. Smith, serve as our Compensation Committee, which we refer to in this Item 11 as “Compensation Committee” or “Committee.” Mr. W. Smith serves as chairman of the committee, and Messrs. W. Smith and P. Smith meet the standards for independence under the NASDAQ Global Select Market. Mr. Quinn is a managing partner of the NGP private equity funds.

Prior to 2008 and except with respect to executive officers hired in 2007, compensation for our executive officers was set by the amounts previously put in place through negotiations by our management and our private investors, usually as set by the general partner of Eagle Rock Holdings, L.P., which we refer to in this Item 11 as “Holdings” and the “Holdings Board.”

In early 2008, the Compensation Committee redesigned our executive compensation program to better attract, motivate, and retain key executives and to reward executives for creating and improving the value of our company.  In this regard, the Compensation Committee engaged Towers Perrin, a nationally recognized compensation consulting firm with experience in assisting master limited partnerships that own and operate upstream or midstream oil and gas assets. The Compensation Committee and our Chief Executive Officer worked with Towers Perrin to refine our executive compensation design, including compensation of our Chief Executive Officer, and to ensure that compensation to our executive management is commensurate with executive management compensation among industry peers and that our overall compensation fosters a performance-oriented environment by aligning a meaningful portion of each executive’s cash and equity compensation to the achievement of performance targets which are important to us and our unitholders. In this regard, our Chief Executive Officer worked closely with both the Compensation Committee and Towers Perrin, including attending routine Compensation Committee meetings and meeting with representatives of Towers Perrin.

The discussion of executive compensation in this Item 11 includes the compensation arrangement of Darin Holderness during the period in 2008 when he served as Chief Financial Officer of G&P – May 19, 2008 to August 15, 2008.

On January 5, 2009, the Compensation Committee set the base salary and bonus target for, and made initial Long Term Incentive Plan restricted common unit grants and Holdings incentive interests grants to Jeffrey P. Wood in connection with his employment as Senior Vice President and Chief Financial Officer of G&P.  For a more detailed discussion, see “Compensation to New Chief Financial Officer” below.

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Discussion and Analysis of Executive Compensation

Goals of the Compensation Program

The Committee has focused on establishing an executive compensation program which is intended to attract, motivate, and retain key executives and to reward executives for creating and improving the value of our company. The goal of the program is to foster a performance-oriented environment by aligning a meaningful portion of each executive’s cash and equity compensation to the achievement of performance targets that are important to us and our public unitholders. In 2008, the Committee analyzed all facets of our named executive officers’, as well as all other officers’, total compensation based on these goals, and the Committee engaged its compensation consultant, Towers Perrin, to produce a study, utilizing surveys of public information and publicly available information of a peer group of companies to assist the Committee in developing a range of overall compensation as a benchmark for our named executive officers’ overall compensation. Because we have a combination of both midstream assets and upstream assets, which is not a typical combination for publicly-traded limited partnerships, part of the Committee’s evaluation process was to identify and develop an appropriate peer group for this benchmarking process. In this regard, the Committee relied heavily on the expertise and guidance of Towers Perrin.  Ultimately, the Committee decided on an appropriate peer group, consisting of the following companies:

Atlas Pipeline Partners, L.P.	DCP Midstream Partners, LP	MarkWest Energy Partners, L.P.
BreitBurn Energy Partners L.P.	Encore Acquisition Company	Petrohawk Energy Corporation
Brigham Exploration Company	EV Energy Partners, L.P.	Petroquest Energy, Inc.
Buckeye Partners, L.P.	Goodrich Petroleum Corporation	Quicksilver Resources Inc.
Cabot Oil & Gas Corporation	Hiland Partners, LP	Regency Energy Partners LP
Comstock Resources, Inc.	Legacy Reserves LP	Swift Energy Company
Copano Energy, L.L.C.	Linn Energy, LLC	Whiting Petroleum Corporation
Crosstex Energy, L.P.	Magellan Midstream Partners, L.P.

In addition to publicly-disclosed peer group pay data being presented by Towers Perrin, the Committee also reviewed compensation data provided by Towers Perrin for individuals holding positions similar to the named executive officers obtained from compensation survey sources.  Survey data presented were collected from a combination of industry-specific and general industry sources.  Energy industry data were collected from Mercer’s 2008 Energy Industry Compensation Survey, which includes data for 262 organizations across a variety of energy industry segments (including upstream and midstream oil and gas).  General industry data were also presented to the Committee from Towers Perrin’s 2008 Executive Compensation Database, which includes data for 783 companies across a variety of industries.  Survey data provided from both sources are reflective of pay data for companies with revenues of between $500 million and $1 billion, and may be considered “size adjusted.”  Although the Committee reviewed survey data in addition to public peer group data in order to have some additional broader-market perspective on the Company’s compensation programs, and to help identify emerging trends in compensation in the broader marketplace, in making decisions on individual pay levels, the Committee relied most heavily on the public peer group data.

In the end, the Committee targeted for our overall executive compensation program, excluding any equity or incentive interests at Holdings and/or Montierra, to be approximately at the 50th percentile among this peer group, but actually ended-up between the 25th and 50th percentile among the peer group.

Our executive compensation program currently has the following three principal elements: base salary, cash bonuses and equity.  This mix of compensation balances compensation with the company’s short term and long term goals. We will continue to evaluate the benefit of this mix as well as the benefit of the mix of components of our equity element.

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Base Salary

2008

In early 2008, following a presentation of a study prepared by Towers Perrin, the Compensation Committee increased the base salaries for our named executive officers, with the exception of Mr. Holderness, to the following levels:

•    Mr. Mills	$	400,000
•    Mr. Garcia	$	210,000
•    Mr. Boettcher	$	243,750
•    Mr. Hendrickson	$	220,000
•    Mr. Schimelpfening	$	220,000

Mr. Mills’ base salary was established at a level that the Compensation Committee determined to be commensurate with Mr. Mills’ experience and knowledge in the energy industry and which would properly incentivize Mr. Mills. In doing so, the Committee considered Mr. Mills prior performance and also sought to target the 50th percentile for Mr. Mills’ overall compensation as among the peer group outlined in the Towers Perrin study. The base salaries of Messrs. Garcia, Boettcher, Hendrickson, and Schimelpfening were similarly established, by iterating to the 50th percentile for the other ranked named executive officers of those in the peer group outlined in the Towers Perrin study, without specific correlation between type or title of each respective officer.

The base salary of Mr. Holderness was established at $240,000 through a negotiation between Mr. Mills and Mr. Holderness. Mr. Mills consulted with the Committee in connection with making this decision. Mr. Holderness accepted employment and resigned his employment within the year.

2009 Going Forward

For 2009 and subsequent years, the Committee will analyze the appropriateness of base salaries through two primary means: first, through surveys of public information and other benchmarking techniques of our executive compensation with respect to our peer group, which the Committee will continue to identify and develop, as part of the named executive officer’s overall compensation; and, second, through a review process of base salaries on an annual basis to determine if the performance of both Eagle Rock (as an overall enterprise) and the executive officers (as a group and individually) support the continued or adjusted base salary. For 2009, the Committee has set specific performance factors and goals for Eagle Rock with respect to its cash bonus decisions specifically, but the Committee will also use those targets as a guideline in making base salary decisions. The Committee will continue to evaluate the appropriate levels of performance factors and goals as a tool to measure and reward performance. See the discussion of the Eagle Rock Performance Goals below under “—Cash Bonus—2009 Going Forward.”

Cash Bonus

2008

For 2008, the Committee has authorized the payment of cash bonuses to the named executive officers, including our Chief Executive Officer, and other employees based on a review of Eagle Rock’s overall performance during 2008 and the individual performance of the executive officer or other employee, resulting in cash bonuses to the named executive officers, to be paid on March 31, 2009, as follows:

Joseph A. Mills	$	385,000
Darin G. Holderness (resigned)	NA
Alfredo Garcia	$	101,063
Charles C. Boettcher	$	117,305
Steven G. Hendrickson	$	105,875
Joseph E. Schimelpfening	$	105,875

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The Committee made its decisions based on the following predetermined enterprise performance goals and factors as guidelines for the Committee.  These goals and factors were communicated to the executive officers and other employees during the year.

•    Adjusted EBITDA	Confidential Target
•    Safety	2.5 Recordable Injury Rate (i.e., number of recordable injuries per 1,000 man hours)
•    Environmental	No major recordable spills or notices of violations in the states in which we conduct business
•    Maintenance Capital
—Midstream	$14.44 million
—Upstream	$8.97 million
•    Growth Capital	$24.9 million
•    Total Operating Expenditures
—Opex Midstream	$0.32 per Mcf
—Opex Upstream	$1.40 per Mcfe
•    Finding & Dev. Cost	$1.38 per Mcfe

When making its bonus assessment for 2008, the Committee first determined that in 2008 the Partnership achieved at least 95% of each of the financial, safety and operation targets above, with the exception of the environmental target.  The Partnership did not achieve the environmental target because certain of the Partnership’s subsidiaries received notices of violation and notices of enforcement from the TCEQ with respect to deficiencies in air quality permitting.  Notwithstanding the failure to achieve the environmental target for 2008, the Committee determined that bonuses should be funded to the employees in light of the high percentage of successful achievement of the other targets (including, most notably, the 96.3% achievement of Adjusted EBITDA target, which would have been 132% achievement if not adjusted for the Stanolind and Millennium Acquisitions and the high realized commodity prices), as well as (i) the historical nature of the issues noticed by the TCEQ, (ii) the successes of the Partnership in rectifying the issues noticed by the TCEQ, and (iii) the sweeping changes implemented by the Partnership within its environmental and regulatory compliance programs, including performance of extensive internal audits and related disclosures under the Texas Environmental, Health, and Safety Audit Privilege Act, as amended.

For the 2008 bonus payments, 75% of an employee’s bonus amount is determined by Eagle Rock’s performance against the target results, and 25% of an employee’s bonus amount is determined by the employee’s individual performance as measured in 2008.  The Chief Executive Officer and other named executive officers’ bonus percentages were established by the Committee, with input from the Chief Executive Officer regarding targets for named executive officers (other than the Chief Executive Officer), and the Committee based its determinations of the 25% individual performance component on the individual performance measured against the individual performance goals and targets established by the Committee for (and communicated during 2008 to) each named executive officer.

2009 Going Forward

For 2009 and subsequent years, the Committee intends to continue providing annual incentive compensation (cash bonuses) in the future to allow Eagle Rock to:

• Reward achievement of financial or operational goals (earnings, safety, cost control, personnel development, and strategic initiatives) so that total compensation more accurately reflects actual company and individual performance; and

• Convert a portion of fixed employee costs into variable costs.

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In furtherance of these stated intentions, the Committee recommended to the Board of Directors to adopt, and the Board Directors adopted, the 2009 Short Term Incentive Bonus Plan on February 4, 2009.

While the purposes stated above remain very similar to the purposes of annual incentive compensation in 2008, the design of the 2009 Short Term Incentive Bonus Plan weighs the actual bonus payout equally between Company performance and individual performance which is a significant change from the Committee’s 2008 incentive compensation program.

Performance factors and goals for Eagle Rock in 2009 have been developed through an iterative effort by the Committee with input from the Chief Executive Officer and other senior management members. As a result, the 2009 Short Term Incentive Bonus Plan contains specific financial, safety and operational targets (the “Enterprise Goals”) as follows:

Financial Goals:
·Adjusted EBITDA	[$****]
·    Maintenance Capital Expenditures	Not to exceed $20,000,000 (excluding increases for any new acquisitions or major organic growth projects)
·    Growth Capital Expenditures	Not to exceed $20,000,000 (excluding increases for any new acquisitions)
·    Target IRR (for Capital Projects)	To be at (or greater than):
	18% IRR for Midstream Business; and
	25% IRR for Upstream Business
·Operating Expenses	Not to exceed
	$55,000,000 in aggregate ($[****] /Mcfe) for Midstream Business
	$25,000,000 in aggregate ($[****] /Mcfe) for Upstream Business
·    Finding & Development Costs (Upstream)	Not to exceed $10.50 / Boe
Environmental and Safety Goals:
·Recordable Incident Rate	Not to exceed 2.0
·    Spills	No major NRC Recordable Spills
·    Regulatory Compliance Program:	- Complete environmental air permitting audits
	- Complete permitting for disclosed air permitting deficiencies
	- File regulatory forms on time and conduct training for key operations personnel on TCEQ rules
	- Continue to implement proactive Environmental, Health and Safety Program
	- Implement Drug and Alcohol Program required training matrix and internal audit plan
Governance Goals:
·Sarbanes Oxley Compliance	No material weaknesses in Sarbanes Oxley Section 404 Attestation Audit of Internal Controls Over Financial Reporting

[****]  Indicates redacted terms for which confidential treatment has been requested from the Securities and Exchange Commission.

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In addition to the Enterprise Goals set forth above, pursuant to the 2009 Short Term Incentive Bonus Plan each employee must document a set of measurable individual goals in support of the achievement of the Enterprise Goals. The achievement of his or her Individual Goals will be a key factor in determining an employee’s actual bonus payout, the formula of which takes into account the following factors:

• Annual Base Salary

• Bonus Target Percentage

• Funding Percentage, determined by the Board of Directors and dependent on achievement of the Enterprise Goals above.

• Individual Performance Factor, discretionary value from 0 to 125% depending on individual performance relative to the employee’s Performance Appraisal Rating.

The Committee maintains ultimate discretion in assigning the Individual Performance Factor for the Chief Executive Officer, while the Chief Executive Officer, with input from the Committee, maintains ultimate discretion in assigning the Individual Performance Factor for the leadership team.  The Board of Directors maintains ultimate discretion in determining whether our Enterprise Goals have been met such that funding is appropriate, and if so what level of funding (Funding Percentage) is appropriate.

Long-Term Incentives

We offer long-term incentive awards to eligible employees, including our named executive officers, through the 2006 Long-Term Incentive Plan of Eagle Rock Energy Partners, L.P., as amended in 2008 to increase the aggregate available common units for grant and further amended in 2009 for compliance with Section 409A of the Internal Revenue Code of 1986, as amended, which we refer to in this Item 11 as the “LTIP.” The LTIP is described in further detail below. LTIP awards are intended to further align the interests of our employees with the interests of our public unitholders through shared ownership of Eagle Rock.

Additionally, although we do not control the ability to cause equity grants by Eagle Rock Holdings, L.P., the Holdings Board, controlled by NGP, in the past has from time-to-time granted equity in Holdings to certain of our employees, including our named executive officers, when such equity is available -- primarily because of forfeitures upon the departure of members of our management. The Committee does factor in the percentage of ownership of Holdings when determining appropriate awards under our LTIP. During 2008, the Holdings Board consisted of three representatives of NGP, and Messrs. Mills and Garcia.

2008

In 2008, the Compensation Committee amended the LTIP to increase the aggregate common units authorized to be issued pursuant to the LTIP from 1,000,000 to 2,000,000.  In 2008, the Compensation Committee authorized awards of restricted common units under the LTIP to the following named executive officers in the following amounts, providing for vesting in three substantially equivalent increments (i.e., 33%, 33%, and 34%) on each of May 15, 2009, May 15, 2010, and May 15, 2011:

	Restricted Common Units
Joseph A. Mills		85,000
Darin G. Holderness (resigned)		40,000
Alfredo Garcia		15,000
Charles C. Boettcher		25,000
Steven G. Hendrickson		25,000
Joseph E. Schimelpfening		25,000

With the exception of Mr. Holderness, all of the foregoing named executive officers continue to hold these restricted common units, subject to the vesting schedule listed above. Mr. Holderness forfeited these units as a result of his resignation, effective August 15, 2008.

In addition, the Compensation Committee authorized several awards to other executive officers in 2008, as well as delegating to the Chief Executive Officer discretion, within a prescribed range, to make grants of awards to other employees. The Compensation Committee intends for these awards to serve as an incentive and a retention tool. The Compensation Committee and the Chief Executive Officer exercised a great deal of discretion in establishing the amount of these awards. The awards to Messrs. Mills, Holderness, Garcia, Boettcher, Hendrickson and Schimelpfening were greater in number of restricted common units per person than awards made to other members of senior management. These awards were made with the intent of equalizing the cash and non-cash compensation incentives among senior management and rewarding outstanding performance and as a retention tool. As among the group receiving awards, senior management received the vast majority of the awards by number of restricted common units.

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As mentioned above, although it has no discretion in granting any awards the Holdings level, the Compensation Committee does review prior discretionary grants made by the Holdings Board to our named executive officers. As of January 1, 2008, Mr. Garcia and certain other executive officers held direct, non-incentive equity ownership in Holdings based on prior capital contributions which were made at the time of initial employment, and all of the named executive officers had been granted incentive interests in Holdings in the form of various “tier” units. The incentive units were intended to create incentives for the management of the private company to reach certain pre-determined payout goals.  These payout goals are confidential and were set by NGP in negotiations with the limited partners of Holdings. The incentive interests, which consist of several “tiers” of incentive interests, represent an interest in the future profits of Holdings and are intended to be treated as “profits interests” for federal income tax purposes. The incentive interests are subject both to time-vesting requirements and to meeting payout hurdles defined as cumulative cash payout amounts distributed to equity owners of Holdings within a certain time period. Because these time-vesting requirements and payout hurdles are considered confidential performance targets of Holdings and because of the proprietary and competitive nature of the Holdings structure to NGP, we have been asked by NGP not to disclose these performance targets in this Annual Report on Form 10-K. The first of these incentive tiers has met its payout goal and is therefore participating ratably in distributions from Holdings. Tier I incentive interests issued prior to January of 2006 are no longer subject to forfeiture; however, Tier I incentive interests issued on or after January 1, 2006 continue to be subject to forfeiture.

Messrs. Mills, Holderness, Boettcher, Hendrickson and Schimelpfening have not invested in Holdings and do not hold non-incentive equity ownership. During 2008, in addition to grants made to other executive officers, the Holdings Board determined to make grants to Messrs. Mills, Holderness, Boettcher, Hendrickson and Schimelpfening of incentive interests which, if and when the payout goals for these units at the Holdings’ level are achieved, would entitle such named executive officers to approximately the percentage of overall distributions from Holdings as follows:

	Tier I			Tier III
Joseph A. Mills		0.25	%		—
Darin G. Holderness (resigned)		0.72	%		0.07	%
Charles C. Boettcher		0.16	%		0.04	%
Steven G. Hendrickson		0.12	%		—
Joseph E. Schimelpfening		0.12	%		—

With the exception of Mr. Holderness, all of the foregoing named executive officers continue to hold the interests granted in 2008.  Mr. Holderness forfeited his interests as a result of his resignation, effective August 15, 2008.

Because the payout goal for the Tier I incentive interests had already been achieved prior to these grants, the recipients became eligible immediately to participate pro rata in any future distributions, as and when paid, as to their Tier I incentive interests.  In contrast, the payout goal for the Tier III incentive interests remains to be achieved and thus these interests do not entitle the holder to any share of current distributions, as and when declared.  The interests are subject to vesting and forfeiture.

In the Summary Compensation Table, in accordance with FAS 123R and SEC Staff Accounting Bulletin Topic 1.B, we show these 2008 grants as “Other Compensation.”

2009 Going Forward

Restricted Common Units under the LTIP. The Committee intends to use grants of restricted common units from the LTIP as a primary equity incentive for executive officers. Under the LTIP, as amended in 2008, the Committee has the right to grant awards of up to 2,000,000 common units in the form of option awards or other types of incentive grants. Notwithstanding the fact that the Committee has this discretion to issue awards of varying types, the Committee thus far has determined that it is in the best interest of the publicly-traded limited partnership to make only grants of restricted common units because of the important sense of ownership created by these grants, which the Committee believes will align the interests of our executive officers and other recipients more closely with the interests of our public unitholders. As of December 31, 2008, the Committee has granted to employees, officers, and directors of G&P 1,304,371 common units as restricted units, and 199,393 of such restricted common units have been forfeited and while 7,400 of such restricted common units were canceled in connection with their vesting on October 26, 2007.  Because the forfeited and canceled units are available for reissuance under the LTIP, the Committee continues to have 902,422 common units available for issuance under the LTIP as of December 31, 2008.

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The historical grants under the LTIP have been made under restricted common unit award agreements, which generally call for the restricted common units to vest in three approximately equal increments over an approximately three-year vesting period (i.e., 33%, 33% and 34%). As a result of negotiations by our officers who became officers upon completion of the Montierra Acquisition, the current form of award agreement provides that quarterly distributions from Eagle Rock, which are declared and paid on restricted common units under the LTIP, are paid directly to the holder of such restricted common units. Prior to May 2007, the previous form of the award agreement provided that our quarterly distributions, that were declared and paid on restricted common units under the LTIP, were to be held by Eagle Rock for the benefit of the holder of the restricted common units until the restricted common units vested or for the benefit of Eagle Rock if the restricted common units were forfeited prior to vesting. At the time of the change in award forms, all awards made prior to May 2007 were altered to provide for future distributions to be treated in similar fashion, while past distributions continue to be handled in accordance with the original terms of the original award agreements (i.e., continue to be held until the vesting or forfeiture of the underlying common units to which they relate).  In general, the restricted common units are forfeited upon termination of the holder’s employment with G&P, and vesting of the restricted common units is accelerated upon a change of control or upon death of the holder.

Incentive Interests in Holdings. As mentioned above, although the Committee does not control the ability to issue any equity ownership in Holdings, which is controlled by NGP, and does not know the exact terms or performance used by the Holdings Board in making its equity grant decisions at the Holdings level for our officers, the Committee from time-to-time may request from NGP, and from Holdings, information regarding equity interests at the Holdings level that have been granted to our officers by the Holdings Board. The Committee will use this information in determining appropriate levels of grants from the LTIP as well as in making overall compensation decisions to ensure that each officer’s equity ownership in the Eagle Rock enterprise (including Holdings, for this purpose) as well as his or her overall compensation is in line with what the Committee deems appropriate in its discretion with respect to each officer’s level of seniority within the Eagle Rock organization.  Holdings currently owns 2,338,419 common units and 20,691,495 subordinated units as well as indirectly benefiting from the general partner units and the incentive distribution rights owned by our general partner (although certain economic value in these incentive distribution rights has been assigned to Montierra—for a description of the Montierra Acquisition, see Part III, Item 12. Certain Relationships and Related Transactions, and Director Independence).

At this time, after the grants to Jeffrey P. Wood (our new Chief Financial Officer) discussed in “Compensation to New Chief Financial Officer,” there remain to be allocated at Holdings certain tier I incentive interests that would entitle the holder(s) to 0.14 % of overall distributions from Holdings.  Because the incentive interests at Holdings represent an interest in the future profits of Holdings and receive distributions and allocations only from Holdings’ cash and net income, these incentive interests are not an additional burden on, or dilutive to, the returns on our common units (beyond such dilution or burden that already exists by virtue of the incentive distribution rights and general partner units held by our general partner and the common units and subordinated units held by Holdings). On the contrary, such incentive interests are solely a burden on, and dilutive to, the returns of the equity owners of Holdings, including NGP as the substantial majority owner of Holdings. We strongly believe that having a substantial component of our executive officers’ equity incentives funded in this manner is a competitive advantage for us and our common unitholders because it potentially lowers our overall costs related to executive officer compensation, which, in turn, should increase returns to our common unitholders.

Equity Interests in Montierra. Similar to Holdings, although the Committee does not control the ability to issue any equity ownership in Montierra, which is controlled by NGP, and does not know the exact terms or performance targets used by Montierra in making its equity grant decisions at the Montierra level for our officers, the Committee from time-to-time may request from NGP, and from Montierra, information regarding equity interests at the Montierra level owned by our officers. The Committee will use this information in determining appropriate levels of grants from the LTIP, as well as making overall compensation decisions for these officers, to ensure that each officer’s equity ownership in the Eagle Rock enterprise, as well as his or her overall compensation, is in line with what the Committee deems appropriate. Montierra, which is controlled by NGP but which is partially owned by our Chief Executive Officer, Mr. Mills, our Senior Vice Presidents, Messrs. Hendrickson and Schimelpfening, and two of our other officers, currently owns 2,897,047 common units as well as the economic interest of certain incentive distribution rights owned by our general partner (for a description of the Montierra Acquisition, see Part III, Item 12. Certain Relationships and Related Transactions, and Director Independence). For a description of their ownership of Montierra, see footnote 4 to the chart appearing in Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

As with Holdings’ incentive interests, we strongly believe that having a substantial component of Mr. Mills’ and other named executive officers’ and officers’ equity incentives funded through their ownership in Montierra is a competitive advantage for us and our common unitholders by potentially lowering our overall costs related to their compensation, which, in turn, should increase returns to our common unitholders.

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Compensation to New Chief Financial Officer

On January 5, 2009, Jeffrey P. Wood began employment with Eagle Rock Energy G&P, LLC, as Senior Vice President and Chief Financial Officer.  Mr. Wood’s base salary, target bonus under the 2009 Short Term Bonus Plan, and LTIP grant were negotiated between Mr. Wood and our Chief Executive Officer (with input, oversight and approval from the Compensation Committee) and were established as follows:  $250,000 base salary; 50 percent bonus target for 2009 Short Term Bonus Plan; and LTIP grant of 50,000 restricted common units vesting 33% on November 15, 2009, 33% on November 15, 2010, and 34% on November 15, 2011.  In addition, Mr. Wood received a grant from Holdings of Tier I and Tier III incentive interests which, if and when the payout goals for these interests are achieved, would entitle Mr. Wood to approximately 0.58% (for Tier I) and 0.19% (for Tier III) of overall distributions from Holdings.  Because the payout goal for the Tier I incentive interests has already been achieved, upon grant Mr. Wood became eligible to participate pro rata in any future distributions, as and when paid.  In contrast, the payout goal for the Tier III incentive interests remains to be achieved and thus Mr. Wood is not entitled to share in current distributions, as and when declared, on account of his grant of Tier III incentive interests.  The restricted units and incentive interests granted to Mr. Wood are subject to vesting and forfeiture consistent with the discussions regarding these vesting and forfeiture provisions in other sections in this discussion.

Impact of Financial Reporting and Tax Accounting Rules

SFAS No. 123R. Effective January 1, 2006, the Partnership adopted Statement of Financial Accounting Standards (“SFAS”) No. 123R, “Share-Based Payment,” which requires that compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost is measured based on the fair value of the equity or liability instruments issued.

Despite the fact that the grants of incentive interests at Holdings are solely a burden on, and dilutive to, the returns of the equity owners of Holdings, including NGP as the substantial majority owner of Holdings, under the guidance of U.S. Securities and Exchange Commission Staff Accounting Bulletin Topic 1.B: “Allocation Of Expenses And Related Disclosure In Financial Statements Of Subsidiaries, Divisions Or Lesser Business Components Of Another Entity,” the Partnership recorded a portion of the value of the incentive units as compensation expense in the Partnership’s 2008 financial statements.  Unlike grants of restricted common units under our LTIP, which fair value is relatively easy to determine (based on the freely-tradable nature of a common unit once the restrictions lapse), the grants of incentive interests at Holdings are susceptible to a host of difficult determinations including (i) estimating fair value of an illiquid, minority interest of a holding company; (ii) estimating when the fair value accretes to the grantee; and (iii) allocating the portion of such fair value that is “for the benefit of” the Partnership based on grantee’s portion of time dedicated to the Partnership as opposed to other business of Holdings.  The Partnership has recorded a non-cash compensation expense of $1,665,831 based on management’s estimates related to the Tier I incentive interest grants made by Holdings in 2008.  The Partnership has not recorded any non-cash compensation expense related to other incentive interest (Tier II or Tier III) grants made by Holdings in 2008 because management has determined that the value, if any, of such incentive interests has not yet accreted to the grantee.

IRC Section 162(m). Section 162(m) of the Internal Revenue Code, as amended (the “Code”), limits the deductibility of certain compensation expenses in excess of $1,000,000 to any one individual in any fiscal year. Compensation that is “performance based” is excluded from this limitation. For compensation to be “performance based,” it must meet certain criteria including certain predetermined objective standards approved by the Committee. We believe that maintaining the discretion to evaluate the performance of its executive officers is an important part of our responsibilities and benefits our unitholders. The Committee, in coordination with management, periodically assesses the potential application of Section 162(m) on incentive compensation awards and other compensation decisions.

Change in Named Executive Officers; Employment Agreements; and Separation Agreements

Effective May 15, 2008, Mr. Holderness started as Senior Vice President and Chief Financial Officer of G&P and in similar capacity with affiliates of G&P, and effective August 15, 2008, Mr. Holderness resigned from all offices and positions with G&P and its affiliates. Mr. Holderness did not receive any severance payments in connection with his resignation, and we do not have any obligations to make payments to Mr. Holderness based on his resignation. As a result of his resignation, Mr. Holderness forfeited the unvested restricted common units that were awarded to him under the LTIP in 2008 and forfeited the unvested Tier I incentive interests and unvested Tier III incentive interests in Holdings that were awarded to him in 2008. The forfeited restricted common units were returned to the pool of available common units for issuance pursuant to the LTIP. Mr. Holderness’s forfeited incentive interests in Holdings, together with other forfeited incentive interests in Holdings, were re-issued, in part, in November of 2008 (as part of the grants discussed under “Long Term Incentives – 2008 above”); however, the most significant portion of the forfeited incentive interests from Mr. Holderness were granted to Jeffrey P. Wood (our new Chief Financial Officer) as discussed under “Compensation to New Chief Financial Officer” above.  At this time, after the aforementioned grants, there remain to be allocated at Holdings certain Tier I incentive interests that would entitle the holder to 0.14 % of overall distributions from Holdings.

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As a result of Mr. Holderness’s resignation, Mr. Garcia was re-appointed as Interim Chief Financial Officer on August 15, 2008. Mr. Garcia relinquished that position on January 5, 2009 in connection with the appointment of Mr. Wood.

Compensation Committee Report:

Our compensation committee has reviewed and discussed with management the Compensation Discussion and Analysis contained in this Annual Report on Form 10-K. Based on the compensation committee’s review of, and discussions with management with respect to, the Compensation Discussion and Analysis, the compensation committee has recommended to our board of directors that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.

William A. Smith, Chairman

William J. Quinn

Philip B. Smith

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Compensation Tables

The Summary Compensation Table below sets forth information regarding 2008, 2007 (where applicable), and 2006 (where applicable) compensation for our Chief Executive Officer, persons who served as our Chief Financial Officer, and our other named executive officers:

Name and Principal Position	Year	Salary ($)		Bonus ($)(4)		Unit Awards ($)(5)		Option Awards ($)(6)		Non-Equity Incentive Plan Compensation ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)		All Other Compensation ($)(7)(8)(10)		Total ($)
Joseph A. Mills	2008	$	359,615	$	385,000	$	1,437,350		—		—		—	$	554,552	$	2,736,517
Chief Executive Officer, Chairman of the Board, Director	2007	$	166,668	$	266,667	$	1,984,750		—		—		—	$	77,467	$	2,495,552
Darin G. Holderness	2008	$	60,050		—	$	676,400		—		—		—	$	1,974,656	$	2,711,106
Senior Vice President and Chief Financial Officer (1)(2)
Alfredo Garcia	2008	$	205,191	$	101,063	$	253,650		—		—		—	$	30,425	$	590,329
Senior Vice President,	2007	$	191,664	$	100,000		—		—		—		—	$	18,250	$	309,914
Corporate Development and Former Interim Chief Financial Officer (2)	2006	$	171,666		—		—		—		—		—	$	6,867	$	178,533
Charles C. Boettcher	2008	$	236,468	$	117,305	$	422,750		—		—		—	$	551,010	$	1,327,533
Senior Vice President, General Counsel, Chief Compliance Officer and Secretary (9)	2007	$	85,243	$	75,000	$	1,119,000		—		—		—	$	88,599	$	1,367,842
Steven G. Hendrickson	2008	$	212,692	$	105,875	$	422,750		—		—		—	$	290,053	$	1,031,370
Senior Vice President, Technical Evaluation	2007	$	133,331	$	100,000	$	575,134		—		—		—	$	21,052	$	829,517
Joseph E. Schimelpfening	2008	$	212,692	$	105,875	$	422,750		—		—		—	$	287,113	$	1,028,430
Senior Vice President, Upstream and Minerals Business (3)	2007	$	133,331	$	100,000	$	575,134		—		—		—	$	19,052	$	827,517

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(1) Mr. Holderness was appointed on May 15, 2008 to the office of Senior Vice President and Chief Financial Officer of Eagle Rock Energy G&P, LLC, the general partner of Eagle Rock Energy GP, L.P. which is the general partner of Eagle Rock, the publicly-traded limited partnership, referred to as the “Partnership,” and served in such capacity until he resigned effective as of August 15, 2008. As a result of his resignation, Mr. Holderness forfeited the restricted common units and incentive interests granted to him in 2008.

(2) Mr. Garcia served as Senior Vice President, Corporate Development since the Partnership’s initial public offering in 2006, and has also served on three separate occasions as the Acting or Interim, as applicable, Chief Financial Officer.  All other listed officers were appointed in 2007 and served throughout 2008.

(3) Mr. Schimelpfening’s title changed in 2008.

(4) Bonuses accrued for executives with regard to 2008 performance will be paid on March 31, 2009.

(5) With respect to 2008, the amounts represents: the dollar amount of 85,000 restricted common units awarded to Mr. Mills on May 15, 2008; the dollar amount of 40,000 restricted common units awarded to Mr. Holderness on May 15, 2008; the dollar amount of 15,000 restricted common units awarded to Mr. Garcia on May 15, 2008; the dollar amount of 25,000 restricted common units awarded to Mr. Boettcher on May 15, 2008; the dollar amount of 25,000 restricted common units awarded to Mr. Hendrickson on May 15, 2008; and the dollar amount of 25,000 restricted common units awarded to Mr. Schimelpfening on May 15, 2008. Such units vest 33% on May 15, 2009, 33% on May 15, 2010, and 34% on May 15, 2011. In determining the dollar amount, such units are valued at $16.91, which is the price of such units on the date of grant, May 15, 2008. With respect to 2007, the amounts represent: the dollar amount of 85,000 restricted common units awarded to Mr. Mills on May 15, 2007; the dollar amount of 50,000 restricted common units awarded to Mr. Boettcher on August 15, 2007; the dollar amount of 24,631 restricted common units awarded to Mr. Hendrickson on May 15, 2007; and the dollar amount of 24,631 restricted common units awarded to Mr. Schimelpfening on May 15, 2007. Such units vest 33% on May 15, 2008, 33% on May 15, 2009, and 34% on May 15, 2010. In determining the dollar amount, such units are valued at $23.35, which is the price of such units on the date of grant, May 15, 2007, except for Mr. Boettcher, whose units were granted on August 15, 2007 and which are valued at $22.38 per unit.

(6) No options were awarded by the Partnership.

(7) With respect to 2008, the amounts include contributions that we made to each named executive officer under our 401(k) plan in the following amounts: Mr. Mills, $32,993; Mr. Holderness, $0; Mr. Garcia, $18,125; Mr. Boettcher, $22,807; Mr. Hendrickson, $18,679; and Mr. Schimelpfening, $15,739. With respect to 2007, represents the amount of contributions that we made to each named executive officer under our 401(k) plan in the following amounts: Mr. Mills, $15,417; Mr. Holdereness, $0; Mr. Garcia, $18,250; Mr. Boettcher, $0; Mr. Hendrickson, $12,000; and Mr. Schimelpfening, $10,000.

(8) The amounts include distributions that we made to each named executive officer on account of outstanding restricted common units under the LTIP that had not yet vested (i.e., for which the restrictions had not yet lapsed).  With respect to 2008, the distribution payments were in the following amounts: Mr. Mills, $183,761; Mr. Holderness, $16,400; Mr. Garcia, $12,300; Mr. Boettcher, $87,595; Mr. Hendrickson, $53,552; and Mr. Schimelpfening, $53,552. With respect to 2007, the distribution payments were in the following amounts: Mr. Mills, $62,050; Mr. Holderness, $0; Mr. Garcia, $0; Mr. Boettcher, $18,375; Mr. Hendrickson, $9,052; and Mr. Schimelpfening, $9,052.

(9) In connection with Mr. Boettcher’s relocation from Dallas, Texas to Houston, Texas to accept his position with G&P, to cover closing costs and to compensate for an unfavorable price environment in the Dallas housing market: (i) in 2008, Mr. Boettcher received $5,747, and (ii) in 2007, Mr. Boettcher received $47,102 and $34,463 ($23,122, net of taxes) as a gross-up to cover taxes on the $47,102.

(10) Certain of the named executive officers received grants of incentive interests in Eagle Rock Holdings, L.P. from the Holdings Board. Pursuant to SEC Staff Accounting Bulletin Topic 1.B., the Tier I incentive interests are valued and included in “other compensation” but the Tier II and III incentive interests are not included.  For 2008, the value of the tier I incentive interests for the named executive officers is as follows:  Mr. Mills, $337,799; Mr. Holderness, $1,958,256; Mr. Garcia, $0; Mr. Boettcher, $440,608; Mr. Hendrickson, $217,822; and Mr. Schimelpfening, $217,822. Mr. Holderness forfeited his incentive interests upon his resignation.  For a discussion of the incentive interests granted, see “—Discussion and Analysis of Executive Compensation—Long-Term Incentives—2008.”

The named executive officers listed above were previously granted incentive interests in, and are limited partners of, Eagle Rock Holdings, L.P., which owns common units and subordinated units in us as well as general partner units and incentive distribution rights through its ownership of our general partner. In addition, Mr. Garcia previously purchased limited partnership interests in Eagle Rock Holdings, L.P. As a result of these prior grants and purchases, (i) during 2008, the named executive officers received cash distributions based on their limited partnership interests in Eagle Rock Holdings, L.P. in the following amounts: Mr. Mills, $21,794; Mr. Holderness, $0; Mr. Garcia, $1,236,281 ; Mr. Boettcher, $29,807; Mr. Hendrickson, $10,507; and Mr. Schimelpfening, $10,507 based on their limited partnership interests in Eagle Rock Holdings, L.P., and (ii) during 2007, Mr. Garcia received $460,139  in cash distributions based on his limited partnership interests in Eagle Rock Holdings, L.P. and no other named executive officer received any distributions. We do not consider these amounts to be compensation from the Partnership to these individuals; however, we consider a majority of the value of the incentive interests (on the date granted in 2008) to be compensation from the Partnership. These amounts are distributions based on their respective ownership in Holdings, which holds the equity in us as described above. These distributions are funded by Holdings and are not funded by us, other than indirectly by virtue of our direct and indirect distributions to Holdings on account of its direct and indirect equity ownership in us.

152

Grants of plan-based awards in 2008

The table below sets forth information regarding grants of plan-based awards made to our named executive officers during 2008.

		Estimated Future Payouts Under Non-Equity Incentive Plan Awards						Estimated Future Payouts Under Equity Incentive Plan Awards
Name	Grant Date	Threshold ($)		Target ($)		Maximum ($)		Threshold (#)		Target (#)		Maximum (#)		All Other Unit Awards(1): Number of Restricted Units (#)		All Other Option Awards: Number of Securities Underlying Options (#)		Exercise or Base Price of Option Awards ($/Unit)		Grant Date Fair Value of Unit and Option Awards(2)
Joseph A. Mills	5/15/08		—		—		—		—		—		—		85,000		—		—	$	1,437,350
Darin G. Holderness (3)	5/15/08		—		—		—		—		—		—		40,000		—		—	$	676,400
Alfredo Garcia	5/15/08		—		—		—		—		—		—		15,000		—		—	$	253,650
Charles C. Boettcher	5/15/08		—		—		—		—		—		—		25,000		—		—	$	422,750
Steven G. Hendrickson	5/15/08		—		—		—		—		—		—		25,000		—		—	$	422,750
Joseph E. Schimelpfening	5/15/08		—		—		—		—		—		—		25,000		—		—	$	422,750

______________

(1) Represents the amount of restricted units awarded on the grant date. Such units vest 33% on May 15, 2009, another 33% on May 15, 2010, and a final 34% on May 15, 2011.

(2) Calculated based upon unit price on May 15, 2008 of $16.91 times the number of restricted units. 

(3) Resigned effective August 15, 2009.

153

Outstanding equity awards at December 31, 2008

The following table summarizes the number of securities underlying outstanding plan awards for each named executive officer as of December 31, 2008.

	Option Awards										Unit Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)		Option Exercise Price ($)		Option Expiration Date		Number of Units That Have Not Vested (#)		Market Value of Units That Have Not Vested(1) ($)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)
Joseph A. Mills		—		—		—		—		—		141,950	$	668,584		—		—
Darin G. Holderness		—		—		—		—		—		—	$	—		—		—
Alfredo Garcia		—		—		—		—		—		15,000	$	70,650		—		—
Charles C. Boettcher		—		—		—		—		—		58,500	$	275,535		—		—
Steven G. Hendrickson		—		—		—		—		—		41,503	$	195,479		—		—
Joseph E. Schimelpfening		—		—		—		—		—		41,503	$	195,479		—		—

(1) Calculated based upon common unit price at end of the fiscal year of $4.71 times the number of unvested restricted unit awards.

	Option Awards				Unit Awards
Name	Number of units acquired on exercise (#)		Value realized on exercise ($)		Number of units acquired on vesting (#)		Value realized on vesting(1) ($)
Joseph A. Mills		—		—		28,050	$	474,326
Darin G. Holderness		—		—		—	$	—
Alfredo Garcia		—		—		—	$	—
Charles C. Boettcher		—		—		16,500	$	279,015
Steven G. Hendrickson		—		—		8,128	$	137,444
Joseph E. Schimelpfening		—		—		8,128	$	137,444

(1) Calculated based upon a closing unit price of $16.91 on May 15, 2008, the date of vesting.

154

Employment Agreements and Severance and Change of Control Arrangements

The award agreements under the LTIP provide for accelerated vesting upon a change of control of G&P or Eagle Rock ((i) ownership of more than 50% of the voting securities by a person or entity other than an NGP Affiliate, (ii) a sale or liquidation of substantially all of the assets to any other non-affiliated party, or (iii) G&P or an affiliate of NGP ceases to be the general partner) or termination of employment by reason of death or disability of the employee.

The following table illustrates the potential value of the acceleration of the vesting requirements of prior equity grants under our LTIP to our named executive officers in certain circumstances described in the table. We do not have any obligation to make cash payments upon termination of employment or a change in control transaction for any of the named executive officers. The amounts in the table represent the value of the restricted common units that would vest as a result of the termination of the named executive officer’s employment or a change in control if such transaction had occurred at December 31, 2008. For purposes of valuing the restricted common unit grants, the amounts below are based on a per common unit price of $4.71, which was the closing price as reported on the NASDAQ Global Select Market December 31, 2008.  Mr. Holderness is no longer an employee and did not receive any severance payments or accelerated vesting of prior equity grants upon his resignation of employment.

Benefits and Payments upon Termination	Retirement, Termination for cause, or Voluntary Termination		Termination Without Cause or for Good Reason		Change of Control(1)			Death or Disability
Joseph A. Mills	$	—	$	—	$	668,585	(2)	$	668,585	(2)
Darin G. Holderness	$	—	$	—	$	—		$	—
Alfredo Garcia	$	—	$	—	$	70,650	(3)	$	70,650	(3)
Charles C. Boettcher	$	—	$	—	$	346,185	(4)	$	346,185	(4)
Steven G. Hendrickson	$	—	$	—	$	195,479	(5)	$	195,479	(5)
Joseph E. Schimelpfening	$	—	$	—	$	195,479	(6)	$	195,479	(6)

_________________

(1) The definition of change of control is defined above in this subsection.

(2) Based on 141,950 unvested common units.

(3) Based on 15,000 unvested common units.

(4) Based on 73,000 unvested common units.

(5) Based on 41,503 unvested common units.

(6) Based on 41,503 unvested common units.

In addition to the restricted common units granted under the LTIP, any equity grants under the Holdings limited partnership agreement and the Montierra limited partnership agreement are subject to vesting requirements that may be accelerated in certain change of control transactions similar to the definition of change of control described above and certain termination scenarios similar to those described above. However, these equity grants either are (i) subject to reaching further payout goals that have not been met, as described above in “—Discussion and Analysis of Executive Compensation—Long Term Incentives” and for which the confidential and proprietary nature of these payout goals with respect to NGP prevents disclosure, or (ii) have reached the applicable payout goal (in the case of Tier I incentive interests of Holdings) and the expense allocation has already been included in our 2008 financial statements pursuant to SEC Staff Accounting Bulletin Topic 1.B as discussed above. Based on the lack of value of those equity units that have not achieved their payout goals using the hypothetical transaction date of December 31, 2008, we have not included any disclosure in the table above regarding these equity units.

155

2008 Director Compensation

The table below sets forth certain information concerning the compensation earned in 2008 by our non-employee directors who served in 2008. Information on our employee director who served in 2008, Joseph A. Mills, is set forth above for named executive officers.

Name	Fees Earned or Paid in Cash(1) ($)		Unit Awards ($)			Option Awards ($)		Non-Equity Incentive Plan Compensation ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings		All Other Compensation(5) ($)		Total ($)
Kenneth A. Hersh		—		—			—		—		—		—		—
William J. Quinn		—		—			—		—		—		—		—
John A. Weinzierl		—		—			—		—		—		—		—
Philip B. Smith	$	65,016	$	59,185	(2)		—		—		—	$	14,956	$	139,157
William A. Smith	$	69,746	$	59,185	(3)		—		—		—	$	9,580	$	138,511
William K. White	$	70,012	$	59,185	(4)		—		—		—	$	18,310	$	147,507

______________

(1) Reflects fees paid or earned by our non-employee directors in 2008.

(2) Represents the dollar amount of 3,500 restricted common units awarded to Mr. Philip B. Smith, on May 15, 2008. Such units vest 33% on May 15, 2009, another 33% on May 15, 2010, and a final 34% on May 15, 2011. In determining the dollar amount, such units are valued at $16.91 which was the grant date fair value as computed in accordance with FAS 123R.

(3) Represents the dollar amount of 3,500 restricted common units awarded to Mr. William A. Smith, on May 15, 2008. Such units vest 33% on May 15, 2009, another 33% on May 15, 2010, and a final 34% on May 15, 2011. In determining the dollar amount, such units are valued at $16.91, which was the grant date fair value as computed in accordance with FAS 123R.

(4) Represents the dollar amount of 3,500 restricted common units awarded to Mr. William K. White, on May 15, 2008. Such units vest 33% on May 15, 2009, another 33% on May 15, 2010, and a final 34% on May 15, 2011. In determining the dollar amount, such units are valued at $16.91, which was the grant date fair value as computed in accordance with FAS 123R.

(5) Represents the amount of distributions that we made to each director on account of outstanding restricted common units under the LTIP that had not yet vested (i.e., for which the restrictions had not yet lapsed).

Officers or employees of G&P or its affiliates who also serve as directors will not receive additional compensation for their service as a director of G&P. Our general partner intends for directors who are not officers or employees of G&P or its affiliates to receive compensation for serving on the board of directors and committees thereof. In 2008, the Board of Directors, by unanimous vote of all directors other than the independent directors who abstained from the vote, authorized revisions to the compensation of the independent directors pursuant to a recommendation received from management in connection with a study prepared by Towers Perrin.  As a result, it is expected that the independent directors will receive (a) $50,000 per year as an annual retainer fee; (b) $5,000 per year for each committee of the board of directors on which such director serves and an additional $10,000 per year for the Audit Committee chairman, $5,000 per year for the Compensation Committee chairman, and $2,500 per engagement (of the Conflicts Committee) for the Conflicts Committee chairman; (c) 5,000 restricted common units upon becoming a director, vesting in roughly one-third increments over a three-year period; (d) 3,500 restricted common units annually after becoming a director, vesting in roughly one-third increments over a three-year period; (e) reimbursement for out-of-pocket expenses associated with attending meetings of the board of directors or committees; (f) reimbursement for educational costs relevant to the director’s duties; and (g) director and officer liability insurance coverage. Each director is fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law.

Compensation Committee Interlocks and Insider Participation

As of December 31, 2008, William A. Smith, William J. Quinn and Philip B. Smith served on the Compensation Committee of the Board of Directors of G&P which is the general partner of our general partner. Mr. Smith served as the Chairman of the Committee during 2008. In addition to his service as a member of the Board of Directors and the Compensation Committee, Mr. Quinn also served as a managing partner of the NGP private equity funds during 2008. For additional disclosure on relationships of NGP to Eagle Rock, see Item 13, “Certain Relationships and Related Transactions, and Director Independence.” In addition, during 2008, none of our executive officers served as a director or as a member of the compensation committee of another company which employs any of our directors or members of our Compensation Committee.

156

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

The following table sets forth the beneficial ownership of our units as of March 6, 2009 held by:

• each person or group of persons who beneficially own 5% or more of the then outstanding common units;

• each member of the board of directors of Eagle Rock Energy G&P, LLC;

• each named executive officer of Eagle Rock Energy G&P, LLC; and

• all current directors and executive officers of Eagle Rock Energy G&P, LLC as a group.

Name of Beneficial Owner (1) (2)	Common Units Beneficially Owned		Percentage of Common Units Beneficially Owned			Subordinated Units Beneficially Owned			Percentage of Subordinated Units Beneficially Owned			Percentage of Total Common and Subordinated Units Beneficially Owned
Eagle Rock Holdings, L.P.(3)		2,338,419		4.2	%		20,691,495	(10)		100.0	%		30.1	%
NGP 2004 Co-Investment Income, L.P.(9)		3,500,136		6.3	%		----			---	%		4.6	%
Montierra Minerals & Production, L.P.(4)		2,868,556		5.1	%		----			---	%		3.8	%
Barclays PLC(5)		3,534,349		6.3	%		----			---	%		4.6	%
Steven B. Klinsky(6)		5,572,692		10.0	%		----			---	%		7.3	%
Joseph A. Mills(3)(8)		162,480		*	%		----			---	%		*	%
Jeffrey P. Wood(8)		50,000		*	%		----			---	%		*	%
Alfredo Garcia(3)(8)		15,000		*	%		----			---	%		*	%
Charles C. Boettcher(3)(8)		70,615		*	%		----			---	%		*	%
Steven G. Hendrickson(3)(8)		47,451		*	%		----			---	%		*	%
Joseph E. Schimelpfening(3)(8)		49,631		*	%		----			---	%		*	%
William E. Puckett(3)(8)		48,231		*	%		----			---	%		*	%
Kenneth A. Hersh(7)		12,310,046		22.1	%		20,691,495	(10)		100.0	%		16.1	%
William J. Quinn		10,000		*	%		----			---	%		*	%
Phillip B. Smith		13,500		*	%		----			---	%		*	%
William A. Smith		8,500		*	%		----			---	%		*	%
John A. Weinzierl		8,800		*	%		----			---	%		*	%
William K. White		18,700		*	%		----			---	%		*	%
All directors and executive officers as a group (13 persons)		12,812,954		23.0	%		20,691,495	(10)		100.0	%		43.9	%

____________

*      Less than 1%

(1) Unless otherwise indicated, the address for all beneficial owners in this table, except Barclays PLC and Steven B. Klinsky is 16701 Greenspoint Park Drive, Suite 200 Houston, Texas 77060.

(2) All units are subject to the beneficial owner’s sole voting and dispositive power unless otherwise indicated in the footnotes below.

(3) Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., Joseph A. Mills, Jeffrey P. Wood, Alfredo Garcia, Charles C. Boettcher, Steven G. Hendrickson, Joseph E. Schimelpfening and William E. Puckett based on equity ownership and profits interests in Eagle Rock Holdings, L.P. (“Holdings”), and Eagle Rock GP, L.L.C., its general partner which is owned 39.14% and 60.35% by Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. and which owns a 1.0% general partner interest in Holdings, have the right to receive distributions (based on equity units and Tier I incentive interests which achieved payout target) in the following percentages, respectively: 32.2%, 49.7%, 0.3%, 0.6%, 3.3%, 0.2%, 0.1%, 0.1% and 0.8%.  Our common units and subordinated units held by Holdings are not being reported in this table as beneficially owned by each of the limited partners and profits interests holders, except for Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. (See footnote (7) below)

157

(4) NGP VII, Joseph A. Mills, Steven G. Hendrickson and Joseph E. Schimelpfening, based on equity ownership and profits interests in Montierra Minerals & Production, L.P. (“Montierra”) and Montierra Management LLC, have the right to receive distributions (based on equity units only, as no tier of incentive interests has achieved payout target) in the following percentages, respectively: 97.1%, %, 2.4%, 0.1% and 0.2%.  NGP VII appoints three managers on the board of Montierra Management LLC (“Montierra Management”), which serves as the general partner of Montierra. NGP VII also owns a 97.6% interest in Montierra Management, and thus may be deemed to beneficially own all of the reported securities of Montierra Management and Montierra.

(5) Based solely on information furnished in the Schedule 13G jointly filed by Barclays PLC and Barclays Capital Inc. with the SEC on October 8, 2008.  The address for Barclays PLC is 1 Churchill Place, London, E14 5HP, England.  For purposes of this beneficial ownership table, we have assumed that Barclays acquired the common units previously reported as being beneficially owned by Lehman Brothers Holdings Inc. and its affiliates although the Partnership has not been able to verify this ownership.  As reported on the Form 8-K filed by Lehman Brothers Holding Inc. with the SEC on September 22, 2008, on September 16, 2008 Barclays Capital Inc. (“Barclays”) entered into an asset purchase agreement with Lehman Brothers Holdings Inc., Lehman Brothers Inc. and LB 745 LLC (“Lehman”) whereby Barclays acquired certain assets related to Lehman’s U.S. and Canadian investment banking and capital markets businesses including the fixed income and equities cash trading, brokerage, dealing, trading and advisory businesses, investment banking operations and business as a futures commission merchant.  The sale closed on September 22, 2008.  Prior to the closing of the sale, Lehman Brothers Holdings Inc. filed a Schedule 13D/A disclosing that it beneficially owned 4,975,306 common units of the Partnership.  Various direct and indirect subsidiaries of Lehman Brothers Holdings Inc. own the common units that Lehman Brothers Holdings Inc. is deemed to beneficially own.

(6) Based solely on information furnished in the Schedule 13G/A filed New Mountain Vantage, L.P. with the SEC on January 9, 2009.  Mr. Klinsky may be deemed to beneficially own an aggregate of 5,572,692 common units that are owned by New Mountain Vantage, L.P., New Mountain Vantage (California), L.P., New Mountain Vantage (California) II, L.P., New Mountain Vantage (Texas), L.P. and New Mountain Vantage (Cayman) Ltd. representing, in the aggregate, approximately 10.0% of the issued and outstanding common units.  Mr. Klinsky disclaims beneficial ownership of the Common Units beneficially owned by New Mountain Vantage, L.P., New Mountain Vantage (California), L.P., New Mountain Vantage (California) II, L.P., New Mountain Vantage (Texas), L.P. and New Mountain Vantage (Cayman) Ltd., to the extent that partnership interests or limited liability company interests in New Mountain Vantage, L.P., New Mountain Vantage (California), L.P., New Mountain Vantage (California) II, L.P., New Mountain Vantage (Texas), L.P. and New Mountain Vantage (Cayman) Ltd. are held by persons other than Mr. Klinsky.  The address for Steven B. Klinsky is 787 Seventh Avenue, 49th Floor, New York, NY 10019.

(7) G.F.W. Energy VII, L.P., GFW VII, L.L.C., G.F.W. Energy VIII, L.P. and GFW VIII, L.L.C. may be deemed to beneficially own the units held by Eagle Rock Holdings, L.P. (“Holdings”) that are attributable to Natural Gas Partners VII, L.P. (“NGP VII”) and Natural Gas Partners VIII, L.P. (“NGP VIII”) by virtue of GFW VII, L.L.C. being the sole general partner of G.F.W. Energy VII, L.P. and GFW VIII, L.L.C. being the sole general partner of G.F.W. Energy VIII, L.P. Kenneth A. Hersh, who is an Authorized Member of each of GFW VII, L.L.C. and GFW VIII, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition of, those units.  NGP VII and NGP VIII collectively own a 98.1% LP interest in Holdings and NGP VII owns a 96.2% LP interest in Montierra. NGP VII and NGP VIII control the general partner of Holdings. NGP VII controls the general partner of Montierra. NGP VII owns 100% of NGP Income Management L.L.C. which serves as the general partner of both NGP-VII Income Co-Investment Opportunities, L.P. (“NGP-VII Income Co-Investment”) and NGP 2004 Co-Investment Income, L.P. (“NGP 2004”). NGP-VII Income Co-Investment owns 100% of NGP Co-Investment Income Capital Corp. (“NGP Capital Corp.”). NGP VII may be deemed to beneficially own all of the units of NGP 2004 and NGP Capital Corp. Kenneth A. Hersh may be deemed to share dispositive power over the units held by NGP VII, thus, he may also be deemed to be the beneficial owner of these units. In addition to the amounts deemed beneficially owned, NGP VII also has direct beneficial ownership of 1,701,497 units, and NGP VIII also has direct beneficial ownership of 1,763,206 units.  Mr. Hersh disclaims beneficial ownership of our units except to the extent of his pecuniary interest therein.

(8) Joseph A. Mills beneficially owns 162,480 units, 141,950 of which remain subject to a three-year vesting schedule pursuant to our long term incentive plan.  Jeffrey P. Wood beneficially owns 50,000 units that are subject to a three-year vesting schedule pursuant to our long-term incentive plan.  Alfredo Garcia beneficially owns 15,000 units that are subject to a three-year vesting schedule pursuant to our long-term incentive plan.  Charles C. Boettcher beneficially owns 70,615 units, 58,500 of which remain subject to a three-year vesting schedule pursuant to our long-term incentive plan.  Steven G. Hendrickson beneficially owns 47,451 units, 41,503 of which remain subject to a three-year vesting schedule pursuant to our long term incentive plan.  William E. Puckett beneficially owns 48,231 units, 40,034 of which remain subject to a three-year vesting schedule pursuant to our long-term incentive plan.  Joseph E. Schimelpfening beneficially owns 49,631 units, 41,503 of which remain subject to a three-year vesting schedule pursuant to our long term incentive plan.

(9) See footnote (7) above for a description of NGP VII’s ownership and control of this beneficial owner.

(10) Kenneth A. Hersh may be deemed to share dispositive power over the subordinated units, thus, he may also be deemed to be the beneficial owner of these units.  Mr. Hersh disclaims beneficial ownership of these units except to the extent of his pecuniary interest therein.

158

Equity Compensation Plan Information

The following table sets forth certain information with respect to our equity compensation plans as of December 31, 2008.

	Number of securities to be issued upon exercise of outstanding options, warrants and rights: (a)			Weighted-average exercise price of outstanding options, warrants and rights (b)			Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders		N/A			N/A			N/A
Equity compensation plans not approved by security holders
—2006 Long-Term Incentive Plan(1)		N/A	(1)		N/A	(1)		902,422	(1)
Total		N/A			N/A			902,422

_____________

(1) The long-term incentive plan, which did not require approval by our public limited partners and was adopted by our general partner in connection with our initial public offering in 2006 and amended by our general partner in 2008 and 2009, currently permits the grant of awards covering an aggregate of 2,000,000 common units in various forms of grants. For more information about our long-term incentive plan, or LTIP, refer to Part III, Item 11. Executive Compensation—Discussion and Analysis of Compensation—Long-Term Incentives.  To date, all award grants under the long-term incentive plan have been in the form of restricted unit grants, which generally vest over a three-year period. As of March 6, 2009, we had outstanding 955,986 restricted common units granted under our LTIP.

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

Since January 1, 2006, we have been involved in several transactions involving Holdings or affiliates of Natural Gas Partners (“NGP”). Holdings, which is the sole member of Eagle Rock Energy G&P, LLC, which is the general partner of our general partner, is currently owned by NGP and certain members of our management team. Since April 30, 2007, the Partnership has been involved in several transactions with Montierra Minerals & Production, L.P. (“Montierra”), an affiliate of NGP.  Joseph A. Mills, our Chief Executive Officer, is the chief executive officer and a manager of Montierra Management LLC, which is the general partner of Montierra.  See Item 12., Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters, for additional information regarding the Partnership’s relationship with NGP and the ownership of Holdings and Montierra.

The following members of the board of directors of Eagle Rock Energy G&P, LLC (G&P) hold positions at NGP set forth next to each person’s name: William J. Quinn, Executive Vice President of NGP Energy Capital Management and a managing partner of the NGP private equity funds, Kenneth A. Hersh, Chief Executive Officer of NGP Energy Capital Management and is a managing partner of the NGP private equity funds, and John A. Weinzierl, a managing director of the NGP private equity funds.  The Partnership does not directly employ any persons to manage or operate our business. Those functions are provided by G&P. We reimburse G&P for all direct and indirect costs of these services.

On January 5, 2009, Jeffrey P. Wood was appointed to the position of senior vice president and chief financial officer of G&P, general partner of Eagle Rock Energy GP, L.P., which is our general partner.  While serving as a principal with the private equity division of Lehman Brothers, Mr. Wood oversaw the investment of an aggregate of $94 million by certain Lehman Brothers’ private equity funds in our common units through private placements during 2007.  The proceeds from these private placement transactions were used to fund the cash portion of the purchase prices of certain acquisitions by us closed in May and July of 2007. While Mr. Wood oversaw the investment process, Mr. Wood did not control the investment decisions for the Lehman Brothers private equity funds and does not have, and specifically disclaims, any beneficial ownership or pecuniary interest in the common units acquired by the Lehman Brothers private equity funds.

On July 1, 2006, we entered into a month-to-month contract for the sale of natural gas with an affiliate of NGP, Odyssey Energy Services, LLC, under which we sell a portion of our gas supply.  In July 2008, the company to which we sell our natural gas was sold by the affiliate of NGP and thus ceased being a related party.  The Partnership recorded revenues of $16.0 million, $35.3 million and $19.4 million for the years ended December 31, 2008, 2007 and 2006, respectively, from the agreement, of which there was a receivable of $5.5 million outstanding at December 31, 2007.

In the fourth quarter of 2006 and in connection with consummating our initial public offering, the Partnership entered into an Omnibus Agreement with G&P, Holdings and our general partner, Eagle Rock Energy GP, L.P., which requires us to reimburse G&P for the payment of certain expenses incurred by G&P or its employees, officers, or representatives on our behalf, including payroll, benefits, insurance and other operating expenses, and provides certain indemnification obligations.

159

In connection with the closing of our initial public offering, on October 24, 2006, we entered into a registration rights agreement with Eagle Rock Holdings, L.P. in connection with its contribution to us of all of its limited and general partner interests in Eagle Rock Pipeline. In the registration rights agreement, we agreed, for the benefit of Eagle Rock Holdings, L.P., to register the common units it holds, the common units issuable upon conversion of the subordinated units it holds, and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds.

In connection with the closing of the acquisition of certain assets from Montierra and NGP-VII Income Co-Investment Opportunities, L.P. (“Co-Invest”), on April 30, 2007, we entered into registration rights agreements with Montierra and Co-Invest. In the registration rights agreements, we agreed, for the benefit of Montierra and Co-Invest, to register the common units they hold, the common units issuable upon conversion of the subordinated units that they hold and any common units or other equity securities issuable in exchange for the common units and subordinated units they hold. We have registered for resale the common units related to this transaction.

On April 30, 2008, we completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp., (“Stanolind”) for an aggregate purchase cash price of $81.9 million (the “Stanolind Acquisition”), from one or more NGP private equity funds, which directly or indirectly owned a majority of the equity interests in Stanolind.  Because of the potential conflict of interest between the interests of the Company and the public unitholders of Eagle Rock, the Board of Directors authorized the Company’s Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Stanolind Acquisition.  The Conflicts Committee, consisting of independent Directors of the Company, determined that the Stanolind Acquisition was fair and reasonable to Eagle Rock and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In determining the purchase consideration for the Stanolind Acquisition, the Board of Directors 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 flow of Stanolind.  The members of the Conflicts Committee –Messrs. Philip Smith, William Smith and William White – have been determined to be independent under the rules of the SEC and NASDAQ applicable to audit committees.

The conflicts resolution process described immediately above is the process we generally use to approve related-party transactions.

During the year ended December 31, 2008, we purchased and sold natural gas from certain companies affiliated with one or more NGP private equity funds, which include Crow Creek Energy II, LLC, Momentum Energy Holdings, L.P. and BlueStone Natural Resources Holdings, LLC. During the year ended December 31, 2008, we purchased natural gas from one or more of these affiliated companies, totaling approximately $0.6 million, and sold natural gas to one or more of these affiliated companies, totaling approximately $0.2 million.   During the year ended December 31, 2008, we rented office space from Montierra and we were also reimbursed by Montierra for work performed by our employees on their behalf.  We paid Montierra $0.1 million in rental payments and were reimbursed $0.2 million by Montierra.

During the year ended December 31, 2008, the Partnership incurred approximately $2.1 million for services performed by Stanolind Field Services (“SFS”), which is controlled by NGP and certain individuals, including one employee of G&P.

Additional information is provided in Note 9, Related Party Transactions, of our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report.

160

Item 14. Principal Accountant Fees and Services.

The following sets forth fees billed by Deloitte & Touche LLP for the audit of our annual financial statements and other services rendered for the fiscal years ended December 31, 2008, 2007 and 2006:

	December 31,
	2008		2007		2006
Audit fees(1)	$	2,209,550	$	1,628,611	$	1,762,006
Audit related fees(2)		—		29,645		—
Tax fees(3)		798,254		405,677		16,660
All other fees(4)		567,540		—		—
Total	$	3,575,344	$	2,063,933	$	1,778,666

_____________

(1) Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of interim financial statements, audits of businesses acquired and other customary documents filed with the Securities and Exchange Commission.

(2) Includes fees related to consultations concerning financial accounting and reporting standards and services related to the implementation of our internal controls over financial reporting.

(3) Includes fees related to professional services for tax compliance, tax advice, and tax planning.

(4) Includes fees for due diligence work performed on our Stanolind and Millennium Acquisitions.

Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and to establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.

The Audit Committee has started a process for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Deloitte & Touche LLP, including audit services, audit-related services, tax services and other services, must be pre-approved by the Committee.

The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):

• the auditors’ internal quality-control procedures;

• any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;

• the independence of the external auditors;

• the aggregate fees billed by our external auditors for each of the previous two fiscal years; and

• the rotation of the lead partner.

161

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	F-3
Consolidated Statements of Operations	F-4
Consolidated Statements of Cash Flows	F-5
Consolidated Statements of Members’ Equity	F-6
Notes to Consolidated Financial Statements	F-7

(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:

Exhibit Number	Description
2.1	Partnership Interests Purchase and Contribution Agreement By and Among Laser Midstream Energy II, LP, Laser Gas Company I, LLC, Laser Midstream Company, LLC, Laser Midstream Energy, LP, and Eagle Rock Energy Partners, L.P., dated as of March 30, 2007 (incorporated by reference to Exhibit 2.1 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
2.2	Partnership Interests Contribution Agreement By and Among Montierra Minerals & Production, L.P., NGP Minerals, L.L.C. (Montierra Management LLC) and Eagle Rock Energy Partners, L.P., dated as of March 31, 2007 (incorporated by reference to Exhibit 2.2 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
2.3	Asset Contribution Agreement By and Among NGP 2004 Co-Investment Income, L.P., NGP Co-Investment Income Capital Corp., NGP-VII Income Co-Investment Opportunity, L.P., and Eagle Rock Energy Partners, L.P., dated as of March 31, 2007 (incorporated by reference to Exhibit 2.3 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
2.4	Contribution and Sale Agreement By and Among Eagle Rock Energy Partners, L.P., Redman Energy Holdings, L.P. and Certain Other Parties Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 2.4 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
2.5	Contribution and Sale Agreement By and Among Eagle Rock Energy Partners, L.P., Redman Energy Holdings II, L.P. and Certain Other Parties Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 2.5 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
2.6	Asset Contribution Agreement By and Among NGP Co-Investment Opportunities Fund II, L.P. and Eagle Rock Energy Partners, L.P., dated July 11, 2007 (incorporated by reference to Exhibit 2.6 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
2.7	Stock Purchase Agreement dated April 2, 2008 among Eagle Rock Energy Partners, L.P., Stanolind Holdings, L.P. and Stanolind Oil and Gas Corp. (incorporated by reference to Exhibit 2.8 of the registrant’s current report on Form 8-K filed with the Commission on April 4, 2008 (File No. 001-33016))
2.8	Partnership Interests Purchase Agreement dated September 11, 2008, as amended, among Eagle Rock Energy Partners, L.P. and Millennium Midstream Partners, L.P. (incorporated by reference to Exhibit 2.1 of the registrant’s quarterly period for the period ended September 20, 2008 filed with the Commission on November 10, 2008 (File No. 001-33016))
2.9*	Amendment No. 2 to the Partnership Interests Purchase Agreement dated February 9, 2009 among Eagle Rock Energy Partners, L.P. and Millennium Midstream Partners, L.P.
2.10*	Amendment No. 3 to the Partnership Interests Purchase Agreement dated February 27, 2009 among Eagle Rock Energy Partners, L.P. and Millennium Midstream Partners, L.P.

162

Exhibit Number	Description
3.1	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))
3.2	First 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 October 31, 2006)
3.3	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))
3.4	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))
3.5	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))
3.6	Second Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.2 of the registrant’s current report on Form 8-K filed with the Commission on October 31, 2006)
4.1	Registration Rights Agreement dated March 27, 2006, among Eagle Rock Pipeline, L.P. and the Purchasers listed thereto (incorporated by reference to Exhibit 4.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
4.3	Registration Rights Agreement between Eagle Rock Energy Partners, L.P. and Eagle Rock Holdings, L.P. (incorporated by reference to Exhibit 4.1 of the registrant’s current report on Form 8-K filed with the Commission on October 31, 2006)
4.4	Form of Common Unit Certificate (included as Exhibit A to the Amended and Restated Partnership Agreement of Eagle Rock Energy Partners, L.P., which is included as Appendix A to the Prospectus) (incorporated by reference to Exhibit 3.2 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
4.5	Form of Common Unit Certificate (included as Exhibit A to the Amended and Restated Partnership Agreement of Eagle Rock Energy Partners, L.P., which is included as Appendix A to the Prospectus) (incorporated by reference to Exhibit 3.2 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
4.6	Registration Rights Agreement dated July 31, 2007, among Eagle Rock Energy Partners, L.P. and the purchasers listed thereto (incorporated by reference to Exhibit 4.6 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
4.7	Registration Rights Agreement dated April 30, 2007, between Eagle Rock Energy Partners, L.P. and NGP-VII Income Co-Investment Opportunities, L.P. (incorporated by reference to Exhibit 4.7 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
4.8	Registration Rights Agreement dated April 30, 2007, between Eagle Rock Energy Partners, L.P. and Montierra Minerals & Production, L.P. (incorporated by reference to Exhibit 4.8 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
10.1	Amended and Restated Credit and Guaranty Agreement (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.2	Omnibus Agreement (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on October 31, 2006)
10.3**	Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 of the registrant’s registration statement on Form S-1 (File No. 333-134750))

163

Exhibit Number	Description
10.4	Sale, Contribution and Exchange Agreement by and among the general and limited partners of Midstream Gas Services, L.P., Eagle Rock Energy Services, L.P. and Eagle Rock Pipeline, L.P. (incorporated by reference to Exhibit 10.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.5†	Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and ONEOK Texas 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))
10.6	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))
10.7	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))
10.8†	Minimum Volume Agreement between ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC (incorporated by reference to Exhibit 10.8 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.9†	Gas Purchase Agreement between ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC (incorporated by reference to Exhibit 10.9 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.10	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))
10.11	Contribution, Conveyance and Assumption Agreement (incorporated by reference to Exhibit 10.3 of the registrant’s current report on Form 8-K filed with the Commission on October 31, 2006)
10.12**	Employment Agreement dated August 2, 2006 between Eagle Rock Energy G&P, LLC and Richard W. FitzGerald (incorporated by reference to Exhibit 10.12 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.13	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))
10.14	Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The Purchasers Named Therein, dated March 30, 2007 (incorporated by reference to Exhibit 10.14 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
10.15	Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The Purchasers Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 10.15 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
10.16**	Severance Agreement with former executive officer (incorporated by reference to Exhibit 10.16 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
10.17**	Form of Award Agreement pursuant to the Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.14 of the Form 8-K filed with the Commission on May 22, 2007)
10.18	Credit Agreement dated December 13, 2007 among Eagle Rock Energy Partners, L.P. and Wachovia Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A., as syndication agent, HSH Nordbank AG, New York Branch, the Royal Bank of Scotland, plc, and BNP Paribas, as co-documentation agents, and the other lenders who are parties thereto (incorporated by reference to Exhibit 10.17 of the Form 8-K filed with the Commission on December 13, 2007)

164

Exhibit Number	Description
10.19**†	Eagle Rock Energy G&P, LLC 2009 Short Term Incentive Bonus Plan effective February 4, 2009 (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on February 9, 2009 (File No. 001-33016))
10.20***	Eagle Rock Energy Partners Long-Term Incentive Plan (Amended and Restated Effective February 4, 2009)
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 Deloitte & Touche LLP
23.2*	Consent of Cawley, Gillespie & Associates, Inc.
23.3*	Consent of K.E. Andrews & Company
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*	Audit Committee Charter (Amended and Restated Effective February 4, 2009)
99.2*	Compensation Committee Charter (Amended and Restated Effective February 4, 2009)
99.3*	Conflicts Committee Charter (Amended and Restated Effective February 4, 2009)

______________

* Filed herewith

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

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

165

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 12, 2009.

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	Chief Executive Officer (Principal Executive Officer)	March 12, 2009
Joseph A. Mills
/s/    Jeffrey P. Wood	Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	March 12, 2009
Jeffrey P. Wood
/s/    Kenneth A. Hersh	Director	March 12, 2009
Kenneth A. Hersh
/s/    William J. Quinn	Director	March 12, 2009
William J. Quinn
/s/    Philip B. Smith	Director	March 12, 2009
Philip B. Smith
/s/    William A. Smith	Director	March 12, 2009
William A. Smith
/s/    John A. Weinzierl	Director	March 12, 2009
John A. Weinzierl
/s/    William K. White	Director	March 12, 2009
William K. White

166

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, 2008 and 2007	F-3
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006	F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006	F-5
Consolidated Statements of Members’ Equity for the Years Ended December 31, 2008, 2007 and 2006	F-6
Notes to Consolidated Financial Statements	F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P. Houston, Texas

We have audited the consolidated balance sheets of Eagle Rock Energy Partners, L.P. and subsidiaries (the “Partnership”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, members’ equity, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 12, 2009 expressed an unqualified opinion on the Partnership’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 12, 2009

F-2

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2008 AND 2007

($ in thousands)

	December 31, 2008			December 31, 2007
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	17,916		$	68,552
Accounts receivable(1)		115,932			135,633
Risk management assets		76,769			—
Prepayments and other current assets		2,607			3,992
Total current assets		213,224			208,177
PROPERTY, PLANT AND EQUIPMENT —Net		1,357,609			1,207,130
INTANGIBLE ASSETS —Net		154,206			153,948
RISK MANAGEMENT ASSETS		32,451			—
GOODWILL		—			29,527
OTHER ASSETS		15,571			11,145
TOTAL	$	1,773,061		$	1,609,927
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	116,578		$	132,485
Due to affiliate		4,473			16,964
Accrued liabilities		19,565			9,776
Income taxes payable		1,559			723
Risk management liabilities		13,763			33,089
Total current liabilities		155,938			193,037
LONG-TERM DEBT		799,383			567,069
ASSET RETIREMENT OBLIGATIONS		19,872			11,337
DEFERRED TAX LIABILITY		42,349			17,516
RISK MANAGEMENT LIABILITIES		26,182			94,200
OTHER LONG TERM LIABILITIES		1,622			—
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS’ EQUITY:
Common unitholders(2)		625,590			617,563
Subordinated unitholders(3)		105,839			112,360
General partner(4)		(3,714	)		(3,155	)
Total members’ equity		727,715			726,768
TOTAL	$	1,773,061		$	1,609,927

____________

(1) Net of allowance for bad debt of $12,080 and $1,046 as of December 31, 2008 and 2007, respectively.

(2) 53,043,767 and 50,699,647 units were issued and outstanding as of December 31, 2008 and 2007, respectively.

(3) 20,691,495 units were issued and outstanding as of December 31, 2008 and 2007.

(4) 844,551 units were issued and outstanding as of December 31, 2008 and 2007.

See notes to consolidated financial statements.

F-3

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

($ in thousands, except per unit amounts)

	Years Ended December 31,
	2008			2007			2006
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales	$	1,498,975		$	868,101		$	486,911
Gathering, compression, processing and treating fees		38,871			27,417			14,862
Minerals and royalty income		42,994			15,004			—
Commodity risk management gains (losses)		161,765			(133,834	)		(24,004	)
Other revenue		716			110			621
Total revenue		1,743,321			776,798			478,390
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		1,154,707			686,882			377,580
Operations and maintenance		73,620			52,793			32,905
Taxes other than income		19,936			8,340			2,301
Other operating		10,699			2,847			6,000
General and administrative		45,701			27,799			10,860
Impairment of property and plants		143,857			5,749			—
Goodwill impairment		30,994			—			—
Depreciation, depletion and amortization		116,754			80,559			43,220
Total costs and expenses		1,596,268			864,969			472,866
OPERATING (LOSS) INCOME		147,053			(88,171	)		5,524
OTHER INCOME (EXPENSE):
Interest income		793			1,160			996
Other income		5,328			696			—
Interest expense, net		(32,884	)		(38,936	)		(30,281	)
Interest rate risk management gains (losses)		(32,931	)		(11,988	)		3,296
Other expense		(955	)		(8,226	)		(1,619	)
Total other (expense) income		(60,649	)		(57,294	)		(27,608	)
INCOME (LOSS) BEFORE INCOME TAXES		86,404			(145,465	)		(22,084	)
INCOME TAX PROVISION		(1,116	)		169			1,230
NET INCOME (LOSS)	$	87,520		$	(145,634	)	$	(23,314	)
NET INCOME (LOSS) PER COMMON UNIT—BASIC AND DILUTED:
Basic:
Net Income (Loss)
Common units	$	1.20		$	(2.11	)	$	(1.26	)
Subordinated units	$	1.20		$	(3.14	)	$	(0.43	)
General partner units	$	1.20		$	(3.14	)	$	(0.80	)
Basic (units in thousands)
Common units		51,534			37,008			12,123
Subordinated units		20,691			20,691			17,873
General partner units		845			845			557
Diluted:
Net Income (Loss)
Common units	$	1.20		$	(2.11	)	$	(1.26	)
Subordinated units	$	1.20		$	(3.14	)	$	(0.43	)
General partner units	$	1.20		$	(3.14	)	$	(0.80	)
Diluted: (units in thousands)
Common units		51,699			37,008			12,123
Subordinated units		20,691			20,691			17,873
General partner units		845			845			557

See notes to consolidated financial statements.

F-4

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

($ in thousands)

	Years Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	87,520		$	(145,634	)	$	(23,314	)
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		116,754			80,559			43,220
Impairment		174,851			5,749			—
Amortization of debt issuance costs		958			1,777			1,114
Write-off of debt issuance costs		—			6,215			—
Equity in earnings of unconsolidated affiliates		(4,021	)		(714	)		—
Distribution from unconsolidated affiliates—return on investment		3,643			408			—
Reclassing financing derivative settlements		11,063			1,667			(978	)
Advisory termination fee		—			—			6,000
Equity-based compensation		7,694			2,395			142
Gain of sale of assets		(1,265	)		—			—
Other		(1,618	)		(69	)		1,424
Changes in assets and liabilities—net of acquisitions:
Accounts receivable		40,873			(17,565	)		(10	)
Prepayments and other current assets		941			986			(1,422	)
Risk management activities		(199,339	)		136,132			23,531
Accounts payable		(44,013	)		19,200			3,105
Due to affiliates		(12,491	)		16,964			—
Accrued liabilities		(1,258	)		(1,790	)		5,672
Other assets		23			(58	)		(3,492	)
Other current liabilities		836			723			—
Net cash provided by operating activities		181,151			106,945			54,992
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment		(66,741	)		(66,116	)		(38,416	)
Acquisitions, net of cash acquired		(262,245	)		(407,626	)		(101,182	)
Escrow cash		—			—			7,643
Investment in partnerships		(3,936	)		—			—
Proceeds from sale of asset		1,294			—			—
Purchase of intangible assets		(2,975	)		(2,048	)		(2,918	)
Net cash used in investing activities		(334,603	)		(475,790	)		(134,873	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		432,128			740,470			10,366
Repayment of long-term debt		(199,814	)		(579,131	)		(15,001	)
Proceeds from revolver		—			—			12,500
Repayment of revolver		—			—			(10,600	)
Payment of debt issuance costs		(789	)		(4,280	)		(2,939	)
Proceeds from derivative contracts		(11,063	)		(1,667	)		978
Unit issuance costs for IPO and other equity issuances		—			(381	)		(3,723	)
Net cash flow from IPO, including overallotment		—			—			248,067
Distributions of IPO proceeds to pre-IPO members		—			—			(245,067	)
Proceeds from equity issuances		—			331,500			—
Repurchase of common units		—			(154	)		—
Contribution by members		—			—			98,540
Distributions to members and affiliates		(117,646	)		(59,541	)		(22,033	)
Net cash provided by financing activities		102,816			426,816			71,088
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(50,636	)		57,971			(8,791	)
CASH AND CASH EQUIVALENTS—Beginning of period		68,552			10,581			19,372
CASH AND CASH EQUIVALENTS—End of period	$	17,916		$	68,552		$	10,581
Interest paid—net of amounts capitalized	$	29,822		$	40,948		$	30,657
Investments in property, plant and equipment not paid	$	2,242		$	2,297		$	2,981
Issuance of common units for acquisitions	$	24,236		$	307,017		$	20,280

See notes to consolidated financial statements.

F-5

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

	General Partner			Number of Common Units			Common Units			Number of Subordinated Units		Subordinated Units			Total
	($ in thousands, except unit amounts)
BALANCE—January 1, 2006	$	83			24,150,731		$	208,013			—	$	—		$	208,096
Net loss		(448	)		—			(15,229	)		—		(7,637	)		(23,314	)
Distributions		(287	)		—			(4,159	)		—		(12,587	)		(17,033	)
Conversion of common units to subordinated units		—			(20,691,495	)		(193,481	)		20,691,495		193,481			—
Issuance of common units—March 2006		—			3,922,930			98,540			—		—			98,540
Issuance of common units—March 2006		—			809,329			20,280			—		—			20,280
IPO and overallotment		4,883			12,500,000			37,144			—		206,039			248,066
Distribution of IPO proceeds		(4,824	)		—			(35,860	)		—		(204,383	)		(245,067	)
IPO offering costs		(74	)		—			(1,593	)		—		(2,056	)		(3,723	)
Advisory fee termination		120			—			2,567			—		3,313			6,000
Restricted units expense		3			—			61			—		78			142
BALANCE—December 31, 2006		(544	)		20,691,495			116,283			20,691,495		176,248			291,987
Equity issued to private investors		—			16,236,265			331,500			—		—			331,500
Equity issued in acquisitions		—			13,742,097			307,017			—		—			307,017
Distribution to affiliates		—			—			(421	)		—		—			(421	)
Unit issuance costs for IPO		—			—			(381	)		—		—			(381	)
Net loss		(2,329	)		—			(86,334	)		—		(56,971	)		(145,634	)
Distributions		(310	)		—			(51,627	)		—		(7,604	)		(59,541	)
Vesting of restricted units		—			37,190			—			—		—			—
Repurchase of common units		—			(7,400	)		(154	)		—		—			(154	)
Restricted unit expense		28			—			1,680			—		687			2,395
BALANCE—December 31, 2007		(3,155	)		50,699,647			617,563			20,691,495		112,360			726,768
Net Income		1,009			—			61,794			—		24,717			87,520
Distributions		(1,643	)		—			(82,588	)		—		(33,415	)		(117,646	)
Vesting of restricted units		—			162,302			—			—		—			—
Repurchase of common units		—			—			—			—		—			—
Equity-based  compensation		75			—			5,442			—		2,177			7,694
Distributions to affiliates		—			—			(857	)		—		—			(857	)
Equity issued in acquisitions		—			2,181,818			24,236			—		—			24,236
BALANCE—December 31, 2008	$	(3,714	)		53,043,767		$	625,590			20,691,495	$	105,839		$	727,715

See notes to consolidated financial statements.

F-6

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Eagle Rock Pipeline, L.P., a Texas limited partnership, is an indirect wholly-owned subsidiary of Eagle Rock Holdings, L.P. (“Holdings”). Holdings is a portfolio company of Irving, Texas based private equity capital firm, Natural Gas Partners. Eagle Rock Pipeline, L.P. was formed on November 14, 2005 for the purpose of owning a limited partnership interest in Eagle Rock Midstream Resources, L.P.

In May 2006, Eagle Rock Energy Partners, L.P., a Delaware limited partnership and an indirect wholly-owned subsidiary of Holdings, was formed for the purpose of completing a public offering of common units. On October 24, 2006, it offered and sold 12,500,000 common units in its initial public offering, or IPO, at a price of $19.00 per unit. Net proceeds from the sale of the units, $222.1 million after underwriting costs, were used for reimbursement of capital expenditures for investors prior to the initial public offering, replenish working capital, and a distribution arrearage payment. In connection with the initial public offering, Eagle Rock Pipeline, L.P. was merged with and into a newly-formed subsidiary of Eagle Rock Energy Partners, L.P. (“Eagle Rock Energy” or the “Partnership”).

Basis of Presentation and Principles of Consolidation—The accompanying financial statements include assets, liabilities and the results of operations of Eagle Rock Energy from October 24, 2006, and the results of operations of Eagle Rock Pipeline, L.P. for the periods prior to October 24, 2006. The reorganization of these entities was accounted for as a reorganization of entities under common control. The general partner of Eagle Rock Energy and Eagle Rock Midstream Resources, L.P. is Eagle Rock Energy GP, L.P., a wholly-owned subsidiary of Holdings. Eagle Rock Pipeline, L.P., Eagle Rock Midstream Resources, L.P. and their subsidiaries and, effective October 24, 2006, Eagle Rock Energy Partners, L.P. are collectively referred to as “Eagle Rock Energy” or the “Partnership.”

Description of Business—We are a growth-oriented limited partnership engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs, which we call our “Midstream” business; the business of acquiring, developing and producing interests in oil and natural gas properties, which we call our “Upstream” business; and the business of acquiring and managing fee minerals and royalty interests, which we call our “Minerals” business. The Partnership’s 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 on the Partnership’s pipelines or third party pipelines, is treated to remove contaminants and conditioned or processed into marketable natural gas and natural gas liquids. The Partnership conducts its midstream operations within Louisiana and three geographic areas of Texas. The Partnership’s Texas Panhandle Segment assets consist of assets acquired from ONEOK, Inc. on December 1, 2005, and include gathering and processing assets (“Texas Panhandle Segment”). The Partnership’s East Texas/Louisiana assets include a non-operated 25% undivided interest in a processing plant as well as a non-operated 20% undivided interested in a connected gathering system the (“East Texas/Louisiana Segment”). On April 7, 2006, the Partnership’s East Texas/Louisiana Segment completed the acquisition of a 100% interest in the Brookeland and Masters Creek processing plants in East Texas from Duke Energy Field Services and Swift Energy Corporation. On June 2, 2006, the Partnership’s Texas Panhandle Segment completed the acquisition of 100% of Midstream Gas Services, L.P. On May 3, 2007, the Partnership completed the acquisition of Laser Midstream Energy, L.P. (“Laser”) and certain of its subsidiaries (“Laser Acquisition”) (see Note 4). The Laser assets include gathering systems and related compression and processing facilities in South Texas, East Texas, and North Louisiana, now a part the Partnership's East Texas/Louisiana Segment and which created the Partnership's South Texas Segment.   On October 1, 2008, the Partnership completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”) (see Note 4).   The MMP assets include natural gas gathering and related compression and processing facilities in West Texas, Central Texas, East Texas, Southern Louisiana and the Gulf of Mexico that are now a part of the Partnership's East Texas/Louisiana Segment, South Texas Segment and which created the Partnership's Gulf of Mexico Segment.

With respect to our Minerals Business, we completed 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 Income Co-Investment Opportunities, L.P. (“Co-Invest”) (collectively, the “Montierra Acquisition”) on April 30, 2007 (see Note 4). As a result of this acquisition, our mineral assets include royalty interests located in multiple producing trends across the United States. The assets include interests in mineral acres and interests in wells. On June 18, 2007, we also completed the acquisition of certain assets owned by MacLondon Energy, L.P. (see Note 4), which include additional interests in wells in which the Partnership already owns a royalty interest as a result of the Montierra Acquisition.

F-7

On July 31, 2007, the Partnership entered the upstream business when it completed the acquisition of Escambia Asset Co., LLC and Escambia Operating Co., LLC (“the Escambia Acquisition”) (see Note 4). The assets subject to this transaction include operated wells in Escambia County, Alabama. The transaction also included two treating facilities, one natural gas processing plant and related gathering systems. Also on July 31, 2007, Eagle Rock Energy completed the acquisition 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. These transactions are collectively referred to as the “Redman Acquisition” (see Note 4). The assets conveyed in the Redman Acquisition included operated and non-operated wells mainly located in East and South Texas.  On April 30, 2008, the Partnership completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (“Stanolind”) (see Note 4).  The Stanolind assets include operated oil and natural gas producing properties in the Permian Basin, primarily in Ward, Crane and Pecos Counties, Texas.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. Eagle Rock Energy is the owner of a non-operating undivided interest in the Indian Springs gas processing plant and the Camp Ruby gas gathering system. 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.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.

Oil and Natural Gas Accounting Policies

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, including dry holes, 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. Statement of Financial Accounting Standards (“SFAS”) No. 19, Financial Accounting and Reporting for Oil and Gas Producing Companies 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.

Impairment of Oil and Natural Gas Properties

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 projection of future oil and natural gas reserves 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 amount of an asset exceeds the sum of the undiscounted estimated future net cash flows, the Partnership recognizes impairment expense equal to the difference between the carrying value and the fair value of the asset, which is estimated to be the expected present value of discounted future net cash flows from proved reserves utilizing the Partnership’s weighted average cost of capital. During the year ended December 31, 2008, the Partnership recorded impairment charges of $107.0 million and $1.7 million in its Upstream and Minerals Segments, respectively, as a result of substantial declines in commodity prices in the fourth quarter.  During the year ended December 31, 2007, the Partnership recorded an impairment charge in its Minerals segment of $5.7 million as a result of steeper decline rates in certain fields. The Partnership did not own any oil and gas properties during the year ended December 31, 2006 and, therefore, did not incur impairment charges during this period.  We cannot predict the amount of additional impairment charges that may be recorded in the future.

F-8

Unproved leasehold costs are reviewed periodically and a loss is recognized to the extent, if any, that the cost of the property has been impaired. Unproved properties that are individually insignificant are amortized. Unproved properties that are individually significant are assessed for impairment on a property-by-property basis. If considered impaired, costs are charged to expense when such impairment is deemed to have occurred.

Property Retirement Obligations

The Partnership is required to make estimates of the future costs of the retirement obligations of its producing oil and natural gas properties. This requirement necessitates that we make 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 changes in regulatory requirements, technological advances and other factors that may be difficult to predict.

Other Significant Accounting Policies

Cash and Cash Equivalents—Cash and cash equivalents include certificates of deposit or 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. During 2006, the Partnership increased the parties to which it was selling liquids and natural gas from two to seven. The Partnership further increased the number of parties to which it sells liquids and natural gas as a result of the acquisitions completed during 2007 and 2008. 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 credit 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 our allowance for doubtful accounts during the years ended December 31, 2008 and 2007.

Year	Description	Balance at beginning of period		Charged to bad debt expense		Write-offs/adjustments charged to allowance		Balance at end of period
2008	Allowance for doubtful accounts receivable	$	1,046	$	11,136	$	102	$	12,080
2007	Allowance for doubtful accounts receivable	$	—	$	1,046	$	—	$	1,046

 Of the $11.1 million charged to bad debt expense during the year ended December 31, 2008, $10.7 relates to outstanding receivables from SemGroup, L.P. which filed for bankruptcy in July 2008.  For further discussion, see Note 18.

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 37.0% of its natural gas supply in the Texas Panhandle Segment, 24.4% of its natural gas supply in the East Texas/Louisiana Segment, 48.8% of its natural gas supply in the South Texas Segment and in the Gulf of Mexico Segment, one customer accounted for 90% of its natural gas supply for the month of December 2008. 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 MMBtus gathered during the month of December 2008.

F-9

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 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 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:

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

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. During the year ended December 31, 2008, 2007 and 2006, the Partnership capitalized interest costs of approximately $0.4 million, $1.4 million and $0.4 million, respectively.

Impairment of Long-Lived Assets—Management evaluates whether the carrying value of 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 change 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.

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.  During the year ended December 31, 2008, the Partnership recorded an impairment charge related to certain processing plants, pipelines and contracts in its Midstream business of $35.1 million due to the substantial decline in commodity prices in the fourth quarter.

Goodwill—Goodwill acquired in connection with business combinations represent the excess of consideration over the fair value of tangible net assets and identifiable intangible assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired and liabilities assumed, as well as in determining the allocation of goodwill to the appropriate reporting unit.

The Partnership acquired goodwill as part of its acquisition of Redman (See Note 4 and Note 15) on July 31, 2007.  During the year ended December 31, 2008, goodwill increased by $1.4 million due to adjustments made to the Redman purchase price allocation.  The Partnership performed its annual impairment test in May 2008 and determined that no impairment appeared evident. The Partnership’s goodwill impairment test involves a comparison of the fair value of each of its reporting units with their carrying value. The fair value is determined using discounted cash flows and other market-related valuation models. Certain estimates and judgments are required in the application of the fair value models.  As a result of the impairment charge incurred within the Partnership’s Upstream Segment during the fourth quarter of 2008 which resulted from the substantial decline in commodity prices during the fourth quarter of 2008, the Partnership performed an assessment of its goodwill and recorded an impairment charge of $31.0 million, which reduced its goodwill amount to zero.

F-10

Other Assets— As of December 31, 2008, other assets primarily consist of costs associated with: debt issuance costs, net of amortization ($4.2 million); business deposits to various providers and state or regulatory agencies ($0.5 million); and investment in unconsolidated affiliates ($9.3 million). As of December 31, 2007, other assets primarily consist of costs associated with: debt issuance costs, net of amortization ($4.2 million); business deposits to various providers and state or regulatory agencies ($0.6 million); and investment in unconsolidated affiliates ($6.0 million).

Within the Partnership’s investments of unconsolidated non-affiliates, the Partnership owns 13.2%, 5.0% and 5.0% of the common units of Ivory Working Interests, L.P., Buckeye Pipeline, L.P. and Trinity River, LLC, respectively. The Partnership also owns a 50% joint venture in Valley Pipeline, LLC. These investments are accounted for under the equity method and as of December 31, 2008 are not considered material to the Partnership’s financial position or results of operations.

Transportation and Exchange Imbalances—In the course of transporting natural gas and natural gas liquids for others, the Partnership may receive for redelivery different quantities of natural gas or natural gas liquids 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 natural gas liquids 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, 2008, the Partnership had imbalance receivables totaling $0.3 million and imbalance payables totaling $2.8 million, respectively. For the Midstream Business, as of December 31, 2007, the Partnership had imbalance receivables totaling $0.2 million and imbalance payables totaling $2.7 million, respectively. 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.

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 and condensate;

• 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;

• NGL transportation from which we generate revenues from transportation fees; and

• royalties, overriding royalties and lease bonuses.

Revenues associated with sales of natural gas, NGLs, crude oil and condensate 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 when the service is provided.

For gathering and processing services, Eagle Rock Energy either receives fees or commodities from natural gas producers depending on the type of contract. Under the percentage-of-proceeds contract type, Eagle Rock Energy is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the keep-whole contract type, Eagle Rock Energy purchases wellhead natural gas and sells processed natural gas and NGLs to third parties.

Transportation, compression and processing-related revenues are recognized in the period when the service is provided and include the Partnership’s fee-based service revenue for services such as transportation, compression and processing.

The Partnership’s Upstream Segment recognizes revenues based on actual volumes 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. Material imbalances are reflected as adjustments to reported natural gas reserves and future cash flows.  As of December 31, 2008, the Partnership had an imbalance receivable balance of $3.5 million and an imbalance payable balance of $0.2 million.

A significant portion of the Partnership’s sale and purchase arrangements are accounted for on a gross basis in the consolidated statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements which establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location at the same or at another specified date. These arrangements are detailed either jointly, in a single contract, or separately in individual contracts which are entered into concurrently or in contemplation of one another with a single or multiple counterparties. Both transactions require physical delivery of the natural gas and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk. In accordance with the provision of Emerging Issues Task Force Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty (“EITF 04-13”), the Partnership reflects the amounts of revenues and purchases for these transactions as a net amount in its consolidated statements of operations beginning with April 2006. For the years ended December 31, 2008 and 2007, the Partnership did not enter into any purchase and sale agreements with the same counterparty.

F-11

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 our 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. and Eagle Rock Upstream Development Company, Inc., both of which are consolidated subsidiaries of ours. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our 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, our tax status in the State of Texas changed from non-taxable to taxable effective with the 2007 tax year.

Since we are structured as a pass-through entity, we are not subject to federal income taxes. As a result, our partners are individually responsible for paying federal and certain income taxes on their share of our taxable income. Since we do not have access to information regarding each partner’s tax basis, we cannot readily determine the total difference in the basis of our net assets for financial and tax reporting purposes.

In accordance with Financial Accounting Standards Board Interpretation 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), we must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized upon settlement. This guidance was effective January 1, 2007, and our adoption of this guidance had no material impact on our financial position, results of operations or cash flows. See Note 15 for additional information regarding our income taxes.

Derivatives—SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (“SFAS No. 133”), establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 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. SFAS No. 133 provides that normal purchase and normal sale contracts, when appropriately designated, are not subject to the statement. Normal purchases and normal 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 sales. Substantially all forward contracts fall within a one-month to four-year term; however, the Partnership does have certain contracts which extend through the life of the dedicated production. The terms of these contracts generally preclude unplanned netting. The Partnership uses financial instruments such as puts, swaps 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.

Reclassifications—Prior periods have been reclassified to conform to current period presentation to reflect taxes other than income as a separate financial statement line item on the Statement of Operations.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). This statement defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007.  SFAS No.157, as it relates to financial assets and financial liabilities, was effective for the Partnership on January 1, 2008 and had no material impact on our consolidated results of operations or financial position.

F-12

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”), which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 was effective for us as of January 1, 2008 and had no impact, as we have elected not to fair value additional financial assets and liabilities.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS No. 141R”), which replaces SFAS No. 141.  SFAS 141R requires that all assets, liabilities, contingent consideration, contingencies and in-process research and development costs of an acquired business be recorded at fair value at the acquisition date; that acquisition costs generally be expensed as incurred; that restructuring costs generally be expensed in periods subsequent to the acquisition date; and that changes in accounting for deferred tax asset valuation allowances and acquired income tax uncertainties after the measurement period impact income tax expense.  SFAS No. 141R is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, with the exception for the accounting for valuation allowances on deferred tax assets and acquired tax contingencies associated with acquisitions.  SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes, such that adjustments made to valuation allowances on deferred taxes and acquired tax contingencies associated with acquisitions that closed prior to the effective date of SFAS No. 141R would also apply the provisions of SFAS No. 141R.  The impact of the adoption of SFAS No. 141R on the Partnership’s consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 (“SFAS No. 160”). SFAS No.160 requires that accounting and reporting for minority interests will be re-characterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This Statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. The Partnership has not yet determined the impact, if any, that SFAS No. 160 will have on its financial statements.   The Partnership does not expect the adoption of SFAS No. 160 to have a material impact on its consolidated financial statements.

In March 2008, the FASB issued Statement No. 161, Disclosures About Derivative Instruments and Hedging Activities (“SFAS No. 161”). SFAS No. 161 requires enhanced disclosures to help investors better understand the effect of an entity’s derivative instruments and related hedging activities on its financial position, financial performance, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged.  The Partnership does not expect the adoption of SFAS No. 161 to have a material impact on its consolidated financial statements.

In March 2008 the FASB approved EITF Issue No. 07-4,  Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships (“EITF Issue No. 07-4”), which requires that master limited partnerships use the two-class method of allocating earnings to calculate earnings per unit. EITF Issue No. 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008. The Partnership is evaluating the effect that EITF Issue No. 07-4 will have on its earnings per unit calculation and consolidated financial statements. 

In April 2008, the FASB issued FASB Staff Position (“FSP”) No. SFAS 142-3, Determination of the Useful Life of Intangible Assets (“FSP SFAS 142-3”).  FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS 142”).  The intent of FSP SFAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R (revised 2007), Business Combinations (“SFAS 141R”) and other applicable accounting literature.  FSP SFAS 142-3 is effective for financial statements issued forfiscal years beginning after December 15, 2008 and must be applied prospectively to intangible assets acquired after the effective date.  The impact of the adoption of FSP SFAS 142-3 on the Partnership’s consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009. 

In May 2008, the FASB issued SFAS No. 162, Hierarchy of Generally Accepted Accounting Principles (“SFAS 162”).  This statement is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with GAAP.  This statement will be effective 60 days following the U.S. Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board amendment to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.  The Partnership does not expect the adoption of SFAS 162 to have a material impact on its consolidated financial statements.  

F-13

In June 2008, the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”).  FSP EITF 03-6-1 affects entities that accrue cash dividends on share-based payment awards during the awards’ service period when dividends do not need to be returned if the employees forfeit the awards.  FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008 and earnings-per-unit calculations would need to be adjusted retroactively.  The Partnership is evaluating the effect that FSP EITF 03-6-1 will have on its earnings per unit calculation and consolidated financial statements.

In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling will become effective for disclosures in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009.

NOTE 4. ACQUISITIONS

2008 Acquistions

Stanolind Acquisition.  On April 30, 2008, the Partnership completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (“Stanolind”), for an aggregate purchase price of $81.9 million, subject to working capital and other purchase price adjustments (the “Stanolind Acquisition”). One or more Natural Gas Partners’ (“NGP”) private equity funds, which directly or indirectly owned a majority of the equity interests in Stanolind, is an affiliate of the Partnership and is the majority owner of the sole owner of Eagle Rock Energy G&P, LLC (the “Company”), which is the general partner of Eagle Rock Energy GP, L.P., which is the general partner of the Partnership.  The Partnership funded the transaction from borrowings under its existing credit facility as well as existing cash from operations.  Stanolind owned and operated oil and natural gas producing properties in the Permian Basin, primarily in Ward, Crane and Pecos Counties, Texas.

The purchase price was allocated on a preliminary basis to acquired assets and liabilities assumed based on their respective fair value as determined by management.  The Partnership recorded the Stanolind acquisition under the guidance of Staff Accounting Bulletin Topic 2D, Financial Statements of Oil and Gas Exchange Offers (“Topic 2D”). In accordance with Topic 2D, the Partnership has recorded the interest attributable to the ownership of NGP in Stanolind at their carryover basis. Those interests not attributable to NGP have been recorded at their fair value.  As a result, the Partnership recorded $0.9 million of the net cash paid in excess of the carryover basis as a distribution to NGP for the Stanolind acquisition.

F-14

The preliminary purchase price allocation is set forth below.

	($ in thousands)
Oil and gas properties:
Proved properties	$	110,747
Unproved properties		7,597
Cash and cash equivalents		537
Accounts receivable		4,561
Other assets		459
Accounts payable and accrued liabilities		(4,948	)
Risk management liabilities		(2,865	)
Deferred income taxes		(27,468	)
Asset retirement obligations		(4,770	)
Other long-term liabilities		(2,825	)
Total purchase price allocation		81,025
Distribution to NGP		857
Total Consideration Paid	$	81,882

The Partnership commenced recording results of operations with regard to Stanolind on May 1, 2008.  

Due to the potential conflict of interest between the interests of the Company and the public unitholders of Eagle Rock Energy, as a result of one or more NGP private equity funds directly or indirectly owning a majority of the equity interests in Eagle Rock Energy and Stanolind, the Board of Directors authorized the Company’s Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Stanolind Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Stanolind Acquisition was fair and reasonable to Eagle Rock Energy and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In considering the fairness of the Stanolind acquisition, the Conflicts Committee considered the valuation of the assets and liabilities involved in the transaction and the cash flow of Stanolind. Based on the recommendation of management and the Conflicts Committee, the Board of Directors approved the transaction.

Millennium Acquisition. On October 1, 2008, the Partnership completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”) for an aggregate purchase price of $205.2 million, comprised of approximately $181.0 million in cash and 2,181,818 (recorded value of $24.2 million) common units, subject to post closing purchase price adjustments (the “Millennium Acquisition”).  The cash portion of the consideration was funded through borrowings of $176.4 million under the Partnership’s Revolving Credit Facility made prior to September 30, 2008 and cash on hand.  MMP is in the natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana.  With respect to the South Louisiana assets acquired in the Millennium Acquisition, the Yscloskey and North Terrebonne facilities were flooded with three to four feet of water as a result of the storm surges caused by Hurricanes Ike and/or Gustav.  The Partnership has reported, is preparing to file claims for, and expects to receive payment on physical damage and its business interruption insurance coverage related to Hurricane Ike and Gustav’s damage to these two facilities. The timing of collection of such insurance claims is unknown at this time.  The North Terrebonne facility came back on-line in November 2008 and the Yscloskey facility came back on-line in January 2009.  The former owners of MMP provided the Partnership indemnity coverage for Hurricanes Ike and Gustav to the extent losses are not covered by insurance and established an escrow account of 1,818,182 common units and $0.6 million in cash available for the Partnership to recover against for this purpose.  Prior to December 31, 2008, the Partnership recovered 40,880 units and $0.3 million in cash from this escrow account.  As of March 6, 2009, the Partnership has recovered an additional 65,841 common units and the remaining $0.3 million in cash from the escrow account.

F-15

The purchase price was allocated, excluding amounts held in escrow, on a preliminary basis to assets acquired and liabilities assumed, based on their respective fair value as determined by management with the assistance of K.E. Andrews & Company, a third-party valuation specialist.  The Millennium Acquisition was accounted for as a purchase in accordance with SFAS No. 141, Business Combinations (“SFAS No. 141).  The preliminary purchase price allocation is set forth below.

	($ in thousands)
Property, plant and equipment	$	189,753
Intangibles, right-of-way and contracts		28,371
Cash and cash equivalents		38
Accounts receivable		19,130
Other current assets		1,188
Derivatives		89
Other current liabilities		(24,650	)
Other current liabilities		(3,103	)
Asset retirement obligations		(2,490	)
Minority interest		(1,346	)
Other liabilities		(1,749	)
	$	205,231

The Partnership commenced recording results of operations with regard to MMP on October 2, 2008.

2007 Acquisitions

Montierra Acquisition. On April 30, 2007, the Partnership acquired (through part entity purchase and part asset purchase in the Montierra Acquisition) certain fee mineral acres, royalty and overriding royalty interests in oil and natural gas producing wells from Montierra (a Natural Gas Partners VII, L.P. portfolio company) and Co-Invest (a Natural Gas Partners affiliate). Eagle Rock Energy paid consideration that totaled 6,458,946 (recorded value of $133.8 million) of our common units and $5.4 million of cash. As part of this transaction, a 39.34% economic interest in the incentive distribution rights was conveyed from Eagle Rock Holdings, L.P. to Montierra.

The Partnership recorded the Montierra Acquisition under the guidance of Staff Accounting Bulletin Topic 2D, Financial Statements of Oil and Gas Exchange Offers (“Topic 2D”). In accordance with Topic 2D, the Partnership has recorded the interest attributable to the ownership of Natural Gas Partners in Montierra at their carryover basis. Those interests not attributable to Natural Gas Partners have been recorded at their fair value.

The purchase price was allocated to assets acquired and liabilities assumed based on their respective fair value as determined by management. The purchase price allocation is set forth below.

	($ in thousands)
Oil and gas properties
Proved properties	$	66,884
Unproved properties		65,855
Cash and cash equivalents		936
Accounts receivable		3,267
Prepayments		15
Accounts payable and accrued liabilities		(1,671	)
Risk management liabilities		(759	)
Investment in unconsolidated affiliates		4,694
	$	139,221

The Partnership commenced recording results of operations with regard to Montierra on May 1, 2007.

One or more NGP private equity funds directly or indirectly owned a majority of the equity interests in Eagle Rock and Montierra. Because of the potential conflict of interest between the interests of the Company and the public unitholders of Eagle Rock, the Board of Directors authorized the Company’s Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Montierra Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Montierra Acquisition was fair and reasonable to Eagle Rock and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In considering the fairness of the Montierra Acquisition, the Conflicts Committee 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 flow of Montierra. Based on the recommendation of the Conflicts Committee, the Board of Directors approved the transaction.

F-16

Laser Acquisition. On May 3, 2007, Eagle Rock Energy Partners, L.P. acquired certain entities from Laser Midstream Energy II, LP, a Delaware limited partnership, and Laser Midstream Company, LLC, a Texas limited liability company. The Partnership paid total consideration of $113.4 million in cash and 1,407,895 (recorded value of $29.2 million) of our common units. The assets subject to the transaction include gathering systems and related compression and processing facilities in south Texas, east Texas and north Louisiana.

The purchase price was allocated to assets acquired and liabilities assumed based on their respective fair value as determined by management with the assistance of K.E. Andrews & Company, a third-party valuation specialist. The Laser acquisition was accounted for as a purchase in accordance with SFAS No. 141, Business Combinations. The purchase price allocation is set forth below.

	($ in thousands)
Property, plant and equipment	$	98,883
Intangibles, right-of-way and contracts		39,057
Cash and cash equivalents		1,823
Accounts receivable		44,136
Other current assets		1,713
Accounts payable		(42,639	)
Other current liabilities		(376	)
	$	142,597

The Partnership commenced recording results of operations with regard to Laser on May 1, 2007.

MacLondon Acquisition. On June 18, 2007, the Partnership acquired from MacLondon Energy, L.P. (“MacLondon”) certain mineral royalty and overriding royalty interests in which the Partnership already owned an interest as a result of the Montierra Acquisition. MacLondon Energy, L.P.’s assets were acquired for total consideration of $18.2 million, consisting of 757,065 (recorded value of $18.1 million) common units and cash of approximately $0.1 million. The Partnership commenced recording results of operations with regard to MacLondon on July 1, 2007.

EAC Acquisition. On July 31, 2007, the Partnership completed the acquisition of Escambia Asset Co., LLC and Escambia Operating Co., LLC (the “EAC Acquisition”). Upon closing, the Partnership paid total consideration of $224.6 million in cash and 689,857 (recorded value of $17.2 million) in common units, subject to adjustment. The assets subject to the EAC Acquisition include operated productive wells in Escambia County, Alabama, two associated treating facilities, one associated natural gas processing plant and related gathering systems.

The purchase price was allocated to assets acquired and liabilities assumed, based on their respective fair value as determined by management with the assistance of K.E. Andrews & Company, a third-party valuation specialist. The EAC Acquisition was accounted for as a purchase in accordance with SFAS No. 141, Business Combinations. The purchase price allocation is set forth below.

	($ in thousands)
Oil and gas properties
Proved Properties	$	210,082
Plant and related assets		25,246
Cash and cash equivalents		4,679
Accounts receivable		21,052
Derivative contracts-fair value		107
Intangibles		725
Accounts payable		(11,694	)
Accrued liabilities		(1,865	)
Asset retirement obligations		(6,507	)
	$	241,825

The Partnership commenced recording results of operations with regard to EAC on August 1, 2007.

F-17

Redman Acquisition. On July 31, 2007, Eagle Rock completed the acquisition of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. (Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. portfolio companies, respectively) and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (a Natural Gas Partners affiliate (the “Redman Acquisition”). Upon closing, the Partnership paid, as consideration, a total of 4,428,334 (recorded value of $108.2 million) common units and $84.6 million in cash.

The purchase price was allocated to assets acquired and liabilities assumed based on their respective fair value as determined by management. Goodwill acquired in the acquisition was the result of deferred tax liability relating to book/tax differences created as a result of the acquisition (See Note 15) and due to the increase in the price of the Partnership’s common units from the time the acquisition was negotiated to when the acquisition was recorded. The acquisition of Redman was accounted for as a purchase in accordance with Topic 2D. Those interests not attributable to Natural Gas Partners have been recorded at their fair value. In accordance with Topic 2D, the Partnership has recorded the interest attributable to the ownership of Natural Gas Partners in Redman at their carryover basis and as a result the Partnership recorded $0.4 million of the net cash paid in excess of the carryover basis as a distribution to Natural Gas Partners for the Redman Acquisition. Those interests not attributable to Natural Gas Partners have been recorded at their fair value.

The purchase price was allocated to assets acquired and liabilities assumed based on their respective fair value as determined by management. The purchase price allocation is set forth below.

	($ in thousands)
Oil and gas properties
Proved Properties	$	169,357
Cash and cash equivalents		12,975
Accounts receivable, net		5,932
Prepayments		573
Risk management assets		1,002
Other assets		2,077
Goodwill		29,527
Accounts payable		(8,427	)
Deferred tax payable		(16,826	)
Other long-term liabilities		(3,384	)
	$	192,806

The Partnership commenced recording results of operations with regard to Redman on August 1, 2007.

One or more NGP private equity funds directly or indirectly owned a majority of the equity interests in Eagle Rock and the Redman entities. Because of the potential conflict of interest between the interests of the Company and the public unitholders of Eagle Rock, the Board of Directors authorized the Company’s Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Redman Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Redman Acquisition was fair and reasonable to Eagle Rock and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In considering the fairness of the Redman Acquisition, the Conflicts Committee 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 flow of Redman. Based on the recommendation of the Conflicts Committee, the Board of Directors approved the transaction.

2006 Acquisitions

Brookeland and Masters Creek Acquisitions. On March 31, 2006, the Partnership’s East Texas/Louisiana System completed the acquisition of an 80% interest in the Brookeland gathering and processing facility, a 76.3% interest in the Masters Creek gathering system and 100% of the Jasper NGL line for $75.7 million to solidify the Partnership’s East Texas/Louisiana Segment and to integrate with the segment’s existing operations. The Partnership commenced recording these results of operations on April 1, 2006. On April 7, 2006, the remaining interests were acquired for $20.2 million and the results of operations have been recorded effective as of April 1, 2006, as results of operations for the period April 1, 2006 to April 7, 2006, were not material. The purchase price was allocated to property, plant and equipment and intangibles in the amounts of $88.8 million and $7.9 million, respectively, based on their respective fair value as determined by management with the assistance of a third-party valuation specialist. In addition to long-term assets, the Partnership assumed certain accrued liabilities. The purchase price has been allocated as presented below.

F-18

	($ in thousands)
Property, plant, and equipment	$	88,858
Intangibles		7,992
Other current liabilities		(750	)
Asset retirement obligations		(291	)
	$	95,809

Midstream Gas Services, L.P. Acquisition. On June 2, 2006, the Partnership purchased Midstream Gas Services, L.P. (“MGS”) from a Natural Gas Partners affiliate for $4.7 million in cash and 809,174 (recorded value of $20.3 million) in common units to integrate with the Texas Panhandle Systems’ existing operations. The Partnership would have issued up to 798,113 common units to the previous equity owner of MGS, as a contingent earn-out payment if MGS achieved certain financial objectives for the year ending December 31, 2007. These financial objectives were not achieved. The Partnership commenced recording the results of operations on June 2, 2006.

The following pro forma information for the years ended December 31, 2008 and 2007, assumes the Stanolind,  Millennium, Laser, Montierra, EAC and Redman acquisitions had been acquired by Eagle Rock Energy on January 1, 2008 and 2007, respectively (unaudited):

	December 31, 2008			December 31, 2007
	($ in thousands, except per unit amounts)
Revenues	$	1,972,495		$	1,148,240
Costs and expenses		1,820,644			1,224,543
Operating (loss) income		151,851			(76,303	)
Other expense, net		69,125			78,864
Income tax provision		(2,202	)		(4,080	)
Net income (loss)	$	84,928		$	(151,087	)
Net income (loss) per common unit	$	1.16		$	(2.20	)

NOTE 5. PROPERTY PLANT AND EQUIPMENT AND ASSET RETIREMENT OBLIGATIONS

Fixed assets consisted of the following:

	December 31, 2008			December 31, 2007
	($ in thousands)
Land	$	1,211		$	1,153
Plant		232,219			156,092
Gathering and pipeline		653,016			541,247
Equipment and machinery		18,672			14,081
Vehicles and transportation equipment		3,958			3,657
Office equipment, furniture, and fixtures		1,023			1,023
Computer equipment		4,714			4,636
Corporate		126			126
Linefill		4,269			4,157
Proved properties		515,452			487,481
Unproved properties		73,622			66,023
Construction in progress		39,498			20,884
		1,547,780			1,300,560
Less: accumulated depreciation, depletion and amortization		(190,171	)		(93,430	)
Net property plant and equipment	$	1,357,609		$	1,207,130

F-19

Depreciation expense for the years ended December 31, 2008, 2007 and 2006 was approximately $44.1 million, $41.1 million, and $27.4 million respectively. Depletion expense for the year ended December 31, 2008 and 2007 was approximately $52.8 million and $21.7 million, respectively. The Partnership did not own oil and natural gas properties in 2006 or 2005 and, therefore, did not incur depletion expense during these periods.  During the year ended December 31, 2008, the Partnership recorded impairment charges related to its plants and gathering and pipeline assets and proved properties of $4.3 million, $19.5 million and $108.8 million, respectively.  During the year ended December 31, 2007, the Partnership recorded impairment charges of $5.7 million related to its proved properties.  During the year ended December 31, 2006, the Partnership did not record any impairment charges to its property plant and equipment.

Asset Retirement Obligations—The Partnership recognizes asset retirement assets for its oil and gas working interests in accordance with FASB Statement No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”). SFAS 143 applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. SFAS 143 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. The Partnership recognizes asset retirement obligations for its midstream assets in accordance with FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation”, as used in SFAS No. 143, Accounting for Asset Retirement Obligations, 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 our 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, we are required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated.

A reconciliation of our liability for asset retirement obligations is as follows:

	2008		2007		2006
	($ in thousands)
Asset retirement obligations—January 1	$	11,337	$	1,819	$	679
Additional liability on newly constructed assets		204		325		17
Additional liability related to acquisitions		7,260		8,722		297
Revisions		—		—		698
Accretion expense		1,071		471		128
Asset retirement obligations—December 31	$	19,872	$	11,337	$	1,819

NOTE 6. INTANGIBLE ASSETS

Intangible assets consist of right-of-ways and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. Amortization expense was approximately $19.9 million $17.8 million and $15.8 million for the years ended December 31, 2008, 2007 and 2006, respectively. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2009—$22.9 million; 2010—$21.9 million; 2011—$11.2 million; 2012—$11.2 million; and 2013—$10.1 million. Intangible assets consisted of the following (as of December 31, 2008 and 2007):

	December 31, 2008			December 31, 2007
	($ in thousands)
Rights-of-way and easements—at cost	$	89,203		$	80,069
Less: accumulated amortization		(11,437	)		(7,274	)
Contracts		119,743			108,772
Less: accumulated amortization		(43,303	)		(27,619	)
Net intangible assets	$	154,206		$	153,948

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The amortization period for our rights-of-way and easements is 20 years. The amortization period for contracts range from 5 to 20 years, and are approximately 8 years on average as of December 31, 2008.  During the year ended December 31, 2008, the Partnership recorded impairment charges related to its Right-of-way and easements and contracts of $3.7 million and $7.6 million, respectively.  During the years ended December 31, 2007 and 2006, the Partnership did not record any impairment charges related to its intangible assets.

NOTE 7. LONG-TERM DEBT

Long-term debt consisted of:

	December 31, 2008		December 31, 2007
	($ in thousands)
Revolver	$	799,383	$	567,069
Total debt		799,383		567,069
Less: current portion		—		—
Total long-term debt	$	799,383	$	567,069

On December 13, 2007, the Partnership entered into a new senior secured revolving credit facility (the “Revolving Credit Facility”) with aggregate commitments of $800 million. During the year ended December 31, 2008, the Partnership exercised $180 million of its $200 million accordion feature of the Revolving Credit Facility, which increased the total commitment to $980 million.  The Revolving Credit Facility was entered into with a syndicate of commercial and investment banks, led by Wachovia Capital Markets, LLC and Bank of America Securities LLC as joint lead arrangement agents and joint book runners. The Revolving Credit Facility provides for $980 million aggregate principal amount of revolving commitments and has a maturity date of December 13, 2012. The Revolving Credit Facility provides the Partnership with the ability to potentially increase the total amount of revolving commitments by an additional $20 million to a total of $1 billion.  Subsequently, as a result of Lehman Brothers’ bankruptcy filing, the amount of available commitments was reduced by the unfunded portion of Lehman Brother’s commitment in an amount of approximately $9.1 million to a total of $970.9 million.

Upon entering into the Revolving Credit Facility, the Partnership drew approximately $567 million from the revolving commitments to repay its then outstanding indebtedness under its previously existing credit facility of approximately $561 million and pay accrued interest of approximately $6 million. In addition, during the year ended December 31, 2007, the Partnership recorded a $6.2 million charge to other expense to write off unamortized debt issuance costs related to its previous credit facility. In connection with the closing of the Revolving Credit Facility, the Partnership incurred debt issuance costs of $4.3 million.  During the year ended December 31, 2008, the Partnership incurred an additional $0.8 million of debt issuance costs in connection with exercising the accordion feature of the Revolving Credit Facility.  During the years ended December 31, 2008, 2007 and 2006, the Partnership recorded approximately $1.0 million, $1.8 million and $1.2 million of debt issuance amortization expense, respectively. As of December 31, 2008 the unamortized amount of debt issuance cost was $4.2 million.

The Revolving Credit Facility includes a sub-limit for the issuance of standby letters of credit for a total of $200 million. At December 31, 2008, the Partnership had $0.2 million of outstanding letters of credit.

In certain instances defined in the Revolving Credit Facility, the Partnership’s outstanding debt is subject to mandatory repayments and/or is subject to a commitment reduction for asset and property sales, reductions in borrowing base and for insurance/condemnation proceeds.

The Revolving Credit Facility contains various covenants which limit the Partnership’s ability to grant liens, make certain loans and investments; make certain capital expenditures outside the Partnership’s current lines of business or certain related lines of business; make distributions other than from available cash; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Partnership’s assets. Additionally, the Revolving Credit Facility limits the Partnership’s ability to incur additional indebtedness with certain exceptions and purchase money indebtedness and indebtedness related to capital or synthetic leases not to exceed 2.5% of tangible net worth.

The Revolving Credit Facility also contains covenants, which, amount other things, require the Partnership, on a consolidated basis, to maintain specified ratios or conditions as follows:

• Consolidated EBITDA (as defined) to Consolidated Interest Expense (as defined) of not less than 2.5 to 1.0;

• Total Funded Indebtedness (as defined) to Adjusted Consolidated EBITDA (as defined) of not more than 5.0 to 1.0 (5.25 to 1.0 for the three quarters following a material acquisition); and

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• Borrowing Base Indebtedness (as defined) not to exceed the Borrowing Base (as defined) as re-determined from time to time.

The Partnership’s credit facility accommodates, through the use of a  borrowing base for our Upstream Business and traditional cash-flow based covenants for our Midstream and Minerals Businesses, the allocation of indebtedness to either our Upstream Business (to be measured against the borrowing base) or to our Midstream and Minerals Businesses (to be measured against the cash-flow based covenant).  At December 31, 2008, we were in compliance with our covenants under the credit facility. Our interest coverage ratio, as defined in the credit agreement (i.e., Consolidated EBITDA divided by Consolidated Interest Expense), was 6.6 as compared to a minimum interest coverage covenant of 2.5, and our leverage ratio, as defined in the credit agreement (i.e., Total Funded Indebtedness divided by Adjusted Consolidated EBITDA), was 3.7 as compared to a maximum leverage ratio of 5.0 times (5.25 times until March 31, 2009 due to the Millennium Acquisition).  As of December 31, 2008, the borrowing base for our Upstream Business was determined at $206 million.  As a result of the current commodity price environment and depressed economic activity, which will negatively impact our financial results going forward we expect that our borrowing base will be re-determined in early April 2009 to a lower amount (resulting in a higher allocation of indebtedness to our Midstream and Minerals Businesses) and a rise in our leverage ratio in 2009.  This may cause us to take steps to reduce our leverage or enhance our Adjusted Consolidated EBITDA, as defined in our credit facility.

Based upon the above mentioned ratios and conditions as calculated as of December 31, 2008, the Partnership has approximately $171.5 million of unused capacity under the Revolving Credit Facility at December 31, 2008 on which the Partnership pays a 0.3% commitment fee per year.

At the Partnership’s election, its outstanding indebtedness bears interest on the unpaid principal amount either at a base rate plus the applicable margin (currently 0.75% per annum based on the Partnership’s total leverage ratio and utilization of its borrowing base as part of its total indebtedness); or at the Adjusted Eurodollar Rate plus the applicable margin (currently 1.75% per annum based on the Partnership’s total leverage ratio and utilization of its borrowing base as part of its total indebtedness). At December 31, 2008, the weighted average interest rate on our outstanding debt balance was 5.76%.

Base rate interest loans are paid the last day of each March, June, September and December. Eurodollar Rate Loans are paid the last day of each interest period, representing one-, two-, three-, six-, nine- or twelve months, as selected by the Partnership. The Partnership pays a commitment fee equal to (1) the average of the daily differences between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding loans times (2) 0.30% per annum, based on our current leverage ratio and borrowing base utilization. The Partnership also pays a letter of credit fee equal to (1) the applicable margin for revolving loans which are Eurodollar Rate loans times (2) the average aggregate daily maximum amount available to be drawn under all such Letters of Credit (regardless of where any conditions for drawing could then be met and determined as of the close of business on any date of determination). Additionally, the Partnership pays a fronting fee equal to 0.125% per annum, times the average aggregate daily maximum amount available to be drawn under all letters of credit.

The obligation under the Revolving Credit Facility are secured by first priority liens on substantially all for the Partnership’s assets, including a pledge of all of the capital stock of each of its subsidiaries.

Scheduled maturities of long-term debt as of December 31, 2008, were as follows:

	Principal Amount
	($ in thousands)
2009	$	—
2010		—
2011		—
2012		799,383
	$	799,383

The Partnership was in compliance with the financial covenants under the Revolving Credit Facility as of December 31, 2008. If an event of default existed under the Amended Revolving Credit Facility, the lenders would be able to accelerate the maturity of the Revolving Credit Facility and exercise other rights and remedies.

NOTE 8. MEMBERS’ EQUITY

At December 31, 2005, the Partnership had common units outstanding representing 98.01% of limited partnership interests and 1.99% of general partner interests, all of which were controlled by Holdings. On March 27, 2006, the Partnership sold 5,455,050 common units in a private placement for $98.3 million and converted the 98.01% limited partnership interest into 33,582,918 subordinated units. In June 2006, the Partnership issued 1,125,416 common units in connection with the MGS acquisition. At the initial public offering, the pre-IPO common units outstanding were converted into publicly traded common units using a factor of approximately 0.7191. Additionally, Holdings contributed $0.2 million in cash during 2006. For the initial public offering, the Partnership issued 12.5 million common units. The overallotment option was exercised by the underwriters in November 2006 with 1,463,785 common units being issued from common units acquired by the Partnership from Holdings and selected private investors. The exercise of the overallotment did not result in additional shares being issued by the Partnership.

F-22

Additionally, during the fourth quarter of 2006, Holdings paid $6.0 million to terminate the advisory fee arrangement with Natural Gas Partners. The expense was recorded on the Partnership’s financial results of operations with the offset to members’ equity.

On August 15, 2006, the Partnership declared and paid a distribution of $1.9 million to its common unit holders. As of September 30, 2006, the Partnership was in arrears on its subordinated units and general partner units in the amount of $10.7 million and $0.3 million, respectively for the second quarter of 2006. The arrearages were declared and paid at the time of the initial public offering. The IPO net cash received was $222.1 million, including $3.0 million for initial public offering transaction costs reimbursement to the Partnership. Distributions of $219.1 million were made in the fourth quarter for capital expenditure and working capital reimbursements and distribution arrearages. On November 14, 2006, the Partnership distributed $14.4 million from its third quarter 2006 results. This distribution was made to the unitholders on record as of September 30, 2006. In November, the Partnership received net cash of $26.0 million for the exercise of the overallotment by the underwriters. This amount was used to buy common units from Holdings and certain Pre-IPO investors.

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

Quarter Ended	Distribution per Unit			Record Date	Payment Date
December 31, 2006+	$	0.2679	(1)	Feb. 7, 2007	Feb. 15, 2007
March 31, 2007+	$	0.3625		May 7, 2007	May 15, 2007
June 30, 2007+	$	0.3625		Aug. 8, 2007	Aug. 14, 2007
September 30, 2007	$	0.3675		Nov. 8, 2007	Nov. 14, 2007
December 31, 2007	$	0.3925		Feb. 11, 2008	Feb. 14, 2008
March 31, 2008	$	0.4000		May 9, 2008	May 15, 2008
June 30, 2008	$	0.4100		Aug. 8, 2008	Aug. 14, 2008
September 30, 2008	$	0.4100		Nov. 7, 2008	Nov. 14, 2008
December 31, 2008	$	0.4100		Feb. 10, 2009	Feb. 13, 2009

__________

(1) Represents a prorated distribution to the common unitholders from the IPO date of October 24, 2006 through December 31, 2006.

+ The distribution per unit represents distributions made only on common units.

Subordinated units represent limited partner interests in the Partnership, and holders of subordinated units exercise the rights and privileges available to unitholders under the Partnership’s agreement of limited partnership. Subordinated units, during the subordination period, will generally receive quarterly cash distributions only when the common units have received a minimum quarterly distribution of $0.3625 per common unit. Subordinated units will convert into common units on a one-for-one basis when the subordination period ends. Pursuant to the Partnership’s agreement of limited partnership, the subordination period will extend to the earliest date following September 30, 2009 for which there does not exist any cumulative common unit arrearage and other conditions pursuant to the partnership agreement have been met.

On May 3, 2007, the Partnership completed the private placement of 7,005,495 common units among a group of institutional investors for gross proceeds of $127.5 million. The proceeds from the private offering were used to fully fund the cash portion of the purchase price of the Laser Acquisition. The offering closed contemporaneously with the Laser Acquisition.

On July 31, 2007, the Partnership entered into a common unit purchase agreement to sell in a private placement 9,230,770 common units to third-party investors for total cash proceeds of approximately $204.0 million. The private placement closed contemporaneously with the EAC and Redman Acquisitions on July 31, 2007.

At December 31, 2008, there were 53,043,767 common units (exclusive of restricted unvested common units and common units held in escrow related to the Millennium Acquisition), 20,691,495 subordinated units (all subordinated units are owned by Holdings) and 844,551 general partner units outstanding. In addition, there were 905,486 restricted unvested common units outstanding.

As of December 31, 2008, 2007 and 2006, Eagle Rock Energy GP, L.P. owned 1.09%, 1.16% and 2.0%, respectively, of the Partnership.

F-23

NOTE 9. RELATED PARTY TRANSACTIONS

On July 1, 2006, the Partnership entered into a month-to-month contract for the sale of natural gas with an affiliate of Natural Gas Partners, under which the Partnership sells a portion of its gas supply.  In July 2008, the company to which the Partnership sells its natural gas was sold by the affiliate of NGP and thus ceased being a related party.  The Partnership recorded revenues of $16.0 million, $35.3 million and $19.4 million for the years ended December 31, 2008, 2007 and 2006, respectively, from the agreement, of which there was a receivable of $5.5 million outstanding at December 31, 2007.

In addition, during the years ended December 31, 2008 and 2007, the Partnership incurred of $0.6 million and $1.5 million, respectively, in expenses with related parties, of which there was an outstanding accounts payable balance of $0.7 million and $0.5 million, respectively, as of December 31, 2008 and December 31, 2007.  During the year ended December 31, 2008, we generated revenue from related parties of $0.2 million, of which no amounts are outstanding as of December 31, 2008.

Related to its investments in unconsolidated subsidiaries, during the year ended December 31, 2008 and 2007, the Partnership recorded income of $4.0 million and $0.7 million, respectively, of which there was no outstanding account receivable balance as of December 31, 2008 and 2007.

During the year ended December 31, 2008, the Partnership leased office space from Montierra and was also reimbursed by Montierra for services performed by its employees on behalf of Montierra.  The Partnership made rental payment of $0.1 million and was reimbursed $0.2 million by Montierra. As of December 31, 2008, we have an outstanding receivable balance of $0.3 million due from Montierra and an outstanding payable balance of $0.7 million due to Montierra.

During the year ended December 31, 2008, the Partnership incurred approximately $2.1 million for services performed by Stanolind Field Services (“SFS”), which are assets controlled by NGP and certain individuals, including one employee of Eagle Rock Energy G&P, LLC.  As of December 31, 2008, the Partnership had an outstanding payable balance due to SFS of $0.1 million.

The Partnership entered into an Omnibus Agreement with Eagle Rock Energy G&P, LLC, Holdings and the Partnership’s general partner on October 24, 2006, in connection with the initial public offering of the Partnership. The Omnibus Agreement requires the Partnership to reimburse Eagle Rock Energy G&P, LLC for the payment of certain expenses incurred on the Partnership’s behalf, including payroll, benefits, insurance and other operating expenses, and provides certain indemnification obligations.

The Partnership does not directly employ any persons to manage or operate our business. Those functions are provided by the general partner of our general partner. We reimburse the general partner of our general partner for all direct and indirect costs of these services under the Omnibus Agreement.

On April 30, 2007, the Partnership completed the acquisition of certain fee minerals, royalties, overriding royalties and non-operated working interest properties from Montierra and Co-Invest, a Natural Gas Partners portfolio company and affiliate, respectively. Montierra and Natural Gas Partners received as consideration a total of 6,458,946 Eagle Rock Energy common units and $6.0 million in cash, subject to adjustments. As part of this transaction, a 39.34% economic interest in the incentive distribution rights was conveyed from Eagle Rock Holdings, L.P. to Montierra. One or more NGP private equity funds directly or indirectly owns a majority of the equity interests in Eagle Rock Energy, Montierra and Co-Invest. Because of the potential conflict of interest between the interests of Eagle Rock Energy G&P, LLC (the “Company”) and the public unitholders of Eagle Rock Energy, the Board of Directors authorized the Company’s Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Montierra Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Montierra Acquisition was fair and reasonable to Eagle Rock Energy and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In determining the purchase consideration for the Montierra Acquisition, the Board of Directors 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 flow of Montierra and Co-Invest, including cash receipts and royalty interests.

In connection with the closing of our initial public offering, on October 24, 2006, we entered into a registration rights agreement with Eagle Rock Holdings, L.P. in connection with its contribution to us of all of its limited and general partner interests in Eagle Rock Pipeline. In the registration rights agreement, we agreed, for the benefit of Eagle Rock Holdings, L.P., to register the common units it holds, the common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.

F-24

In connection with the closing of the Montierra Acquisition, we entered into a registration rights agreements with Montierra and Co-Invest. In the registration rights agreements, we agreed, for the benefit of Montierra and Co-Invest, to register the common units it holds, the common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.

On July 31, 2007, Eagle Rock Energy Partners, L.P. completed the acquisition of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. (Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. portfolio companies, respectively) and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (a Natural Gas Partners affiliate) (the “Redman Acquisition”). Redman sellers and NGP received as consideration a total of 4,428,334 newly-issued Eagle Rock common units and $83.8 million in cash, subject to adjustments. One or more NGP private equity funds directly or indirectly owns a majority of the equity interests in Eagle Rock and the Redman entities. Because of the potential conflict of interest between the interests of the Company and the public unitholders of Eagle Rock, the Board of Directors authorized the Company’s Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Redman Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Redman Acquisition was fair and reasonable to Eagle Rock and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In determining the purchase consideration for the Redman Acquisition, the Conflicts Committee 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 flow of Redman. Based on the recommendation of the Conflicts Committee, the Board of Directors approved the transaction.

On April 30, 2008, the Partnership completed the acquisition of all of the outstanding capital stock of Stanolind, for an aggregate purchase price of $81.8 million. One or more NGP private equity funds, which directly or indirectly owned a majority of the equity interests in Eagle Rock and Stanolind.  Because of the potential conflict of interest between the interests of the Company and the public unitholders of Eagle Rock, the Board of Directors authorized the Company’s Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Stanolind Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Stanolind Acquisition was fair and reasonable to Eagle Rock and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In determining the purchase consideration for the Stanolind Acquisition, the Conflicts Committee 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 flow of Stanolind. Based on the recommendation of the Conflicts Committee, the Board of Directors approved the transaction.

Holdings had a management advisory arrangement with Natural Gas Partners requiring a quarterly fee payment. For years ended 2006, the Partnership expensed the $0.4 million for the management advisory arrangement. At the time of the initial public offering, Holdings terminated the agreement with a $6.0 million payment to Natural Gas Partners. The termination fee was recorded as an other operating expense of the Partnership during the fourth quarter of 2006, with the offset as a capital contribution.

In 2006, the Partnership paid a $215.2 million distribution to Holdings, for initial public offering related activities and earning distributions. A portion of this amount was distributed to Holdings from the Partnership’s distributions to its general partner. Holdings owns and controls the general partner of the Partnership while Holdings is controlled by Natural Gas Partners with minority ownership by certain management personnel and board members of the Partnership’s general partner.

As of December 31, 2008 and 2007, Eagle Rock Energy G&P, LLC had $4.5 million and $17.0 million, respectively, of outstanding checks paid on behalf of the Partnership. This amount was recorded as Due to Affiliate on the Partnership’s balance sheet in current liabilities. As the checks are drawn against Eagle Rock Energy G&P, LLC’s cash accounts, the Partnership reimburses Eagle Rock Energy G&P, LLC.

NOTE 10. FAIR VALUE OF FINANCIAL INSTRUMENTS

Effective January 1, 2008, the Partnership adopted SFAS No. 157, as discussed in Note 3, which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.

As defined in SFAS No. 157, 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.  SFAS No. 157 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 measurement) and the lowest priority to unobservable inputs (Level 3 measurements).  The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

F-25

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, 2008, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and natural gas liquids (“NGLs”), at fair value. The Partnership has classified the inputs to measure the fair value of its interest rate swap, crude oil derivatives and natural gas derivatives as Level 2.  Because the NGL market is considered to be less liquid and thinly traded, the Partnership has classified the inputs related to its NGL derivatives as Level 3. The following table discloses the fair value of the Partnership’s derivative instruments as of December 31, 2008:

	Level 1		Level 2			Level 3		Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	87,329		$	—	$	87,329
Natural gas derivatives		—		7,875			—		7,875
NGL derivatives		—		—			14,016		14,016
Total	$	—	$	95,204		$	14,016	$	109,220
Liabilities:
Interest rate swaps	$	—	$	(39,945	)	$	—	$	(39,945	)

As of December 31, 2008, risk management current assets and risk management long-term assets in the Consolidated Balance Sheet include investment premiums of $13.3 million and $1.7 million, respectively.

The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the year ended December 31, 2008 (in thousands):

Net liability balances as of January 1, 2008	$	(52,793	)
Settlements		16,098
Unrealized gains		50,711
Net asset balances as of December 31, 2008	$	14,016

The Partnership values its Level 3 NGL derivatives using forward curves, volatility curves, volatility skew parameters, interest rate curves and model parameters.

F-26

Realized and unrealized losses related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the Consolidated Statements of Operations.  Realized and unrealized gains and losses and premium amortization related to the Partnership’s commodity derivatives are recorded as a component of revenue in the Consolidated Statements of Operations. 

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, 2008, the debt associated with the Credit Agreement bore interest at floating rates. As such, carrying amounts of this debt instrument approximates fair value.

NOTE 11. RISK MANAGEMENT ACTIVITIES

To mitigate its interest rate risk, the Partnership 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 December 4, 2008, we executed a series of interest rate hedge transactions by which we extended the term on our existing interest rate swaps with a then notional amount of $450 million. The expiration dates on these swaps were extended from December 31, 2010 (for swaps with a notional value of $150 million), and January 3, 2011 (for swaps with a notional value of $300 million) to December 31, 2012. In addition, we blended the existing swap rates with the then prevailing interest rate swap rate for the period January 2011 through December 2012 (“blend and extend” strategy). This resulted in our weighted average three month LIBOR swap rate on our existing swaps decreasing from approximately 4.84% to approximately 4.16%.

In addition, on December 5, 2008, we executed an incremental interest rate swap on a notional amount of $150 million with an expiration of December 31, 2012 at a three month LIBOR swap rate of 2.56%. This additional transaction further reduced our weighted average three month LIBOR swap rate to approximately 3.76%.

The table below summarizes the terms, amounts received or paid and the fair values of the various interest rate swaps:

Effective Date	Expiration Date	Notional Amount		Fixed Rate			Fair Value December 31, 2008
	($ in thousands, except notional amount)
09/30/2008	12/31/2012	$	150,000,000		4.020	%	$	(11,398	)
09/30/2008	12/31/2012		150,000,000		4.295			(12,900	)
10/03/2008	12/31/2012		150,000,000		4.170			(12,199	)
12/31/2008	12/31/2012		150,000,000		2.560			(3,448	)
							$	(39,945	)

For the years ended December 31, 2008, 2007 and 2006, the Partnership recorded a fair value (loss) gain within interest expense of ($27.7) million, ($13.4) million and $2.8 million (unrealized), respectively, and a realized (loss) gain of ($5.2) million, $1.4 million and $0.5 million, respectively. As of December 31, 2008 and 2007, the fair value of these contracts totaled an approximate $39.9 million liability and an approximate $12.2 million liability, respectively.

The prices of natural gas, crude oil and NGLs are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors which are beyond the Partnership’s control. In order to manage the risks associated with natural gas, crude oil and NGLs, the Partnership engages in risk management activities that take the form of commodity derivative instruments. Currently these activities are overseen by the Partnership’s Risk Management Committee and are governed by the general partner, which today typically prohibits speculative transactions and limits the type, maturity and notional amounts of derivative transactions. We have implemented a Risk Management Policy which will allow management to execute crude oil, natural gas liquids and natural gas hedging instruments in order to reduce exposure to substantial adverse changes in the prices of these commodities. We continuously monitor and ensure compliance with this Risk Management Policy through senior level executives in our operations, finance and legal departments.

During 2005 and 2006, the Partnership entered into the following risk management activities in connection with risks in our midstream business (excluding transactions that settled in previous periods):

• NGL puts, costless collar and swap transactions for the sale of Mont Belvieu natural gas liquids with a combined notional amount of 57,000 Bbls per month and 54,000 Bbls per month for 2009, and 2010, respectively; and

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• Condensate puts and costless collar transactions for the sale of West Texas Intermediate crude oil with a combined notional amount of 40,000 Bbls per month and 40,000 Bbls per month for 2009, and 2010, respectively.

The NGL derivatives are intended to hedge the risk of lower prices for NGLs with offsetting increases in the value of the NGL derivatives. The condensate derivatives are intended to hedge the risk of lower NGL and condensate prices with offsetting increases in the value of the derivatives based on the correlation between NGL prices and crude oil prices. The natural gas derivatives are intended to hedge the risk of increasing natural gas prices with the offsetting value of the natural gas derivatives.

The Partnership entered or assumed the following derivative transactions related to our upstream business in association with the Montierra, EAC and Redman acquisitions during the year ended December 31, 2007. Transactions shown with a floor price only are puts; all other are costless collars (excluding transactions that settled in previous periods).

				Price ($/mmbtu or $/bbl)
Period	Commodity	Average Monthly Volumes	Index	Avg. Floor		Avg. Ceiling
Jan-Dec 2009	Gas	20,000 MMBtu	NYMEX		6.25		11.20
Jan-Mar 2009	Gas	92,700 MMBtu	NYMEX		7.50		13.75
Jan-May 2009	Gas	40,000 MMBtu	NYMEX		7.00
Jan-May 2009	Oil	7,000 Bbl	NYMEX WTI		60.00		80.75
Jan-Dec 2009	Oil	6,000 Bbl	NYMEX WTI		60.00		77.00

In addition to the upstream derivative transaction described above, the Partnership also entered into or assumed the following derivative transactions associated with our midstream business in conjunction with the Escambia Acquisition (excluding transactions that settled in previous periods). All of these derivatives are swaps.

Period	Commodity	Average Monthly Volumes	Index	Price ($/gal)
Jan-Dec 2009	Propane	2,955 Bbl	OPIS MTB TET		1.0875
Jan-Dec 2009	Propane	5,486 Bbl	OPIS MTB non-TET		1.0775
Jan-Dec 2009	n-Butane	6,042 Bbl	OPIS MTB non-TET		1.2775
Jan-Dec 2009	i-Butane	3,040 Bbl	OPIS MTB non-TET		1.2950

On September 13, 2007, Eagle Rock entered into the following crude oil swaps for 2009 and 2010 to help mitigate its upstream business’ commodity price exposure:

Period	Commodity	Average Monthly Volumes	Index	Swap Price ($/Bbl)
Jan-Dec 2009	Crude oil	25,000 Bbl	NYMEX WTI		71.25
Jan-Dec 2010	Crude oil	25,000 Bbl	NYMEX WTI		70.00

On September 25, 2007, Eagle Rock entered into additional swap transactions on ethane and propane volumes for 2009 per the following table:

Period	Commodity	Average Monthly Volumes	Index	Swap Price ($/gal)
Jan-Dec 2009	Ethane	25,000 Bbl	OPIS MTB non-TET		0.6361
Jan-Dec 2009	Propane	15,000 Bbl	OPIS MTB TET		1.0925

On November 7 and 8, 2007, the Partnership entered into additional commodity hedge transactions (excluding transactions settled in previous periods), as described below:

Period	Commodity	Average Monthly Volumes	Index	Swap Price ($/Bbl)
Jan-Dec 2010	Crude oil	10,000Bbl	NYMEX WTI		78.35
Jan-Dec 2011	Crude oil	45,000Bbl	NYMEX WTI		80.00
Jan-Dec 2012	Crude oil	40,000 Bbl	NYMEX WTI		80.30
Jan-Dec 2009	Natural Gas	85,000 MMBtu	NYMEX		8.35

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Period	Commodity	Average Monthly Volumes	Index	Floor ($/Bbl)		Cap $/Bbl
Jan-Dec 2011	Crude oil	50,000 Bbl	NYMEX WTI		75.00		85.70
Jan-Dec 2012	Crude Oil	50,000 Bbl	NYMEX WTI		75.30		86.00
Jan-Dec 2009	Natural Gas	85,000 MMbtu	NYMEX		7.85		9.25
Jan-Dec 2010	Natural Gas	110,000 MMbtu	NYMEX		7.70		9.10
Jan-Dec 2011	Natural Gas	100,000 MMbtu	NYMEX		7.50		8.85
Jan-Dec 2012	Natural Gas	90,000 MMbtu	NYMEX		7.35		8.65

In addition to entering into the derivative instruments described in the tables above, the Partnership also bought back at no cost to the Partnership an option on a swap (“swaption”) during the year ended December 31, 2007. Under that agreement, the other party had the right, but not the obligation, to enter into a swap with us for 26,000 Bbls of NYMEX WTI per month during the period from January to December 2009 at a strike price of $85.00.

During the year ended December 31, 2008, we assumed the following derivative transactions related to our Upstream and Midstream Businesses in association with the Stanolind and Millennium acquisitions during the year ended December 31, 2008. Transactions shown with a floor price only are puts; all other are costless collars (excluding transactions that settled in previous periods).

				Price ($/mmbtu or $/bbl)
Period	Commodity	Average Monthly Volumes	Index	Avg. Floor		Avg. Ceiling
Jan-Mar 2009	Gas	20,000 MMBtu	NYMEX		9.00		9.85
Apr-Jun 2009	Gas	20,000 MMBtu	NYMEX		7.50		7.95
Jul-Sep 2009	Gas	20,000 MMBtu	NYMEX		7.50		8.60
Jan-May 2009	Gas	40,000 MMBtu	NYMEX		7.50		8.90
Jan-Dec 2009	Oil	10,000 Bbl	NYMEX WTI		93.00		105.20
Jan-Dec 2010	Oil	9,000 Bbl	NYMEX WTI		90.00		99.80

The Partnership entered into the following transactions associated with its Midstream Business during the year ended December 31, 2008.  For the crude oil puts that were acquired, the Partnership paid premiums totaling $3.3 million.  The natural gas collars were costless transactions that were entered into in order to reduce the Partnership’s exposure to potential natural gas increases.  For these collars, the Partnership sold floors and bought caps to offset previous derivative transactions and these collars were necessary because of a change in the Partnership’s expected net natural gas position (excluding transactions that settled in previous periods).

				Price ($/mmbtu or $/bbl)
Period	Commodity	Average Monthly Volumes	Index	Avg. Floor		Avg. Ceiling
Jan-Mar 2009	Gas	92,700 MMBtu	NYMEX		8.80		13.75
Jan-Dec 2009	Oil	7,000 Bbl	NYMEX WTI		90.00
Jan-Dec 2009	Oil	5,000 Bbl	NYMEX WTI		100.00
Jan-Dec 2009	Oil	6,000 Bbl	NYMEX WTI		90.00
Jan-Dec 2009	Oil	5,000 Bbl	NYMEX WTI		100.00

On October 31, 2008, the Partnership entered into following transaction:

Period	Commodity	Average Monthly Volumes	Index	Swap Price ($/Bbl)
Jan-Dec 2009	Crude oil	50,000 Bbl	NYMEX WTI		100.00

The above swap was part of a transaction in which the Partnership reset two existing crude oil swaps.  The first swap was reset from $73.90 to $100 on 80,000 barrels per month for the months of November and December 2008 (this swap is excluded from the table because it has already settled).  The cost of this reset swap was $4.1 million.  The second swap was reset from $80.25 to $100 per barrel on 50,000 barrels per month for calendar year 2009.  The cost to reset this swap was $11.7 million.

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On November 25, 2008, the Partnership entered into the following swap transactions on natural gas volumes for 2009 per the following table:

Period	Commodity	Average Monthly Volumes	Index	Swap Price ($/Bbl)
Jan-Dec 2009	Gas	70,000 MMbtu	NYMEX WTI		6.685
Jun-Dec 2009	Crude oil	70,000 MMbtu	NYMEX WTI		6.885

The counterparties used for all of these transactions have investment grade ratings.

The Partnership has not designated these derivative instruments as hedges and as a result is marking these derivative contracts to market with changes in fair values recorded as an adjustment to the mark-to-market gains /(losses) on risk management transactions within revenue. For the year ended December 31, 2008, the Partnership recorded a gain on risk management instruments of $161.8 million, representing a fair value (unrealized) gain of $221.2 million, amortization of derivative costs of $13.3 million and net (realized) settlement losses to the Partnership of $46.1 million. As of December 31, 2008, the fair value of these contracts, including derivative costs, totaled $109.2 million. For the year ended December 31, 2007, the Partnership recorded a loss on risk management instruments of $133.8 million, representing a fair value (unrealized) loss of $130.7 million, amortization of derivative costs of $8.2 million and net (realized) settlement losses to the Partnership of $3.1 million. As of December 31, 2007, the fair value of these contracts, including derivative costs, totaled $(127.3 million). For the year ended December 31, 2006, the Partnership recorded a loss on risk management instruments of $24.0 million, representing a fair value (unrealized) loss of $7.1 million, amortization of put premiums of $19.2 million and net (realized) settlements gain to the Partnership of $2.3 million.

On January 8, 2009, the Partnership executed a series of hedging transactions that involved unwinding certain existing derivative contracts and entering into new derivative contracts.  See Note 19 for further discussion of these transactions.

NOTE 12. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation—The Partnership is subject to several 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 has accruals of approximately $0.1 million and $1.8 million as of December 31, 2008 and 2007, respectively, related to these matters. The Partnership has been indemnified up to a certain dollar amount for two of these lawsuits. For the indemnified lawsuits, the Partnership has not established any accruals as the likelihood of these suits being successful against them is considered remote. If there ultimately is a finding against the Partnership in the indemnified cases, the Partnership would expect to make a claim against the indemnification up to limits of the indemnification. These matters are not expected to have a material adverse effect on our financial position, results of operations or cash flows.

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 our 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.

Regulatory Compliance—In the ordinary course of business, the Partnership is subject to various laws and regulations. In the opinion of management, the Partnership is in material compliance with existing laws and regulations.

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, 2008 and 2007, the Partnership had accrued approximately $8.6 million and $2.4 million, respectively, for environmental matters.

F-30

In June 2008, the Texas Commission on Environmental Quality (“TCEQ”) issued a Notice of Enforcement (“NOE”) to one of the Partnership’s subsidiaries, TCEQ ID No.: CF-0068-J (the “First NOE”) and another NOE to another of its subsidiaries (TCEQ ID No.: CF-0070-W) (the “Second NOE”).  Both the First NOE and the Second NOE were the result of findings made by the TCEQ’s Amarillo Region Office as a result of routine inspections of the Partnership’s Cargray facilities in the Texas Panhandle.  These NOEs were consolidated into one docket during negotiations between the Partnership and the TCEQ. On October 28, 2008, the Partnership executed an Agreed Order resolving with the TCEQ the two NOE matters by, among other things, payment of an administrative penalty and Supplemental Environmental Project payment which, in the aggregate, were less than $10,000. The Partnership considers these matters concluded.

On September 29, 2008, the TCEQ issued another NOE to one of the Partnership’s subsidiaries concerning the environmental compliance of its Red Deer Gas Plant; TCEQ ID No.: RH-0004-B (the “Third NOE”). The allegations in the Third NOE are also the result of findings made by the TCEQ’s Amarillo Region Office as a result of a routine inspection.  In response, the Partnership’s subsidiary took certain steps to come into compliance, and provided substantial documentation, some of which is corrective in nature, to the TCEQ. We also contested certain allegations. On December 5, 2008, TCEQ issued a proposed Agreed Order to the Partnership, offering settlement by, among other things, payment of an administrative penalty. On February 13, 2009, the Partnership executed this Agreed Order, paying an administrative penalty and Supplemental Environmental Project payment which, in the aggregate, were $46,072. The Partnership considers this matter concluded.

The Partnership has voluntarily undertaken a self-audit of its compliance with air quality standards, including permitting in the Texas Panhandle Segment as well as a majority of our other Midstream Business locations and some of its Upstream Business locations. This auditing has been and is being undertaken pursuant to the Texas Environmental, Health and Safety Audit Privilege Act, as amended. The Partnership has begun making the disclosures to the TCEQ as a result of the completion of the first of these self audits, and it is addressing in due course the deficiencies that it disclosed therein.  The Partnership does not foresee at this time any impediment to its successful conclusion of these audits and the resulting corrective effort.

Since 2008, the Partnership has received additional NOEs and a notice of violation from the TCEQ related to air compliance matters in the Texas Panhandle Segment.  One of the NOEs has been resolved for $2,575. The Partnership expects to receive additional NOEs or NOVs from the TCEQ from time to time throughout 2009.  Though the TCEQ has the discretion  to adjust penalties and settlements upwards based on a compliance history containing multiple, successive NOEs, the Partnership does not expect that the resolution of any existing NOE or any future similar  NOE will vary significantly from the administrative penalties and agreed settlements experienced by it to date.

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, the Partnership is currently making payments in satisfaction of the retained revenue interests, and it expects these payments to continue through the end of 2009 and possibly 2010.   With respect to the Partnership’s Big Escambia Creek field, these payments are expected to begin in 2010 and continue 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 operation. Rental expense, including leases with no continuing commitment, amounted to approximately $5.8 million, $3.6 million and, $0.3 million for the years ended December 31, 2008, 2007 and 2006, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term. At December 31, 2008, commitments under long-term non-cancelable operating leases for the next five years are as follows: 2009—$1.7 million; 2010—$0.8 million; 2011—$0.7 million; 2012—$0.6 million; and 2013—$0.6 million.

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NOTE 13. SEGMENTS

Based on our approach to managing our assets, we believe our operations consist of four geographic segments in its Midstream Business, one mineral/royalty segment, one Upstream Segment and one functional (corporate) segment:

(i) Midstream—Texas Panhandle Segment:

gathering, processing, transportation and marketing of natural gas in the Texas Panhandle;

(ii) Midstream—South Texas Segment:

gathering, processing, transportation and marketing of natural gas in South Texas;

(iii) Midstream—East Texas/Louisiana Segment:

gathering, processing and marketing of natural gas and related NGL transportation in East Texas and Louisiana;

(iv) Midstream—Gulf of Mexico Segment:

Gathering and processing of natural gas; and fractionation, transportation and marketing of NGLs in South Louisiana, Gulf of Mexico and inland waters of Texas;

(v) Upstream Segment:

crude oil and natural gas production from operated and non-operated wells;

(vi) Minerals Segment:

fee minerals, royalties and non-operated working interest ownership, lease bonus and rental income and equity in earnings of unconsolidated non-affiliate; and

(vii) Corporate Segment:

risk management and other corporate activities.

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The Partnership’s chief operating decision-maker currently reviews its operations using these segments. The Partnership evaluates segment performance based on segment operating income or loss. Summarized financial information concerning the Partnership’s reportable segments is shown in the following table:

Year Ended December 31, 2008	Texas Panhandle Segments		South Texas Segment			East Texas/ Louisiana Segment			Gulf of Mexico Segment			Total Midstream Segments
	($ in millions)
Sales to external customers	$	603.1	$	438.7		$	322.0		$	1.7		$	1,365.5
Cost of natural gas and natural gas liquids		459.1		425.2			269.0			1.4			1,154.7
Operating costs and other expenses		34.3		2.9			16.5			0.6			54.3
Depreciation, depletion, amortization and impairment		43.7		12.5			40.6			1.5			98.3
Operating income (loss)	$	66.0	$	(1.9	)	$	(4.1	)	$	(1.8	)	$	58.2
Capital Expenditures	$	30.7	$	1.1		$	17.4		$	—		$	49.2
Segment Assets	$	543.5	$	97.3		$	368.6		$	80.1		$	1,089.5

Year Ended December 31, 2008	Total Midstream Segments		Upstream Segment			Minerals Segment		Corporate Segment		Total Segments
	($ in millions)
Sales to external customers	$	1,365.5	$	173.0		$	43.0	$	161.8	$	1,743.3
Cost of natural gas and natural gas liquids		1,154.7		—			—		—		1,154.7
Operating costs and other expenses		54.3		37.5			1.7		56.4		149.9
Depreciation, depletion, amortization and impairment		98.3		183.0			9.5		0.8		291.6
Operating income (loss)	$	58.2	$	(47.5	)	$	31.8	$	104.6	$	147.1
Capital Expenditures	$	49.2	$	20.7		$	—	$	0.8	$	70.7
Segment Assets	$	1,089.5	$	398.0		$	143.9	$	141.7	$	1,773.1

Year Ended December 31, 2007	Texas Panhandle Segment		South Texas / Segment		East Texas / Louisiana Segment		Total Midstream Segments
	($ in millions)
Sales to external customers	$	488.0	$	188.6	$	167.2	$	843.8
Cost of natural gas and natural gas liquids		372.2		181.3		133.4		686.9
Operating costs and other expenses		32.5		1.1		10.9		44.5
Depreciation and amortization		42.3		2.5		10.8		55.5
Operating income (loss)	$	41.0	$	3.8	$	12.1	$	56.9
Capital expenditures	$	34.9	$	3.4	$	25.6	$	63.9
Segment assets		586.9		99.3		254.4		940.6

Year Ended December 31, 2007	Total Midstream Segments		Upstream Segment		Minerals Segment		Corporate Segment			Total Segments
	($ in millions)
Sales to external customers	$	843.8	$	51.8	$	15.0	$	(133.8	)(a)	$	776.8
Cost of natural gas and natural gas liquids		686.9		—		—		—			686.9
Operating costs and other expenses		44.5		15.9		0.8		30.5			91.8
Depreciation, depletion, amortization and impairment		55.5		16.2		13.8		0.8			86.3
Operating income (loss)	$	56.9	$	19.6	$	0.5	$	(165.2	)	$	(88.2	)
Capital Expenditures	$	63.9	$	2.2	$	—	$	—		$	66.1
Segment Assets		940.6		503.8		155.2		10.3			1,609.9

(a) Represents results of our derivatives activity.

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Year Ended December 31, 2006	Texas Panhandle Segment		East Texas / Louisiana Segment			Corporate Segment			Total Midstream Segments
	($ in millions)
Sales to external customers	$	423.1	$	79.3		$	(24.0	)(a)	$	478.4
Cost of natural gas and natural gas liquids		317.6		60.0			—			377.6
Operating costs and other expenses		30.1		5.1			16.9			52.1
Depreciation and amortization		36.3		5.9			1.0			43.2
Operating income (loss)	$	39.1	$	8.3		$	(41.9	)	$	5.5
Capital expenditures	$	12.2	$	20.7		$	5.5		$	38.4
Segment assets		573.6		148.9	��		57.4			779.9

(a) Represents results of our derivatives activity.

NOTE 14. EMPLOYEE BENEFIT PLAN

The Partnership offers a defined contribution benefit plan to its employees. The plan, which was amended in December 2007 to eliminate, in part, a requirement that an employee have been with the Partnership longer than six months, provides for a dollar for dollar matching contribution by the Partnership of up to 3% 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, 2008, 2007 and 2006 were approximately $1.4 million, $0.8 million and $0.3 million, respectively.

NOTE 15. INCOME TAXES

The Partnership’s provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc, (acquiring entity of certain entities acquired in 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”)  The comparative data presented below for 2006 does not include the income taxes of the above referenced corporations since they were acquired in 2007 and 2008. In addition, with the amendment of the Texas Franchise Tax in 2006, we have become a taxable entity in the state of Texas. Our federal and state income tax provision is summarized below:

	For the Year Ended December 31,
	2008			2007			2006
	($ in thousands)
Current:
Federal	$	140		$	(26	)	$	—
State		849			724			—
Total current provision		989			698			—
Deferred:
Federal		(6,766	)		(493	)		—
State		2,217			(62	)		1,230
Total deferred		(4,549	)		(555	)		1,230
Total provision for income taxes		(3,560	)		143			1,230
Add Back: valuation allowance for Federal loss		2,444			26			—
Total Provision for income taxes less valuation allowance	$	(1,116	)	$	169		$	1,230

The effective rate for the twelve months ended December 31, 2008, 2007 and 2006 are shown in the table below.  For 2007 and 2006 the federal and state based income taxes were applied against book losses which resulted in a 100% effective tax rate for 2007 and 2006. The changes in the 2008 effective rate are attributable to the state and federal taxes being applied against book income for 2008.  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:

F-34

	For the Year Ended December 31,
	2008			2007			2006
	($ in thousands)
Pre-tax net book income (loss)	$	86,404		$	(145,465	)	$	(22,084	)
Texas Margin Tax current and deferred		3,066			662			1,230
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities		(4,182	)		(519	)		—
NOL used		(2,444	)		—			—
Valuation allowance		2,444			26			—
Provision for income taxes	$	(1,116	)	$	169		$	1,230
Effective income tax rate		(1.3	)%		100.0	%		100.0	%

Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2008 and 2007 are as follows:

	At December 31,
	2008			2007
	($ in thousands)
Deferred Tax Assets:
Net operating loss carryovers	$	3,616		$	1,998
Current year adjustment to net operating loss carryforwards		(2,444	)		26
Statutory depletion carryover		1,842			—
AMT credit carryforward		140			—
Unrealized hedging transactions		—			1,278
Total deferred tax		3,154			3,302
Less: Valuation allowance		(3,154	)		(2,578	)
Net Deferred Tax Assets		—			724
Deferred Tax Liabilities:
Property, plant equipment & amortizable assets		(2,621	)		(1,906	)
Unrealized hedging transactions		(765	)		—
Book/tax differences from partnership investment		(38,963	)		(16,334	)
Total Deferred Tax Liabilities		(42,349	)		(18,240	)
Total Net Deferred Tax Liabilities	$	(42,349	)	$	(17,516	)
Current portion of total net deferred tax liabilities	$	—		$	—
Long-term portion of total net deferred tax liabilities	$	(42,349	)	$	(17,516	)

We had net operating loss carryforwards and depletion deduction carryforwards of $1.2 million and $2.0 million at December 31, 2008 and 2007, respectively. These losses expire in various years between 2008 and 2028 and are subject to limitations on their utilization. We record a valuation allowance to reduce our deferred tax assets to the amount of future tax benefit that is more likely than not to be realized. The valuation allowance was $3.1 million and $2.6 million at December 31, 2008 and 2007, respectively. Of the $3.1 million valuation allowance at December 31, 2008, none is for timing differences from hedging transactions which impact the Texas Margins Tax and $3.0 million is from net operating loss carryovers from the C Corporations and $0.1 is from AMT credit carryforwards from the C corporations.  For 2007, $0.6 million was for timing differences from hedging transactions which impact the Texas Margins Tax and $2.0 million is from net operating loss carryovers from the Redman Acquisition and current year losses from our wholly owned corporations Eagle Rock Energy Acquisition Co, Inc. and Eagle Rock Upstream Development Company, Inc. We expect to pay minimal federal taxes for the foreseeable future and this valuation allowance serves to eliminate the recognized tax benefit associated with carryovers of our corporate entities to an amount that will, more likely than not, be realized.

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The largest single component of our deferred tax liabilities is related to federal income taxes of the C Corporations described above.  Book/tax differences were created by the Redman and Stanolind Acquisitions. These book/tax temporary differences result in a net deferred tax liability of $39.0 million at December 31, 2008, which will be reduced as allocation of depletion in proportion to the assets contributed brings the book and tax basis closer together over time. This deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets.

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. Due to the enactment of the Revised Texas Franchise Tax, we recorded a net deferred tax liability of $3.4 million, $1.9 million and $1.2 million during the years ended December 31, 2008, 2007 and 2006, respectively. The offsetting net charges of $0.9 million, $0.7 million and $1.2 million are shown on our Statement of Consolidated Operations for the years ended December 31, 2008, 2007 and 2006, respectively, as a component of provision for income taxes.

In accordance with FASB Interpretation  No. 48, Accounting for Uncertainty in Income Taxes, the Partnership must recognize the tax effects of any uncertain tax positions it may adopt, if the position taken by the Partnership is more likely than not sustainable.  If a tax position meets such criteria, the tax effect to be recognized is by the Partnership would be the largest amount of benefit with more than 50% chance of being realized upon settlement.  This guidance was effective January 1, 2007, and the Partnership’s adoption of this guidance had and continues to have no material impact on its financial position, results of operations or cash flows.

NOTE 16. EQUITY-BASED COMPENSATION

Eagle Rock Energy G&P, LLC the general partner of the general partner for the Partnership, approved a long-term incentive plan (LTIP), as amended, for its employees, directors and consultants who provide services to the Partnership covering an aggregate of 2,000,000 common units to be granted either as options, restricted units or phantom units.  On October 25, 2006, 124,450 restricted common units were issued to employees and directors of the General Partner who provide services to the Partnership. These restricted units were valued at the market price of the initial public offering less a discount for the delay in their cash distributions during the unvested period. The weighted average fair value of the units granted during the year ended December 31, 2006 was $18.75. With the completion of the Montierra and Laser Acquisitions, during May and June 2007, 343,271 restricted common units were issued to employees and independent directors of the General Partner who provide services to the Partnership. Subsequently (but prior to December 31, 2007) 95,700 restricted common units were issued to certain employees and a new independent director (in connection with their acceptance of employment and directorship, respectively).  During the year ended December 31, 2008, the Partnership granted an additional 741,150 restricted common units.  The restricted units granted in 2008 and 2007 were valued at the market price as of the date issued. The weighted average fair value of the units granted during the year ended December 31, 2008 and 2007 were $14.89 and $23.10, respectively. The awards generally vest on the basis of one third of the award each year. During the restriction period, distributions associated with the granted awards will be distributed to the awardees. No options or phantom units have been issued to date.

A summary of the restricted common units activity for the year ended December 31, 2008, is provided below:

	Number of Restricted Units			Weighted Average Fair Value
Outstanding at December 31, 2007		467,062		$	23.01
Granted		741,150		$	14.86
Vested		(162,302	)	$	22.69
Forfeitures		(140,424	)	$	19.09
Outstanding at December 31, 2008		905,486		$	17.00

The total grant date fair value of restricted units that vested during the years ended December 31, 2008 and 2007 were $3.7 million and $0.8 million, respectively.  No restricted units vested in 2006.

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For the years ended December 31, 2008, 2007 and 2006, non-cash compensation expense of approximately $6.0 million, $2.4 million and $0.1 million, respectively, was recorded related to the granted restricted units. The terms of the October 2006 award agreements were amended during the third quarter of 2007 to permit direct distributions to the holders of restricted unvested common units under such award agreements during the unvested period, including the August 14, 2007 distribution. Prior to the amendment, distributions were made on the restricted unvested common units under these award agreements held by the Partnership, to be finally distributed to the holder or forfeited in keeping with (and on the same timing as) the fate of the underlying unit’s vesting or forfeiture, and, per the amendment, the two prior distributions (i.e., the fourth quarter 2006 prorated distribution and the first quarter 2007 minimum quarterly distribution) will continue to be held by the Partnership with the final disposition of said distributions to be determined in the original manner prescribed for distributions. Restricted common units granted during 2007 already were entitled to receive direct distributions during their unvested periods. This modification resulted in a repricing of the unvested units from their original value of $18.75 to the unit price of $22.60 at the time of the amendment. This change affected approximately 109,750 unvested units (135 employees) and resulted in a $0.1 million increase in compensation during the year ended December 31, 2007. On November 5, 2007, the Partnership modified the vesting dates of the options granted on October 25, 2006 and for other individuals granted units between May 15, 2007 and November 5, 2007. This modification moved the individuals vesting dates to either May 15, 2008, 2009 and 2010 or to November 15, 2008, 2009 and 2010. As the price of the Partnership’s units was lower on the date of modification than the unit price on the date of grant, or date of the previous modification, there was no incremental cost associated with this modification and thus there was no impact to compensation.

As of December 31, 2008, unrecognized compensation costs related to the outstanding restricted units under our LTIP totaled approximately $13.3 million. The remaining expense is to be recognized over a weighted average of 2 years.

Due to vesting of certain restricted units during 2007, 7,400 units were repurchased by the Partnership for $0.2 million as reimbursement for the related employee tax liability paid by the Partnership. These units were put back into the plan and are available for future grants under the LTIP plan.

In addition to equity awards involving units of the Partnership, Eagle Rock Holdings, L.P., which is controlled by NGP, in the past has from time to time granted equity in Holdings to certain employees working on behalf of the Partnership, some of which are named executive officers.  During 2008, Holdings granted 417,000 “Tier I” incentive interests in the aggregate to six Eagle Rock employees.  One of these employees subsequently forfeited 200,000 of the interests upon his resignation from Eagle Rock in 2008.  The Tier I incentive interests entitle the holder to share in the cash distributions of Holdings upon achieving a certain payout target, which was reached in 2006.  Holdings also granted 33,415 “Tier III” incentive units during 2008 (20,000 of which were subsequently forfeited in 2008).  These units have not achieved their payout target and as such have no impact to compensation.

The Partnership has no discretion in granting any awards at the Holdings level.  The Tier I incentive interests are intended to provide additional motivation for the grantees to create value at Holdings, in part through their actions to increase the value of the Partnership.  Because the incentive interests represent an interest in the future profits of Holdings, and receive distributions only from the cash flow at Holdings, the incentive interests create no burden on, or dilution to, the returns on the Partnership’s common units.  On the contrary, the incentive units are solely a burden on, and dilutive to, the returns of the equity owners of Holdings, including NGP as the substantial majority owner of Holdings.  Despite this, under the guidance of U.S. Securities and Exchange Commission Staff Accounting Bulletin Topic 1.B: “Allocation Of Expenses And Related Disclosure In Financial Statements Of Subsidiaries, Divisions Or Lesser Business Components Of Another Entity,” the Partnership recorded a portion of the value of the incentive units as compensation expense in the Partnership’s financial statements.  This allocation is based on management’s estimation of the total value of the incentive unit grant and of the grantee’s portion of time dedicated to the Partnership.  Eagle Rock recorded a non-cash compensation expense of $1,665,831 based on management’s estimates related to the Tier I incentive unit grants made by Holdings in 2008.

NOTE 17. EARNINGS PER UNIT

Basic earnings per unit is computed by dividing the net income, or loss, by the weighted average number of units outstanding during a period. To determine net income, or loss, allocated to each class of ownership (common, subordinated and general partner), we first allocated net income, or loss, by the amount of distributions made for the quarter by each class, if any. The remaining net income, or loss, after the deduction for the related quarterly distribution was 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.

We issued restricted, unvested common units at the time of the initial public offering, October 24, 2006 and subsequent award dates. These units will be considered in the diluted common unit weighted average number in periods of net income. In periods of net losses, the units are excluded from the diluted earnings per unit calculation due to their antidilutive effect.

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The following table presents our calculation of basic and diluted earnings per unit for the periods indicated:

	For the Year Ended December 31,
	2008		2007			2006
	($ in thousands, except per unit amounts)
Net (loss) income	$	87,520	$	(145,634	)	$	(23,314	)
Net income allocated to:
Common units		61,794		(86,334	)		(15,229	)
Subordinated units		24,717		(56,971	)		(7,637	)
General partner units		1,009		(2,329	)		(448	)
Basic weighted average unit outstanding during period:
Common units		51,534		37,008			12,123
Subordinated units		20,691		20,691			17,873
General partner units		845		845			557
Basic Earnings Per Unit:
Common units	$	1.20	$	(2.11	)	$	(1.26	)
Subordinated units	$	1.20	$	(3.14	)	$	(0.43	)
General partner units	$	1.20	$	(3.14	)	$	(0.80	)
Diluted weighted average unit outstanding during period:
Common units		51,699		37,008			12,123
Subordinated units		20,691		20,691			17,873
General partner units		845		845			557
Diluted Earnings Per Unit:
Common units	$	1.20	$	(2.11	)	$	(1.26	)
Subordinated units	$	1.20	$	(3.14	)	$	(0.43	)
General partner units	$	1.20	$	(3.14	)	$	(0.80	)

NOTE 18.  OTHER OPERATING EXPENSE

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, through certain subsidiaries, has historically sold portions of its condensate production from its Texas Panhandle and East Texas midstream systems to SemGroup.  As a result of the bankruptcy filing, the Partnership recorded a $10.7 million bad debt charge during the year ended December 31, 2008.  The bad debt charges are included in “Other Operating Expense” in the consolidated statement of operations.  The Partnership stopped all sales to SemGroup as of August 1, 2008, and as a result, the Partnership does not anticipate recording any additional bad debt charges in future periods.  Other operating expenses for the year ended December 31, 2007 consisted of the settlement of a lawsuit for $1.4 million, liquidated damages related to the late registration of our common units for $1.1 million and a severance payment to a former executive of $0.3 million. For the year ended December 31, 2006, other operating expenses consisted of a payment of $6.0 million for the termination of advisory services agreement with an affiliate.

NOTE 19.   SUBSEQUENT EVENTS

On January 8, 2009, the Partnership executed a series of hedging transactions that involved the unwinding of a portion of existing “in-the-money” 2011 and 2012 WTI crude oil swaps and collars, and the unwinding of two “in-the-money” 2009 WTI crude oil collars. With these transactions, and an additional $13.9 million of cash, the Partnership purchased a 2009 WTI crude oil swap on 60,000 barrels per month beginning January 1, 2009 at $97 per barrel. Both the unwound hedges and new hedges relate to expected volumes in the Partnership’s Midstream and Minerals Segments.

In addition to the hedging transactions discussed above, the Partnership also entered into a 125,000 MMBtu per month Henry Hub natural gas swap at $6.65/MMBtu on January 19, 2009 for its 2009 fiscal year, a 170,000 MMBtu per month Henry Hub natural gas swap at $6.14/MMBtu on February 17, 2009 for its 2010 fiscal year, a 45,000 barrel per month WTI crude oil swap at $53.55 per barrel on February 17, 2009 for its 2010 fiscal year and a 40,000 barrel per month WTI crude oil swap at $51.40 per barrel on February 19, 2009 for our 2010 fiscal year.

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NOTE 20. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of proved and proved developed oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all 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 continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure the reported reserve estimates represent the most accurate assessments possible, 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.

Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

Estimates of proved developed reserves as of December 31, 2008, were based on estimates made by our independent engineers, Cawley, Gillespie & Associates, Inc (“Cawley Gillespie”). In 2008, Cawley Gillespie was engaged by and provided their reports to our senior management team.  In order to enhance our controls regarding reserve reporting, we have recently modified the charter of the Audit Committee to include the right to engage the independent engineers, in consideration of management’s recommendations.  For 2009, management has recommended, and the Audit Committee has approved our continued engagement with Cawley Gillespie.

In January 2009, the SEC issued new rules for reserves reporting.  These rules are not currently effective, and the SEC has specifically prohibited early adoption of them.  We will adopt them in our 2009 annual report, however.  The new rules include several significant changes, such as the use of average (rather than year-end), the optional inclusion of probable and possible reserves, and the option to include price sensitivities.

We make representations to the independent engineers that we have provided all relevant operating data and documents, and in turn, we review the reserve reports provided by the independent engineers to ensure completeness and accuracy. Our Chief Executive Officer makes the final decision on booked proved reserves by incorporating the proved reserves from the independent engineers’ reports.

Our relevant management controls over proved reserve attribution, estimation and evaluation include:

• Controls over and processes for the collection and processing of all pertinent operating data and documents needed by our independent reservoir engineers to estimate our proved reserves; and

• Engagement of well qualified and independent reservoir engineers for review of our operating data and documents and preparation of reserve reports annually in accordance with all SEC reserve estimation guidelines.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, the standardized measure should not be construed as the current market value of the proved oil and natural gas reserves or 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 risk.

The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley, Gillespie and Associates. Natural gas liquids are included in oil reserves. Oil and natural gas liquids are based on the December 31, 2008 West Texas Intermediate posted price of $44.60 per barrel and are adjusted by lease for quality, transportation fees, and regional price differentials. Gas prices are based on a December 31, 2008 Henry Hub spot market price of $5.63 per MMBtu and are adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.   All of the Company’s reserves are located in the United States.

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	Proved Reserves
	Oil (MBbls)			Gas (MMcf)			Natural Gas Liquids (MBbls)
Proved reserves, January 1, 2007		—			—			—
Extensions and discoveries		—			—			—
Purchase of minerals in place		9,816			48,336			5,727
Production		(442	)		(2,456	)		(227	)
Sale of minerals in place		—			—			—
Revision of previous estimates		707			(1,237	)		242
Proved reserves, December 31, 2007		10,081			44,643			5,743
	Proved Developed Reserves
	Oil (MBbls)			Gas (MMcf)			Natural Gas Liquids (MBbls)
December 31, 2007		9,634			38,868			5,437

	Proved Reserves
	Oil (MBbls)			Gas (MMcf)			Natural Gas Liquids (MBbls)
Proved reserves, January 1, 2008		10,081			44,643			5,743
Extensions and discoveries		189			3,566			45
Purchase of minerals in place		3,513			8,157			1,432
Production		(988	)		(5,400	)		(508	)
Sale of minerals in place		—			—			—
Revision of previous estimates		(2,789	)		(6,378	)		(1,073	)
Proved reserves, December 31, 2008		10,006			44,588			5,639
	Proved Developed Reserves
	Oil (MBbls)			Gas (MMcf)			Natural Gas Liquids (MBbls)
December 31, 2008		10,568			40,908			5,391

In 2008, we experienced significant negative revisions to our proved reserves.  These revisions can be attributed to technical factors and economic factors.  Revisions due to economic factors are primarily due to the dramatic decline in commodity prices that occurred between December 31, 2007 and December 31, 2008.  We estimate that approximately 3,782 mboe of the 2008 negative reserve revisions can be attributed to price changes.

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 (in thousands) at December 31, 2008 and 2007.

	December 31, 2008			December 31, 2007
Evaluated properties	$	593,520		$	461,884
Unevaluated properties—excluded from depletion		73,622			66,023
Gross oil and gas properties		667,142			527,907
Accumulated depreciation, depletion, amortization		(52,771	)		(23,865	)
Impairment		(108,758	)		—
Net oil and gas properties	$	505,613		$	504,042

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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 (in thousands) for the years ended December 31, 2008 and 2007:

	For the Year Ended December 31,
	2008		2007
Property acquisition costs, proved	$	110,747	$	464,204
Property acquisition costs, unproved		7,597		66,023
Exploration and extension well costs		1,610		—
Development costs		12,294		3,429
Total costs	$	132,248	$	533,656

Our exploration and extension well costs are primarily related to low risk drilling around our existing fields.

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

The following information has been developed utilizing SFAS 69, Disclosures about Oil and Gas Producing Activities, (SFAS 69) procedures and is based on oil and natural gas reserves estimated by the Company’s independent reserves engineer. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Company.

The Company 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 are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Use of a 10% discount rate and year-end prices are required by SFAS 69.

In our Standardized Measure calculations we have excluded the future revenues that would be associated with the sales of sulfur since it is not a hydrocarbon and SFAS 69 does not allow for the inclusion of non-hydrocarbon revenues.  Also, we have included the expected impact of the retained revenue interests as a revenue reduction.

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The Standardized Measure is as follows (in thousands) as of December 31, 2008 and 2007:

	December 31, 2008			December 31, 2007
Future cash inflows	$	788,154		$	1,565,539
Future production costs		(322,931	)		(500,240	)
Future development costs		(60,189	)		(10,045	)
Future net cash flows before income taxes		405,034			1,055,254
Future income tax benefit		1,895			—
Future net cash flows before 10% discount		406,929			1,055,254
10% annual discount for estimated timing of cash flows		(197,185	)		(498,294	)
Standardized measure of discounted future net cash flows	$	209,744		$	556,960

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 Company’s proved oil and natural gas reserves for the years ended December 31, 2008 and 2007 (in thousands).

	For the Year Ended December 31,
	2008			2007
Beginning of year	$	556,960		$	—
Sale of oil and gas produced, net of production costs		(127,125	)		(48,294	)
Net changes in prices and production costs		(293,537	)		99,252
Extensions, discoveries and improved recovery, less related costs		8,842			—
Previously estimated development costs incurred during the period		(12,294	)		888
Net changes in future development costs		11,766			—
Revisions of previous quantity estimates		(49,546	)		26,110
Purchases of property		45,239			459,041
Sales of property		—			—
Accretion of discount		50,531			21,274
Net changes in income taxes		1,033			—
Other		17,875			(1,311	)
End of year	$	209,744		$	556,960

Results of Operations

The following are the results of operations for the Partnership’s oil and natural gas producing activities for the year ended December 31, 2008 and 2007 (in thousands):

	For the Year Ended December 31,
	2008			2007
Revenues	$	166,948		$	64,934
Costs and expenses:
Production costs		39,823			16,640
General and administrative		4,282			1,593
Depreciation, depletion and amortization		52,771			24,262
Impairment		108,758			5,749
Total costs and expenses		205,634			48,244
Results of operations	$	(38,686	)	$	16,690

* * * * *

F-42

Index to Exhibits

Exhibit Number	Description
2.1	Partnership Interests Purchase and Contribution Agreement By and Among Laser Midstream Energy II, LP, Laser Gas Company I, LLC, Laser Midstream Company, LLC, Laser Midstream Energy, LP, and Eagle Rock Energy Partners, L.P., dated as of March 30, 2007 (incorporated by reference to Exhibit 2.1 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
2.2	Partnership Interests Contribution Agreement By and Among Montierra Minerals & Production, L.P., NGP Minerals, L.L.C. (Montierra Management LLC) and Eagle Rock Energy Partners, L.P., dated as of March 31, 2007 (incorporated by reference to Exhibit 2.2 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
2.3	Asset Contribution Agreement By and Among NGP 2004 Co-Investment Income, L.P., NGP Co-Investment Income Capital Corp., NGP-VII Income Co-Investment Opportunity, L.P., and Eagle Rock Energy Partners, L.P., dated as of March 31, 2007 (incorporated by reference to Exhibit 2.3 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
2.4	Contribution and Sale Agreement By and Among Eagle Rock Energy Partners, L.P., Redman Energy Holdings, L.P. and Certain Other Parties Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 2.4 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
2.5	Contribution and Sale Agreement By and Among Eagle Rock Energy Partners, L.P., Redman Energy Holdings II, L.P. and Certain Other Parties Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 2.5 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
2.6	Asset Contribution Agreement By and Among NGP Co-Investment Opportunities Fund II, L.P. and Eagle Rock Energy Partners, L.P., dated July 11, 2007 (incorporated by reference to Exhibit 2.6 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
2.7	Stock Purchase Agreement dated April 2, 2008 among Eagle Rock Energy Partners, L.P., Stanolind Holdings, L.P. and Stanolind Oil and Gas Corp. (incorporated by reference to Exhibit 2.8 of the registrant’s current report on Form 8-K filed with the Commission on April 4, 2008 (File No. 001-33016))
2.8	Partnership Interests Purchase Agreement dated September 11, 2008, as amended, among Eagle Rock Energy Partners, L.P. and Millennium Midstream Partners, L.P. (incorporated by reference to Exhibit 2.1 of the registrant’s quarterly period for the period ended September 20, 2008 filed with the Commission on November 10, 2008 (File No. 001-33016))
2.9*	Amendment No. 2 to the Partnership Interests Purchase Agreement dated February 9, 2009 among Eagle Rock Energy Partners, L.P. and Millennium Midstream Partners, L.P.
2.10*	Amendment No. 3 to the Partnership Interests Purchase Agreement dated February 27, 2009 among Eagle Rock Energy Partners, L.P. and Millennium Midstream Partners, L.P.
3.1	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))
3.2	First 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 October 31, 2006)
3.3	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))
3.4	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))
3.5	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))

Exhibit Number	Description
3.6	Second Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.2 of the registrant’s current report on Form 8-K filed with the Commission on October 31, 2006)
4.1	Registration Rights Agreement dated March 27, 2006, among Eagle Rock Pipeline, L.P. and the Purchasers listed thereto (incorporated by reference to Exhibit 4.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
4.3	Registration Rights Agreement between Eagle Rock Energy Partners, L.P. and Eagle Rock Holdings, L.P. (incorporated by reference to Exhibit 4.1 of the registrant’s current report on Form 8-K filed with the Commission on October 31, 2006)
4.4	Form of Common Unit Certificate (included as Exhibit A to the Amended and Restated Partnership Agreement of Eagle Rock Energy Partners, L.P., which is included as Appendix A to the Prospectus) (incorporated by reference to Exhibit 3.2 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
4.5	Registration Rights Agreement dated May 2, 2007, among Eagle Rock Energy Partners, L.P. and the purchasers listed thereto (incorporated by reference to Exhibit 4.5 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
4.6	Registration Rights Agreement dated July 31, 2007, among Eagle Rock Energy Partners, L.P. and the purchasers listed thereto (incorporated by reference to Exhibit 4.6 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
4.7	Registration Rights Agreement dated April 30, 2007, between Eagle Rock Energy Partners, L.P. and NGP-VII Income Co-Investment Opportunities, L.P. (incorporated by reference to Exhibit 4.7 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
4.8	Registration Rights Agreement dated April 30, 2007, between Eagle Rock Energy Partners, L.P. and Montierra Minerals & Production, L.P. (incorporated by reference to Exhibit 4.8 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
10.1	Amended and Restated Credit and Guaranty Agreement (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.2	Omnibus Agreement (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on October 31, 2006)
10.3**	Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.4	Sale, Contribution and Exchange Agreement by and among the general and limited partners of Midstream Gas Services, L.P., Eagle Rock Energy Services, L.P. and Eagle Rock Pipeline, L.P. (incorporated by reference to Exhibit 10.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.5†	Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and ONEOK Texas 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))
10.6	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))
10.7	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))

Exhibit Number	Description
10.8†	Minimum Volume Agreement between ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC (incorporated by reference to Exhibit 10.8 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.9†	Gas Purchase Agreement between ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC (incorporated by reference to Exhibit 10.9 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.10	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))
10.11	Contribution, Conveyance and Assumption Agreement (incorporated by reference to Exhibit 10.3 of the registrant’s current report on Form 8-K filed with the Commission on October 31, 2006)
10.12**	Employment Agreement dated August 2, 2006 between Eagle Rock Energy G&P, LLC and Richard W. FitzGerald (incorporated by reference to Exhibit 10.12 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.13	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))
10.14	Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The Purchasers Named Therein, dated March 30, 2007 (incorporated by reference to Exhibit 10.14 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
10.15	Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The Purchasers Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 10.15 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
10.16**	Severance Agreement with former executive officer (incorporated by reference to Exhibit 10.16 of the registrant’s registration statement on Form S-1 (File No. 333-144938))
10.17**	Form of Award Agreement pursuant to the Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.14 of the Form 8-K filed with the Commission on May 22, 2007)
10.18	Credit Agreement dated December 13, 2007 among Eagle Rock Energy Partners, L.P. and Wachovia Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A., as syndication agent, HSH Nordbank AG, New York Branch, the Royal Bank of Scotland, plc, and BNP Paribas, as co-documentation agents, and the other lenders who are parties thereto (incorporated by reference to Exhibit 10.17 of the Form 8-K filed with the Commission on December 13, 2007)
10.19**†	Eagle Rock Energy G&P, LLC 2009 Short Term Incentive Bonus Plan effective February 4, 2009 (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on February 9, 2009 (File No. 001-33016))
10.20***	Eagle Rock Energy Partners Long-Term Incentive Plan (Amended and Restated Effective February 4, 2009)
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 Deloitte & Touche LLP
23.2*	Consent of Cawley, Gillespie & Associates, Inc.
23.3*	Consent of K.E. Andrews & Company

Exhibit Number	Description
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*	Audit Committee Charter (Amended and Restated Effective February 4, 2009)
99.2*	Compensation Committee Charter (Amended and Restated Effective February 4, 2009)
99.3*	Conflicts Committee Charter (Amended and Restated Effective February 4, 2009)

* Filed herewith

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

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