Edgar Filing: EAGLE ROCK ENERGY PARTNERS L P

Form 10-K for the Fiscal Year Ended December 31, 2007

Index to Financial Statements

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, 2007

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

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, Suite 200

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 x No ¨

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 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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 29, 2007, the aggregate market value of the registrant’s common units held by non-affiliates of the registrant was $661,780,693 based on the closing sale price as reported on Nasdaq Global Select Market.

The issuer had 51,210,108 common units and 21,536,046 subordinated and general partner units outstanding as of March 10, 2008.

DOCUMENTS INCORPORATED BY REFERENCE:

None

Index to Financial Statements

TABLE OF CONTENTS


		Page
Item 1.	Business	1
Item 1A.	Risk Factors	43
Item 1B.	Unresolved Staff Comments	66
Item 2.	Properties	66
Item 3.	Legal Proceedings	66
Item 4.	Submission of Matters to a Vote of Security Holders	67
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	68
Item 6.	Selected Financial Data	69
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	76
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	107
Item 8.	Financial Statements and Supplementary Data	112
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	112
Item 9A.	Controls and Procedures	112
Item 9B.	Other Information	118
Item 10.	Directors, Executive Officers and Corporate Governance	118
Item 11.	Executive Compensation	124
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	139
Item 13.	Certain Relationships and Related Transactions, and Director Independence	142
Item 14.	Principal Accountant Fees and Services	144
Item 15.	Exhibits and Financial Statement Schedules	145

Index to Financial Statements

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 or risk factors set forth under Item 1A of this annual report. These factors include but are not limited:

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Drilling and exploration risks;

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Assumptions underlying oil and natural gas reserve levels;

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Commodity prices;

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Hedging activities;

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Ability to obtain credit and access capital markets;

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Conditions in the securities and/or capital markets;

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Future processing volumes and throughput;

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Loss of significant customers;

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Availability and cost of processing and transportation;

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Competition in the oil and natural gas industry;

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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;

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

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Shortages of personnel and equipment;

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Increases in interest rates;

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Creditworthiness of our counterparties;

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

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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.

Index to Financial Statements

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.

Bcfe: One billion cubic feet of natural gas equivalent, using a ratio of six Mcf 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 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.

CAGR: Compound annual growth rate.

development well: A well drilled within the proved area of a natural gas or oil reservoir to produce proved undeveloped reserves.

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.

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 and natural gas reserves that are not proved and generally has a significant economic risk.

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.

fixed-recovery arrangements: Under these arrangements, raw natural gas is gathered and processed 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

iii

Index to Financial Statements

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.

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.

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 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.

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

MBoe: One thousand barrels of oil equivalent.

Mcf: One thousand cubic feet.

Mcf/d: One thousand cubic feet per day.

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

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.

MMcf/d: One million cubic feet per day.

Natural gas liquids or NGLs: The combination of ethane, propane, butane and natural gasolines 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 gross wells.

NYMEX: New York Mercantile Exchange.

oil: Crude oil and condensate.

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 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

Index to Financial Statements

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; (2) the proceeds based on an index price; or (3) the proceeds from the sale of processed natural gas or NGLs or both.

productive well: A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

proved developed reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

proved reserves: The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating 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: number of years required to produce the proved reserve 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: Trillion cubic feet

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 and oil regardless of whether such acreage contains proved reserves.

West Texas Intermediate (“WTI”): Light, sweet crude oil with high API gravity and low sulfur content used as the benchmark for U.S. crude oil refining and trading. NYMEX futures contracts for light, sweet crude oil specify the delivery of WTI at Cushing, Oklahoma.

working interest: The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property or lease and to receive a share of production.

workover: Operations on a producing well to restore or increase production.

/d: per day

Index to Financial Statements

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, 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. We completed our IPO in October of 2006. References to “Natural Gas Partners” 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., our largest holder of our securities, which is owned by the NGP Investors.

PART I

Item 1.

Business.

Overview

We are a growth-oriented publicly traded Delaware limited partnership engaged in the following three businesses:

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Midstream Business—gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs;

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

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Minerals Business—acquiring and managing fee minerals and royalty interests.

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 midstream and upstream sectors of the oil and natural gas value chain, and one of a small group of MLPs that are 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. Our MLP structure gives us a lower cost of capital 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 assets that have a combination of midstream and upstream assets, provide us with a natural hedge on a portion of our natural gas throughput volumes in our upstream business (to the extent of the volumes of natural gas purchased under our natural gas purchase agreements in our midstream business), and exploit vertical integration synergies in selected regions of our operations.

Our midstream business is strategically located in three significant natural gas producing regions: (i) the Texas Panhandle; (ii) East Texas/Louisiana; and (iii) South Texas. These three regions are productive, mature, long-lived natural gas producing basins that are currently experiencing significant drilling activity. Eagle Rock’s natural gas gathering systems within these regions represent approximately 4,800 miles of natural gas gathering pipelines with approximately 2,500 well connections and approximately 466 MMcf/d of plant processing capacity in 16 natural gas processing plants, with 125,500 horsepower, and averaging 349 MMcf/d of gathered volumes and averaging 267 MMcf/d of processed volumes during 2007.

Our upstream business has long-lived, high working interest properties located primarily in the Southern Alabama (where we also operate the associated gathering and processing assets), East Texas, and South Texas

Index to Financial Statements

regions. In December 2007, these working interest properties included 74 operated productive wells and 80 non-operated wells with net production of approximately 5,600 Boe/d and proved reserves of approximately 39 Bcf of natural gas, 7.3 MMBbls of crude oil, and 5.7 MMBbls of natural gas liquids, of which 91% are proved developed producing. The reserve life index is approximately 9.7 years.

Our minerals business has a diversified set of fee mineral and royalty interests comprised of interest in over 5.6 million gross mineral acres (430,000 net mineral acres) and interests in over 2,500 productive wells across 17 states. As of December 31, 2007, these interests had proved reserves of approximately 5.4 Bcf of natural gas and 2.8 MMBbls of crude oil (100% proved developed producing). These interests produced an average of approximately 1100 Boe/d (net to our interest).

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 2,187,871 common units and 20,691,495 subordinated units and all of the equity interests in our general partner. 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. 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 is among the oldest of the private equity firms that specialize in the energy industry. Through its family of nine institutionally-backed investment funds, Natural Gas Partners has sponsored over 125 portfolio companies and has controlled invested capital and additional commitments totaling $7 billion.

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:

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Pursuing acquisitions. We have grown significantly through acquisitions and will continue to employ a disciplined acquisition strategy that capitalizes on the operational experience of our management team as well as bring new expertise to the Partnership. We believe that the extensive experience of our management team in acquiring and operating natural gas gathering /processing assets, oil and 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 of managing midstream, mineral and upstream 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. 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:

Midstream Business Asset Criteria:

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

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High level of drilling activity behind our Midstream Business assets—We seek a balance of future development potential and current production rate. The current production rate is important to ensure that the acquisition will immediately provide adequate cash flow so that distributions can be increased, but the active drilling is necessary to ensure that production declines can be offset by additional well connects or recompletions.

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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.

Index to Financial Statements

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Operations—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.

Upstream and Mineral 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.

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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 immediately provide adequate cash flow so that distributions can be increased, but the undeveloped potential is necessary to ensure that production declines can be offset by additional drilling and recompletions.

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Relatively low risk development—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.

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Oil/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 that are focused on that commodity.

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

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Operations—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.

The primary measures we use to assess the success of our acquisition program are distribution accretion, reserve life index, and internal rate of return.

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Maximizing the profitability of our existing assets. In our Midstream segment, we intend to maximize the profitability of our existing assets by marketing, and contracting with new customers to add new volumes of natural gas to our gathering and processing systems. We also strive to provide superior customer service while undertaking additional initiatives to enhance utilization, minimize excess processing capacity and improve operating efficiencies across our midstream assets. In our Upstream segment, we will utilize best practices and technologies to improve the recoveries of oil and gas from our existing wellbores as well as focus on reducing our overall operating expenses in our upstream business. We manage our assets in a manner to maximize the amount of hydrocarbons 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 production enhancement activities are distribution accretion, internal rate of return, and unit operating cost.

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Expanding our operations through organic growth projects. In our Midstream Segment, 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 and infill drilling and recompletions in our Upstream Segment. In our Upstream Segment, infill drilling and recompletions are the source of organic growth. We employ sound petroleum engineering practices to identify and quantify these opportunities, and pursue them in a manner that reduces risk and cost.

We measure the success of these projects by their distribution accretion, unit development cost, and internal rate of return.

Index to Financial Statements

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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. 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 contracts are more than offset by our long natural gas position associated with midstream percent-of-proceeds contracts, our upstream assets, and our mineral interests. We use a variety of hedging instruments to accomplish our risk management objectives, and have hedged substantially all of our expected equity volumes through 2009.

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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. We are committed to maintaining a balanced capital structure, which will allow us to use our available capital to selectively pursue accretive investment opportunities.

Competitive Strengths

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

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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, mineral and upstream assets. Our senior management team has an average of over 25 years of industry-related experience. Our 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. Members of our senior management team have a substantial economic interest in us. We have a staff of engineers, geologists, commercial, operational and support staff who are experts at drilling and operating oil and gas wells and managing gathering and processing assets.

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We have sufficient financial flexibility to pursue significant acquisitions—We currently have approximately $240 million of available capacity under our credit facility, and the ability to expand the facility by an additional $200 million. We also believe that we have ample access to capital markets to raise additional funds for future acquisitions; however, we recognize that the availability of capital has been reduced due to recent events surrounding the crisis in the sub-prime mortgage market. We expect conditions in the capital markets to continue to be challenging in 2008, but also feel the tightening of capital availability has reduced the competition for acquisitions. This should create opportunities to purchase properties on more attractive terms.

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We are affiliated with NGP. We expect that our relationship with NGP will 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 midstream assets.

History

Our Partnership, formed in May 2006, is the legal successor to Eagle Rock Pipeline, L.P. which continues to exist in our organization. By virtue of the transaction detailed below, ONEOK Texas Field Services, L.P. is considered to be our predecessor and is referred to throughout this filing as “Eagle Rock Predecessor” 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 filing to “Eagle Rock Pipeline” refer to Eagle Rock Pipeline, L.P., which is the acquirer of Eagle Rock Predecessor and the entity contributed to Eagle Rock Energy Partners, L.P. in connection with our initial public offering.

Index to Financial Statements

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

Dry Trail Plant

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On December 5, 2003, Eagle Rock Pipeline commenced operations with the acquisition of the Dry Trail plant CO₂ 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;

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On July 1, 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;

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

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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)

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On December 1, 2005, Eagle Rock Pipeline acquired Eagle Rock Predecessor for approximately $531.1 million, which was financed through an additional equity contribution of $133 million cash and incurrence of debt of $400 million;

Tyler County Pipeline

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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 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 (Brookland Acquisition)

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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;

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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)

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On June 2, 2006, Eagle Rock Pipeline acquired all of the partnership interests in Midstream Gas Services, L.P., 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 and $20.3 million in Eagle Rock Pipeline partnership units;

Index to Financial Statements

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

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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;

Initial Public Offering

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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 were redeemed by Eagle Rock Holdings, L.P. and certain private investors as part of the exercise of the underwriters’ overallotment option we granted in conjunction with our IPO;

Tyler County Pipeline Extension

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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. and acquired certain fee minerals, royalties and working interest properties directly from NGP-VII Income Co-Investment Opportunities, L.P. 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)

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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 other general company purposes;

Acquisition of Complimentary Assets to Minerals Segment (MacLondon Acquisition)

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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

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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;

Index to Financial Statements

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) (EAC and Redman Acquisitions)

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On July 31, 2007, we acquired Escambia Asset Co., LLC and Escambia Operating Company, LLC (collectively “EAC”) 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, subject to post-closing adjustments;

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On July 31, 2007, we acquired 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) (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;

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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 EAC and Redman acquisitions.

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, segment, and assets:

Table of Acquisitions/Dispositions


Closing Date	Cost			Financing Sources	Segment	Acquisition/Dispositions
12-5-03		$18M		$6M Equity; $12M Debt	NA	Dry Trail Acquisition

7-1-04	($	37.4M	)	NA	NA	Dry Trail Disposition

7-1-04		$20M		Proceeds from sale of Dry Trail Plant	East Texas/ Louisiana Segment	Indian Springs Acquisition

12-1-05		$533M		$133M Equity; $400M Debt	Texas Panhandle Segment	ONEOK Acquisition

3-31-06 & 4-7-06		$96M		$96M Cash (financed through $98.3M private equity offering)	East Texas/Louisiana Segment	Brookeland Acquisition

6-2-06		$25M		$4.7M Cash; $20.3M Equity	Texas Panhandle Segment	Midstream Gas Services Acquisition

4-30-07		$139.2M		$5.4M Cash; $133.8M Equity	Minerals Segment	Montierra Acquisition

5-3-07		$142.6M		$113.4M Cash (financed through private equity offering); $29.2M Equity	East Texas/Louisiana Segment & South Texas Segment	Laser Acquisition

6-18-07		$18.2M		$0.1M Cash $18.1M Equity	Minerals Segment	MacLondon Acquisition

7-31-07		$241.8M		$224.6M Cash (financed through private equity offering and debt); $17.2M Equity	Upstream Segment	EAC Acquisition

7-31-07		$192.8M		$84.6M Cash (financed through private equity offering); $108.2M Equity	Upstream Segment	Redman Acquisition

Index to Financial Statements

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Table of Organic Growth Projects


In-Service Date	Cost		Financing Sources		Segment	Organic Growth Project
2-28-06	$	8M	$	8M Cash	East Texas/Louisiana Segment	Tyler County Pipeline

8-1-06	$	3.1M	$	3.1M Cash	Texas Panhandle Segment	Quinduno Pipeline Connecting East to West

3-31-07	$	24.2M	$	24.2M Debt	East Texas/Louisiana Segment	Tyler County Pipeline Extension

6-21-07	$	16.2M	$	16.2M Debt	Texas Panhandle Segment	Red Deer Processing Plant in East Panhandle

Index to Financial Statements

The following graph depicts our growth over time in Adjusted EBITDA, total distributions, and quarterly distribution rate per unit, from our Initial Public Offering in October 2006 to December 31, 2007:

Note: Total distribution for the fourth quarter of 2006 was equal to the minimum quarterly distribution per common unit prorated for the period from the date of our IPO, on October 24, 2006, through December 31, 2006.

For a definition of Adjusted EBITDA and reconciliation to GAAP, see Item 6 “Selected Financial Data”.

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 Item 1A. Risk Factors.

Our Three Lines of Business and Our Six Operating Segments

Midstream Business

Midstream Industry Overview

General. Raw natural gas produced from the wellhead is gathered and delivered to a processing plant located near the production, where it is treated, dehydrated, and/or processed. Processing natural gas involves the separation and treating of raw natural gas to deliver 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.

Index to Financial Statements

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) and the transmission lines.

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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 three 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 a higher pressure downstream pipelines. We own and operate compression on all our systems.

Processing and treating. 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 NGLs (such as ethane, 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 three geographic regions.

Fractionation. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, 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.

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

Index to Financial Statements

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. We do not own any natural gas transportation assets.

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:

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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.

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Percent-of-Proceeds Arrangements. Under these arrangements, generally raw natural gas is gathered from producers at the wellhead, transported through the gathering system, processed and sold at prices based on published index prices, and 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 share 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. Under percent-of-proceeds arrangements, the margin correlates directly with the prices of natural gas and NGLs and under percent-of-liquids arrangements, the margin correlates directly with the prices of NGLs (although there is often a fee-based component to both of these forms of contracts in addition to the commodity sensitive component).

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Fixed Recovery Arrangements. Under these arrangements, raw natural gas is gathered and processed from producers at the wellhead, transported through our gathering system, processed and sold at prices based on published index prices, and we pay the producers an amount 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.

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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. 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 of keep-whole contracts include provisions that reduce commodity price exposure, including (1) conditioning floors that require the keep-whole contract 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

Index to Financial Statements

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 three significant natural gas producing segments: the Texas Panhandle, East Texas/Louisiana and South Texas. Our gathering and processing assets are located in basins that are experiencing consistent growth in natural gas land leases, drilling and production. These core basins are known as the Anadarko basin, East Texas basin, and South Texas basin. Our focus has been on acquiring assets with strong growth prospects located in these areas or other natural gas prone areas and then to continue to develop those prospects. The Laser Acquisition fits both of these goals. The Laser 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 South Texas, where substantial growth opportunities exist.

Within our geographic areas of operation, we want to be the premier natural gas gatherer and processor in our geographic areas. 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 safe and reliable service at reasonable costs to our customers and to improve our competitiveness through more efficient operations for securing new customers. From a commercial perspective, our focus is to improve the value of service to our customers by providing them with a greater value for their commodity through adding additional options and capacity for the movement and marketing of their natural gas and natural gas liquids.

The growth prospects in our core areas are primarily a result of 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 March of 2007, we completed the pipeline connection between our Tyler County pipeline system and our Brookeland pipeline system (our “Tyler County Pipeline Extension”) adding an additional 50 MMcf/d of outlet capacity for producers in the Austin Chalk trend in East Texas. In June of 2007, we completed the refurbishment and startup of the idle Red Deer Plant connected to our Canadian gathering system adding an additional 20 MMcf/d of capacity for producers in the Granite Wash trend in the Texas Panhandle area. Additional compression projects are underway in this area to add an additional 15 MMcf/d of capacity by first quarter of 2008. In the South Texas area, a compression and treating project was completed adding 24 MMcf/d of capacity to the Phase 1 20” gathering system.

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 above. As of December 31, 2007, the percentage of natural gas under the contract structures were 24% fixed recovery, 35% fee-based, 30% percent-of-proceeds and 11% keep-whole. The following is a summary of the contracts that are significant to our operations, consisting of a natural gas liquids exchange agreement and the two largest volume natural gas purchase agreements.

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.

Index to Financial Statements

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.

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.

Chesapeake and its affiliates and Cimarex and its affiliates account for 12.8% and 8.5%, respectively, of all the volumes gathered by us as of December 31, 2007.

Midstream Business Strategies

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Acquiring Midstream assets. Our goal is 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 oil and gas production assets. The primary measures we use to assess the success of our acquisition program are distribution accretion and internal rate of return. We employ an experienced and qualified staff of engineering, commercial, operations, and 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:

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

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Relatively high level 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 immediately provide adequate cash flow so that distributions can be increased, but the active drilling is necessary to ensure that production declines can be offset by additional well connects or recompletions.

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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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Operations—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.

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Maximizing the profitability of our existing assets. Our goal is to maximize the profitability of our existing midstream assets through organic growth opportunities, adding new volumes of natural gas and undertaking

Index to Financial Statements

additional initiatives to enhance utilization and improve operating efficiencies. We differentiate ourselves by taking the following steps:

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Customer service—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; and

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Asset optimization—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.

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Distribution Accretion—The primary measures we use to assess the success of maximizing the profitability of our existing assets is distribution accretion, improved run times and growing throughput to our plants and gathering systems, internal rates of return and improved operating cost structures and efficiencies.

Midstream Competitive Strengths

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

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We have sufficient financial flexibility to pursue significant acquisitions.

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

Index to Financial Statements

Our Midstream business consists of the following:


	Length (miles)	Compression (Horsepower)	Processing Plant Through-put Volume Capacity (MMcf/d)
Asset
Texas Panhandle Segment	3,808	125,500	197
East Panhandle System	892	44,000	96
Canadian Plant and gathering system	299		25
Arrington Plant and gathering system	336		40
Red Deer Plant(1)	na		24
Roberts County Plant and gathering system(1)(2)	4		7
System 97 gathering system	140		na
Buffalo Wallow gathering system	113		na
West Panhandle System	2,916	81,500	101
Cargray Plant and gathering system(1)	1,275		30
Gray Plant and gathering system(1)	518		20
Lefors Plant and gathering system	663		11
Stinnett Plant and gathering system	451		40
Turkey Creek gathering system	9		na
East Texas/Louisiana Segment	854	12,500	182.5
Brookeland Plant and gathering system	342		100
Indian Springs Plant (25% non-operated) and Camp Ruby gathering system (20% non-operated)(3)	na		37.5	(net)
Tyler County gathering system	62		na
Panola JT Plant and gathering system(1)	29		15
Quitman gathering system	51		na
Rosewood JT Plant and gathering system(1)	35		10
Vixen gathering system	7		na
Belle Bower JT Plant and gathering system(1)	68		20
Simsboro gathering system	30		na
Sligo gathering system	10		na
South Texas Segment	137	8,100	87
Phase 1 gathering system	70		na
Raymondville gathering system(1)	48		na
Raymondville JT Plant	na		40
San Ignacio gathering system	6		na
TGP McAllen JT Plant and gathering system	13		40
Merit JT Plant	na		7

TOTAL Midstream Segments	4,799	146,100	466

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

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

(3)	Our net plant capacity is based on the recent plant expansion to 150 MMcf/d total capacity.

Index to Financial Statements

Below is a graph showing processing plant utilization. The graph shows the plant processing capacity by month and includes both acquisitions such as the Laser Midstream Acquisition and organic growth such as the start-up of the Red Deer 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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Index to Financial Statements

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, Roberts, Gray, Wheeler 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 2007 was approximately 163 MMcf/d. As of December 2007, Cimarex Energy and Chesapeake Energy represented 18.6% 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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Index to Financial Statements

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.

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Our Texas Panhandle Systems are located in the Texas Railroad Commission, or 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 2005 to 5.9 TCF at year-end 2006 in District 10. This area has experienced significant drilling activity during the last three years.

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 that has experienced substantial drilling and reserve growth since 2002.

The processing plants in our East Panhandle System are rapidly reaching capacity. In order to provide additional processing capacity to our East Panhandle System, we have constructed a 10-mile pipeline from the West Panhandle System to the East Panhandle System, and have refurbished and restarted a 20 MMcf/d processing plant. We are also looking to move processing plants located in the West Panhandle System and relocate those processing plants to the East Panhandle System where feasible.

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

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approximately 892 miles of natural gas gathering pipelines with approximately 44,000 horsepower of associated pipeline compression;

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Four active natural gas processing plants with an aggregate capacity of 96 MMcf/d;

Index to Financial Statements

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Two natural gas treating facilities with an aggregate capacity of 75 MMcf/d; and

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average gathered volumes of both wet and dry gas of approximately 104 MMcf/d for 2007.

Canadian Gathering System: The Canadian gathering system consists of 299 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to the Canadian Plant, Red Deer Plant, Cargray gathering system or the Arrington gathering system.

Canadian Plant: The Canadian plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Canadian gathering system. This plant was acquired by us in 2005.

Red Deer Plant: The Red Deer plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Canadian gathering system. This plant, acquired by us in 2005, has recently been refurbished and placed back in service in June 2007.

Arrington Gathering System: Arrington gathering system consists of 336 miles of natural gas gathering. The system gathers raw natural gas from producers and delivers the gas to the Arrington Plant.

Arrington Plant: The Arrington plant is a refrigerated lean oil natural gas processing plant that processes raw natural gas gathered on the Arrington gathering system. This plant was acquired by us in 2005. We are in the process of replacing this plant with a cryogenic processing plant.

System 97 Gathering System: The System 97 gathering system consists of 140 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.

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 H₂S that is removed prior to delivering the gas to the interstate pipeline system.

Natural Gas Supply. As of December 31, 2007, approximately 640 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 Devon Energy Production Company, L.P., Peak Operating of Texas LLC, Prize Operating Company 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 117 MMcf/d during the fourth quarter of 2007.

Natural gas from wells located in the area served by the East Panhandle System generally have a rate of decline of 10% to 15% after the first year of production. Approximately 72% 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 28% 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.

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, 2007, approximately 70%, 13%, 4% and 13% of our total throughput in the East Panhandle System was under percent-of-proceeds, fee-based, fixed recovery and keep-whole arrangements, respectively.

Index to Financial Statements

Competition. With the growth in the Granite Wash production, 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 production area. We expanded these systems during 2007 by approximately 24 MMcf/d by refurbishing and restarting the Red Deer cryogenic plant. In addition to this capacity, we have additional compression projects under construction to maintain low gathering pressures and to add 15 MMcf/d of additional outlet capacity in the first quarter of 2008. 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:

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approximately 2,916 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with approximately 81,500 horsepower of associated pipeline compression;

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four active natural gas processing plants with an aggregate capacity of 101 MMcf/d;

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three natural gas treating facilities with an aggregate capacity of 65 MMcf/d;

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a propane fractionation facility with capacity of 1,000 Bbls/d;

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a condensate collection facility; and

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average gathered volumes of both wet and dry gas of approximately 47 MMcf/d for 2007.

Cargray Gathering System: The Cargray gathering system consists of 1,275 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to Cargray Plant. The gathering system is a vacuum pressure gathering system gathering natural gas from very low volume wells.

Cargray Plant: The Cargray plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Cargray gathering system. This plant was acquired by us in 2005. The Cargray Plant includes a propane fractionation facility for producing specification propane for sales into local markets.

Gray Gathering System: The Gray gathering system consists of 518 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to Gray Plant. The gathering system is a vacuum pressure gathering system gathering natural gas from very low volume wells.

Gray Plant: The Gray plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Gray gathering system. This plant was acquired by us in 2005.

Lefors Gathering System: The Lefors gathering system consists of 663 miles of natural gas gathering pipelines The system gathers raw natural gas from producers and delivers the gas to Lefors Plant. The gathering system is a vacuum pressure gathering system gathering natural gas from very low volume wells.

Lefors Plant: The Lefors plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Lefors gathering system. This plant was acquired by us in 2005.

Stinnett Gathering System: The Stinnett gathering system consists of 451 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to Stinnett Plant. The gathering system is a vacuum pressure gathering system gathering natural gas from very low volume wells.

Index to Financial Statements

Stinnett Plant: The Stinnett plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Stinnett gathering system. This plant was acquired by us in 2005. We are in the process of shutting down the Stinnett Plant and redirecting the Stinnett gathering system natural gas to the Cargray Plant. The Stinnett Plant will then be relocated to the Arrington Plant in the East Panhandle System to replace the existing lean oil plant with a cryogenic processing plant.

Turkey Creek Gathering System: The Turkey Creek gathering system consists of 9 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to a third party plant. The gathering system is a vacuum pressure gathering system gathering natural gas from very low volume wells.

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.

Natural Gas Supply. As of December 31, 2007, approximately 1,500 wells and central delivery points were connected to our West Panhandle System. There are approximately 150 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 system throughput of approximately 46 MMcf/d during the fourth quarter of 2007.

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. The interstate pipelines to which the plants are connected have continued to waive their gas quality specifications requiring lower nitrogen 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 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 as 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, 2007, approximately 40%, 40%, and 20% 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 and to maintain equipment reliability for improved on line operations. In 2007, we approved a project to consolidate our Stinnett system into our Cargray system in order to achieve better overall utilization. The result will be the shutdown and redeployment of the Stinnett Plant which was running at a utilization rate of approximately 32% and increase in the Cargray Plant utilization rate to over 90%. The operating and efficiency gains will help us to remain competitive.

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 trucked and purchased by SemCrude, L.P. and Petro Source Partners, LP or injected into a pipeline and sold to ConocoPhillips. The condensate is sold under contract terms of one year or less.

Index to Financial Statements

East Texas/Louisiana Segment

Our East Texas/Louisiana operations are located primarily in 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. The following is a map of our East Texas/Louisiana Segment.

LOGO

Index to Financial Statements

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.

Systems Description. The facilities that comprise our East Texas/Louisiana operations, including the Laser transaction completed in May 2007, consist of:

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approximately 854 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with approximately 12,500 horsepower of associated pipeline compression;

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a 100 MMcf/d cryogenic processing plant;

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a 150 MMcf/d cryogenic processing plant, in which we own a 25% undivided interest;

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three JT processing plants with an aggregate capacity of 45 MMcf/d; and

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a 19-mile NGL pipeline.

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average gathered volumes of both wet and dry gas of approximately 133MMcf/d for 2007†

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

Brookeland/Masters Creek Gathering System: Brookeland/Masters Creek gathering system consists of 342 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to the Brookeland Plant.

Brookeland Plant: The Brookeland plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Brookeland/Masters Creek and Tyler County gathering system. This plant was acquired by us in 2006 through the Brookeland Acquisition.

Index to Financial Statements

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.

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.

Tyler County Gathering System: Tyler County gathering system consists of 62 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.

Panola Gathering System: The Panola gathering system consists of 29 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to the Panola JT plant.

Panola JT Plant: The Panola 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. This plant, which was acquired by us in 2007 through the Laser Acquisition.

Rosewood Gathering System: The Rosewood gathering system consists of 35 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to the Rosewood JT plant.

Rosewood JT Plant: The Rosewood 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. This plant was acquired by us in 2007 pursuant to the Laser Acquisition.

Belle Bower Gathering System: The Belle Bower gathering system consists of 68 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to the Belle Bower JT plant.

Belle Bower JT Plant: The Belle Bower 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. This plant was acquired by us in 2007 through the Laser Acquisition.

Vixen Gathering System: The Vixen gathering system consists of 7 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.

Sligo Gathering System: The Sligo gathering system consists of 10 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.

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.

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.

Natural Gas Supply. As of December 31, 2007, approximately 340 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

Index to Financial Statements

systems are situated in an active Austin Chalk drilling play in Tyler and Jasper Counties, Texas. The East Texas/Louisiana segment averaged gathered volumes of approximately 157 MMcf/d during the fourth quarter of 2007. As of December 2007, Ergon Exploration, Anadarko Petroleum and Goodrich Petroleum represented 22.3% 11.9% and 11.0%, 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, percent-of-liquids or percent-of-index arrangements. Natural gas is purchased at the wellhead from the producers under percent-of-proceeds contracts or keep-whole contracts or is gathered for a fee and redelivered at the plant tailgates. As of December 31, 2007, the percentage of natural gas under the contract structures were 46% fixed recovery, 37% fee based, 15% percent of proceeds and 2% purchased at the wellhead.

Markets. Residue gas remaining after processing is primarily taken in kind by the producer customers into the markets available at the tailgates of the plants. Some of the available markets are Houston Pipeline Company, Natural Gas Pipeline Company, Tennessee Gas Pipeline, Crosstex and Sonat. 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. and Enterprise Products Partners, L.P. The key drivers are high run time rates of the assets and low pressure gathering services. In 2007, we completed the extension of the Tyler County pipeline to interconnect with our Brookeland gathering system. This increased the capacity to gather natural gas by approximately 50 MMcf/d by adding an additional outlet to the Tyler County system. The additional pipeline outlet has increased the run time experienced by the producers on the Tyler County system. We have also approved and are under construction on a number of compressor projects in the East Texas area to expand our low pressure gathering services to our existing and new producers on the Rosewood system and the Belle Bower systems.

Index to Financial Statements

South Texas Segment

With the Laser Acquisition completed in May of 2007, we expanded the footprint of our midstream business into South Texas. Our South Texas operations are primarily located in Hidalgo, Willacy, Brooks, Zapata, Starr, Cameron, Colorado, Fort Bend, McMullen and San Patricio Counties. The South Texas systems primarily gather natural gas and recovers NGLs and condensate from natural gas produced in the Frio, Vicksburg, Miocene and Wilcox formations in Hidalgo, Willacy, Brooks, Zapata, Starr, Cameron, and Colorado Counties in South Texas. The South Texas operation also provides producer services by purchasing natural gas at the wellhead for sale into third party pipeline systems. The following is a map of our South Texas Segment.

Index to Financial Statements

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:

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Approximately 137 miles of natural gas pipeline ranging in size from two inches to 20 inches in diameter;

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Three main compressor stations with approximately 8,100 aggregate horsepower;

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

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

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average gathered volumes of both wet and dry gas of approximately 95 MMcf/d for the eight months we have owned these systems in 2007.

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.

Raymondville Gathering System: The Raymondville gathering system consists of 48 miles of natural gas gathering pipelines. The system gathers treated natural gas from producers and delivers the gas to multiple market outlets.

Raymondville JT Plant: The Raymondville 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 Raymondville gathering system.

Index to Financial Statements

San Ignacio Gathering System: The San Ignacio gathering system consists of 6 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.

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.

Merit JT Plant: The Merit 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 by us in 2007.

Natural Gas Supply. As of December 31, 2007, the South Texas Operations provide gathering and/or marketing services to approximately 160 producers. The South Texas systems operate approximately 46 meter stations for receipt or delivery of producer gas. The primary producers on the South Texas systems are Chesapeake, Samson, Cody and Royal. The Producer Services three largest producers are Century Exploration, Kebo Oil & Gas, and Rincon Petroleum. Natural gas production from wells located in the area served by the south Texas 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 92 MMcf/d during the fourth quarter of 2007. As of December 2007, Chesapeake Energy, Samson, XTO, Cody and Royal represented 26.3%, 22.6%, 11.0%, 10.6% and 10.0%, respectively, of the total volumes of our South Texas Segment.

On the South Texas 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. Producer Services 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 Pipeline. The natural gas is sold primarily at the delivery points into the interstate or intrastate pipeline systems to various customers. Producer Services three largest markets were Cypress Pipeline, Houston Pipeline, and Total Gas & Power North America.

Competition. Our primary competition in south Texas 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 offer 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. In 2007 we added a new market with 24 MMcf/d of capacity and are evaluating additional market outlets from the system. Producer Services 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 the Producer Services.

Upstream Business

As of December 2007, Exxon Mobil, Shell Trading and BP represented 37.1%, 13.3% and 13.0%, respectively of total revenues of our Upstream Segment.

Index to Financial Statements

Upstream Business Strategies

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Acquiring oil and 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:

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

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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 that are focused on that commodity.

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

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Operations—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.

The primary measures we use to assess the success of our acquisition program are distribution accretion, reserve life index, and internal rate of return.

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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; 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 distribution accretion, internal rate of return, and unit operating cost.

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Pursuing organic growth opportunities—In our Upstream Business, infill drilling and recompletions are the source of organic growth. We employ sound petroleum engineering and geological practices to identify and quantify these opportunities, and pursue them in a manner that seeks to reduce risk and cost. We measure the success of these projects by their distribution accretion, internal rate of return, and unit development cost.

Upstream Competitive Strengths

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

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We have sufficient financial flexibility to pursue significant acquisitions.

Index to Financial Statements

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

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, 2007.


Field	Location	Average net daily production rate in December 2007			Gross producing wells in December 2007
Field	Location	Oil, Bbl/d	Natural gas, MMcf/d	Natural gas liquids, Bbl/d	Operated	Non- Operated
Big Escambia Creek	Escambia County, Alabama	1,507	3,390	738	16	1
Ginger/Ginger SE	Rains County, Texas	158	694	280	7	1
Fanny Church	Escambia County, Alabama	397	1,573	57	4
Jourdanton	Atascosa County, Texas	11	2,680		10
Flomaton	Escambia County, Alabama	145	1,720		6
All others	various	343	2,057	272	31	78

Total		2,561	12,114	1,347	74	80

Big Escambia Creek. The Big Escambia Creek Field produces from the Smackover formation at depths ranging from approximately 15,000 to 16,000 feet. The reservoir is a sour, gas condensate reservoir whose produced fluids contain a high percentage of hydrogen sulfide and carbon dioxide. These impurities are extracted at the 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.

Ginger/Ginger Southeast. The production from these fields is from the Smackover formation at depths of approximately 12,000 to 13,000 feet. The produced fluids contain high levels of hydrogen sulfide and carbon dioxide. The full well stream is gathered by Regency Partners and delivered to their Eustace Plant, where it is treated for impurities and extraction of natural gas liquids for a combination of fees and percentage of proceeds.

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. 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 purified 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.

Jourdanton. The Jourdaton Field produces relatively dry gas from several members of the Edwards formation at depths from approximately 7,000 to 7,500 feet. The production has minor amounts of hydrogen sulfide, but at much lower concentrations than those encountered in our Smackover operations.

Flomaton. The Flomaton Field is adjacent to and partially underlies the Big Escambia Creek Field. It produces from the Norphlet formation at depths from approximately 15,000 to 16,000 feet. As is the case with the Smackover production in the area, the produced fluids from the Flomaton Field contain significant quantities of hydrogen sulfide and carbon dioxide. The produced fluids from Flomaton are treated in the same manner as from the Fanny Church Field.

Index to Financial Statements

Proved Reserves

The following table presents the Partnership’s estimated net proved natural gas and oil reserves in the Upstream Business on December 31, 2007. These values are based on reserve reports prepared by Cawley, Gillespie & Associates, Inc.


	As of December 31, 2007
Reserve Data: Upstream Segment
Estimated net proved reserves:
Natural gas (Bcf)	39.226
Oil (MMBbls)	7.275
Natural Gas Liquids (MMBbls)	5.743
Total (Bcfe)	117.334
Proved developed (Bcfe)	107.047
Proved developed reserves as % of total proved reserves	91	%

(source: CGA Proved Reserves Estimate)

Productive Wells

On December 31, 2007 we operated 9 gross (5.9 net) productive oil wells and 65 gross (55.3 net) productive natural gas wells. We owned working interests in an additional 80 gross (3.2 net) productive natural gas wells that were non-operated.

Developed and Undeveloped Acreage

The following table describes the leasehold acreage we owned on December 31, 2007. (This table also includes very minor amounts of leasehold that are included in our Minerals segment).


	Developed Acreage(1)		Undeveloped Acreage(2)		Total Acreage
	Gross(3)	Net(4)	Gross(3)	Net(4)	Gross	Net
Operated	52,451	39,233	945	399	53,396	39,632
Non-operated	23,532	1,726	40	31	23,572	1,757
Total	75,983	40,959	985	430	76,968	41,389

(1)	Developed acres are acres spaced 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 Activity

In 2007, we completed the drilling of 2 wells (1.02 net), both of which were classified as development wells and for when drilling had begun prior to our acquisitions of these companies. Both wells were productive. We did not drill any wells in 2005 or 2006.

On December 31, 2007, we were in the process of completing 1 additional well (0.65 net). This well was subsequently deemed to be productive.

Index to Financial Statements

Minerals Business

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 over 2,500 producing wells in 17 states and the Gulf of Mexico. We do not operate the majority of these properties, but we do have small mineral interests underlying several of our Escambia Upstream assets.

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

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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. These types of interest 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 involves an important trade-off, however: they do not bear any of the costs of drilling or production (other than certain production taxes), but their 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.

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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 the operation of the wells and drilling future ones. The mineral interest owner receives a portion of the revenues from the sale of the products of the wells.

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Their 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 mineral lease, and are only valid so long as the underlying lease is valid. Many leases last for decades, however.

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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 or 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.

Because our Minerals Business consists almost entirely 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.

Minerals Competitive Strengths

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

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We have sufficient financial flexibility to pursue significant acquisitions.

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

Index to Financial Statements

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, 2007. These volumes are based on reserve reports prepared by Cawley, Gillespie & Associates, Inc.


Reserve Data: Minerals Segment
Estimated net proved reserves:
Natural gas (Bcf)	5.417
Oil (MMBbls)	2.806
Total (Bcfe)	22.253
Proved developed (Bcfe)	22.253
Proved developed reserves as % of total proved reserves	100	%

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 oil 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.

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

Another significant asset in the Mineral 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 is approximately 220 Mcf/d of natural gas per day, which represents approximately 6% of our gas production in the Minerals Business.

Ivory Acquisitions Partners, L.P.

The majority of our mineral interests (all but approximately 10,000 net mineral acres) are related to our ownership in Ivory Acquisition Partners, LP (“IAP”). This is a private partnership, of which we own approximately 13.2% of the limited partner units, that was formed in 2004 to acquire the mineral assets of 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 partnership is managed by Black Stone Minerals Company (“BSMC”) who, in addition to performing a number of management duties on behalf of the limited partners, holds the executive rights of the mineral interests. Because we own direct title to the interests we acquired through our investment in IAP, we account for the revenues and expenses related to them in our consolidated financial statements.

Also in our Minerals Business is a 13.2% equity interest in Ivory Working Interests, LLC (“IWI”). This entity owns non-operating working interests in some of the wells in which we own a mineral interest, and is also managed by BSMC. We do not own direct title to the working interests of IWI, so it is accounted for under the equity method.

Index to Financial Statements

Under the agreements that exist between IAP, IWI and BSMC, IWI has the right to use the revenues generated in IAP 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. Since inception, this has not occurred.

Regulation of Our Operations

Safety and Maintenance Regulation

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act of 1970, referred to as OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection and auditing designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.

Our upstream activities related to the working interests we acquired via the EAC and Redman transactions are also subject to a number of federal and state laws and regulations whose purpose is to protect the health and safety of workers and the general public. In addition to the OSHA regulations described above, we are also subject to a number of regulations relating to the drilling and operation of oil and natural gas wells, and their related production equipment. The purpose of these is to regulate the drilling and operation of wells to protect the safety of workers and the public, and to avoid environmental damage. We are also subject to additional state regulations that relate to wells and facilities that produce hydrocarbons which contain hydrogen sulfide (“sour production”).

FERC Regulation in General

Under the Natural Gas Act of 1938, or NGA, as amended by the Energy Policy Act of 2005, or EPA 2005, FERC 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 maintains substantial enforcement authority, including the ability to assess civil penalties, order disgorgement of profits and recommend criminal penalties.

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. Certain provisions of the NGA—principally those having to do with market manipulation—were modified by EPA 2005, and FERC retained after EPA 2005 regulatory influences over certain aspects of our business. FERC exercises jurisdiction over natural gas companies that provide natural gas pipeline transportation services in interstate commerce and its authority to regulate those services includes:

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the certification and construction of new facilities;

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the review and approval of cost-based transportation rates;

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the extension or abandonment of services and facilities;

Index to Financial Statements

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the maintenance of accounts and records;

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the acquisition and disposition of facilities; and

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the initiation and discontinuation of services.

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 under the Natural Gas Act. 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.

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 nonutility 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 DOT 192 and 195.

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

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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 and four miles of our MGS 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, the recently purchased Hesco Pipeline Company, LLC is 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.

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

Index to Financial Statements

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.

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. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action 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.

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

Index to Financial Statements

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:

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the location of wells;

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the method of drilling and casing wells;

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the surface use and restoration of properties upon which wells are drilled;

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the disposal of fluids and solids used in connection with our operations;

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air emissions associated with our operations;

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the plugging and abandoning of wells; and

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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.

Natural Gas Regulation. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’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 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 impair our operations that affect the environment 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; and imposing substantial liabilities on us for pollution resulting from our operations. The costs 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 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 clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, accidental releases or spills are associated with our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this trend will continue in the future.

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. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we 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. While there exists an exclusion from the definition of 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 hazardous wastes. 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 remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.

Index to Financial Statements

The 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 certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air emission-related issues, we do not believe that such requirements will have a material adverse affect on our operations.

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 EPA issued revised SPCC rules in July 2002 whereby SPCC plans are subject to more rigorous review and certification procedures. Pursuant to these revised rules, SPCC plans must be amended, if necessary to assure compliance, and implemented by no later than October 31, 2007. We believe that our operations are in substantial compliance with applicable Clean Water Act and analogous state requirements, including those relating to wastewater and stormwater discharges and SPCC plans.

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 subjects owners of certain facilities to strict, joint and potentially unlimited liability for containment and removal costs, natural resource damages and certain other consequences of an oil spill, where such spill is into navigable waters, along shorelines or in the exclusive economic zone of the U.S. Any unpermitted release of petroleum or other pollutants from our operations could also result in fines or penalties. OPA applies to vessels, offshore platforms and onshore facilities, including terminals, pipelines and transfer facilities. In order to handle, store or transport oil, shore facilities are required to file oil spill response plans with the United States Coast Guard, the United States Department of Transportation Office of Pipeline Safety (“OPS”) or the EPA, as appropriate.

Some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Contamination resulting from spills or releases of oil or gas is an inherent risk within our industry. To the extent that groundwater contamination requiring remediation exists along our pipeline systems as a result of past operation, we believe any such contamination could be controlled or remedied without having a material adverse effect on our financial position, but such costs are site specific and we cannot predict that the effect will not be material in the aggregate.

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, that are suspected of contributing to global warming. 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 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, various states have already adopted legislation

Index to Financial Statements

addressing greenhouse gas emissions from various sources, primarily power plants, and various 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 property, soil, groundwater or surface water. Some of our, oil and gas operations are located near populated areas and emissions or accidental releases could affect the surrounding properties and population.

Upstream Business and Minerals Business

We believe that our properties are in substantial compliance with applicable environmental laws and regulations, and have not resulted in any material environmental liabilities. To protect against potential environmental risk, we typically obtain Phase I environmental assessments by independent third party Environmental and Engineering consultants of the properties to be acquired.

A portion of our upstream business is derived from minerals, royalties, and overriding royalty interests. These interests are non-costbearing and we believe that we would not be liable or responsible for any environmental damage caused by the operator or other parties as a result of drilling or production activities on these particular properties. On our working interest properties, and particularly our operated properties, we are responsible for conducing the operations in a manner that complies with applicable environmental laws and regulations; we may be held liable if we fail to do so.

General. 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:

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require the acquisition of various permits before drilling commences;

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require the installation of expensive pollution control equipment;

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

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

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

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impose substantial liabilities for pollution resulting from our operations; and

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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.

These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a

Index to Financial Statements

significant impact on our operating costs. We believe that we and our operators substantially comply with all current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how future environmental laws and regulations may impact our properties.

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.

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 the leases, easements, rights-of-way, permits and licenses to be transferred to us require the consent of the grantor of such rights, which in certain instances is a governmental entity. Our general partner expects to obtain, prior to the closing of this offering, sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects as described in this prospectus. With respect to any material consents, permits or authorizations that have not been obtained prior to closing of this offering, the closing of this offering will not occur unless reasonable basis exist that permit our general partner to conclude that such consents, permits or authorizations will be obtained within a reasonable period following the closing, or the failure to obtain such 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, 2007, Eagle Rock Energy G&P, LLC or its affiliates employed approximately 270 people who provide direct support for our operations. None of these employees are covered by collective bargaining agreements. Our general partner considers its employee relations to be good.

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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., Investor Relations Department, 16701 Greenspoint Park Drive, Suite 200, Houston, TX 77060, or call 281-408-1329.

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.

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. Currently, natural gas prices are high in relation to historical prices. For example, the average NYMEX daily settlement price of natural gas has increased from $5.492 per MMBtu in 2003 to $7.11 per MMBtu in 2007. If the high price for natural gas were to decline, the level of drilling activity could decrease. A sustained decline in natural gas prices could result in a decrease in

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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.

Now that we have entered the 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 the 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 daily settlement price for natural gas for the prompt month contract in 2007 ranged from a high of $8.64 per MMBtu to a low of $5.38 per MMBtu. The NYMEX daily settlement price for crude oil for the prompt month contract in 2007 ranged from a high of $98.18 per barrel to a low of $50.48 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;

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

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

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the level of consumer product demand;

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

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overall domestic and global economic conditions;

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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;

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delays or cancellations of crude oil and natural gas drilling and production activities;

Index to Financial Statements

•

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. We may incur 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.

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, or the instruments we use may not adequately correlate with changes in the prices we receive. Our current hedging position is presented in Item 7A.—“Qualitative and Quantitative Disclosure About Market Risk.”

Index to Financial Statements

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 estimate at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimate, 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, 2007, we experienced positive movements in our underlying commodities’ prices which led to an unrealized derivative loss of $130.7 million. This $130.7 million loss had a direct impact on our net income (loss) line resulting in a net loss of $144.9 million. For additional information regarding our hedging activities, please read 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.

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.

Index to Financial Statements

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. 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:

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volume throughput through our pipelines and processing facilities;

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the estimated quantities of our oil and natural gas reserves;

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the amount of oil and natural gas produced from existing wells;

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the prices at which we sell our production or that of our midstream customers; and

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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.

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

Index to Financial Statements

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.

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 are success of the producer’s drilling programs, additions or cancellations of new agreements and acquisition of new systems. As of December 31, 2007, our two largest suppliers were affiliates of Chesapeake Energy Corporation and Cimarex Company, accounting for approximately 12.8% and 8.5%, respectively, of our natural gas supply. 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 a material 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 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.

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.

Index to Financial Statements

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.

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, but FERC regulation still affects these businesses 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, 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.

Index to Financial Statements

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 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:

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

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

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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

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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.

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,

Index to Financial Statements

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 Item 1. Business—Regulation of Our Operations.

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.

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,

Index to Financial Statements

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:

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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;

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an inability to integrate successfully the businesses we acquire;

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

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

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

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limitations on rights to indemnity from the seller;

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mistaken assumptions about the overall costs of equity or debt;

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decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;

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

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

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

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customer or key employee losses at the acquired businesses; and

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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.

Index to Financial Statements

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:

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geographically separated organizations and possible differences in corporate cultures and management philosophies;

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significant demands on management resources, which may distract management’s attention from day-to-day business;

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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

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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:

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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;

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inadvertent damage from construction, farm and utility equipment;

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leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of pipeline, equipment or facilities;

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fires and explosions; and

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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

Index to Financial Statements

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 do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. We are not insured against all environmental accidents that might occur which may include toxic tort claims, other than those considered to be sudden and accidental. 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.

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. Our level of debt could have important consequences to us, including the following:

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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, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect 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 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

Index to Financial Statements

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.

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

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:

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unexpected drilling conditions;

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drilling, production or transportation facility or equipment failure or accidents;

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shortages or delays in the availability of drilling rigs and other services and equipment;

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adverse weather conditions;

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compliance with environmental and governmental requirements;

•

title problems;

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unusual or unexpected geological formations;

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pipeline ruptures;

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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.

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

Our results of operations could be adversely affected by asset impairments.

If we expect significant sustained decreases in oil and natural gas prices in the future, we may be required to write down the value of our oil and gas properties if the future cash flows from these properties fall below their net book value. Future non-cash asset impairments could negatively affect our results of operations.

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

Index to Financial Statements

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.

The credit markets recently have experienced record lows in interest rates over the past several years. As the overall economy strengthens, it is likely that monetary policy will continue to tighten further, 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.

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 and South Texas and Louisiana and all of our upstream operated properties are located in 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.

Index to Financial Statements

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.

We have reported certain material weaknesses in our internal controls, and if we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud.

Prior to our initial public offering, which was completed on October 24, 2006, we were a private company and did not file reports with the SEC. We produce our consolidated financial statements in accordance with the requirements of GAAP, but our internal accounting controls currently do not meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports to prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future, including compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 requires us, among other things, annually to review and report on, and our independent registered public accounting firm to attest to, our internal control over financial reporting. We have reported certain material weaknesses with respect to our internal controls. Please see Item 9A. Internal Controls for a description of our material weaknesses. Continued failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls could harm our operating results or cause us to fail to meet our reporting obligations.

Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s, conclusions about the effectiveness of our internal controls and we may incur significant further costs in our efforts to comply with Section 404. Ineffective internal controls subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

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 and subordinated 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 common unit per complete quarter, or $1.45 per common unit per year, we will require available cash of approximately $26.4 million per quarter, or $105.4 million per year, based on the common units, restricted units under our Long Term Incentive Plan and subordinated units outstanding as of December 31, 2007. 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;

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

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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;

Index to Financial Statements

•

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

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

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

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

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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:

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the level of capital expenditures we make;

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the cost of acquisitions;

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our debt service requirements and other liabilities;

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fluctuations in our working capital needs;

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our ability to borrow funds and access capital markets;

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restrictions contained in our debt agreements; and

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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, 2007, 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 $74.2 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 $105.4 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.

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

Index to Financial Statements

interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

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

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

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

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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;

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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;

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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;

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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;

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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;

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

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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.

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

Index to Financial Statements

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:

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its limited call right;

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its voting rights with respect to the units it owns;

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its registration rights; and

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

Index to Financial Statements

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;

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

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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

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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:

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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

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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

Index to Financial Statements

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.

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:

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our unitholders’ proportionate ownership interest in us will decrease;

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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;

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the relative voting strength of each previously outstanding unit may be diminished; and

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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), certain private investors and certain employees of Eagle Rock Energy G&P, LLC hold, as of December 31, 2007, an aggregate of 51,166,709 common units, including 467,062 common units which are still subject to a vesting requirement, and 20,691,495 subordinated units. Of that number, 27,873,812 common units have been registered for resale to the public. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. Based on recent amendments to Rule 144 as promulgated under the Securities Act of 1933, as amended, many of these common units will be subject to resale after February 15, 2008. The sale of these 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, which requires us to file with the SEC a registration statement registering for resale to the public Holdings’ units.

Index to Financial Statements

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, 2007, our general partner and its affiliates owned approximately 25.2% 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 46.6% of our outstanding common units.

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:

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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

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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.

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.

Index to Financial Statements

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.

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. Members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly-traded partnerships. For example, federal income tax legislation has been proposed that would eliminate partnership tax treatment for certain publicly-traded partnerships. Although the currently proposed legislation would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. 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 will, for example, be subject to a new entity level tax on the portion of our income that is generated in Texas beginning in our tax year ending December 31, 2007. Specifically, the Texas tax will be imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such a tax on us by Texas, or any other 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.

Index to Financial Statements

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.

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. 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.

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.

Index to Financial Statements

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 foreign, 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 foreign, 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, foreign, 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. 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 or our business.

While we own our facilities, plants and gathering systems, in many cases, we do no 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

Item 3.

Legal Proceedings.

Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we are and may, at any given time, be a 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. We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our

Index to Financial Statements

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.

Item 4.

Submission of Matters to a Vote of Security Holders.

Not applicable.

Index to Financial Statements

PART II

Item 5.

Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

Our common units have been listed on the Nasdaq Global Select Market under the symbol “EROC.” The following table sets forth 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 from our initial public offering date, October 24, 2006, through December 31, 2007.


Quarter Ended	High		Low		Distribution per Unit			Record Date	Payment Date
December 31, 2006	$	20.70	$	17.50	$	0.2679	(1)	Feb. 7, 2007	Feb. 15, 2007

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

(1)	Represents a prorated distribution to the common unitholders from the IPO date of October 24, 2006 through December 31, 2006.

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 prospectus.

The last reported sale price of our common units on the Nasdaq Global Select Market on March 28, 2008, was $14.38. As of that date, there were 259 holders of record and approximately 8,900 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. 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 1.16% 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 1.16% 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.

Index to Financial Statements

Sales of Unregistered Securities

There were no sales of securities by the Partnership in the fourth quarter of 2007.

The following table sets for certain information with respect to repurchases of our common units during the three months ended December 31, 2007:


Period	Total Number of Units Purchased(1)	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 Plans or Programs
October 1 – October 31	7,114	$	21.69	—	—
November 1 – November 30	—		—	—	—
December 1 – December 31	—		—	—	—

(1)

All of the units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units awarded on October 25, 2006. As a result, we are deeming the surrenders to be “repurchases”. These repurchases were not part of a publicly announced program to repurchase our common units, nor do we have a publicly announced program to repurchase our common units.

Item 6.

Selected Financial Data.

The following table shows selected historical financial data of our predecessor, ONEOK Texas Field Services L.P. and 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 Eagle Rock Energy Partners, L.P. 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 2003 and 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 NGL puts, costless collars and swaps, crude costless collars and natural gas calls, as well as interest rate swaps that we accounted for using mark-to-market accounting. The amounts related to commodity

Index to Financial Statements

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 do not include the financial results of our existing East Texas assets (Indian Springs, Camp Ruby and Live Oak County assets).

•

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/Masters Creek 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, 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 periods 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 from Montierra Minerals & Production, L.P. and 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 periods 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 periods for the periods prior to May 2007 do not include the financial results from these assets.

•

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 periods 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 Company, 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 periods 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. (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) 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 periods for the periods prior to July 2007 do not include the financial results from these assets.

•

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

Index to Financial Statements

The selected historical financial data as of and for the year ended December 31, 2003, 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, 2003, 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 and 2007 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 income tax provision, interest-net (including both realized and unrealized interest rate risk management activities), depreciation, depletion, and amortization expense, other operating expense, other non-cash operating and general and administrative expenses (including non-cash compensation related to our equity-based compensation program) less non-realized revenues risk management instrument gain (loss) activities and other income/expense. Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash 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 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. 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.”

Index to Financial Statements


	Eagle Rock Predecessor									Eagle Rock Pipeline, L.P.									Eagle Rock Energy Partners, L.P.
	Year Ended December 31, 2003			Year Ended December 31, 2004			Period from January 1, 2005 to November 30, 2005			Year Ended December 31, 2003			Year Ended December 31, 2004			Year Ended December 31, 2005(1)			Year Ended December 31, 2006			Year Ended December 31, 2007
Statement of Operations Data:
Sales to external customers	$	297,290		$	335,519		$	396,953		$	—		$	10,636		$	66,382		$	502,394		$	910,632
Unrealized derivative gains/(losses)		—			—			—			—			—			7,308			(26,306	)		(130,773	)
Realized derivative gains/(losses)		—			—			—			—			—			—			2,302			(3,061	)

Total revenues		297,290			335,519			396,953			—			10,636			73,690			478,390			776,798
Cost of natural gas and NGLs		249,284			263,840			316,979			—			8,811			55,272			377,580			686,882
Operating and maintenance expense		22,395			25,219			25,326			—			34			2,955			32,905			52,793
Non-income based taxes		1,510			2,208			2,192			—			—			149			2,301			8,340
General and administrative expense		—			—			—			144			2,406			4,616			10,860			27,799
Other operating		—			—			—			—			—			—			—			2,847
Advisory termination fee		—			—			—			—			—			—			6,000			—
Depreciation, depletion, amortization and impairment expense		7,187			8,268			8,157			—			619			4,088			43,220			86,308

Operating income (loss)		16,914			35,984			44,299			(144	)		(1,234	)		6,610			5,524			(88,171	)
Interest (income) expense		(189	)		(646	)		(859	)		—			—			4,031			28,604			50,924
Other (income) expense		(52	)		(23	)		(17	)		—			(24	)		(171	)		(996	)		6,370

Income (loss) before income taxes		17,155			36,653			45,175			(144	)		(1,210	)		2,750			(22,084	)		(145,465	)
Income tax provision		6,071			12,731			15,811			—			—			—			1,230			169

Income (loss) from continuing operations		11,084			23,922			29,364			(144	)		(1,210	)		2,750			(23,314	)		(145,634	)
Discontinued operations		—			—			—			533			22,192			—			—			—
Cumulative effect of change in accounting principle		227			—			—			—			—			—			—			—

Net income (loss)	$	10,857		$	23,922		$	29,364		$	389		$	20,982		$	2,750		$	(23,314	)		(145,634	)

Loss per common unit	$	—		$	—		$	—		$	—		$	—		$	—		$	(1.26	)		(2.11	)


Balance Sheet Data (at period end):
Property plant and equipment, net	$	246,640		$	243,939		$	242,487		$	18,529		$	19,564		$	441,588		$	554,063		$	1,207,130
Total assets		259,577			304,631			376,447			21,379			28,017			700,659			779,901			1,609,927
Long-term debt		—			—			—			14,221			—			408,466			405,731			567,069
Net equity		180,422			204,344			233,708			6,629			27,655			208,096			291,987			726,768

Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	32,219		$	41,813		$	47,603		$	(337	)	$	3,652		$	(1,667	)	$	54,992		$	106,945
Investing activities		(5,203	)		(5,567	)		(6,708	)		(18,282	)		16,918			(543,501	)		(134,873	)		(475,790	)
Financing activities		(27,016	)		(36,246	)		(40,895	)		20,240			(13,955	)		556,304			71,088			426,816
Other Financial Data:
Cash distributions per Common Unit (declared)	$	—		$	—		$	—		$	—		$	—		$	—		$	0.2679		$	1.455

Adjusted EBITDA(2)	$	23,926		$	44,275		$	52,473		$	(144	)	$	(591	)	$	3,561		$	81,192		$	133,357

(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.

Index to Financial Statements

(2)

Excludes $7.3 million in unrealized derivative gains for the year ended December 31, 2005, $26.3 million in unrealized derivative losses for the year ended December 31, 2006 and $144.2 million for year ended December 31, 2007. Excludes $0.1 of non-cash LTIP compensation expense for the year ended December 31, 2006 and $2.4 million for the year ended December 31, 2007. Excludes, in the year ended December 31, 2007, $2.8 million of other operating expenses, which includes severance payments of $0.3 million, litigation settlement of $1.4 million and liquidated damages of $1.1 million for late registration of common units. Excludes, in the year ended December 31, 2007, an impairment charge of $5.7 million. Excludes $0.5 million in 2003 and $22.2 million in 2004 of income from discontinued operations.

Non-GAAP Financial Measures

We include in this filing the following non-GAAP financial measure: Adjusted EBITDA (as defined on page 71). 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 earnings 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.

Index to Financial Statements


	Eagle Rock Predecessor									Eagle Rock Pipeline, L.P.									Eagle Rock Energy Partners, L.P.
	Period from January 1, 2005 to November 30, 2005			Year Ended December 31, 2004			Year Ended December 31, 2003			Year Ended December 31, 2005(1)			Year Ended December 31, 2004			Year Ended December 31, 2003			Year Ended December 31, 2006			Year Ended December 31, 2007
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	$	47,603		$	41,813		$	32,219		$	(1,667	)	$	3,652		$	(337	)	$	54,992		$	106,945
Add (deduct):
Depreciation, depletion, amortization and impairment		(8,157	)		(8,268	)		(7,187	)		(4,088	)		(1,174	)		(98	)		(43,220	)		(86,308	)
Amortization of debt issue cost		—			—			—			(76	)		—			—			(1,114	)		(1,777	)
Risk management portfolio value changes		—			—			—			5,709			—			—			(23,531	)		(136,132	)
Advisory termination fee																				(6,000	)		—
Net realized gain on derivatives		—			—			—			—			—			—			978			(1,667	)
Other		—			—			—			(6	)		—			—			(1,566	)		(8,235	)
Gain on sale of Dry Trail plant		—			—			—			—			19,465			—			—			—
Provision for deferred income taxes		(1,559	)		(7,325	)		(10,943	)		—			—			—			—			—
Accounts receivable and other current assets		56,599			30,905			23,791			43,179			(901	)		883			1,432			16,579
Accounts payable, due to affiliates and accrued liabilities		(64,320	)		(34,705	)		(21,363	)		(40,197	)		(169	)		(192	)		(8,777	)		(34,374	)
Other assets and liabilities		(802	)		1,502			(5,660	)		(104	)		109			133			3,492			(665	)

Net income (loss)		29,364			23,922			10,857			2,750			20,982			389			(23,314	)		(145,634	)

Add:
Interest (income) expense, net		(859	)		(646	)		(189	)		4,031			—			—			30,383			44,587
Depreciation, depletion, amortization and impairment		8,157			8,268			7,187			4,088			619			—			43,220			86,308
Income tax provision (benefit)		15,811			12,731			6,071			—			—			—			1,230			169

EBITDA(2)	$	52,473		$	44,275		$	23,926		$	10,869		$	21,601		$	389		$	51,519		$	(14,570	)

ADJUSTED EBITDA(3)	$	52,473		$	44,275		$	23,926		$	3.561		$	(591	)	$	(144	)	$	81,192		$	133,357

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

(2)

Includes $7.3 million in unrealized derivative gains for the year ended December 31, 2005, $26.3 million in unrealized derivative losses for the year ended December 31, 2006 and $134.5 million in unrealized derivative losses for the year ended December 31, 2007. Excludes $0.5 million in 2003 and $22.2 million in 2004 of income from discontinued operations. Includes $0.1 of non-cash LTIP compensation expense for the year ended December 31, 2006 and $2.4 million for the year ended December 31, 2007. Includes, in the year ended December 31, 2007, $2.8 million of other operating expenses, which includes severance payments of $0.4 million, litigation settlement of $1.4 million and liquidated damages of $1.0 million for late registration of common units.

(3)

Index to Financial Statements

The following table summarizes our quarterly financial data for 2007.


	For the Quarters Ended
	December 31, 2007			September 30, 2007(1)			June 30, 2007(1)			March 31, 2007(1)
	($ in thousands)
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			—
Risk management instrument—realized transactions		(7,385	)		(177	)		1,502			2,999
Risk management instrument—unrealized		(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 provision		(603	)		352			256			164
Other expense (income)		6,866			(352	)		619			397

Net income (loss)	$	(111,554	)	$	9,371		$	(23,783	)	$	(19,668	)

Earnings per unit—basic
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.

The following table summarizes our quarterly financial data for 2006.


	For the Quarters Ended
	December 31, 2006(1)			September 30, 2006(1)			June 30, 2006(1)			March 31, 2006(1)
	($ in thousands)
Sales of natural gas, NGLs and condensate	$	113,909		$	132,830		$	123,250		$	116,922
Gathering and treating services		4,367			4,549			4,192			1,754
Risk management instrument—realized transactions		2,180			(449	)		(240	)		811
Risk management instrument—unrealized		(4,975	)		14,480			(14,931	)		(20,881	)
Other revenues		185			109			147			180

Total operating revenues		115,666			151,519			112,418			98,787
Cost of natural gas and NGLs		88,699			100,645			93,807			94,429
Operating and maintenance expense		9,810			9,878			9,419			6,100
General and administrative expense		3,255			2,314			3,144			2,145
Advisory termination fee		6,000			—			—			—
Depreciation and amortization expense		11,762			11,244			11,001			9,214
Interest—net including realized risk management instrument		7,490			7,881			7,541			7,471
Unrealized risk management interest related instrument		(136	)		6,449			(4,113	)		(4,975	)
Income tax provision		486			236			508			—

Net (loss) income	$	(11,700	)	$	12,872		$	(8,889	)	$	(15,597	)

Earnings per unit—basic
Common units	$	(0.09	)	$	0.44		$	(0.31	)	$	(0.63	)
Subordinated units	$	(0.46	)	$	0.44		$	(0.31	)	$	(0.63	)
General partner	$	(0.46	)	$	0.44		$	(0.31	)	$	(0.63	)

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

Index to Financial Statements

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 growth-oriented publicly traded Delaware limited partnership engaged in the following three businesses:

•

Midstream Business—gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs;

•

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

•

Minerals Business—acquiring and managing fee minerals and royalty interests.

We report on our businesses in six accounting segments.

We conduct, evaluate and report on our Midstream Business within three distinct segments—the Texas Panhandle Segment, the East Texas/Louisiana Segment (formerly referred to by us in prior filings and records as our Southeast Texas and North Louisiana Segment), and South Texas 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/Louisiana. Our South Texas Segment consists of gathering systems and related compression and processing facilities in South Texas.

We conduct, evaluate and report on our Upstream Business as one segment. Our Upstream Segment includes operated wells in Escambia County, Alabama and 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 East and South Texas in Rains, Van Zandt, Henderson and Atascosa Counties.

We conduct, evaluate and report on our Minerals Business as one segment. Our Minerals Segment consists of certain fee minerals, royalties, overriding royalties and non-operated working interest properties, located in multiple producing trends across the United States, and interests in mineral acres and wells.

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.

We have an experienced management team dedicated to growing, operating and maximizing the profitability of our assets. Our management team is experienced in gathering and processing natural gas, operation of oil and natural gas properties and assets, and management of royalties and minerals.

Acquisitions

Historically, we have grown through acquisitions. During 2007, we grew by 79.8%, based on gross revenues, excluding unrealized commodity derivative impact, for the year ended December 31, 2007, as compared to the year ended December 31, 2006. With the Montierra Acquisition, described below, completed in the second quarter of 2007, we expanded our business from solely a midstream company to an upstream minerals company as well. With our Redman and EAC Acquisitions, described below, we further expanded our presence in the upstream business by adding operator working interests as well as other oil and natural gas interests and properties.

Index to Financial Statements

Going forward in 2008 and beyond, 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 2007.

Montierra Acquisition

On April 30, 2007, we completed the acquisition of (by direct acquisition or acquisition of certain entities) certain fee minerals, royalties and working interest properties from Montierra Minerals & Production, L.P. and NGP-VII Income Co-Investment Opportunities, L.P. (the “Montierra Acquisition”). We paid consideration that totaled 6,458,946 (recorded value of $133.8 million) of our common units and $5.4 million of cash. The assets acquired include interests in over 2,500 wells in multiple producing trends across 17 states in the United States, interests in approximately 5.6 million gross mineral acres or 430,000 net mineral acres, and interests in over 2,500 well with net proved producing reserves, as of the date of the Montierra Acquisition, of approximately 4.5 billion cubic feet of natural gas and 3.5 million barrels of crude oil.

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”). We 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 over 405 miles of gathering systems and related compression and processing facilities in South Texas, East Texas/Louisiana.

MacLondon Acquisition

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

EAC Acquisition

On July 31, 2007, we completed the acquisition of Escambia Asset Co., LLC and Escambia Operating Company, 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 this transaction included 31 operated productive wells in Escambia County, Alabama with net production of approximately 3,300 Boe/d and proved reserves at the time of acquisition of approximately 11.8 MMBoe, of which 93% is proved developed producing. The transaction also included two treating facilities with 100 MMcf/d of capacity, one natural gas processing plant with 40 MMcf/d of capacity and related gathering systems.

Redman Acquisition

On July 31, 2007, Eagle Rock Energy 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 assets

Index to Financial Statements

conveyed in the Redman Acquisition included 45 operated and 78 non-operated productive wells mainly located in East and South Texas with a net production of 1,810 Boe/d and combined proved reserves at the time of acquisition of 8.1 MMBoe, of which 78% is proved developed producing.

Presentation of Financial Information

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

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.

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.

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 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 an 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, 2007, we incurred an impairment charge in our Minerals Segment of $5.7 million as a result of steeper decline rates in certain fields.

Index to Financial Statements

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.

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 Sales Recognition. We record revenue and cost of sales 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.

We currently record the monthly results of operations using primarily actual results which include settling most of our volumes with producers, shippers and customers around the 25th of the month following the production month. This process results in us reporting later than other similar partnerships that report on estimates.

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 five 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.

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 January 2011 for our interest rate hedges, and December 2012 for our commodity hedges. The option premium costs we incurred as part of our Panhandle acquisition are being expensed through the unrealized risk management instruments in total revenue. We monitor and review hedging positions regularly.

Index to Financial Statements

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 the Consolidated Financial Statements, depreciation of our midstream assets is generally computed using the straight-line method over the estimated useful life of the assets. The costs of renewals and betterments which extend the useful life of property, plant and equipment are also capitalized. The costs of repairs, replacements and maintenance projects are expensed as incurred.

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

Impairment of Long-Lived Assets—We assess our long-lived assets for impairment 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;

•

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.

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, 2007, we have recorded a $2.4 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 $11.3 million for future asset retirement obligations in its midstream and upstream operations. Related accretion expense has been recorded in operating expenses (See Note 5 to the Consolidated Financial Statements).

Index to Financial Statements

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 on a company-wide basis.

Volumes (by Operational Segments)

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 a couple of legacy non-operating working interests, and therefore, we do not operate any of these properties. In order to maintain or increase our cash flows from our Minerals Segment, we are reliant 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 (with the exception of the two wells in which we own legacy working interests). The level of drilling and recompletion activity conducted by the operators of our mineral interests is a function of many factors beyond our control, such as commodity prices, availability of oilfield goods and services, and the requirements and limitations placed by various legislative and regulatory entities. 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.

Commodity Pricing

Our margins in our Midstream Segment 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. Both in our Upstream and Minerals Segments, increases in crude oil, natural gas and NGL prices will generally favorably impact our revenues.

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, this committee

Index to Financial Statements

meets regularly to review the hedge portfolio and make recommendations for additional hedges. They routinely estimate the potential effect of price and interest rate fluctuations on the expected future cash flows associated with our existing operations, and they evaluate whether the hedges sufficiently mitigate the effect of these fluctuations. Our risk management activities are captured in our Corporate Segment.

Operating Expenses

Midstream Operating Expenses. Operating expenses are a separate measure we use to evaluate operating performance of 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 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 staffs. The majority of the cost of operating these facilities is independent of their throughput. This includes items such as labor, chemicals, materials, and insurance.

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

We define Adjusted EBITDA as net income (loss) plus income tax provision, interest-net (including both realized and unrealized interest rates risk management activities), depreciation, depletion and amortization expense, other operating expense, other non-cash operating and general and administrative expenses (including non-cash compensation related to our equity-based compensation program) less non-realized revenues risk management instrument gain (loss) activities and other income/(expense). Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash 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 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.

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.

Index to Financial Statements

Natural Gas Supply and Demand

Natural gas is a significant source of energy and raw materials in the United States. The graph depicts the annual domestic natural gas consumption from 1997 to 2006, both in total and by the consuming sector of the economy. The data exclude consumption that occurs in delivering the natural gas to the consumer (lease, plant and pipeline uses), as well as the relatively insignificant amount consumed as vehicle fuel. Together, these activities consume approximately 1.7 Tcf per year.

LOGO

During this period, domestic natural gas consumption by end users declined very slightly to its current level of approximately 20 Tcf per year. Notable shifts have occurred in this period, however, between the categories of consumption. Most significant are the decline in consumption in the industrial category (-3.0% CAGR) and the rise in consumption in power generation (4.8% CAGR). Residential and commercial consumption have both declined slightly (-1.5% and -1.4% CAGR, respectively).

We believe these changes in consumption patterns reflect a number of economic and social factors in the United States including the movement of manufacturing operations to other countries, relatively low population growth, increased productivity and fuel efficiency, the relocation of large numbers of people from northern to southern latitudes, and the attractiveness of natural gas as a fuel for electricity generation. It is important to note that demand within certain categories of consumption (as well as total consumption) have been relatively inelastic with respect to the price of natural gas. According to the EIA, natural gas wellhead prices averaged $2.32/Mcf for 1997; by 2006, this had risen to $6.40/Mcf. Prices paid by the various consuming sectors reflect similar significant increases.

As expected, natural gas supply exhibits similar behavior as natural gas consumption. The chart below shows natural gas supplied to the United States in total and from three sources: domestic production, net pipeline imports, and net LNG imports. (The total supply is slightly higher than that shown on the consumption graph

Index to Financial Statements

because the data in the consumption graph excluded the various lease, plant and pipeline uses that occur prior to delivering the natural gas to consumers.)

LOGO

Domestic production declined slightly in this period, while net pipeline imports increased initially (primarily from Canada) but have recently declined. These declines have been partially offset by increases in net LNG imports.

In the future, there are a number of factors that could increase domestic supply, and potentially put downward pressure on natural gas prices. These include increased natural gas production from the Rockies after completion of the Rockies Express Pipeline, and increases in LNG imports. Nevertheless, these increases in supply may not be sufficient to offset the natural decline of existing domestic wells and continued declines in natural gas imported via pipeline. Since 1997, the number of domestic producing natural gas wells (which account for approximately 75% of domestic natural gas production) increased by 44%, while the total domestic production declined slightly. The average natural gas well produced 58Mcf/d in 1997; by 2006, this value was 40 Mcf/d. While an economic recession in the United States could reduce demand, we also believe that lower natural gas prices, combined with a weak dollar, would result in diversion of LNG cargoes to more lucrative markets, effectively reducing supply and providing support for prices.

Consequently, our outlook for natural gas prices is for them to remain near their current levels, except for short term price fluctuations related to seasonal demand and natural gas storage factors. Nevertheless, we recognize that declining natural gas prices could jeopardize our ability to make cash distributions to our unitholders, so we utilize derivative instruments to reduce the volatility in the prices we receive for the natural gas we produce (see “Risk Management Activities”). Consistent with our expectation for strong natural gas prices is our belief that natural gas well drilling activity will continue to remain robust.

Index to Financial Statements

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. It is plainly evident that 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.

Currently, worldwide demand for petroleum has never been higher, and as of the spring of 2008, real prices for crude oil were at historical highs. During the period from 1997 to 2006 (the latest for which final, complete year figures are available from the Energy Information Agency), worldwide demand for petroleum (including condensate and NGL’s) increased at a 1.9% CAGR. This increase in demand was due in large part to the demand increase in China (8.1% CAGR), Russia (2.4% CAGR) and India (3.4% CAGR). In 2006, these countries were the second, fourth, and sixth largest consuming countries of petroleum. From 1997 to 2006, petroleum consumption growth for the rest of the world was only 1.3% CAGR, indicating that a large portion of worldwide growth was attributable to these populous countries. We expect the underlying economic factors that have contributed to the rapid increases in petroleum consumption in countries like China and India, such as globalization and market liberalization, will continue, and that demand for petroleum will remain high and increasing. We also expect to see significant rates of consumption growth in economies that are predominantly petroleum-based (such as the Middle Eastern countries and Russia), at least so long as oil prices remain high.

The United States is the world’s largest consumer of petroleum (24% in 2006), and its consumption has increased 1.0% CAGR during this period, which is approximately equal to its estimated population growth rate of 0.9% (United States Census Bureau). We expect this rate of consumption growth to decline slightly over the near term due to the potential economic recession, the increasing dollar cost of petroleum, and the desire of many American’s to reduce petroleum consumption due to environmental concerns.

With respect to petroleum supply, we believe that the most significant issue affecting supply, other than higher prices, has been the continued concentration of a very high percentage of the world’s petroleum reserves in the hands of national oil companies. According to a report prepared in 2007 for the United States Congress by the Congressional Research Service, all of the world’s top ten reserve holders (except Lukoil) was a state-owned oil company. These companies controlled an estimated 81% of the world’s reserves, and had an average reserve life index of 78. In contrast, the world’s five largest international oil companies had reserves with a reserve life index of 11.

National oil companies are subject to a variety of forces beyond market forces, and they do not always act in ways that maximize value, production or ultimate recovery. Many national oil companies are in countries in which petroleum production is the primary, sometimes only, source of exports, and the revenues are used for a variety of social purposes. Investment in new wells, and the use of proper reservoir management techniques is often secondary to the immediate needs of these social obligations. As a result, the national oil companies of some of these countries, notably Mexico and Venezuela, have recently experienced stagnant or declining production rates. In addition to these issues, petroleum production in other large, mature producing regions (the United States, Norway, and the United Kingdom) continues to decline, and political unrest and terrorism have had an adverse affect on production in other countries, such as Iraq and Nigeria.

We also note that this current period of high prices has not been caused by the overt restriction of petroleum production by OPEC or other significant producers. We believe that producing countries are working very hard to meet demand, and that further significant increases in demand may require higher prices to justify additional production.

Index to Financial Statements

We believe that the balance of supply and demand forces will result in continued high oil prices, barring a significant worldwide recession. As is the case with natural gas, we recognize that declining natural gas prices could jeopardize our ability to make cash distributions to our unitholders, so we utilize derivative instruments to reduce the volatility in the prices we receive for the crude, condensate, and natural gas liquids we produce (see “Risk Management Activities”).

Impact of Interest Rates and Inflation

Worldwide credit markets are experiencing a high level of turmoil and uncertainty regarding the scope and duration of the impact of the United States subprime mortgage crisis. We believe that these effects will persist through 2008 and possibly beyond, and are likely to place the United States economy into a recession. We expect the United States Federal Open Market Committee to respond to these economic circumstances by continuing to reduce interest rates. This should reduce the interest expense associated with our current debt exposure, but will not necessarily increase the amount of credit available to us on attractive terms.

There are currently a number of economic factors that could increase inflation in 2008. These include the previously-mentioned, anticipated reduction in interest rates, but also include the record high prices that are being observed for certain commodities, such as energy and agricultural products, and the dramatic decline in the value of the US dollar. We do not expect this type of inflationary pressure to have a material adverse impact on our business, however.

Index to Financial Statements

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
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, amortization and impairment		86,308			43,220

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)

Adjusted EBITDA consists of net income plus income tax, interest-net, depreciation and amortization expense, other non-cash operating expenses less non realized revenues risk management loss (gain) activities and less net income from discontinued operations. See Item 6. Selected Financial Data for a definition and reconciliation to GAAP.

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. We intend to acquire and construct additional assets in both our midstream and upstream businesses, and we intend to be opportunistic with potential acquisitions for our minerals business.

Index to Financial Statements

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
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 2006, and (ii) flat natural gas pricing, as compared to pricing in 2006.

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.

Index to Financial Statements

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.

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 current 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 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 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 spend 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.

Index to Financial Statements

East Texas/Louisiana Segment


	Twelve Months Ending December 31
	2007			2006
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

Index to Financial Statements

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. Depending upon the success of Anadarko’s drilling activities on this acreage, this area may provide added volume growth to the segment during 2008.

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.

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 $20.7 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
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	$	—

Index to Financial Statements

Revenues and Cost of natural gas and natural gas liquids. This segment is a new area of operations for us in 2007. We entered 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 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. The spend was primarily growth capital focused on adding capacity and new supply to our Phase 1 20” pipeline.

Upstream Segment


	Twelve Months Ending December 31
	2007		2006
Revenues:
Oil and condensate	$	24,874	$	—
Natural gas		11,210		—
NGLs		14,603		—
Income fees and other		948
Other		130		—

Total revenues		51,765		—
Operating Costs and expenses:
Operations and maintenance		11,474		—
Taxes other than income		4,407		—
Depletion, depreciation and amortization		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

Index to Financial Statements

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 (H2S) and carbon dioxide (CO2) 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, H2S 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 H2S 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.

Revenues. During the Upstream Covered Period, the 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.

Index to Financial Statements

Operating Expenses. Operating expenses during the period, including severance and advalorem taxes, totaled $15.9 million for the Upstream assets. 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
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”).

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.

Index to Financial Statements

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. However, we are confident that we will receive revenues in 2008 for new wells that were drilled in 2007. After we have sufficient production history, we will account for these as extensions and discoveries in our 2008 proved reserves report.

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.

Revenues from the sale of production were approximately $13.7 million during the Minerals Covered Period. This represents approximately 91% of our Minerals segment revenues.

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 approximately $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 approximately $8.0 million. In addition, 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 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.

Index to Financial Statements

Corporate Segment


	Twelve Months Ending December 31
	2007			2006
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	)	$	(10,737	)

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, 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 $130.7 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 loss in 2006 and 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 $130.7 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 $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

Index to Financial Statements

price increased during the year, and $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.

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 $59.7 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 increased 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 loss 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 loss 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.

Index to Financial Statements

Adjusted EBITDA. Adjusted EBITDA as defined, 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, as compared to 2006.

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.

Other Expense. Other expense reflects the arbitration award recorded during 2007 of approximately $1.4 million (see Contingencies, Note 11) 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 (see Note 14).

Index to Financial Statements

Year Ended December 31, 2006 Compared with Year Ended December 31, 2005

The following table is a summary of the results of operations of Eagle Rock Pipeline for the two years ended December 31, 2006 and 2005.


	Year Ended December 31, 2006			Year Ended December 31, 2005
	($ in thousands)
Operating Revenues:
Sales of natural gas, NGLs and condensate	$	486,911		$	59,921
Compressing, gathering and processing services		14,862			6,247
Gain (loss) on risk management instruments		(24,004	)		7,308
Other		621			214

Total operating revenues		478,390			73,690
Cost of natural gas and cost of natural gas and NGLs		377,580			55,272
Operating and maintenance expense		32,905			2,955
General and administrative expense		13,161			4,765
Advisory termination fee		6,000			—
Depreciation and amortization expense		43,220			4,088
Interest and other income		(996	)		(171	)
Interest and other expense		28,604			4,031
Income Tax Provision		1,230			—

Net income (loss)	$	(23,314	)	$	2,750

Adjusted EBITDA(†)	$	81,192		$	3,390

(†)

Financial results for the year ended December 31, 2006, include activities of the ONEOK Texas Field Services assets (acquired in December 2005), Brookeland assets (acquired in March and April 2006) and acquisition of MGS (acquired in June 2006).

Operating revenues for sales of natural gas, NGLs and condensate increased by $427.0 million, primarily from the Panhandle assets (twelve months of contribution in 2006 versus one month in 2005), Brookeland assets and MGS acquisitions and the contribution from the constructed Tyler County pipeline during the latter part of 2006. The increase of $8.6 million in revenues for compression, gathering and processing services was also favorably impacted by the increased activities from the acquired assets.

As a result of our commodity hedging activities, total revenues include a realized gain of $2.3 million on risk management investments that were settled for the twelve month period and an unrealized mark-to-market net loss of $26.3 million which includes the fair value change of the option premiums associated with the Panhandle assets. 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 mark-to-market net unrealized loss reflects overall favorable forward curve price movements during the twelve month period for the underlying commodities for the derivative instruments. The net unrealized loss is comprised of $18.6 million gain related to our NGL position and crude oil as the forward curve prices in these commodities decreased during the quarter. Partially offsetting the unrealized gain, we recorded an unrealized net loss of $25.7 million related to natural gas forward curve price movements during the year. The $19.2 million remaining difference refers to the amortization of the put premiums as the underlying

Index to Financial Statements

options have expired. The unrealized net loss of $26.3 million did not have any impact on cash activities for the 2006 period as applicable, and as such is excluded from our calculation of Adjusted EBITDA.

Purchase of natural gas and NGLs increased by $322.3 million reflecting the cost of goods expense for the increased sales of natural gas, NGLs and condensate revenue as discussed above.

Revenues minus cost of natural gas and natural gas liquids increased by $82.4 million reflecting the increased business activity in revenues and purchases, as discussed above. Reducing revenues minus cost of natural gas and natural gas liquids for the 2006 period is the $26.3 unrealized mark-to-market loss related to our risk management activities as described above. Excluding this amount, revenues minus cost of natural gas and natural gas liquids would have been $127.1 million as compared to $11.1 million for the 2005 period.

Operations and maintenance expense increased by $30.0 million for the year ended 2006 compared to 2005, due to the increased operations from the acquired assets as well as from the first phase of the Tyler County pipeline project completed earlier in 2006.

General and administrative expense also increased by $8.4 million, as the Partnership built up its corporate infrastructure and personnel to manage the acquired assets and public partnership expenses. Included in general and administrative expense is property tax, employee benefit programs and the Partnership’s property and liability insurance programs.

Adjusted EBITDA for the 2006 year was $81.2 million as compared to $3.4 million for 2005. The increase is primarily from the contribution of the acquired assets during the year, as well as the contribution from the Tyler County Pipeline project.

During the fourth quarter of 2006, Holdings paid $6.0 million at the time of the initial public offering to terminate the advisory services agreement with Natural Gas Partners. The transaction was recorded as an expense on the Partnership’s income with the offset to members’ equity.

As the purchase price of the acquired assets was allocated and pushed down to the operating entities’ balance sheets, depreciation and amortization expense also increased by $39.1 million from the associated higher fixed assets and intangible assets of the acquired assets, as well as additions during the year.

As the Panhandle acquisition was substantially financed with a credit loan facility, interest expense, net increased by $23.7 million, including interest swap realized gain of $0.5 million. We did not have outstanding debt prior to the Panhandle assets acquisition in 2005. Included in interest expense for 2006 is approximately $0.4 million of direct cost expensed related to the amended and restated credit agreement which became effective on August 31, 2006, as well as higher debt issuance cost amortization during 2006.

We recorded an unrealized mark-to-market gain of $2.8 million related to our interest rate risk management position. The unrealized gain relates to our future periods interest swaps and from changes during the quarter in the underlying interest rate associated with the derivatives. The unrealized mark-to-market gain did not have a significant impact on cash activities during the 2006 period.

We recorded $1.2 million of income taxes related to temporary differences caused by the Texas entity level tax to become effective in 2008.

Other Matters

Hurricanes Katrina and Rita. Hurricanes Katrina and Rita struck the Gulf Coast region of the United States on August 29, 2005 and September 24, 2005, respectively, causing widespread damage to the energy infrastructure in the region. The storms did not cause material direct damage to any of our assets in the region. While neither Hurricane Katrina nor Hurricane Rita caused material direct damage to our facilities, Hurricane Rita did disrupt the operations of NGL pipelines and fractionators in the Houston, Texas area and caused power

100

Index to Financial Statements

outages to some of our producers in the Southeast Texas area. As a result of these disruptions, in 2005 we were forced to temporarily curtail certain of our producers in the region for approximately four days and to operate our Indian Springs facility in a reduced recovery mode for approximately six days.

Wild fires in Texas Panhandle. Wild fires in the Texas Panhandle during the week of March 11, 2006, temporarily affected our operations in the region. While the fires did not cause material direct damage to our facilities, some experienced down-time was caused by power outages at the local electric co-ops. Our Lefors and Cargray plants came back up with reduced flow rates as producers had shut-in their production during the fires. There was minimal and temporary damage sustained in the field to a very small number of metering facilities and one flow line. Less than $0.1 million was spent on repairs caused by the fires. The overall economic impact has been estimated to be between $0.5 million and $1.0 million during the first quarter of 2006.

Liquidity and Capital Resources

Historically, our sources of liquidity have included cash generated from operations, equity investments by our owners and borrowings under our existing credit facilities. More recently, we have successfully raised significant resources through the private placement of our common units among institutional investors.

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.

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 ratio of debt and equity issued will be determined by our management and our board of directors as deemed appropriate.

Cash Flows

From January 1, 2006 through December 31, 2007, there have been several key events that have had major impacts on our cash flows. They are:

•

the completion of the first phase of construction of the 23-mile, 10 inch Tyler County Pipeline on February 28, 2006 at a cost of approximately $8 million, which we financed from operating cash flow;

•

the private placement of 5,455,050 common units for $98.3 million among a group of private investors on March 27, 2006;

•

the acquisition of the Brookeland gathering and processing facility and related assets on March 31, 2006 and April 7, 2006 for approximately $95.8 million, which we financed entirely with equity;

•

the acquisition of all of the partnership interests in Midstream Gas Services, L.P. on June 2, 2006 , for which the sellers received $4.7 million in cash and $20.3 million in Eagle Rock Pipeline, L.P. units;

•

the completion of the 10-mile Quinduno pipeline connecting our East and West Panhandle Systems on August 1, 2006 at a cost of approximately $3.1 million, which we financed from operating cash flow;

•

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 which we paid 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 which we paid $113.4 million in cash;

101

Index to Financial Statements

•

the acquisition of certain fee minerals, royalties and non-operated working interest properties from MacLondon Energy, L.P. on June 18, 2007 for which we paid 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.

•

the acquisition of Escambia Asset Co, LLC and Escambia Operating Co, LLC on July 31, 2007, for which we paid $224.6 million in cash, subject to adjustment;

•

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 which we paid $84.6 million in cash; and

•

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 EAC and Redman Acquisitions.

On February 7, 2007, Eagle Rock Energy 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, Eagle Rock Energy 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 (see Note 4). No distribution was made to the general partner or Holdings (on the general partner units or subordinated units) for the quarter.

On July 31, 2007, Eagle Rock Energy completed the EAC and Redman Acquisitions. In the aggregate, the EAC and Redman Acquisitions resulted in the payment of $307.8 million in cash, including working capital adjustments, subject to adjustment. Additionally, Eagle Rock Energy completed the private placement of 9,230,770 common units to third-party investors, for total cash proceeds of approximately $204.0 million. The proceeds from this equity private placement were used to partially fund the cash portion of these acquisitions. In addition, on July 31, 2007, the Partnership drew $106.0 million from its revolver under its Amended and Restated Credit Facility to finance the remaining cash consideration of the EAC and Redman Acquisitions.

On August 6, 2007, the Partnership 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 (see Note 4). No distribution was made to the general partner or Holdings (on the general partner units or subordinated units) for the quarter.

102

Index to Financial Statements

On November 8, 2007, the Partnership 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).

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, 2007, working capital was $15.1 million as compared to a $12.1 million balance as of December 31, 2006.

The net increase in working capital of $3.0 million from December 31, 2006 to December 31, 2007, resulted primarily from the following factors:

•

cash balances and marketable securities, net of due to affiliates, increased overall by $41.0 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 $17.0 million as of December 31, 2007 is owed to Eagle Rock Energy G&P, LLC;

•

trade accounts receivable increased by $92.1 million primarily from the receivables activities from the acquisitions completed during the 2007 year;

•

risk management net working capital balance decreased by a net $45.9 million as a result of the changes in current portion of the mark-to-market unrealized positions and fair value changing of the option premiums;

•

accounts payable increased by $83.0 million from December 31, 2006 primarily as a result of the payables activities from the acquisitions during the current year, activities and timing of payments, including capital expenditures activities; and

•

accrued liabilities increase of $1.8 million primarily reflects unbilled expenditures related primarily to capital expenditures and activities from the acquisitions during the year.

Cash Flows Year Ended 2007 Compared to Year Ended 2006

Cash Flow from Operating Activities. Increase of $52.0 million during the current year 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 the current year reflect the net cash consideration for acquisition assets, $407.6 million, versus net cash consideration for acquisition assets, $101.2 million for the previous year. In addition, investing activities for the current year 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.

103

Index to Financial Statements

Capital Requirements

As we continue to expand our Midstream Business (all three segments), our Upstream Segment, and our Mineral Segment through acquisitions and organic projects, our need for capital, both as growth capital and as maintenance capital, continues to increase. We anticipate that we will have sufficient access to capital to grow, maintain and commercially exploit the Midstream Business (all three segments), Upstream Segment, and Mineral Segment assets.

As an operator of upstream assets and as a working interest owner, our capital requirements have increased to maintain those properties and to replace depleting resources. We anticipate that we will meet these requirements through cash generated from operations, equity issuances, or debt incurrence; however, we cannot provide assurances that we will be able to obtain the necessary capital under terms acceptable to us.

Our 2007 capital budget anticipated that we would spend approximately $33.2 million in total in 2007 on our existing assets. We actually spent approximately $66.1 million in total in 2007, primarily in the Tyler County Pipeline Extension, Red Deer Processing Plant project, Anadarko Sagg project and various well connections and maintenance capital (in both our Upstream and Midstream Segments).

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:

•

growth capital expenditures, which are made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities, or 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.

Since our inception in 2002, we have made substantial growth capital expenditures. We anticipate we will continue to make significant growth capital expenditures and acquisitions. Consequently, 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 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, 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.

Our 2008 capital budget anticipates that we will spend approximately $54.3 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 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.

Revolving Credit Facility

On December 13, 2007, we entered into a credit agreement with 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 to the agreement with aggregate commitments up to $800 million. Concurrently with and upon the effectiveness of the new credit agreement, all of our commitments under our previous $600 million Amended and Restated Credit and Guaranty Agreement among the Partnership, as borrower, Goldman Sachs

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Index to Financial Statements

Credit Partners L.P., as administrative agent and the several lenders who are parties to the prior credit agreement were cancelled and terminated. The new credit agreement provided terms and pricing options more favorable than the prior credit agreement. Initial availability under the new credit agreement based on financial covenants was $725 million. The maximum amount of the credit facility may, at our request and subject to the terms and conditions of the credit facility, be increased up to $1 billion. The Credit Agreement is scheduled to expire on December 13, 2012. We did not initially increase the amount of debt outstanding over what was outstanding under the prior credit agreement other than to pay accrued interests.

Off-Balance Sheet Obligations.

We have no off-balance sheet transactions or obligations.

Debt Covenants.

At December 31, 2007, we were in compliance with the covenants of the credit facilities.

Total Contractual Cash Obligations.

The following table summarizes our total contractual cash obligations as of December 31, 2007.


	Payments Due by Period
Contractual Obligations	Total	2008	2009	2010	2011- 2012	Thereafter
	($ in millions)
Long-term debt (including interest)(1)	760.0	38.8	38.8	38.8	643.6	—
Operating leases	8.1	1.2	1.2	0.4	0.6	4.7
Purchase obligations(2)	—	—	—	—	—	—
Total contractual obligations	768.1	40.0	40.0	39.2	644.2	4.7

(1)	Assumes our fixed swapped average interest rate of 4.92% 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 February 2006, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and No. 140 (“SFAS No. 155”). SFAS No. 155 amends SFAS No. 133, which required a derivative embedded in a host contract which does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS No. 155 amends SFAS No. 133 to narrow the scope of such exception to strips which represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS No. 155 amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS No. 155 amends SFAS No. 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued (or subject to a re-measurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. The Partnership adopted SFAS No. 155 on January 1, 2007, and it had no effect on the results of operations or financial position.

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Index to Financial Statements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. 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. The Partnership is currently evaluating the effect the adoption of this statement will have, if any, on its consolidated results of operations and financial position.

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 is effective for us as of January 1, 2008 and will have no impact as we have elected not to measure additional financial assets and liabilities at fair value.

In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109 (“FIN 48”), which clarifies the accounting and disclosure for uncertainty in tax positions, as defined. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. This interpretation was effective for the partnership on January 1, 2007. The adoption of FIN 48 did not have a material impact on our results of operations or financial position.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces SFAS No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired in connection with a business combination. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effect of the business combination. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s first fiscal year that begins after December 15, 2008. We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 141R on the Partnership’s financial statements.

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 recharacterized 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 have not yet determined the impact, if any, that SFAS No. 160 will have on its 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 have not yet determined the impact, if any, that SFAS No. 161 will have on its financial statements.

Recent Developments

On February 6, 2008, the Partnership declared a $0.3925 per unit distribution on all outstanding units (including common units, general partner units, and subordinated units) for the fourth quarter of 2007, payable on February 14, 2008 to the unitholders of record on February 11, 2008. The distribution to the common units, general partner units and subordinated units was paid on February 14, 2007.

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Index to Financial Statements

which is expected to be completed in the first quarter of 2009 at a cost of approximately $25 million, involves diverting West Panhandle volumes from the Partnership’s Stinnett Plant, located in Moore County, Texas to its Cargray Plant, located in Carson County, Texas and subsequently relocating the Stinnett Plant’s high-efficiency cryogenic technology to the East Panhandle Arrington System, located in Hemphill County, Texas.

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 product prices or interest rates could adversely impact our ability to make distributions to our unitholders, meet debt service obligations, fund required capital expenditures and other similar requirements. Our management has established a comprehensive review of our market risks and has developed risk management policies and procedures to monitor and manage these market risks. Our general partner is responsible for the overall approval of market risk management policies, delegation of transaction authority levels, and for the establishment of a Risk Management Committee. 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 “—Critical Accounting Policies and Estimates—Risk Management Activities” for further discussion of the accounting for 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 crude oil, NGLs and natural gas. Both our profitability and our cash flow are affected by volatility in prevailing prices for 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, such as natural gasoline, 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.

To the extent that we market commodities in which pricing terms cannot be matched and there is a substantial risk of price exposure, we attempt to use financial derivative instruments (“hedges”) to mitigate the 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

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Index to Financial Statements

forecasted production, consumption, or outstanding debt service. In no event shall transactions be entered into to speculate on market conditions.

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.

In any quarter, newly-hedged volumes (i.e., added during that quarter) shall not exceed 10% 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 10, Risk Management Activities, 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.

The following table sets forth certain information regarding our NGL options, valued as of December 31, 2007:


Commodity	Period	Notional Volumes (Bbls)	Type	Floor Strike Price ($/gal)		Cap Strike Price ($/gal)		Fair Value
	($ in thousands except $/gal)
Ethane	Jan-Dec 2008	102,000	Costless Collar	$	0.5500	$	0.6500	$	(1,387	)
	Jan-Dec 2009	42,000	Costless Collar		0.4800		0.5800		(1,406	)
	Jan-Dec 2010	108,000	Costless Collar		0.4300		0.5300		(1,619	)
Propane	Jan-Dec 2009	126,000	Costless Collar		0.7650		0.8700		(2,719	)
	Jan-Dec 2010	120,000	Costless Collar		0.7050		0.8100		(3,064	)
Normal Butane	Jan-Dec 2009	66,000	Costless Collar		0.9350		1.0350		(1,566	)
	Jan-Dec 2010	132,000	Costless Collar		0.8200		1.0200		(3,536	)
Iso Butane	Jan-Dec 2009	30,000	Costless Collar		0.9350		1.0350		(748	)
	Jan-Dec 2010	60,000	Costless Collar		0.8200		1.0200		(1,881	)

Total								$	(17,926	)

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Index to Financial Statements

The following table sets forth certain information regarding our NGL fixed swaps, valued as of December 31, 2007:

Units/Commodity


		Notional Volumes (Bbls)	Wt. Avg. $/Gallon			Fair Market Value
Commodity	Period	Notional Volumes (Bbls)	We Receive		We Pay	Fair Market Value
	($ in thousands except $/Gallon)
Ethane	Jan-Dec 2008	402,000	$	0.6896	OPIS avg	$	(4,795	)
	Jan-Dec 2009	420,000		0.6058	OPIS avg		(4,427	)
	Jan-Dec 2010	108,000		0.4800	OPIS avg		(1,809	)
Propane	Jan-Dec 2008	532,000		1.1670	OPIS avg		(7,484	)
	Jan-Dec 2009	407,000		1.0038	OPIS avg		(6,587	)
	Jan-Dec 2010	120,000		0.7550	OPIS avg		(3,300	)
Normal Butane	Jan-Dec 2008	80,000		1.2750	OPIS avg		(1,603	)
	Jan-Dec 2009	139,000		1.1381	OPIS avg		(2,701	)
Iso Butane	Jan-Dec 2008	40,000		1.2950	OPIS avg		(829	)
	Jan-Dec 2009	30,000		1.1551	OPIS avg		(1,332	)

Total						$	(34,867	)

The following table sets forth certain information regarding our crude oil options, valued as of December 31, 2007:


Period	Commodity	Notional Volumes (Bbls)	Type	Floor Strike Price ($/Bbl)		Cap Strike Price ($/Bbl)		Fair Market Value
	($ in thousands except $/Bbl)
Jan-Dec 2008	NYMEX WTI	72,000	Put	$	65.00			$	17
Jan-Dec 2008	NYMEX WTI	2,442,000	Costless Collar		52.85	$	71.32		3,593
Jan-Dec 2009	NYMEX WTI	587,000	Costless Collar		51.82		68.56		(12,127	)
Jan-Dec 2010	NYMEX WTI	480,000	Costless Collar		50.00		67.86		(9,200	)
Jan-Dec 2011	NYMEX WTI	600,000	Costless Collar		75.00		85.70		(2,460	)
Jan-Dec 2012	NYMEX WTI	600,000	Costless Collar		75.30		86.00		(2,309	)

Total								$	(22,486	)

The following table sets forth certain information regarding our crude swaps, valued as of December 31, 2007:


		Notional Volumes (Bbls)
			Wt. Avg. $/Barrel
Commodity	Period		We Receive		We Pay	Fair Market Value
	($ in thousands except $/Barrel)
Crude	Jan-Dec 2008	1,320,000	$	78.1545	NYMEX WTI	$	(19,361	)
	Jan-Dec 2009	900,000		77.2498	NYMEX WTI		(9,335	)
	Jan-Dec 2010	420,000		72.3857	NYMEX WTI		(5,228	)
	Jan-Dec 2011	540,000		80.0000	NYMEX WTI		(2,688	)
	Jan-Dec 2012	480,000		80.3000	NYMEX WTI		(2,130	)

Total						$	(38,742	)

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Index to Financial Statements

The following table sets forth certain information regarding our natural gas options, valued as of December 31, 2007:


Period	Commodity	Notional Volumes (MMBtus)	Type	Floor Strike Price ($/MMBtu)		Cap Strike Price ($/MMBtu)		Fair Market Value
	($ in thousands, except $/MMBtu)
Jan-Dec 2008	Houston Ship Channel IF	480,000	Put	$	7.00			$	160
Jan-Dec 2008	NYMEX HENRY HUB	120,000	Put		7.00				43
Jan-Dec 2009	NYMEX HENRY HUB	200,000	Put		7.00				80
Jan-Dec 2008	NYMEX HENRY HUB	1,926,000	Costless Collar		6.96	$	11.85		294
Jan-Dec 2009	NYMEX HENRY HUB	1,538,100	Costless Collar		7.54		10.37		(138	)
Jan-Dec 2010	NYMEX HENRY HUB	1,320,000	Costless Collar		7.70		9.10		(356	)
Jan-Dec 2011	NYMEX HENRY HUB	1,200,000	Costless Collar		7.50		8.85		(506	)
Jan-Dec 2012	NYMEX HENRY HUB	1,080,000	Costless Collar		7.35		8.65		(468	)

Total								$	(891	)

The following table sets forth certain information regarding our natural gas swaps, valued as of December 31, 2007:


		Notional Volumes (MMBtu)
			Wt. Avg. $/MMBtu			Fair Market Value
Commodity	Period		We Receive		We Pay	Fair Market Value
	($ in thousands except $/MMBtu)
Natural Gas	Jan-Dec 2008	996,000	$	8.35	NYMEX	$	26
	Jan-Dec 2009	900		8.00	NYMEX		(175	)

Total						$	(149	)

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 this swap is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments through the end of 2010. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.

See Note 10, Risk Management Activities, for additional discussion of our interest rate hedging activities.

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, 2007
	($ in thousands except notional amount)
01/03/2006	01/03/2011	$	100,000,000	4.9500	%	$	(3,051	)
01/03/2006	01/03/2011		100,000,000	4.9625			(3,115	)
01/03/2006	01/03/2011		50,000,000	4.8800			(1,429	)
01/03/2006	01/03/2011		50,000,000	4.8800			(1,429	)
09/18/2007	12/31/2010		75,000,000	4.6600			(1,596	)
09/18/2007	12/31/2010		75,000,000	4.6650			(1,608	)

						$	(12,228	)

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Index to Financial Statements

The table below summarizes the changes in commodity and interest rate risk management assets for the applicable periods:


	Year Ended 12/31/2007			Year Ended 12/31/2006
	($ in thousands)
Net risk management assets at beginning of period	$	9,628		$	31,160
Investment premium payments (amortization), net		814			(19,227	)
Acquired contracts in acquisitions		350			—
Cash received from settled contracts		1,647			(2,824	)
Settlements of positions		(1,647	)		2,824
Unrealized mark-to-market valuations of positions		(138,081	)		(4,305	)

Balance of risk management assets at end of period	$	(127,289	)	$	9,628

Risk Management Oversight

The Risk Management Committee (“RMC”) is the primary body responsible for creating and implementing a sound approach to managing our commodity price risk with respect to EROC’s 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;

•

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;

•

Developing and executing policies for risk reporting.

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.

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Index to Financial Statements

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. In the sale of our NGLs and condensates, our principle customers are large natural gas liquids purchasers, fractionators and marketers and large condensate aggregators that also in turn typically sell to large multi-national petrochemical and refining companies. We also sell a small amount of propane to medium sized, local distributors.

We currently sell the predominate share of our natural gas, NGL and condensate to seven companies. Our Texas Panhandle NGLs are sold to ONEOK Hydrocarbon, our largest customer, representing 25% of sales revenue on a month to month basis. All of our natural gas sales are under 30 day term deals, with credit based upon 60 days of deliveries. ONEOK Energy Services, our largest residue gas customer, is our second largest customer overall at 15% of sales. Our third largest customer is Tenaska Marketing Ventures at 5%. A few crude sales contracts and two sulfur sales contracts in our Upstream segment have multi-year terms. 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.

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 Interim Chief Financial Officer, and the our Audit Committee of the Board of Directors of the general partner of the general partner of the Partnership, 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

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system, no evaluation of controls can provide absolute assurance that all control issues, if any, within a Partnership have been detected.

Our management, with the participation of our Chief Executive Officer and Interim Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2007. Based on that evaluation, management concluded that, as of that date, the Partnership’s disclosure controls and procedures were not effective at the reasonable assurance level because of the identification of the material weakness in our internal control over financial reporting, described below, which we view as an integral part of our disclosure controls and procedures.

2007 Acquisitions

Because the Montierra Acquisition, the MacLondon Acquisition, the EAC Acquisition, and the Redman Acquisition were completed in the second and third quarter of 2007, and represent new lines of business for the Partnership, management did not include the internal control processes for these entities in its assessment of internal control over financial reporting as of December 31, 2007. See more details below relating to the exclusion of these acquisitions from Management’s Report on Internal Control Over Financial Reporting. 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 2008 assessment.

Management’s 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 effectiveness of our internal control over financial reporting, as pertains to the calendar year 2007. The evaluation and testing was conducted by our internal auditor and an outside consultant, under the supervision and with the participation of our management, including our Chief Executive Officer and our Interim 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 Montierra Acquisition, the MacLondon Acquisition, the EAC Acquisition and the Redman Acquisition, which were acquired during the second and third quarters of 2007 and whose financial statements constitute 38.3 percent of total assets and 8.6 percent of revenues of the consolidated financial statement amounts as of and for the year ended December 31, 2007. Our evaluation and testing was conducted as of the end of the period covered by this Annual Report on Form 10-K. Based upon our evaluation and testing, management has identified the following material weaknesses within the Partnership that existed at December 31, 2007:

•

Internal Control Environment—The Partnership’s control environment did not sufficiently promote effective internal control over financial reporting through the management structure to prevent a material misstatement. Specifically, the organization lacked adequate training programs and job descriptions to clearly communicate management’s and employees’ roles and responsibilities in our internal control over financial reporting and a sufficient number of accounting and finance professionals to perform supervisory reviews and monitoring activities over financial reporting matters and controls.

•

Period-end Financial Reporting Process—Specifically, controls related to the close process, including controls over non-routine transactions, unusual journal entries, closing of accounting periods, and account reconciliations and variance analyses. Also financial reporting controls related to hedging activities, including controls over recording hedging transactions, validation of monthly settlements and recording of unrealized and realized gains/losses.

•

Midstream Cost of Natural Gas and Natural Gas Liquids—Specifically controls related to pricing, including controls over loading and maintenance of monthly index pricing in the revenue system associated with our Midstream Segment.

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Index to Financial Statements

As a result of the material weaknesses, the Chief Executive Officer and the Interim Chief Financial Officer concluded that the Partnership’s internal control over financial reporting was not effective as of December 31, 2007.

Management’s Response to Material Weaknesses

On account of our determination that a material weakness was present (i.e., there was a reasonable possibility that a material misstatement of our financial annual or interim financial statements for 2007) in the areas of “Financial Reporting” and “Midstream Cost of Natural Gas and Natural Gas Liquids,” management has concluded that, as of December 31, 2007, the Partnership did not maintain effective internal control over financial reporting.

As a result of the foregoing determinations and conclusions, and in order to increase our comfort that our consolidated financial statements included in this Annual Report present fairly, in all material respects, our financial condition, results of operations and cash flows as of, and for, the periods presented in conformity with GAAP, we have increased our end-of-year review and the scope of our internal audit, and applied compensating procedures and processes as necessary in each of the areas identified above as contributing to our determination and conclusion.

Some of the compensating procedures and processes include:

•

Detailed management review of account reconciliations for all accounts for 2007;

•

Engagement of a third party consultant to review the accounting treatment for 3rd quarter 2007 acquisitions which are classified as significant non-routine transactions;

•

Full review and reconciliation of all hedging activities and associated accounting entries for 2007;

•

Full review of actual loading of monthly index pricing in our Midstream Segment for 2007.

In addition to the compensating procedures and processes described above and also in response to the material weaknesses existing at December 31, 2007, our management, with oversight from our Audit Committee, has dedicated significant resources to improving our control environment and to remedying the identified material weaknesses. These ongoing efforts are focused on (i) expanding our organizational capabilities through the addition of employees with appropriate skills and abilities to improve our control environment and (ii) implementing process changes to strengthen our internal control design and monitoring activities.

From an organizational capabilities perspective, we have made, and continue to make, significant strides, including the following:

•

We have engaged a third-party consultant with technical expertise in control environment and accounting to assist us in preparing our 2007 financial reporting and concluding our financial audit and SOX 404 audit.

•

We have hired additional external reporting staff, including a Financial Reporting Manager, and other accounting staff, who possess public company accounting and reporting technical expertise, to supplement our existing technical accounting resources.

•

We have hired a Director of Risk and Internal Audit/Compliance to coordinate our internal audit and internal control compliance efforts and to oversee and ensure improvements in the overall design and operating effectiveness of our internal control framework.

All of these resources were added in the fourth quarter of 2007 or the first quarter of 2008 and, while we believe we have substantially improved our organizational capabilities, the full impact of the changes had not been realized by December 31, 2007. We will continue to evaluate our resources, and we remain committed to adding the necessary resources as needs are identified.

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We have and will continue to implement changes to our processes to improve disclosure controls and procedures and to improve our internal control over financial reporting. Among the changes we have made, or are in the process of making, are the following:

•

We have formalized the monthly account reconciliation process for all balance sheet accounts. We have also implemented a formal review of reconciliations by our business unit accounting management.

•

We have established a Compliance Office within our Risk and Compliance department focused on control deficiency identification and remediation, i.e., The Compliance Office will perform ongoing internal control evaluation and assessment and work actively with the process owners in developing appropriate remediation of control deficiencies.

•

We have established an Enterprise Risk Management Committee, which includes the Chief Executive Officer, the Interim Chief Financial Officer and the senior leadership and management of the Partnership, which will be conducting an Enterprise-wide risk assessment, establishing an internal audit plan, and implementing an internal audit outsourcing and technical consultation arrangement with a professional accounting and/or consulting firm (as necessary). Results will be reported directly to the audit committee.

As a result of this focused internal review and compensating procedures and processes, management now believes that the consolidated financial statements included in this Annual Report present fairly, in all material respects, our financial condition, results of operations and cash flows as of, and for, the periods presented in conformity with GAAP. In addition, 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.

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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 Eagle Rock Energy Partners, L.P. and subsidiaries’ (the “Parnership’s”) internal control over financial reporting as of December 31, 2007, 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 Report on Internal Control Over Financial Reporting, management excluded from their assessment the internal control over financial reporting at Redman, EAC, Montierra and MacLondon (the “Acquired Entities”), which were acquired during the second and third quarter of 2007 and whose financial statements constitute 38.3 percent of total assets and 8.6 percent of revenue of the consolidated financial statement amounts as of and for the year ended December 31, 2007. 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 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 that 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.

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Index to 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.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weaknesses have been identified and included in management’s assessment: Internal Control Environment, period-end Financial Reporting Process and Midstream Cost of Natural Gas and Natural Gas Liquids. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidated financial statements as of and for the year ended December 31, 2007, of the Partnership and this report does not affect our report on such financial statements.

In our opinion, because of the effect of the material weaknesses identified above on the achievement of the objectives of the control criteria, the Partnership has not maintained effective internal control over financial reporting as of December 31, 2007, 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, 2007, of the Partnership and our report dated March 31, 2008 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 31, 2008

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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 partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, 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 our best interests.

Our general partner owes a fiduciary duty to our unitholders. 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 our general partner or 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.

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. In compliance with the rules of the Nasdaq Global Select Market, William A. Smith was named as our third independent director during 2007. 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.

Our board of directors met nine times during 2007 with each board member attending at least 75% of our board meetings (for the time period in which they served on the Board in 2007). Additionally, our board of directors took action by written consent 17 times during 2007.

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 serves as Chairman of our audit committee. 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 standards of the Nasdaq Global Select Market. 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

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Index to Financial Statements

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.

Our audit committee met eight times during 2007 with all three members of the audit committee attending at least 85% of the meetings (for the time period in which they served on the audit committee in 2007). Our audit committee regularly meets with our independent registered public accounting firm, Deloitte & Touche LLP, during audit committee meetings outside the presence of our management.

We also have a compensation committee, comprised of William J. Quinn and Messrs. P. Smith and W. Smith. Mr. Quinn served as chairman of our compensation committee during 2007. Currently, Mr. W. Smith serves as the chairman of our compensation committee. Among other things, the compensation committee oversees the compensation plans and determination of our overall compensation for officers and employees. The compensation committee met three times during 2007 with all three members of the committee attending 100% of the meetings.

Additionally, we have a 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. White serves as chairman of our conflicts committee. 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 to us. 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 (consisting at the time of only Messrs. P. Smith and W. White) met 11 times during 2007, primarily to approve the Montierra acquisition and the Redman acquisitions, with both members attending each meeting.

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 “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.

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 Partners, L.P., 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.

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Index to Financial Statements

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 & Touch 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 their 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 may be modified or supplemented. The committee received written disclosures and the letter from Deloitte & Touche LLP required by Independence Standards Board No. 1, Independence Discussions with Audit Committees, as may be modified or supplemented, and has discussed with Deloitte & Touche LLP its independence from management and Eagle Rock.

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, 2007 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 our current members of our board of directors, our executive officers (for purposes of Item 401(b) of Regulation S-K under the Securities Exchange Act of 1934) and certain other officers of us and our subsidiaries.


Name	Age	Position with Eagle Rock Energy G&P, LLC
Joseph A. Mills	48	Chairman and Chief Executive Officer, Director
Alfredo Garcia	42	Senior Vice President, Corporate Development and Interim Chief Financial Officer
Charles C. Boettcher	34	Senior Vice President, General Counsel, Chief Compliance Officer and Secretary
Steven G. Hendrickson	46	Senior Vice President, Technical Evaluations
Stephen O. McNair	45	Senior Vice President, Midstream Operations
William E. Puckett	52	Senior Vice President, Midstream Commercial Operations
Joseph E. Schimelpfening	46	Senior Vice President, E&P Operations and Development
J. Stacy Horn	45	Vice President, Midstream Commercial Development
Mark S. Terrell	47	Vice President, Land
Elizabeth Wilkinson	50	Vice President, Investor Relations and Treasurer
William J. Quinn	37	Director
Kenneth A. Hersh	45	Director
Philip B. Smith	55	Director
William A. Smith	63	Director
John A. Weinzierl	39	Director
William K. White	64	Director

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Index to Financial Statements

Because of its ownership of a majority interest in Eagle Rock Holdings, L.P., Natural Gas Partners has the right to elect 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 the 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 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 wholly 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.

Alfredo Garcia was elected Senior Vice President, Corporate Development of Eagle Rock Energy G&P, LLC in August 2006. Since December 29, 2007 Mr. Garcia has served as Interim Chief Financial Officer of Eagle Rock Energy G&P, LLC. Mr. Garcia served as Acting Chief Financial Officer of Eagle Rock Energy G&P, LLC from July 16, 2007 until November 9, 2007. Mr. Garcia also served as Senior Vice President and Chief Financial Officer of Eagle Rock Energy G&P, LLC from March 2006 until August 2006, and as Chief Financial Officer of Eagle Rock Pipeline, L.P. from December 2005 until August 2006 and 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 at 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 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.

Stephen McNair was elected Senior Vice President of Midstream Operations of Eagle Rock Energy G&P, LLC in December 2007. Mr. McNair served as Vice President of Midstream Operations from August 2006 to

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Index to Financial Statements

December 2007. Prior to joining the Partnership, Mr. McNair served as Vice President of Natural Gas Services for TEPPCO in Denver, Colorado from March 2005 to July 2006. From September 2002 to February 2005, Mr. McNair was Vice President—Rocky Mountain Region for Duke Energy Field Services. Prior to that, Mr. McNair held the position of General Manager—West Permian Region for Duke Energy Field Service from April 2000 to August of 2002.

William E. Puckett was elected Senior Vice President, Midstream Commercial Operations of Eagle Rock Energy G&P, LLC in March 2006. 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 of E&P Operations and Development of Eagle Rock Energy G&P, LLC in May 2007. 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.

J. Stacy Horn was elected Vice President, Commercial Development of Eagle Rock Energy G&P, LLC in March 2006. Mr. Horn has been Vice President, Commercial Development of Eagle Rock Pipeline, L.P. since December 2005 and Eagle Rock Energy, Inc. from October 2004 to December 2005. Prior to joining Eagle Rock Energy, Inc., Mr. Horn was Commercial Manager, Director of Business Development for El Paso Field Services, L.P., a natural gas gathering and processing and transportation company, from December 2000 to October 2004.

Mark S. Terrell was elected Vice President of Land of Eagle Rock Energy G&P, LLC in May 2007. From November 2006 to May 2007, Mr. Terrell was Vice President of Land for Montierra Minerals & Production, L.P. From 2000 to 2006, Mr. Terrell served as land manager for the Texas Gulf Coast district of El Paso Production Company. Prior to 2000, Mr. Terrell served in various positions of increasing responsibility in the energy sector.

Elizabeth T. Wilkinson was elected Vice President, Investor Relations and Treasurer of Eagle Rock Energy G&P, LLC in January 2008. Prior to joining Eagle Rock, Ms Wilkinson served as a consultant to Paradigm Geophysical Corporation from June 2007 to November 2007 and to Compass Resources Corporation from December 2006 to May 2007. From October 2004 to November 2006 Ms Wilkinson took time off to spend with her family and also worked in a family business. From November 2002 to September 2004 Ms Wilkinson served as Vice President and Treasurer for Kerr-McGee Corporation and prior to that spent over 17 years with GlobalSantaFe Corporation (formerly Global Marine Inc.) where she held a variety of corporate finance positions with extensive responsibilities over mergers and acquisitions, capital market transactions, planning, investor relations, accounting, and systems development.

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 served as Chairman of the Board of Eagle Rock Energy G&P, LLC from January 2007 to May 2007. Mr. Quinn was elected Director in March 2006 and serves as a member of the compensation committee. 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

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Index to Financial Statements

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.

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 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, and a member of the audit committee and conflicts committee, of the board of directors of Eagle Rock Energy G&P, LLC. 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 deputy chairman of the board of BW Offshore, Ltd. and chairman of the board of Flex LNG, Ltd.

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 a member of the conflicts committee, of the board of directors of Eagle Rock Energy G&P, LLC. Mr. White also serves as an audit committee financial expert. Mr. White is President of Amado Energy Management, 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, 2007, except that one group Form 4 filing for Eagle Rock Holdings, L.P., Eagle Rock GP, LLC, Montierra Minerals and Production, L.P., Montierra Management LLC, Natural Gas Partners VII, L.P., NGP Income Management, L.L.C., NGP-VII Income Co-Investment Opportunities, LP, NGP Co-Investment Income Capital Corp., NGP 2004 Co-Investment Income, L.P. and Kenneth A. Hersh reporting the acquisition by the Company of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. from Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P., respectively, in consideration for the issuance of 1,284,315 common units to Natural Gas Partners VII, L.P. and 1,763,206 common units to Natural Gas Partners VIII, L.P., was inadvertently filed late.

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Index to Financial Statements

Item 11.

Executive Compensation.

The following discussion of executive compensation contains references to our employee benefit plan, an employment agreement of our former Chief Financial Officer and an Omnibus Agreement. These descriptions are qualified in their entirety by reference to the full text of the plan, employment agreement 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” or “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”.

Because we now are a publicly-traded limited partnership, we have 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 J. Quinn, Philip B. Smith, and William A. Smith, serve as our Compensation Committee, which we refer to in this Item 11 as “Compensation Committee” or “Committee”. Messrs. P. Smith and W. Smith meet the standards for independence under the Nasdaq Global Select Market. Mr. Quinn is a managing partner of the NGP private equity funds.

Starting in 2007, the Compensation Committee began taking over the role of establishing compensation for the executive officers, approving compensation policies for G&P, approving incentive programs, and determining the total compensation for our executive officers, including our Chief Executive Officer, to be paid by G&P. To a large extent however, except with respect to newly hired executive officers, compensation amounts (especially base salaries) for our executive officers in 2007 were 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”. Since early 2007, the Committee has worked to design a comprehensive 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.

As a result of a search conducted at the end of 2007, the Compensation Committee has engaged Towers Perrin, a nationally recognized compensation consulting firm specializing in assisting master limited partnerships that own and operate upstream or midstream oil and gas assets, with all aspects of executive compensation. The Compensation Committee and our Chief Executive Officer are currently working with Towers Perrin to refine our existing executive compensation design and to ensure that compensation to our executive management is commensurate with executive management compensation among industry peers, and that our overall compensation will 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 unitholders. In this regard, our Chief Executive Officer has worked closely with both the Compensation

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Index to Financial Statements

Committee and Towers Perrin, including attending routine Compensation Committee meetings and meeting with representatives of Towers Perrin, in an effort to assist in determining our compensation strategy and developing our performance targets and goals. The Compensation Committee anticipates making adjustments to the 2008 executive compensation program as a result of this process, including the possibility of using tally sheets to present overall compensation as well as more extensive benchmarking of our executive compensation to our industry peers.

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 will continue to analyze all facets of our named executive officers’, as well as all other officers’, total compensation based on these goals, which are still being developed within the Committee, and will utilize surveys of public information of peer group companies to develop a range of overall compensation as a benchmark for our named executive officers overall compensation. Because we have become 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 ongoing evaluation process will be to identify and develop an appropriate peer group to add in this benchmarking process. The Committee will rely heavily on the expertise and guidance of its compensation consultant, Towers Perrin, in this regard.

Our executive compensation program currently has the following three principal elements: base salary, cash bonuses and equity. We will continue to evaluate the benefit of this mix as well as the benefit of the mix of components of our equity element, as follows:

Base Salaries

2007

During 2007, the Compensation Committee had limited influence on the base salaries established by the Holdings Board prior to, or at the time of, our initial public offering in late 2006. Richard W. FitzGerald’s 2007 base salary was established in his employment agreement as the result of a negotiation at the time of his initial employment prior to our initial public offering. All other 2007 base salaries for named executive officers (except Joseph A. Mills, Charles C. Boettcher, Steven G. Hendrickson and Joseph E. Schimelpfening, who joined Eagle Rock in 2007) were established by the Holdings Board prior to, or at the time of, our initial public offering.

The base salaries of Messrs. Mills, Hendrickson and Schimelpfening were established by negotiation between Eagle Rock, with the Committee’s input, and those prospective executive officers as part of the Montierra Acquisition, at the following levels:


• Mr. Mills	$	250,000
• Mr. Hendrickson	$	200,000
• Mr. Schimelpfening	$	200,000

As part of the Montierra Acquisition, Mr. Mills became our Chief Executive Officer, replacing Alex A. Bucher. Mr. Bucher’s base salary for 2007 had been determined prior to our initial public offering and continued at the same level. During the negotiations for the Montierra Acquisition, Eagle Rock, with the Compensation Committee’s input, looked to establish Mr. Mills salary at a level commensurate with Mr. Mills’ experience and knowledge in the energy industry, especially with respect to the upstream business, and which would provide incentive for Mr. Mills to grow the company. The base salaries of Messrs. Hendrickson and Schimelpfening were established in appropriate relation to Mr. Mills’ base salary.

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Index to Financial Statements

As a result of the salary negotiation in the Montierra Acquisition and the setting of the base salaries as described above, the Committee reviewed and adjusted upward the base salaries of many of our then-existing senior management to provide better parity and alignment of the salaries of all senior management at each level of senior management. In connection with these salary adjustments, the base salaries of Mr. FitzGerald and Alfredo Garcia were adjusted to the following amounts for the balance of 2007:


• Mr. FitzGerald	$	200,000
• Mr. Garcia	$	200,000

During this process of negotiating the salaries of our executive officers in the Montierra Acquisition and adjusting our then-existing executive officers’ base salaries, the Committee did not seek outside information or data points from other companies or industry studies, but the Committee did reference its collective industry experience and observations to determine the appropriate level of compensation.

The Compensation Committee also exercised oversight in establishing the base salary of Mr. Boettcher during 2007, at $225,000, but the base salary was largely arrived at by negotiation between Mr. Mills and Mr. Boettcher. Mr. Boettcher was hired to become our Senior Vice President, General Counsel, Chief Compliance Officer and Secretary.

2008 Going Forward

For 2008 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 continues 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 2008, 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—2008 Going Forward”.

Cash Bonus

2007

For 2007, the Committee has authorized the payment of cash bonuses to the named executive officers, including our Chief Executive Officer, based on a review of Eagle Rock’s overall performance during 2007 and the individual performance of the executive officer. The Committee, however, did not make decisions based on any predetermined performance goals or factors, and none were communicated to the named executive officers during the year. In addition, the Committee authorized our Chief Executive Officer, in his sole discretion, to allocate an additional bonus pool of $250,000 among senior management and other key personnel, including the named executive officers. The purpose of this additional discretionary pool was to allow our Chief Executive Officer to recognize outstanding performance.

Based on its discretionary assessment, the Committee determined that Eagle Rock’s financial performance for 2007 merited cash bonus grants to our key employees, including our named executive officers. Eagle Rock grew extensively during 2007 through acquisitions, which required great effort from all employees and guidance from our senior management team, including our Chief Executive Officer. These acquisitions transformed Eagle Rock from a midstream company into a combined upstream (E&P and minerals) and midstream company and resulted in growth in revenues and Adjusted EBITDA of approximately 62.9% and 64.2%, respectively, as compared to the year ended December 31, 2006, after the effective integration of the acquired businesses with our existing company. Based on these assessments (and a multiplier for 2007 service time multiplied by a

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Index to Financial Statements

pre-determined target that is a percentage of base salary), the Committee and the Chief Executive Officer used their collective experience and observations in determining appropriate levels of bonuses for 2007, resulting in cash bonuses to the named executive officers as follows:


Joseph A. Mills	$	266,667
Alfredo Garcia	$	100,000
Charles C. Boettcher	$	75,000
Steven G. Hendrickson	$	100,000
Joseph E. Schimelpfening	$	100,000

2008 Going Forward

For 2008 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

•

Move fixed employee costs into variable costs.

Performance factors and goals for Eagle Rock in 2008 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 Committee has established the 2008 Short Term Incentive Bonus Plan with specific financial, safety and operational targets, including:


• 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 Notice 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

If we achieve a certain percentage of the target results, there will be a corresponding payout of the bonus pool. In order for any payout to occur, the Partnership must achieve a minimum of 80% of all of the financial, safety and operation targets, based on the discretion of the Board of Directors. In the event the Partnership achieves the 80% threshold, there is a minimum payout of 80% of the 2008 Short Term Incentive Bonus Plan. The Short Term Incentive Bonus Plan payout increases proportionately with the corresponding percentage of the financial, safety and operational targets achieved by the Partnership up to a maximum of 100%. The Board of Directors can approve a target payout in excess of 100% if in their sole discretion they believe the overall results are outstanding as measured against the financial, safety and operational targets. The Chief Executive Officer and other named executive officers’ bonus percentages are established by the Committee, with input from the Chief Executive Officer regarding targets for named executive officers (other than the Chief Executive Officer). Our senior management currently anticipates that Eagle Rock has a 75% chance of achieving all of the goals and targets described above.

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Index to Financial Statements

Under the Bonus Plan, 75% of an executive officer’s bonus amount is to be determined by Eagle Rock’s performance against the target results, and 25% of an executive officer’s bonus amount is to be determined by the employee’s individual performance as measured by the Committee in 2008. The Committee has not established any personal performance targets and goals for the named executive officers and will continue to evaluate and develop these performance targets and goals during 2008 and in the future. Until such time as the performance targets and goals are developed and communicated to the named executive officers, the Committee will maintain its discretion over the individual performance portion of the cash bonus.

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., 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, some of which are 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. For all periods prior to early 2007, the two members of management who served on the Holdings Board, together with NGP’s three nominees/delegates, were Mr. Bucher and our former executive vice president, the original founders of the company (with NGP). As a result of their respective resignations in 2007, two vacancies existed on the Holdings Board, which have been filled by NGP by the appointment of Mr. Mills, our Chief Executive Officer and Mr. Garcia, our Senior Vice President and Interim Chief Financial Officer.

2007

Upon becoming a publicly-traded limited partnership, G&P’s Board adopted the LTIP and granted restricted common units to almost all Eagle Rock employees at the time of our initial public offering. In 2007, the Compensation Committee authorized additional awards of restricted common units under the LTIP to the following named executive officers and in the following amounts, providing for vesting annually in three substantially equivalent increments on each of May 15, 2008, May 15, 2009, and May 15, 2010:


		Restricted Common Units
Joseph A. Mills		85,000
Charles C. Boettcher		50,000
Steven G. Hendrickson		24,631
Joseph E. Schimelpfening		24,631
Richard W. FitzGerald		20,000

With the exception of Mr. FitzGerald, all of the foregoing named executive officers continue to hold these restricted common units, subject to the vesting schedule listed above. Mr. FitzGerald forfeited these units as a result of his resignation, effective December 28, 2007.

In addition, the Compensation Committee authorized several awards to other executive officers in 2007, 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, FitzGerald, Boettcher, Hendrickson and Schimelpfening were greater in number of restricted common units per person than awards made to other

128

Index to Financial Statements

members of senior management. These awards were made with the intent of equalizing the cash and non-cash compensation incentives among senior management. As among the group receiving awards, senior management received the vast majority of the awards by number of restricted common units.

As mentioned above, although it has no discretion in granting any awards at the Holdings level, the Compensation Committee does review prior discretionary grants made by the Holdings Board to our named executive officers. Coming into 2007, all of the named executive officers (except Messrs. Mills, Boettcher, Hendrickson and Schimelpfening, who joined Eagle Rock in 2007), and certain other executive officers (i) held direct, non-incentive equity ownership in Holdings based on prior capital contributions, which capital contributions were either made at the time of initial founding (in the case of Mr. Bucher and a former executive vice president no longer with Eagle Rock) or at the time of initial employment (in the case of Messrs. Garcia and FitzGerald) and (ii) had been granted incentive interests in Holdings in the form of various “tier” units or options, which were designed to create incentives for the management of the private company to reach certain pre-determined confidential payout goals 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 defined cumulative cash payout amounts distributed to equity owners of Holdings within a certain time period. Because these time-vesting requirements and payout amounts are considered confidential performance targets of Holdings and because of the proprietary and competitive nature of the Holdings structure to NGP, we have been requested 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, therefore, is subject only to time-vesting requirements, some of which have been met for holders of this tier who acquired these interests prior to January of 2006.

Messrs. Mills, Boettcher, Hendrickson and Schimelpfening have not invested in Holdings and do not hold non-incentive equity ownership. During 2007, in addition to grants made to other executive officers, the Holdings Board determined to make grants to Messrs. Mills, Boettcher, Hendrickson and Schimelpfening of incentive interests that were forfeited by Mr. Bucher as a result of his resignation from Eagle Rock, which, if and when the payout goals at the Holdings’ level are achieved, would entitle such named executive officers to approximately the percentage of overall distributions from Holdings as follows:


	Tier II		Tier III
Joseph A. Mills	1.46	%	0.99	%
Charles C. Boettcher	0.88	%	0.60	%
Steven G. Hendrickson	0.29	%	0.20	%
Joseph E. Schimelpfening	0.29	%	0.20	%

In the Summary Compensation Table, we show these grants as “Other Compensation”.

2008 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, the Committee has the right to grant awards of up to 1,000,000 common units in the form of option awards or other types of incentive grants. However, 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, 2007, the Committee has granted to employees, officers, and directors of G&P an aggregate of 563,421 restricted common units under the LTIP which remain outstanding (including the unvested portion of prior grants having been forfeited by departing employees).

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Index to Financial Statements

These grants have been made under restricted common unit award agreements, which generally vest in three approximately equal increments over an approximately three-year vesting period. 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, that 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 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 targets of Eagle Rock 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 2,187,871 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 Item 12. Certain Relationships and Related Transactions, and Director Independence).

At this time, certain tier I and tier III forfeited incentive interests (primarily on account of the resignation of Mr. FitzGerald at the end of 2007) are available to be granted by the Holdings Board.

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 dilution 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 dilution 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 by potentially lowering 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 of Eagle Rock used by Montierra’s Board 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

130

Index to Financial Statements

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. 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 executive officers, currently owns 2,849,069 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 Item 12. Certain Relationships and Related Transactions, and Director Independence).

In determining Messrs. Mills’, Hendrickson’s, and Schimelpfening’s compensation for 2007, the Committee, during and after the negotiations for the Montierra Acquisition, considered their ownership of Montierra. For a description of their ownership of Montierra, see footnote six to the chart appearing in 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 executive 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.

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.

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 Partnership’s Compensation Committee. The Partnership believes that maintaining the discretion to evaluate the performance of its executive officers is an important part of the Partnership’s responsibilities and benefits the Partnership’s unitholders. The Partnership’s Compensation 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 January 31, 2007, Joan A.W. Schnepp, a named executive officer for 2006, resigned. In connection with her resignation, we entered into a separation agreement, which includes an obligation of Ms. Schnepp to provide consulting services in accordance with the agreement through March 15, 2008. Under the agreement Ms. Schnepp will be entitled to receive payments in the sum of $300,000, which is equal to eighteen months of her base salary, less deductions required by law, payable in equal or nearly equal installments ending on the last payroll date on or before March 15, 2008. Additionally, G&P agreed to continue to pay, on Ms. Schnepp’s behalf, the cost of continuing her health, dental and vision coverage until the earlier of March 10, 2008 or when she becomes eligible for any similar type of benefit plan.

Effective May 1, 2007, in connection with completing the Montierra Acquisition Mr. Mills became our Chief Executive Officer, and Mr. Bucher, our previous Chief Executive Officer, was named President and Chief Operating Officer. Effective June 15, 2007, Mr. Bucher resigned from all offices and positions with G&P and its affiliates. Mr. Bucher did not receive any severance payments in connection with his resignation, and we do not have any obligations to make payments to Mr. Bucher based on his resignation. As a result of his resignation, Mr. Bucher forfeited certain unvested Tier II and Tier III incentive interests in Holdings, which were subsequently re-issued by Holdings in 2007, as discussed above.

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Index to Financial Statements

Messrs. Hendrickson and Schimelpfening were also made employees of G&P in connection with closing of the Montierra transaction. Similarly, they stopped receiving a salary from Montierra and began receiving a salary from G&P, and they received grants of restricted common units under the LTIP and incentive interests in Holdings. Mr. Boettcher became an employee of G&P three and a half months after the closing of the Montierra transaction. As with the others, Mr. Boettcher received grants of restricted common units under the LTIP and incentive interests in Holdings.

Effective December 28, 2007, Mr. FitzGerald resigned from all offices and positions with G&P and its affiliates. Mr. FitzGerald did not receive any severance payments in connection with his resignation, and we do not have any obligations to make payments to Mr. FitzGerald, under his employment agreement or otherwise, based on his resignation. As a result of his resignation, Mr. FitzGerald forfeited certain unvested restricted common units awarded to him under the LTIP and forfeited certain vested and unvested Tier I incentive interests and unvested Tier III incentive interests in Holdings. The forfeited restricted common units were returned to the pool of available common units for issuance pursuant to the LTIP. The incentive interests in Holdings are also available for re-issuance. As of the date of this annual report on Form 10-K, Holdings has not re-issued these units.

As a result of Mr. Fitzgerald’s resignation, Mr. Garcia was elected as Interim Chief Financial Officer on December 29, 2007. Mr. Garcia continues to hold that position as of the date of this report.

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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Index to Financial Statements

Compensation Tables

The Summary Compensation table below sets forth information regarding 2007 and 2006 (where applicable) compensation for our named executive officers:


Name and Principal Position	Year (3)	Salary ($)		Bonus ($)(4)		Unit Awards ($)(5)		Option Awards ($)(4)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)(6)(7)(9)			Total (%)($)
Alex A. Bucher, Jr.	2007	$	91,666		—		—	—	—	—	$	3,667		$	95,333
President and Chief Executive Officer, Director(1)	2006	$	195,833		—		—	—	—	—	$	7,833		$	203,666

Joseph A. Mills, Chief Executive Officer, Chairman of the Board, Director(2)	2007	$	166,668	$	266,667	$	1,984,750	—	—	—	$	77,467		$	2,495,552

Richard W. FitzGerald,	2007	$	186,897		—	$	467,000	—	—	—	$	37,776		$	691,673
Senior Vice President, Chief Financial Officer and Treasurer(9)	2006	$	72,050		—	$	187,500	—	—	—	$	—		$	259,550

Alfredo Garcia	2007	$	191,664	$	100,000		—	—	—	—	$	18,250		$	309,914
Senior Vice President, Corporate Development and Interim Chief Financial Officer	2006	$	171,666		—		—	—	—	—	$	6,867		$	178,533

Charles C. Boettcher Senior Vice President, General Counsel, Chief Compliance Officer and Secretary	2007	$	85,243	$	75,000	$	1,119,000	—			$	88,597	(8)	$	1,367,840

Steven G. Hendrickson Senior Vice President, Technical Evaluation	2007	$	133,331	$	100,000	$	575,134	—			$	21,052		$	829,517

Joseph E. Schimelpfening Senior Vice President, E&P Operations and Development	2007	$	133,331	$	100,000	$	575,134	—			$	19,052		$	827,517

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Index to Financial Statements

(1)

Mr. Bucher was President and Chief Executive 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”, until May 1, 2007, at which time he ceased to be Chief Executive Officer. Mr. Bucher continued to serve as a director, President and Chief Operating Officer of Eagle Rock Energy G&P, LLC, the general partner of Eagle Rock Energy GP, L.P. which is the general partner of the Partnership, until such time as his resignation from such positions became effective on June 15, 2007.

(2)

Mr. Mills was appointed Chief Executive Officer of Eagle Rock Energy G&P, LLC, the general partner of Eagle Rock Energy GP, L.P. which is the general partner of the Partnership, on May 1, 2007. Mr. Mills was also appointed to serve as a director of Eagle Rock Energy G&P, LLC on May 1, 2007 and was appointed Chairman of the Board on May 1, 2007.

(3)	The employment of each of Messrs. Mills, Boettcher, Hendrickson and Schimelpfening began in 2007.

(4)	Bonuses which were accrued for executives with regard to 2007 performance were paid on February 29, 2008. No options were awarded by the Partnership.

(5)

With respect to 2007, the amounts represent: the dollar amount of 85,000 restricted units awarded to Mr. Mills on May 15, 2007; the dollar amount of 20,000 restricted units awarded to Mr. FitzGerald on May 15, 2007; the dollar amount of 50,000 restricted units awarded to Mr. Boettcher on August 15, 2007; the dollar amount of 24,631 restricted units awarded to Mr. Hendrickson on May 15, 2007; and the dollar amount of 24,631 restricted units awarded to Mr. Schimelpfening on May 15, 2007. Such units vest 33% on May 15, 2008, another 33% on May 15, 2009, and the final 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. With respect to 2006, the amount represents the dollar amount of 10,000 restricted units awarded to Mr. FitzGerald on October 25, 2006, in connection with our initial public offering. Such units vest annually in equal increments over a three-year period beginning October 25, 2006. In determining the dollar amount, such units are valued at $18.75, which is the price of such units at the time of our initial public offering, October 24, 2006, discounted for the delay in cash distributions attributable to such units during the period under which these units remain unvested. Mr. FitzGerald was Senior Vice President, Chief Financial Officer and Treasurer of Eagle Rock Energy G&P, LLC, the general partner of Eagle Rock Energy GP, L.P. which is the general partner of the Partnership until he resigned effective as of December 28, 2007. As a result of his resignation, Mr. FitzGerald forfeited the remaining restricted common units granted to him.

(6)	Represents the amount of contributions that we made to each executive under our 401(k) plan in the following amounts: Mr. Bucher, $3,667; Mr. Mills, $15,417; Mr. FitzGerald, $15,000; Mr. Garcia, $18,250; Mr. Boettcher, $0; Mr. Hendrickson, $12,000, and Mr. Schimelpfening, $10,000.

(7)

Represents the amount of distributions that we made to each executive 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) in the following amounts: Mr. Mills, $62,050; Mr. FitzGerald, $22,776; Mr. Boettcher, $18,375; Mr. Hendrickson, $9,052; and Mr. Schimelpfening, $9,052.

(8)

In connection with Mr. Boettcher’s relocation from Dallas, Texas to Houston, Texas to accept his position with G&P, Mr. Boettcher received $47,102 as compensation, to cover closing costs on the purchase of his home in Houston and to compensate for an unfavorable price environment in the Dallas housing market and resulting depressed sales price for his home in Dallas. Mr. Boettcher received $23,122 as a gross-up on the $47,102.

(9)

The named executive officer received grants of incentive interests in Eagle Rock Holdings, L.P. from the Holdings Board. These grants were not given any valuation by the employee for tax purposes based on $0 current liquidation value and substantial risks of forfeiture. For a discussion of the incentive interests granted, see “—Discussion and Analysis of Executive Compensation—Long-Term Incentives—2007.”

The named executive officers listed above have also purchased limited partnership interests in and/or been 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. As a result, during 2007 such executives received cash distributions based on their limited partnership interests in Eagle Rock Holdings, L.P. in the following amounts: Mr. Bucher, $814,733; Mr. FitzGerald, $94,717; Mr. Garcia, $464,633. We do not consider these amounts to be compensation to these individuals. 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.

134

Index to Financial Statements

Grants of plan-based awards in 2007

The table below sets forth information regarding grants of plan-based awards made to our named executive officers during 2007.


		Estimated Future Payouts Under Non-Equity Incentive Plan Awards			Estimated Future Payouts Under Equity Incentive Plan Awards			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 ($/Unit)	Grant Date Fair Value of Unit and Option Awards(2)
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)	Threshold (#)	Target (#)	Maximum (#)
Alex A. Bucher, Jr.	—	—	—	—	—	—	—	—	—	—		—
Joseph A. Mills	5/15/07	—	—	—	—	—	—	85,000	—	—	$	1,984,750
Richard W. FitzGerald	5/15/07	—	—	—	—	—	—	20,000	—	—	$	467,000
Alfredo Garcia	—	—	—	—	—	—	—	—	—	—		—
Charles C. Boettcher	8/15/07	—	—	—	—	—	—	50,000	—	—	$	1,119,000
Steven G. Hendrickson	5/15/07	—	—	—	—	—	—	24,631	—	—	$	575,134
Joseph E. Schimelpfening	5/15/07	—	—	—	—	—	—	24,631	—	—	$	575,134

(1)	Represents the amount of restricted units awarded on the grant date. Such units vest 33% on May 15, 2008, another 33% on May 15, 2009, and a final 34% on May 15, 2010.

(2)	Calculated based upon unit price on May 15, 2007 of $23.35 times the number of unvested restricted unit awards. Except for Mr. Boettcher, whose units were granted on August 15, 2007 at a value of $22.38.

135

Index to Financial Statements

Outstanding equity awards at December 31, 2007

The following table summarizes the number of securities underlying outstanding plan awards for each named executive officer as of December 31, 2007.


Name	Option Awards					Unit Awards
	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 ($)
				Option Exercise Price ($)	Option Expiration Date	Number of Units That Have Not Vested (#)	Market Value of Units That Have Not Vested(1) ($)
Alex A. Bucher, Jr.	—	—	—	—	—	—	—	—	—
Joseph A. Mills	—	—	—	—	—	85,000	1,553,800	—	—
Richard W. FitzGerald	—	—	—	—	—	—	—	—	—
Alfredo Garcia	—	—	—	—	—	—	—	—	—
Charles C. Boettcher	—	—	—	—	—	50,000	914,000	—	—
Steven G. Hendrickson	—	—	—	—	—	24,631	450,255	—	—
Joseph E. Schimelpfening	—	—	—	—	—	24,631	450,255	—	—

(1)	Calculated based upon common unit price at end of the fiscal year of $18.28 times the number of unvested restricted unit awards.


	Option Awards		Unit Awards
Name	Number of units acquired on exercise (#)	Value realized on exercise ($)	Number of units acquired on vesting (#)	Value realized on vesting(1) ($)
Alex A. Bucher, Jr.	—	—	—	—
Joseph A. Mills	—	—	—	—
Richard W. FitzGerald	—	—	3,333	72,726
Alfredo Garcia	—	—	—	—
Charles C. Boettcher	—	—	—	—
Steven G. Hendrickson	—	—	—	—
Joseph E. Schimelpfening	—	—	—	—

(1)	Calculated based upon a closing unit price of $21.82 on October 25, 2007, the date of vesting.

136

Index to Financial Statements

Employment Agreements and Severance and Change of Control Arrangements

As mentioned previously, at the time of his employment, Mr. FitzGerald, our former Chief Financial Officer, entered into an employment agreement with G&P, which provided for an annual base salary of $200,000. The agreement also entitled Mr. FitzGerald to participate in our compensation and benefit plans and to receive company-provided disability benefits and life insurance and certain other fringe benefits. In addition, the agreement contains a severance provision that provided that if Mr. FitzGerald’s employment is terminated for any reason other than cause (the term is not defined in his employment agreement), he was entitled to a one-time severance payment in the amount of his annual base salary. Because Mr. FitzGerald resigned, we were not required to pay this one-time severance payment.

Other than Mr. FitzGerald’s employment agreement, we have not entered into any employment agreements or similar arrangements with any other named executive officers. Consequently, other than described above, we do not have any severance obligations or change of control obligations with respect to any named executive officers. However, 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. Messrs. Bucher and FitzGerald are no longer employees and did not receive any severance payments or accelerated vesting of prior equity grants upon the termination of their respective employments. We do not have any obligation to make cash payments upon termination of employment or a change in control transactions 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, 2007. For purposes of valuing the restricted common unit grants, the amounts below are based on a per common unit price of $18.28, which was the closing price as reported on the Nasdaq Global Select Market December 31, 2007.


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
Alex A. Bucher, Jr.	$	—	$	—	$	—		$	—
Joseph A. Mills	$	—	$	—	$	1,553,800	(2)	$	1,553,800	(2)
Richard W. FitzGerald	$	—	$	—	$	—		$	—
Alfredo Garcia	$	—	$	—	$	—		$	—
Charles C. Boettcher	$	—	$	—	$	914,000	(3)	$	914,000	(3)
Steven G. Hendrickson	$	—	$	—	$	450,255	(4)	$	450,255	(4)
Joseph E. Schimelpfening	$	—	$	—	$	450,255	(5)	$	450,255	(5)

(1)	The definition of change of control is defined above in this subsection.

(2)	Based on 85,000 common units unvested.

(3)	Based on 50,000 common units unvested.

(4)	Based on 24,631 common units unvested.

(5)	Based on 24,631 common units unvested.

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

137

Index to Financial Statements

of control described above and certain termination scenarios. However, these equity grants either (i) are subject to reaching further payout goals that have not be 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, and are therefore without value, or (ii) have reached the applicable payout goal but have no readily ascertainable value. Based on the lack of value using the hypothetical transaction date of December 31, 2007, we have not included any disclosure in the table above.

2007 Director Compensation

The table below sets forth certain information concerning the compensation earned in 2007 by our non-employee directors who served in 2007. Information on our employee directors who served in 2007, 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 ($)	Total ($)
Kenneth A. Hersh		—		—		—	—	—	—		—
William J. Quinn		—		—		—	—	—	—		—
John A. Weinzierl		—		—		—	—	—	—		—
Philip B. Smith	$	63,750	$	116,750	(2)	—	—	—	—	$	180,500
William A. Smith	$	19,146	$	108,300	(3)					$	127,446
William K. White	$	60,000	$	175,125	(4)	—	—	—	—	$	235,125

(1)	Reflects fees paid or earned by our non-employee directors in 2007.

(2)	Represents the dollar amount of 5,000 restricted units awarded to Mr. Philip B. Smith, on or about May 15, 2007. Such units vest 33% on May 15, 2008, another 33% on May 15, 2009, and a final 34% on May 15, 2010. In determining the dollar amount, such units are valued at $23.35.

(3)	Represents the dollar amount of 5,000 restricted units awarded to Mr. William A. Smith, on or about September 15, 2007. Such units vest 33% on May 15, 2008, another 33% on May 15, 2009, and a final 34% on May 15, 2010. In determining the dollar amount, such units are valued at $21.66.

(4)	Represents the dollar amount of 7,500 restricted units awarded to Mr. William K. White, on or about May 15, 2007. Such units vest 33% on May 15, 2008, another 33% on May 15, 2009, and a final 34% on May 15, 2010. In determining the dollar amount, such units are valued at $23.35.

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 anticipates that directors who are not officers or employees of G&P or its affiliates will receive compensation for serving on the board of directors and committee meetings. It is expected that such 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; (c) 5,000 restricted common units upon becoming a director, vesting in one-third increments over a three-year period; (d) 1,000 restricted common units on each anniversary of becoming a director, vesting in 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.

138

Index to Financial Statements

Compensation Committee Interlocks and Insider Participation

As of December 31, 2007 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. Quinn served as the Chairman of the Committee during 2007. Mr. Quinn also served as a managing partner of the NGP private equity funds during 2007. For additional disclosure on relationships of those individuals to Eagle Rock, see Item 13, “Certain Relationships and Related Transactions, and Director Independence.” In addition, during 2007, 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.

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 1, 2008 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 executive officer of Eagle Rock Energy G&P, LLC; and

•

all directors and officers of Eagle Rock Energy G&P, LLC as a group.

139

Index to Financial Statements


Name of Beneficial Owner (1)	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.(2)	2,187,871	4.3	%	20,691,495	100.00	%	31.82	%
NGP 2004 Co-Investment Income, L.P.(8)	3,500,136	6.8	%	—	—	%	4.87	%
Montierra Minerals & Production, L.P.(3)	2,820,578	5.5	%	—	—	%	3.92	%
Lehman Brothers Holdings, Inc(4)	7,646,473	14.9	%	—	—	%	10.63	%
Joseph A. Mills(6)	154,185	*	%	—	—	%	*	%
Alfredo Garcia(2)(6)	80,691	*	%	763,122	3.7	%	1.17	%
Charles C. Boettcher(6)	50,000	*	%	—	—	%	*	%
Steven G. Hendrickson(6)	27,366	*	%	—	—	%	*	%
Stephen O. McNair(2)(6)	34,782	*	%	116,164	*	%	*	%
William E. Puckett(2)(6)	39,214	*	%	181,714	*	%	*	%
Joseph E. Schimelpfening(6)	29,425	*	%	—	—	%	*	%
J. Stacy Horn (2)(6)	37,551	*	%	132,887	*	%	*	%
Kenneth A. Hersh(5)	12,111,520	23.7	%	—	—	%	16.85	%
Steven B. Klinsky(7)	3,051,700	6.0	%	—	*	%	4.2	%
William J. Quinn	10,000	*	%	—	*	%	*	%
Phillip B. Smith	10,000	*	%	—	*	%	*	%
William A. Smith	5,000	*	%	—	*	%	*	%
John A. Weinzierl	8,800	*	%	—	*	%	*	%
William K. White	14,700	*	%	—	*	%	*	%
All directors and executive officers as a group (15 persons)**	501,714	1.0	%	1,193,887	5.8	%	2.29	%

*	Less than 1%

**	Excludes certain indirect ownership of non-employee directors.

(1)	Unless otherwise indicated, the address for all beneficial owners in this table, except Lehman Brothers Holdings, Inc., is 16701 Greenspoint Park Drive, Suite 200 Houston, Texas 77060.

(2)

Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., Alfredo Garcia, William E. Puckett, J. Stacy Horn and Stephen O. McNair have approximately a 31.35%, 48.33%, 3.72%, 0.89%, 0.65% and 0.57% limited partner interest, respectively, in Eagle Rock Holdings, L.P. Eagle Rock GP, L.L.C., which is owned 39.14% and 60.35% by Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P., respectively, owns a 1.0% general partner interest in Eagle Rock Holdings, L.P. The units held by Eagle Rock Holdings, L.P. are reported in this table as beneficially owned by Mr. Garcia, Mr. Puckett, Mr. McNair and Mr. Horn in proportion to their beneficial ownership in Eagle Rock Holdings, L.P.

(3)

NGP VII owns a 97.561% interest in Montierra Management LLC (“Montierra Management”), which serves as the general partner of Montierra, and NGP VII appoints three Managers on the board of Montierra Management. NGP VII also owns a 96.169% LP interest in Montierra, and thus may be deemed to beneficially own all of the reported securities of Montierra Management and Montierra.

(4)

Lehman Brothers, Inc. is the actual owner of 2,674,421 Common Units reported herein. Lehman Brothers, Inc. is a wholly-owned subsidiary of Lehman Brothers Holdings, Inc. Lehman Brothers Holdings, Inc. may be deemed to be the beneficial owner of the Common Units owned by Lehman Brothers, Inc. Lehman Brothers MLP Opportunity Fund LP is the actual owner of 3,590,859 Common Units reported herein. Lehman Brothers MLP Opportunity Fund LP is wholly-owned by Lehman Brothers MLP Opportunity Associates, LP which is wholly-owned by Lehman Brothers MLP Opportunity Associates, LLC which is wholly owned by Lehman Brothers Holdings, Inc. Lehman Brothers MLP Opportunity Associates, LP,

140

Index to Financial Statements

Lehman Brothers MLP Opportunity Associates, LLC, and Lehman Brothers Holdings, Inc. may be deemed to be the beneficial owners of the Common Units owned by Lehman Brothers MLP Opportunity Fund LP. Lehman Brothers MLP Partners, LP is the actual owner of 1,381,193 Common Units reported herein. Lehman Brothers MLP Partners, LP is wholly-owned by LB I Group, Inc. which is wholly-owned by Lehman Brothers, Inc. which is wholly owned by Lehman Brothers Holdings, Inc. LB I Group, Inc., Lehman Brothers, Inc. and Lehman Brothers Holdings, Inc. may be deemed to be the beneficial owners of the Common Unites owned by Lehman Brothers MLP Partners, LP.

(5)

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. On July 31, 2007, the Issuer acquired Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. from NGP VII and NGP VIII, respectively, in consideration for the issuance of 1,284,315 common units to NGP VII and 1,763,206 common units to NGP VIII. NGP VII and NGP VIII collectively own a 98% LP interest in Holdings and NGP VII owns a 96.169% LP interest in Montierra Minerals & Production, L.P. NGP VII and NGP VIII control the general partner of Holdings. NGP VII controls the general partner of Montierra Minerals & Production, L.P. 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. Mr. Hersh disclaims beneficial ownership of our units except to the extent of his pecuniary interest therein.

(6)

Charles C. Boettcher beneficially owns 50,000 units that are subject to a three-year vesting schedule pursuant to our long-term incentive plan. In addition to the units he holds through his ownership of Eagle Rock Holdings, L.P., William E. Puckett also beneficially owns 20,000 units that are subject to a three-year vesting schedule pursuant to our long-term incentive plan. In addition to the units he holds through his ownership of Eagle Rock Holdings, L.P., J. Stacy Horn also beneficially owns 1,500 units through our directed unit program plus 22,000 units that are subject to a three-year vesting schedule pursuant to our long-term incentive plan. In addition to the units he holds through his ownership of Eagle Rock Holdings, L.P., Stephen O. McNair also beneficially owns 500 units through our directed unit program plus 22,000 units that are subject to a three-year vesting schedule pursuant to our long-term incentive plan. In addition to the 69,185 units he beneficially owns as a result of the Montierra Acquisition, Joseph A. Mills also beneficially owns 85,000 units that are subject to a three-year vesting schedule pursuant to our long term incentive plan. In addition to the 4,794 units he beneficially owns as a result of the Montierra Acquisition, Joseph E. Schimelpfening also beneficially owns 24,631 units that are subject to a three-year vesting schedule pursuant to our long term incentive plan. In addition to the 2,735 units he beneficially owns as a result of the Montierra Acquisition, Steven G. Hendrickson also beneficially owns 24,631 units that are subject to a three-year vesting schedule pursuant to our long term incentive plan.

(7)

Mr. Klinsky may be deemed to beneficially own an aggregate of 3,051,700 Common Units that are owned by New Mountain Vantage, L.P., New Mountain Vantage (California), L.P. and New Mountain Vantage (Texas), L.P., representing, in the aggregate, approximately 6.0% 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. and New Mountain Vantage (Texas), L.P, to the extent that partnership interests or limited liability company interests in New Mountain Vantage, L.P., New Mountain Vantage (California), L.P. and New Mountain Vantage (Texas), L.P. are held by persons other than Mr. Klinsky.

(8)	See footnote (5) above for a description of NGP VII’s ownership and control of this beneficial owner

141

Index to Financial Statements

Equity Compensation Plan Information

The following table sets forth certain information with respect to our equity compensation plans as of December 31, 2007.


	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)	506,480	(1)
Total	N/A		N/A		506,480

(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, currently permits the grant of awards covering an aggregate of 1,000,000 common units in various forms of grants. For more information about our long-term incentive plan, or LTIP, refer to 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 10, 2008, we had outstanding 510,461 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. 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 Natural Gas Partners (approximately 79.8%) and certain current and former members of our management team, including Alfredo Garcia, Interim Chief Financial Officer and Senior Vice President, Corporate Development of G&P (approximately 3.7%), William E. Puckett, Senior Vice President, Commercial Operations—Midstream (approximately 0.8%), J. Stacy Horn, Senior Vice President, Commercial Development—Midstream (approximately 0.6%), and Stephen O. McNair, Vice President, Operations and Technical Services—Midstream (approximately 0.5%). The following members of the board of directors of G&P hold positions at Natural Gas Partners 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 Natural Gas Partners private equity funds, Kenneth A. Hersh, Chief Executive Officer of NGP Energy Capital Management and is a managing partner of the Natural Gas Partners private equity funds, John A. Weinzierl, a managing director of the Natural Gas Partners 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 Natural Gas Partners, under which our Texas Panhandle Systems has the option to sell a portion of its natural gas supply. We received a Letter of Credit related to this agreement securing the purchase of any natural gas under this agreement. We recorded $19.4 million of revenues in 2006 and $36.0 million of revenues in 2007 from this relationship.

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.

142

Index to Financial Statements

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 Partnership does not directly employ any persons to manage or operate our business. Those functions are provided by our general partner. We reimburse the general partner for all direct and indirect costs of these services.

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, for an aggregate purchase price of approximately $138.7 million. Montierra and Natural Gas Partners received as consideration a total of 6,458,946 (recorded value of $133.8 million) Eagle Rock Energy common units and $4.9 million in cash, subject to post-closing 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 Natural Gas Partners private equity funds (“NGP”) directly or indirectly owned 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.

The conflicts resolution process described immediately above is the process we generally use to approve related party transactions.

In connection with the closing of the Montierra Acquisition, we entered into a registration rights agreements with Montierra and NGP-VII Income Co-Investment Opportunities, L.P. (“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. We have registered for resale the common units related to this transaction.

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) for an aggregate purchase price of $193.3 million, including working capital adjustments (“the Redman Acquisition”). Redman sellers and NGP received as consideration a total of 4,428,334 (recorded value of $109.2 million) newly-issued Eagle Rock common units and $84.1 million in cash, subject to post-closing adjustments. 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 determining the purchase consideration for the Redman 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 Redman.

143

Index to Financial Statements

Messrs. Philip Smith, William Smith and William White have been determined to be independent under the rules of the SEC applicable to audit committees.

Item 14.

Principal Accountant Fees and Services.

The following set 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, 2007, 2006 and 2005:


	December 31,
	2007		2006		2005
Audit fees(1)	$	1,628,611	$	1,762,006	$	1,180,000
Audit related fees(2)		29,645		—		60,000
Tax fees(3)		405,677		16,660		53,000
All other fees		—		—		—
Total	$	2,063,933	$	1,778,666	$	1,293,000

(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.

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 & Touch 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.

144

Index to Financial Statements

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:

(a)(2) Financial Statement Schedules:

None.

(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))

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))

145

Index to Financial Statements


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**		Form of 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))

146

Index to Financial Statements


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)

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. (incorporated by reference to Exhibit 21.1 of the registrant’s registration statement on Form S-1 (File No. 333-144938))

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

147

Index to Financial Statements


Exhibit Number		Description

31.2*		Certification of Periodic Financial Reports by Alfredo Garcia 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 Alfredo Garcia in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002

*	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.

148

Index to Financial Statements

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 31, 2008.


EAGLE ROCK ENERGY PARTNERS, L.P.

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

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

By:		/s/ JOSEPH A. MILLS

Name:		Joseph A. Mills.
Title:		Chief Executive Officer

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


Signature	Title	Date

/s/ JOSEPH A. MILLS Joseph A. Mills	Chief Executive Officer (Principal Executive Officer)	March 31, 2008

/s/ ALFREDO GARCIA Alfredo Garcia	Senior Vice President, Corporate Development and Interim Chief Financial Officer (Principal Financial and Accounting Officer)	March 31, 2008

/s/ KENNETH A. HERSH Kenneth A. Hersh	Director	March 31, 2008

/s/ WILLIAM J. QUINN William J. Quinn	Director	March 31, 2008

/s/ PHILIP B. SMITH Philip B. Smith	Director	March 31, 2008

/s/ WILLIAM A. SMITH William A. Smith	Director	March 31, 2008

/s/ JOHN A. WEINZIERL John A. Weinzierl	Director	March 31, 2008

/s/ WILLIAM K. WHITE William K. White	Director	March 31, 2008

149

Index to Financial Statements

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, 2007 and 2006		F-3
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005		F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005		F-5
Consolidated Statements of Members’ Equity for the Years Ended December 31, 2007, 2006 and 2005		F-6
Notes to Unaudited Pro Forma Condensed Financial Statements		F-7

ONEOK Texas Field Services, L.P.:
Report of Independent Registered Public Accounting Firm		F-40
Statement of Operations for the Eleven-Month Period Ended November 30, 2005		F-41
Statement of Partnership Capital for the Eleven-Month Period Ended November 30, 2005		F-42
Statement of Cash Flows for the Eleven-Month Period Ended November 30, 2005		F-43
Notes to Financial Statements		F-44

F-1

Index to Financial Statements

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 (formerly Eagle Rock Pipeline, L.P.) (the “Partnership”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, members’ equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these 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, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, 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 Company’s internal control over financial reporting as of December 31, 2007, 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 31, 2007 expressed an adverse opinion on the Partnership’s internal control over financial reporting because of material weaknesses.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 31, 2008

F-2

Index to Financial Statements

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2007 AND 2006

($ in thousands)


	December 31, 2007			December 31, 2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	68,552		$	10,581
Accounts receivable(1)		135,633			43,567
Risk management assets		—			13,837
Prepayments and other current assets		3,992			2,679

Total current assets		208,177			70,664
PROPERTY, PLANT AND EQUIPMENT —Net		1,207,130			554,063
INTANGIBLE ASSETS —Net		153,948			130,001
RISK MANAGEMENT ASSETS		—			17,373
GOODWILL		29,527			—
OTHER ASSETS		11,145			7,800

TOTAL	$	1,609,927		$	779,901

LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	132,485		$	49,558
Due to affiliate		16,964			—
Accrued liabilities		9,776			7,996
Taxes payable		723			—
Risk management liabilities		33,089			1,005

Total current liabilities		193,037			58,559
LONG-TERM DEBT		567,069			405,731
ASSET RETIREMENT OBLIGATIONS		11,337			1,819
DEFERRED TAX LIABILITY		17,516			1,229
RISK MANAGEMENT LIABILITIES		94,200			20,576
COMMITMENTS AND CONTINGENCIES (Note 11)
MEMBERS’ EQUITY:
Common Unitholders(2)		617,563			116,283
Subordinated Unitholders(3)		112,360			176,248
General Partner(4)		(3,155	)		(544	)

Total members’ equity		726,768			291,987

TOTAL	$	1,609,927		$	779,901

(1)	Net of allowance for bad debt of $1,046 and $0 as of December 31, 2007 and 2006, respectively.

(2)	50,699,647 and 20,691,495 units were issued and outstanding for 2007 and 2006, respectively.

(3)	20,691,495 and 20,691,495 units were issued and outstanding for 2007 and 2006, respectively.

(4)	844,551 and 844,551 units were issued and outstanding for 2007 and 2006, respectively.

See notes to consolidated financial statements.

F-3

Index to Financial Statements

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

($ in thousands, except per unit amounts)


	Years Ended December 31,
	2007			2006			2005
REVENUE:
Natural gas, natural gas liquids, condensate and oil sales	$	868,101		$	486,911		$	59,921
Gathering, compression, and processing fees		27,417			14,862			6,247
Minerals and royalty income		15,004			—			—
Gain/(loss) on risk management instruments		(133,834	)		(24,004	)		7,308
Other revenue		110			621			214

Total revenue		776,798			478,390			73,690
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		686,882			377,580			55,272
Operations and maintenance		52,793			32,905			2,955
Taxes other than income		8,340			2,301			149
Other operating		2,847			6,000			—
General and administrative		27,799			10,860			4,616
Impairment		5,749			—			—
Depreciation, depletion and amortization		80,559			43,220			4,088

Total costs and expenses		864,969			472,866			67,080
OPERATING (LOSS) INCOME		(88,171	)		5,524			6,610
OTHER INCOME (EXPENSE):
Interest income		1,160			996			171
Other income		696			—			—
Interest expense, net		(50,924	)		(26,985	)		(4,031	)
Other expense		(8,226	)		(1,619	)		—

Total other (expense) income		(57,294	)		(27,608	)		(3,860	)
(LOSS) INCOME BEFORE INCOME TAXES		(145,465	)		(22,084	)		2,750
INCOME TAX PROVISION		169			1,230			—

NET (LOSS) INCOME	$	(145,634	)	$	(23,314	)	$	2,750

NET INCOME (LOSS) PER COMMON UNIT—BASIC AND DILUTED:
Basic and Diluted:
Net income (loss)
Common units	$	(2.11	)	$	(1.26	)	$	0.11
Subordinated units		(3.14	)		(0.43	)		—
General partner units		(3.14	)		(0.80	)		4.06
Basic and Diluted Weighted Average Number Outstanding (units in thousands)
Common units		37,008			12,123			24,151
Subordinated units		20,691			17,873			—
General partner units		845			557			20

See notes to consolidated financial statements.

F-4

Index to Financial Statements

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

($ in thousands)


	Years Ended December 31,
	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(145,634	)	$	(23,314	)	$	2,750
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		80,559			43,220			4,088
Impairment		5,749			—			—
Amortization of debt issuance costs		1,777			1,114			76
Write-off of debt issuance costs		6,215			—			—
Equity in earnings of unconsolidated affiliates		(714	)		—			—
Distribution from unconsolidated affiliates—return on investment		408			—			—
Reclassing financing derivative settlements		1,667			(978	)		—
Advisory termination fee		—			6,000			—
Equity-based compensation		2,395			142			—
Other		(69	)		1,424			6
Changes in assets and liabilities—net of acquisitions:
Accounts receivable		(17,565	)		(10	)		(42,821	)
Prepayments and other current assets		986			(1,422	)		(358	)
Risk management activities		136,132			23,531			(5,709	)
Accounts and distributions payable		19,200			3,105			40,094
Due to affiliates		16,964			—			—
Accrued liabilities		(1,790	)		5,672			103
Other assets		(58	)		(3,492	)		104
Other current liabilities		723			—			—

Net cash provided by (used in) operating activities		106,945			54,992			(1,667	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment		(66,116	)		(38,416	)		(4,157	)
Acquisitions, net of cash acquired		(407,626	)		(101,182	)		(530,951	)
Escrow cash		—			7,643			(7,643	)
Purchase of intangible assets		(2,048	)		(2,918	)		(750	)

Net cash used in investing activities		(475,790	)		(134,873	)		(543,501	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		740,470			10,366			400,000
Repayment of long-term debt		(579,131	)		(15,001	)		—
Proceeds from revolver		—			12,500			7,600
Repayment of revolver		—			(10,600	)		—
Payment of debt issuance costs		(4,280	)		(2,939	)		(6,534	)
Payment for derivative contracts		—			—			(27,452	)
Proceeds from derivative contracts		(1,667	)		978			—
Unit issuance costs for IPO and other equity issuances		(381	)		(3,723	)		—
Net cash in 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			192,369
Distributions to members and affiliates		(59,541	)		(22,033	)		(9,679	)

Net cash provided by financing activities		426,816			71,088			556,304

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		57,971			(8,791	)		11,136
CASH AND CASH EQUIVALENTS—Beginning of period		10,581			19,372			8,236

CASH AND CASH EQUIVALENTS—End of period	$	68,552		$	10,581		$	19,372

Interest paid—net of amounts capitalized	$	40,948		$	30,657		$	—

Investments in property, plant and equipment not paid	$	2,297		$	2,981		$	1,190

Distributions payable to member	$	—		$	—		$	5,000

Prepayment financed by note payable	$	—		$	—		$	866

Issuance of common units for acquisitions	$	307,017		$	20,280		$	—

See notes to consolidated financial statements.

F-5

Index to Financial Statements

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005


	General Partner			Number of Common Units		Common Units			Number of Subordinated Units		Subordinated Units			Eagle Rock Pipeline, L.P. Predecessor Equity			Total
	($ in thousands, except unit amounts)
BALANCE—January 1, 2005	$	—		24,150,731		$	—		$	—	$	—		$	27,655		$	27,655
Net income		83		—			4,067			—		—			(1,400	)		2,750
Capital contributions		—		—			142,688			—		—			49,682			192,370
Distributions		—		—			—			—		—			(14,679	)		(14,679	)
Conversion of predecessor equity to common units		—		—			61,258			—		—			(61,258	)		—

BALANCE—December 31, 2005		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 in MGS acquisition		—		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

See notes to consolidated financial statements.

F-6

Index to Financial Statements

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

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, 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. and its predecessor entities 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, and in the business of acquiring, developing and producing interests in oil and natural gas properties, which we call our “Upstream” business. The Partnership’s natural gas pipelines gather natural gas from designated points near producing wells and transports 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, conditioned or processed into marketable natural gas and natural gas liquids (NGL’s). The Partnership conducts its midstream operations within Louisiana and three geographic areas of Texas. The Partnership’s Texas Panhandle 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 System 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 System completed the acquisition of 100% of Midstream Gas Services, L.P. On May 3, 2007, we completed our 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 of both our East Texas/Louisiana and South Texas Segments.

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”) (a Natural Gas Partners VII, L.P. portfolio company) and NGP-VII Income Co-Investment

F-7

Index to Financial Statements

Opportunities, L.P. (“Co-Invest”) (a Natural Gas Partners affiliate) (collectively, “the Montierra Acquistion”) 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 for the Montierra Acquisition.

On July 31, 2007, the Partnership entered the upstream business when it completed the acquisition of Escambia Asset Co., LLC and Escambia Operating Company, LLC (“the EAC 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 LL, 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). These transactions are collectively referred to as “the Redman Acquisition” (Note 4). The assets conveyed in the Redman Acquisition included operated and non-operated wells mainly located in East and South 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.

F-8

Index to Financial Statements

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 Gas Properties

We review our 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, we recognize 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 a risk-free rate of return. We cannot predict the amount of impairment charges that may be recorded in the future. 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 years ended December 31, 2006 and 2005 and therefore, did not incur impairment charges during these periods.

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

We are required to make estimates of the future costs of the retirement obligations of our producing oil and 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. 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.

Certain Other Concentrations—The Partnership relies on natural gas producer customers for its midstream business’s natural gas and natural gas liquid supply, with the top two producers (by segment) accounting for

F-9

Index to Financial Statements

34.6% of its natural gas supply in the Texas Panhandle Segment, 34.2% of its natural gas supply in the East Texas/Louisiana Segment and 48.9% of its natural gas supply in the South Texas Segment for the month ended December 31, 2007. 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 2007.

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 is allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the year ended December 31, 2007 and 2006, the Partnership capitalized interest costs of approximately $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 asset. 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.

F-10

Index to Financial Statements

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 14) on July 31, 2007. The Partnership will perform an impairment test for goodwill assets annually or earlier if indicators of potential impairment exist. The Company’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. Since the date of the acquisition, no event occurred or circumstances changed that would more likely than not reduce the fair value of a reporting unit below its carrying value. If for any reason the fair value of the goodwill or that of any of the Partnership’s reporting units declines below the carrying value in the future, the Company may incur charges for the impairment.

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 $17.8 million $15.8 million and $1.2 million for the years ended December 31, 2007, 2006 and 2005, respectively. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2008—$18.0 million; 2009—$18.0 million; 2010—$17.1 million; 2011—$6.3 million; and 2012—$6.3 million. Intangible assets consisted of the following (as of December 31, 2007 and 2006):


	December 31, 2007			December 31, 2006
	($ in thousands)
Rights-of-way and easements—at cost	$	80,069		$	66,801
Less: accumulated amortization		(7,274	)		(3,510	)
Contracts		108,772			80,210
Less: accumulated amortization		(27,619	)		(13,500	)

Net intangible assets	$	153,948		$	130,001

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, 2007.

Other Assets—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 related to the Montierra and Redman Acquisitions ($6.0 million). As of December 31, 2006, other assets primarily consist of costs associated with debt issuance, net of amortization ($7.8 million,). Amortization of debt issuance costs is calculated using the straight-line method over the maturity of the associated debt (or the expiration of the contract).

Within the Partnership’s investments of unconsolidated non-affiliates, the Partnership owns 13.2%, 86.0%, 5% and 5% of the common units of Ivory Working Interests, L.P., MacLondon Royalty I, 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, 2007 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.

F-11

Index to Financial Statements

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. For the midstream business, as of December 31, 2006, the Partnership had imbalance receivables totaling $0.3 million and imbalance payables totaling $1.9 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;

•

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 purchaser 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 uses the sales method of accounting for natural gas revenues for the upstream segment. Under this method, revenues are recognized 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. There were no material natural gas imbalances in the upstream segment as of December 31, 2007.

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, 2007 and 2006, the Partnership did not enter into any purchase and sale agreements with the same counterparty.

F-12

Index to Financial Statements

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.

Other Operating Expenses—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.

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 has 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 14 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

F-13

Index to Financial Statements

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 10 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 February 2006, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and No. 140 (“SFAS No. 155”). SFAS No. 155 amends SFAS No. 133, which required a derivative embedded in a host contract which does not meet the definition of a derivative to be accounted for separately under certain conditions. SFAS No. 155 amends SFAS No. 133 to narrow the scope of such exception to strips which represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS No. 155 amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS No. 155 amends SFAS No. 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued (or subject to a re-measurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. The Partnership adopted SFAS No. 155 on January 1, 2007, and it had no effect on the results of operations or financial position.

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 is effective for us as of January 1, 2008 and will have no impact, as we have elected not to fair value additional financial assets and liabilities.

In July 2006, the FASB issued FIN 48, which clarifies the accounting and disclosure for uncertainty in tax positions, as defined. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. This interpretation was effective for the Partnership on January 1, 2007. The adoption of FIN 48 did not have a material impact on our results of operations or financial position.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS 141R”), which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired in connection with a business combination. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effect of the business combination. SFAS 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s first fiscal year that begins after December 15, 2008. The Partnership is currently evaluating the potential impact, if any, of the adoption of SFAS 141R on the Partnership’s financial statements.

F-14

Index to Financial Statements

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 recharacterized 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.

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 has not yet determined the impact, if any, that SFAS No. 161 will have on its financial statements.

NOTE 4. ACQUISITIONS

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. 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 assets acquired in the Montierra Acquisition include fee mineral acres, royalty and overriding royalty interests in oil and natural gas producing wells.

The purchase price was allocated on a preliminary basis to assets acquired and liabilities assumed based on their respective fair value as determined by management. The preliminary 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 on May 1, 2007.

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 (recoded 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.

F-15

Index to Financial Statements

The purchase price was allocated 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 Laser acquisition was accounted for as a purchase in accordance with FASB No. 141, Business Combinations. The preliminary 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 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 common units. The Partnership commenced recording results of operations on July 1, 2007.

EAC Acquisition. On July 31, 2007, we completed the acquisition of Escambia Asset Co., LLC and Escambia Operating Company, 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 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 EAC Acquisition was accounted for as a purchase in accordance with FASB No. 141, Business Combinations. The preliminary 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 on August 1, 2007.

F-16

Index to Financial Statements

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 on a preliminary basis to acquired assets 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 14) 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 Montierra and Redman Acquisitions. Those interests not attributable to Natural Gas Partners have been recorded at their fair value. The preliminary 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 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 segments 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 on a preliminary basis 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

F-17

Index to Financial Statements

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.


	($ 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”) 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.

2005 Acquisition

On December 1, 2005, the Partnership completed its acquisition of ONEOK Field Services Texas (“ONEOK Texas”) for $531.1 million (the “Panhandle Acquisition”) to expand the Partnership’s asset base and to obtain critical mass. ONEOK Texas provides natural gas midstream services in the Texas Panhandle and its assets primarily consist of gathering pipelines and processing plants. The results of operations have been included in the statement of operations since the date of acquisition. The Partnership financed the Panhandle Acquisition and related transactions and costs with proceeds from the following:

Borrowings of approximately $393.5 million of the $400.0 million initially available under the then current Credit Facility;

Net proceeds received from Holdings from a $133.0 million private placement of equity to Natural Gas Partners.

With the assistance of a third-party valuation firm, management has prepared an assessment of the fair value of the property, plant and equipment and intangible assets of the Panhandle Acquisition as of December 1, 2005. The purchase price has been allocated as presented below.


	($ in thousands)
Accounts receivable and other current assets	$	673
Property, plant, and equipment		420,551
Intangibles		115,265
Accounts payable		(2,047	)
Other current liabilities		(1,931	)
Asset retirement obligations		(1,405	)

	$	531,106

All liabilities assumed were at their fair values. The fair value of intangibles is estimated to be $115.5 million. There were no identified intangibles which were determined to have indefinite lives.

F-18

Index to Financial Statements

The following pro forma information for the years ended December 31, 2007 and 2006, assumes the Laser, Montierra, EAC, Redman, Brookeland and MasterCreek and Midstream Gas Services, L.P. acquisitions had been acquired by Eagle Rock Energy on January 1, 2007 and 2006, respectively (unaudited):


	December 31, 2007			December 31, 2006
	($ in thousands)
Revenues	$	953,624		$	823,586
Costs and expenses		1,024,475			779,701

Operating (loss) income		(70,851	)		43,885
Other expense, net		57,780			32,032
Income taxes provision		249			1,284

(Loss) income from continuing operations	$	(128,880	)	$	10,569

NOTE 5. PROPERTY PLANT AND EQUIPMENT AND ASSET RETIREMENT OBLIGATIONS

Fixed assets consisted of the following:


	December 31, 2007			December 31, 2006
	($ in thousands)
Land	$	1,153		$	853
Plant		181,689			81,485
Gathering and pipeline		541,247			433,779
Equipment and machinery		14,081			37,185
Vehicles and transportation equipment		3,657			2,740
Office equipment, furniture, and fixtures		1,023			511
Computer equipment		4,636			4,623
Corporate		126			126
Linefill		4,157			3,923
Proved properties		461,884			—
Unproved properties		66,023			—
Construction in progress		20,884			19,677

		1,300,560			584,902

Less: accumulated depreciation, depletion and amortization		(93,430	)		(30,839	)

Net property plant and equipment	$	1,207,130		$	554,063

Depreciation expense for the years ended December 31, 2007, 2006 and 2005 was approximately $41.1 million, $27.4 million and $2.9 million, respectively. Depletion expense for the year ended December 31, 2007 was approximately $21.7 million. The Partnership did not own oil and natural gas properties in 2006 or 2005 and, therefore, did not incur depletion expense during these periods.

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

F-19

Index to Financial Statements

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:


	2007		2006		2005
	($ in thousands)
Asset retirement obligations—January 1	$	1,819	$	679	$	—
Additional liability on newly constructed assets		325		17		—
Additional liability related to acquisitions		8,722		297		674
Revisions		—		698		—
Accretion expense		471		128		5

Asset retirement obligations—December 31	$	11,337	$	1,819	$	679

NOTE 6. LONG-TERM DEBT

Long-term debt consisted of:


	December 31, 2007		December 31, 2006
	($ in thousands)
Revolver	$	567,069	$	106,481
Term loan		—		299,250

Total debt		567,069		405,731
Less: current portion		—		—

Total long-term debt	$	567,069	$	405,731

On December 13, 2007, the Partnership entered into a new senior secured revolving credit facility (the “Revolving Credit Facility”). The Revolving Credit Facility is an $800 million credit agreement 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 arrangements and joint book runners. The Revolving Credit Facility provides for $800 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 $200 million to a total of $1 billion.

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, 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 years ended December 31, 2007, 2006 and 2005, the Partnership recorded approximately $1.8 million, $1.2 million and $0.1 million of debt issuance amortization expense, respectively. As of December 31, 2007 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, 2007, the Partnership had $23.0 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.

F-20

Index to Financial Statements

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; and

•

Total Funded Indebtedness (as defined) to Adjusted Consolidated EBITDA (as defined) of not more than 5.0 to 5.25 to 1.0 for the three quarters following a material acquisition.

•

Borrowing Base Indebtedness (as defined) not to exceed the Borrowing Base (as defined) as redetermined from time to time.

Based upon the above mentioned ratios and conditions as calculated as of December 31, 2007, the Partnership has approximately $232.9 million of unused capacity under the Revolving Credit Facility at December 31, 2007 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, 2007, the weighted average interest rate on our outstanding debt balance was 8.24%.

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.

F-21

Index to Financial Statements

Scheduled maturities of long-term debt as of December 31, 2007, were as follows:


	Principal Amount
	($ in thousands)
2008	$	—
2009		—
2010		—
2011		—
2012		567,069

	$	567,069

The Partnership was in compliance with the financial covenants under the Revolving Credit Facility as of December 31, 2007. 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.

On August 31, 2006, the Partnership amended and restated its then existing credit agreement (the “Amended and Restated Credit Agreement”). The Amended and Restated Credit Agreement was a $500.0 million credit agreement with a syndicate of commercial and investment banks and institutional lenders, with Goldman Sachs Credit Partners L.P., as the administrative agent. The Amended and Restated Credit Agreement provided for $300.0 million aggregate principal amount of Series B Term Loans (the “Term Loan”) and up to $200.0 million aggregate principal amount of Revolving Commitments (the “Revolver”). On May 4, 2007, Eagle Rock Energy expanded the Revolver by $100.0 million to $300.0 million. No incremental funding under the Amended and Restated Credit Agreement was needed for the Laser and Montierra Acquisitions. On July 31, 2007, the Partnership drew $106.0 million from the Revolver to fund a portion of the EAC and Redman acquisitions. On December 13, 2007, the Amended and Restated Credit Agreement was repaid and extinguished by the Partnership with newly incurred indebtedness of approximately $567 million under the Revolving Credit Facility.

NOTE 7. MEMBERS’ EQUITY

At December 31, 2005, the Partnership had common units outstanding representing 98.01% of limited partnership interest 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.

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 (see Note 8).

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

F-22

Index to Financial Statements

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

(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, except with respect to the quarters ended September 30, 2007 and December 31, 2007 that represent distributions made on all common units, general partner units, and subordinated 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, 2007, there were 50,699,647 common units (exclusive of restricted unvested common units), 20,691,495 subordinated units (all subordinated units are owned by Holdings) and 844,551 general partner units outstanding. In addition, there were 467,062 restricted unvested common units outstanding.

As of December 31, 2007 and 2006, Eagle Rock Energy GP, L.P. owned 1.16% and 2.0%, respectively, of the Partnership.

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Index to Financial Statements

NOTE 8. 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. The Partnership has received a Letter of Credit related to this agreement. The Partnership recorded revenues of $35.3 million and $19.4 million for the years ended December 31, 2007 and 2006, respectively, from the agreement, of which there was a receivable of $5.5 and $3.1 million outstanding at December 31, 2007 and 2006, respectively. In addition, during the year ended December 31, 2007, the Partnership incurred $1.5 million in expenses with related parties, of which there was an outstanding accounts payable balance of $0.5 million as of December 31, 2007. Related to its investments in unconsolidated subsidiaries, during the year ended December 31, 2007, the Partnership recorded revenues of $0.7 million, of which there was an outstanding account receivable balance of $0 as of December 31, 2007.

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 Natural Gas Partners private equity funds (“NGP”) 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 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 will all obligations of the agreement.

F-24

Index to Financial Statements

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.

Holdings had a management advisory arrangement with Natural Gas Partners requiring a quarterly fee payment. The agreement was modified on December 1, 2005, to increase the management fee to $0.5 million annually, with an escalation to $1.0 million annually, upon the completion of the initial public offering by the Partnership. The fee paid under the advisory arrangement has been expensed by the Partnership. For years ended 2006 and 2005, the Partnership expensed the $0.4 million and $0.1 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.

During the fourth quarter of 2005, the Partnership declared a $5.0 million distribution to Holdings. In addition, for 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, 2007, Eagle Rock Energy G&P, LLC had $17.0 million 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 9. FAIR VALUE OF FINANCIAL 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.

The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. As of December 31, 2007, the debt associated with the Credit Agreement bore interest at floating rates. As such, carrying amounts of this debt instrument approximates fair value.

F-25

Index to Financial Statements

NOTE 10. 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 this swap is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments through the end of 2010. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense. 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, 2007
	($ in thousands, except notional amount)
01/03/2006	01/03/2011	$	100,000,000	4.9500	%	$	(3,051	)
01/03/2006	01/03/2011		100,000,000	4.9625			(3,115	)
01/03/2006	01/03/2011		50,000,000	4.8800			(1,429	)
01/03/2006	01/03/2011		50,000,000	4.8800			(1,429	)
09/18/2007	12/31/2010		75,000,000	4.6600			(1,596	)
09/18/2007	12/31/2010		75,000,000	4.6650			(1,608	)

						$	(12,228	)

For the years ended December 31, 2007 and 2006, the Partnership recorded a fair value (loss) gain within interest expense of ($15.8) million and $2.8 million (unrealized), respectively, and a realized gain of $1.4 million and $0.5 million, respectively. As of December 31, 2007 and 2006, the fair value of these contracts totaled an approximate $12.2 million liability and an approximate $1.2 million asset, 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 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 195,000 Bbls per month, 17,000 Bbls per month, 57,000 Bbls per month and 54,000 Bbls per month for 2007, 2008, 2009, and 2010, respectively;

•

Condensate puts and costless collar transactions for the sale of West Texas Intermediate crude oil with a combined notional amount of 104,000 Bbls per month, 80,000 Bbls per month, 40,000 Bbls per month and 40,000 Bbls per month for 2007, 2008, 2009, and 2010, respectively;

•

Natural gas calls for the purchase of Henry Hub natural gas with a notional amount of 100,000 MMBtu per month for 2007;

•

Fixed swap agreements to hedge WTS-WTI basis differential in the amount of 20,000 Bbls per month for a term of January through December 2007.

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.

F-26

Index to Financial Statements

In addition to the derivatives previously entered into related to our midstream business, we entered or assumed the following derivative transactions related to our upstream business in association with the Montierra, EAC and Redman acquisitions. Transactions shown with a floor price only are puts; all other are costless collars (excluding transactions that settled in previous periods).


		Average Monthly Volumes		Price ($/mmbtu or $/bbl)
Period	Commodity	Average Monthly Volumes	Index	Avg. Floor	Avg. Ceiling
Jan-Dec 2008	Gas	30,000 MMBtu	NYMEX	6.25	11.15
Jan-Dec 2008	Gas	103,000 MMBtu	NYMEX	7.00	13.98
Jan-Dec 2008	Gas	30,000 MMBtu	NYMEX	7.50	12.01
Jan-Dec 2008	Gas	50,000 MMBtu	NYMEX	7.00
Jan-Dec 2008	Oil	6,000 Bbl	NYMEX WTI	60.00	71.65
Jan-Dec 2008	Oil	29,000 Bbl	NYMEX WTI	65.00	90.00
Jan-Dec 2008	Oil	4,000 Bbl	NYMEX WTI	60.00	77.22
Jan-Dec 2008	Oil	6,000 Bbl	NYMEX WTI	65.00
Jan-Dec 2008	Oil	5,000 Bbl	NYMEX WTI	60.00	83.75
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, we also entered into or assumed the following derivative transactions associated with our midstream business in conjunction with the EAC Acquisition (excluding transactions that settled in previous periods). All of these derivatives are swaps.


Period	Commodity	Average Monthly Volumes	Index	Price ($/gal)
Jan-Dec 2008	Propane	3,272 Bbl	OPIS MTB TET	1.0875
Jan-Dec 2008	Propane	6,076 Bbl	OPIS MTB non-TET	1.0775
Jan-Dec 2008	n-Butane	6,691 Bbl	OPIS MTB non-TET	1.2775
Jan-Dec 2008	i-Butane	3,367 Bbl	OPIS MTB non-TET	1.2950
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 and pursuant to its stated strategy of mitigating its commodity price exposure and reducing the volatility in its cash flows, Eagle Rock entered into the following hedging transactions.

To negate the economic impact of previously entered into, out-of-the-money collars for 2008 crude production, Eagle Rock sold floors and bought caps for a total cost of $9.1 million, as follows:


Period	Commodity	Average Monthly Volumes	Index	Floor ($/Bbl)	Cap ($/Bbl)
Jan-Dec 2008	Crude oil	20,000 Bbl	NYMEX WTI	50.00	65.65
Jan-Dec 2008	Crude oil	20,000 Bbl	NYMEX WTI	50.00	65.70
Jan-Dec 2008	Crude oil	40,000 Bbl	NYMEX WTI	50.00	69.10

F-27

Index to Financial Statements

In addition, we entered into a WTI crude oil swap for 2008 on the same 80,000 barrels per month, as follows:


Period	Commodity	Average Monthly Volumes	Index	Swap Price ($/Bbl)
Jan-Dec 2008	Crude oil	80,000 Bbl	NYMEX WTI	73.90

The combined impact of these two transactions was to raise Eagle Rock’s floor on those volumes by $23.90 per barrel while at the same time raising its cap by $6.51 per barrel (on a weighted-average basis) to its swap price of $73.90.

On the same date, 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 2008 and 2009, per the following table:


Period	Commodity	Average Monthly Volumes	Index	Swap Price ($/gal)
Jan-Dec 2008	Ethane	25,000 Bbl	OPIS MTB non-TET	0.7200
Jan-Dec 2008	Propane	35,000 Bbl	OPIS MTB TET	1.1900
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, as described below:


Period	Commodity	Average Monthly Volumes	Index	Swap Price ($/Bbl)
Jan-Dec 2008	Crude oil	30,000Bbl	NYMEX WTI	89.50
Jan-Dec 2008	Crude oil	50,000 Bbl	NYMEX WTI	80.25
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 2008	Natural Gas	83,000 MMBtu	NYMEX	8.00
Jan-Dec 2009	Natural Gas	85,000 MMBtu	NYMEX	8.35


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

F-28

Index to Financial Statements

In addition to entering into the derivative instruments described in the tables above, we also bought back at no cost to the Partnership an option on a swap (“swaption”). Under that agreement, the other party has 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.

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, 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 put premiums 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 premiums, 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. As of December 31, 2006, the fair value of these contracts, including the put premiums, totaled $8.4 million. For the year ended December 31, 2005, the Partnership recorded a fair value gain of $7.3 million related to these contracts.

NOTE 11. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation—The Partnership is subject to several lawsuits which arise from time to time in the ordinary course of business, primarily related to the payments of liquids and natural gas proceeds in accordance with contractual terms. The Partnership has accruals of approximately $1.8 million and $1.5 million as of December 31, 2007 and 2006, 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 carries insurance coverage which includes the assets and operations, which management believes is consistent with companies engaged in similar commercial operations with similar type properties. These insurance coverages include (1) commercial general liability insurance for liabilities arising to third parties for bodily injury, property damage and pollution resulting from Eagle Rock Energy field operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense, (5) property and reservoir damage insurance for operated and non operated wells in the upstream segment, and (6) corporate liability policies including Directors and Officers coverage and Employment Practice liability coverage. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operation.

The Partnership also maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of 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.

F-29

Index to Financial Statements

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, 2007 and 2006, the Partnership had accrued approximately $2.4 million and $0.3 million, respectively, for environmental matters.

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 $3.6 million, $0.3 million and $0.5 million for the years ended December 31, 2007, 2006 and 2005, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term. At December 31, 2007, commitments under long-term non-cancelable operating leases for the next five years is as follows: 2008—$1.2 million; 2009—$1.2 million; 2010—$0.4 million; 2011—$0.3 million; and 2012—$0.3 million.

NOTE 12. SEGMENTS

Based on our approach to managing our assets, we believe our operations consist of three 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)

Upstream Segment:

crude oil and natural gas production from operated and non-operated wells;

(v)

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

(vi)

Corporate Segment:

risk management and other corporate activities.

F-30

Index to Financial Statements

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:


Midstream Segments 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, depletion, amortization and impairment		42.3		2.5		10.8		55.5

Operating income	$	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	$	843.9	$	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


Year Ended December 31, 2006	Texas Panhandle Segment		East Texas / Louisiana Segment		Corporate Segment			Total 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


Year Ended December 31, 2005	Texas Panhandle Segment		East Texas / Louisiana Segment			Corporate Segment			Total Segments
	($ in millions)
Sales to external customers	$	43.0	$	23.4		$	7.3	(a)	$	73.7
Cost of natural gas and natural gas liquids		35.2		20.1			—			55.3
Operating costs and other expenses		1.8		3.2			2.7			7.7
Depreciation and amortization		2.9		1.0			0.1			4.1

Operating income (loss)	$	3.1	$	(0.9	)	$	4.5		$	6.6

Capital expenditures	$	—	$	4.1		$	0.1		$	4.2
Segment assets		525.4		82.0			93.3			700.7

(a)	Represents results of our derivatives activity.

F-31

Index to Financial Statements

NOTE 13. 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, or in equal portions twice per year. Expenses under the plan for the years ended December 31, 2007, 2006 and 2005 were approximately $0.8 million, $0.3 million and $37,000, respectively.

NOTE 14. INCOME TAXES

Our provision for income taxes relates primarily to federal and state income taxes for the Partnership and federal income taxes for Eagle Rock Energy Acquisition Co, Inc. and Eagle Rock Upstream Development Company, Inc., our wholly owned corporations which are subject to federal income taxes. Eagle Rock Upstream Development Company, Inc. was formerly known as Redman Energy Corporation and was acquired in the form of a corporate entity as part of the Redman I acquisition in July 2007. The comparative data presented below for 2006 does not include the income taxes of the above referenced corporations since they were acquired in 2007. 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
	2007			2006
	($ in thousands)
Current:
Federal	$	(26	)	$	—
State		724			—

Total current provision		698			—

Deferred:
Federal		(493	)
State		(62	)		1,229

Total deferred		(555	)		1,229

Total provision for income taxes		143			1,229

Add Back: valuation allowance for Federal loss		26			—

Total Provision for income taxes less valuation allowance	$	169		$	1,229

Since a master limited partnership is a partnership, for federal income tax purposes, the overall effective rate for federal taxes is zero. However, the result of state based income taxes applied against book losses is a 100% effective tax rate for 2007 and 2006. 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:


	For the Year Ended December 31
	2007			2006
	($ in thousands)
Pre-tax net book loss	$	(145,465	)	$	(22,084	)

Texas Margin Tax Current and Deferred		662			1,229
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities		(519	)		—
Valuation Allowance		26			—

Provision for income taxes	$	169		$	1,229

Effective income tax rate		100.0	%		100.0	%

F-32

Index to Financial Statements

Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2007 and 2006 are as follows:


	At December 31,
	2007			2006
	($ in thousands)
Deferred Tax Assets:
Net operating loss carryovers	$	1,998		$	—
Net Operating Loss 2007		26			—
Unrealized Hedging Transactions		1,278			—
Total Deferred Tax		3,302			—
Less: Valuation allowance		(2,578	)		—

Net Deferred Tax Assets		724			—

Deferred Tax Liabilities:					—
Property, plant equipment & Amortizable Assets		(1,906	)		(1,229	)
Book/Tax Differences from Partnership Investment		(16,334	)		—

Total Deferred Tax Liabilities		(18,240	)		(1,229	)

Total Net Deferred Tax Liabilities	$	(17,516	)	$	(1,229	)

Current portion of total net deferred tax liabilities	$	—		$	—

Long-term portion of total net deferred tax liabilities	$	(17,516	)	$	(1,229	)

We had net operating loss carryforwards of $2.0 million and $0 million at December 31, 2007 and 2006, 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 $2.6 million and $0 million at December 31, 2007 and 2006, respectively. Of the $2.6 million valuation allowance for 2007, $.6 million is 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 or no 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.

The largest single component of our deferred tax liabilities is related to federal income taxes of Eagle Rock Energy Acquisition Co, Inc. and Eagle Rock Upstream Development Company, Inc., our wholly-owned corporations which are subject to income taxes. Eagle Rock Upstream Development Company, Inc. was formerly known as Redman Energy Corporation and was acquired in the form of a corporation as part of the Redman acquisition during 2007. Book/tax differences were created by the Redman acquisition. These book/tax temporary differences result in a net deferred tax liability of $16.3 million 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

F-33

Index to Financial Statements

$1.9 million and $1.2 million during the years ended December 31, 2007 and 2006, respectively. The offsetting net charges of $0.7 million and $1.2 million are shown on our Statement of Consolidated Operations for the years ended December 31, 2007 and 2006, respectively, as a component of provision for income taxes.

NOTE 15. EQUITY-BASED COMPENSATION

On October 24, 2006, the general partner of the general partner for Eagle Rock Energy Partners, L.P., approved a long-term incentive plan (LTIP) for its employees, directors and consultants who provide services to the Partnership covering an aggregate of 1,000,000 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). The restricted units granted in 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, 2007 was $23.10. 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, 2007, is provided below:


	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2006	122,450		$	18.75
Granted	438,971		$	23.10
Vested	(37,190	)	$	22.60
Forfeitures	(57,169	)	$	23.07

Outstanding at December 31, 2007	467,062		$	23.01

The total grant date fair value of restricted units that vested during the year ended December 31, 2007 was $0.8 million. No restricted units vested during the year ended December 31, 2006.

For the years ended December 31, 2007 and 2006, non-cash compensation expense of approximately $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

F-34

Index to Financial Statements

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, 2007, unrecognized compensation costs related to the outstanding restricted units under our LTIP totaled approximately $9.8 million. The remaining expense is to be recognized over a weighted average of 2.2 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.

NOTE 16. 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.

The following table presents our calculation of basic and diluted earnings per unit for the periods indicated:


	For the Year Ended December 31,
	2007			2006			2005
	($ in thousands)
Net (loss) income:	$	(145,634	)	$	(23,314	)	$	2,750
Net (loss) income allocated:
Common units		(86,334	)		(15,229	)		2,667
Subordinated units		(56,971	)		(7,637	)		—
General partner units		(2,329	)		(448	)		83
Weighted average unit outstanding during period:
Common units		37,008			12,123			24,151
Subordinated units		20,691			17,873			—
General partner units		845			557			20
Earnings Per Unit—continuing operations:
Common units	$	(2.11	)	$	(1.26	)	$	0.11
Subordinated units	$	(3.14	)	$	(0.43	)	$	—
General partner units	$	(3.14	)	$	(0.80	)	$	4.06

F-35

Index to Financial Statements

NOTE 17. SUBSEQUENT EVENTS

On February 19, 2008 the Partnership announced the commencement of a two-phase midstream project which will consolidate volumes and operations in the Partnership’s West Panhandle System and enhance the Partnership’s capacity and recovery efficiencies in the fast-growing East Panhandle System. The total project, which is expected to be completed in the first quarter of 2009 at a cost of approximately $25 million, involves diverting West Panhandle volumes from the Partnership’s Stinnett Plant, located in Moore County, Texas to its Cargray Plant, located in Carson County, Texas and subsequently relocating the Stinnett Plant’s high-efficiency cryogenic technology to the East Panhandle Arrington System, located in Hemphill County, Texas.

NOTE 18. 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 reserve estimates reported 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, 2007, were based on estimates made by our independent engineers, Cawley, Gillespie & Associates, Inc (“Cawley Gillespie”). Cawley Gillespie are engaged by and provide their reports to our senior management team. We make representations to the independent engineers that we have provided all relevant operating data and documents, and in turn, we review these 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.

F-36

Index to Financial Statements

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. Natural gas liquids are included in oil reserves. Oil and natural gas liquids are based on the December 31, 2007 West Texas Intermediate posted price of $96.00 per barrel and are adjusted by lease for quality, transportation fees, and regional price differentials. Gas prices are based on a December 31, 2007 Henry Hub spot market price of $7.46 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.


	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
Partnership’s proportional interest in reserves of investees accounted for by the equity method—end of year	58		720		48

	Proved Developed Reserves
	Oil (MBbls)		Gas (MMcf)		Natural Gas Liquids (MBbls)
December 31, 2007	9,634		38,868		5,437

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, 2007.


Evaluated properties	$	461,884
Unevaluated properties—excluded from depletion		66,023

Gross oil and gas properties		527,907
Accumulated depreciation, depletion, amortization		(23,865	)

Net oil and gas properties	$	504,042

The Partnership’s proportional interest in the capitalized costs relating to oil and natural gas producing activities of investees accounted for by the equity method were $1.0 million for the year ended December 31, 2007.

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 year ended December 31, 2007:


Property acquisition costs, proved	$	464,204
Property acquisition costs, unproved		66,023
Exploration and extension well costs		—
Development costs		3,429

Total costs	$	533,656

F-37

Index to Financial Statements

The Partnership’s proportional interest in the costs incurred in oil and natural gas property acquisition, exploration and development activities of investees accounted for by the equity method were $0 for the year ended December 31, 2007.

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 based on oil and natural gas reserve and production volumes estimated by the Company’s engineering staff. 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;

•

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; and

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.

The Standardized Measure is as follows (in thousands) as of December 31, 2007:


Future cash inflows	$	1,565,539
Future production costs		(500,240	)
Future development costs		(10,045	)
Future net cash flows before income taxes		1,055,254
Future income tax expense		—
Future net cash flows before 10% discount		1,055,254
10% annual discount for estimated timing of cash flows		(498,294	)

Standardized measure of discounted future net cash flows	$	556,960

F-38

Index to Financial Statements

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, 2007 (in thousands).


Beginning of year	$	—
Sale of oil and gas produced, net of production costs		(48,294	)
Net changes in prices and production costs		99,252
Extensions, discoveries and improved recovery, less related costs		—
Previously estimated development costs incurred during the period		888
Revisions of previous quantity estimates		26,110
Purchases of property		459,041
Sales of property		—
Accretion of discount		21,274
Net changes in income taxes		—
Other		(1,311	)

End of year	$	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, 2007 (in thousands):


Revenues	$	64,934
Costs and expenses:
Production costs		16,640
General and administrative		1,593
Depreciation, depletion and amortization		24,262
Impairment		5,749

Total costs and expenses		48,244

Results of operations	$	16,690

The following are the results of operations for the oil and natural gas producing activities of the Partnership’s investees accounted for by the equity method for the year ended December 31, 2007 (in thousands):


Revenues	$	1,023
Costs and expenses:
Production costs		64
Depletion & amortization		723

Total costs and expenses		787

Results of operations	$	236

* * * * *

F-39

Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ONEOK Texas Field Services, L.P.

We have audited the accompanying statements of operations, partnership capital, and cash flows for the eleven-month period ended November 30, 2005 of ONEOK Texas Field Services, L.P. (the “Company”). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the results of operations and cash flows of the Company for the eleven-month period ended November 30, 2005, in conformity with accounting principles generally accepted in the United States of America.

As described in the notes 1 and 9 to the financial statements, on December 1, 2005, Eagle Rock Field Services, L.P. (a subsidiary of Eagle Rock Midstream Resources, L.P.) acquired ONEOK Texas Field Services, L.P.

/s/ DELOITTE & TOUCHE LLP

Tulsa, Oklahoma

April 28, 2006

F-40

Index to Financial Statements

ONEOK TEXAS FIELD SERVICES, L.P.

STATEMENT OF OPERATIONS

For the Eleven-Month Period Ended November 30, 2005


	Eleven-Month Period Ended November 30, 2005
REVENUES	$	396,953,100
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		316,978,910
Operations and maintenance		25,326,379
Depreciation and amortization		8,157,159
Ad valorem taxes		2,192,117

Total costs and expenses		352,654,565

OPERATING INCOME		44,298,535

OTHER INCOME:
Other income—net		17,312
Interest income		858,793

Total other income		876,105

INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		45,174,640
INCOME TAX PROVISION		15,811,124

NET INCOME	$	29,363,516

See notes to financial statements.

F-41

Index to Financial Statements

ONEOK TEXAS FIELD SERVICES, L.P.

STATEMENT OF PARTNERSHIP CAPITAL

For the Eleven-Month Period Ended November 30, 2005


	Eleven-Month Period Ended November 30, 2005
PARTNERSHIP CAPITAL—Beginning of period	$	204,344,079
NET INCOME		29,363,516

PARTNERSHIP CAPITAL—End of period	$	233,707,595

See notes to financial statements.

F-42

Index to Financial Statements

ONEOK TEXAS FIELD SERVICES, L.P.

STATEMENT OF CASH FLOWS

For the Eleven-Month Period Ended November 30, 2005


	Eleven-Month Period Ended November 30, 2005
OPERATING ACTIVITIES:
Net income	$	29,363,516
Adjustments to reconcile net income to net cash provided by operating activities Depreciation and amortization		8,157,159
Provision for deferred income taxes		1,559,008
Changes in assets and liabilities:
Accounts receivable and other current assets		(56,598,772	)
Accounts payable and accrued liabilities		64,320,201
Other assets and liabilities		801,622

Net cash provided by operating activities		47,602,734

INVESTING ACTIVITIES:
Capital expenditures		(6,705,325	)
Other investing activities		(2,281	)

Net cash used in investing activities		(6,707,606	)

FINANCING ACTIVITIES—Increase in amounts due from parent		(40,895,128	)

CHANGE IN CASH AND CASH EQUIVALENTS		—
CASH AND CASH EQUIVALENTS—Beginning of period		—
CASH AND CASH EQUIVALENTS—End of period		—

See notes to financial statements.

F-43

Index to Financial Statements

ONEOK TEXAS FIELD SERVICES, L.P.

NOTES TO FINANCIAL STATEMENTS

For the Eleven-Month Period Ended November 30, 2005

1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Through November 30, 2005, ONEOK Texas Field Services, L.P. (the “Company”) was a wholly-owned subsidiary of ONEOK, Inc. (“ONEOK”), and is the predecessor to Eagle Rock Energy Partners, L.P. The Company purchases, gathers and processes natural gas and extracts, sells and markets natural gas liquids (“NGLs”) in the Texas Panhandle area. We own or lease processing facilities and gathering pipelines. On December 1, 2005, the Company merged with Eagle Rock Field Services L.P., a subsidiary of Eagle Rock Midstream Resources, L.P. Subsequent to the merger, Eagle Rock Midstream Resources, L.P. changed its name to Eagle Rock Field Services, Inc.

2. SUMMARY OF ACCOUNTING POLICIES

Critical Accounting Policies—The following is a summary of our most critical accounting policies, which are defined as those policies most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective, or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters. The development and selection of our critical accounting policies and estimates are a reflection of the policies discussed with the audit committee of ONEOK’s Board of Directors for ONEOK’s corporate accounting policies.

Derivatives and Risk Management Activities—To minimize the risk of fluctuations in natural gas, NGLs and crude oil prices, ONEOK periodically enters into futures transactions and swaps on behalf of its subsidiary companies in order to hedge anticipated sales and purchases of natural gas and crude oil production, fuel requirements and NGL inventories on a consolidated basis. The Company, therefore, does not account for these derivative transactions on its books.

Pension and Postretirement Employee Benefits—ONEOK has a defined benefit pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees. No bargaining unit employees hired after December 31, 2004, are eligible for ONEOK’s defined benefit pension plan; however, they are covered by a profit sharing plan. ONEOK’s actuarial consultant calculates the expense and liability related to these plans and uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. In determining the projected benefit obligations and the costs, assumptions can change from period to period and result in material changes in the costs and liabilities we recognize. Our statements of operations reflect the estimated annual expenses that ONEOK incurred on our behalf associated with pension and postretirement employee benefits by allocation.

Contingencies—Our accounting for contingencies covers a variety of business activities including contingencies for legal exposures and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with SFAS No. 5, Accounting for Contingencies. We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Actual results may differ from our estimates resulting in an impact, either positive or negative, on earnings.

Significant Accounting Policies

Revenue Recognition—We recognize revenue when services are rendered or product is delivered. We receive fees for gathering natural gas production from oil and natural gas wells under three primary contract arrangements.

F-44

Index to Financial Statements

•

Keep-Whole—We extract NGLs and return to the producer volumes of merchantable natural gas containing the same amount of BTUs as the raw natural gas that the producer delivered to us. We then sell the natural gas liquids to an affiliate.

•

Percent of Proceeds—We retain a percentage of the NGLs and/or a percentage of the natural gas as payment for gathering, compressing and processing the producer’s raw natural gas. Both the natural gas and natural gas liquids are sold to affiliates.

•

Fee—We are paid a fee for the services provided such as BTUs gathered, compressed, treated and/or processed.

Income Taxes—In 2001, the Company filed an election to be treated as a C corporation for federal income tax purposes, and was included in the consolidated federal income tax return of ONEOK. For financial reporting purposes, the Company computes its income taxes as if it filed a separate federal income tax return. Thus, deferred income taxes are recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities.

Use of Estimates—Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. Items which may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provisions for uncollectible accounts receivable, unbilled revenues for natural gas delivered but for which meters have not been read, natural gas purchased expense for natural gas received but for which no invoice has been received, provision for income taxes including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts. Accordingly, the reported amounts of our assets and liabilities, revenues and expenses, and related disclosures are necessarily affected by these estimates.

We evaluate these estimates on an ongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.

Allocated Expenses—Our historical income statements reflect all of the expenses that the parent incurred on its behalf. The Company’s financial statements therefore include certain expenses incurred by its parent which may include, but are not necessarily limited to, the following:

•

Officer and employee salaries

•

Rent or depreciation

•

Advertising

•

Accounting, tax, and legal services

•

Other selling, general and administrative expenses

•

Costs for pension, medical, postretirement, and other employee benefits

•

Environmental Expenditures—Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed.

F-45

Index to Financial Statements

3. RELATED-PARTY TRANSACTIONS

The majority of the Company’s natural gas and natural gas liquids sales were to affiliates. Total sales to affiliates were $386.3 million for the eleven-month period ended November 30, 2005. Additionally, ONEOK and its subsidiaries (affiliates) provided a variety of services to the Company, including cash management and financing services, employee benefits provided through ONEOK’s benefit plans, administrative services provided by ONEOK employees and management, insurance and office space leased in ONEOK’s headquarters building and other field locations. Where costs are specifically incurred on behalf of an affiliate, the costs are billed directly to the affiliate by ONEOK. In other situations, the costs are allocated to the affiliates through a variety of methods, depending upon the nature of the expense and the activities of the affiliates. For example, a benefit which applies equally to all employees is allocated based upon the number of employees in each affiliate. An expense benefiting the consolidated company but having no direct basis for allocation is allocated by a method using a combination of gross plant and investment, operating income and labor expense. All costs directly charged or allocated to the Company by affiliates are included in the statements of income and all such operating costs have been allocated by ONEOK and its affiliates.

4. COMMITMENTS AND CONTINGENCIES

Leases—We utilize assets under operating leases in several areas of operation. Combined rental expense, including leases with no continuing commitment, amounted to $1.6 million for the eleven-month period ended November 30, 2005.

Future minimum lease payments under non-cancelable operating leases as of November 30, 2005 are immaterial.

Environmental—The Company is subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose the Company to fines, penalties and/or interruptions in our operations that could be material to the results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities, in the process of transporting natural gas or NGLs, or at any facility that we own, operate or otherwise use, the Company could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect our results, operations and cash flow. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.

The Company’s expenditures for environmental evaluation and remediation to date have not been significant in relation to the results of operations and there were no material effects upon earnings related to compliance with environmental regulations.

Other—The Company is a party to other litigation matters and claims, which are normal in the course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position, or liquidity.

Regulatory Compliance—In the ordinary course of business, the Company is subject to various laws and regulations. In the opinion of management, compliance with existing laws and regulations will not materially affect the Company’s financial position.

F-46

Index to Financial Statements

5. INCOME TAXES

Earnings are subject to federal income taxes. The following table shows the components of the Company’s income tax provision (benefit):


	Period Ended November 30, 2005
Current income taxes (benefit)	$	14,252,116
Deferred income taxes		1,559,008

Total provision for income taxes	$	15,811,124

Taxes computed at the corporate federal income tax rate reconcile to the reported income tax provision as follows:


	Period Ended November 30, 2005
Pretax income	$	45,174,640
Federal statutory income tax rate		35	%

Income tax provision	$	15,811,124

6. EMPLOYEE BENEFIT PLANS

Employee Benefit Plans—The Company’s income statements reflect the estimated annual expenses that ONEOK incurred on its behalf associated with pension, medical, postretirement and other employee benefits by allocation. Such allocated amounts were $1.7 million for the eleven-month period ended November 30, 2005. Primary benefit plans offered were as follows:

Retirement Plans—We have defined benefit and defined contribution retirement plans covering substantially all employees. Certain officers and key employees are also eligible to participate in supplemental retirement plans.

Other Postretirement Benefit Plans—We sponsor welfare care plans that provide postretirement medical benefits and life insurance to substantially all employees who retire under the retirement plans with at least five years of service. The postretirement medical plan is contributory, with retiree contributions adjusted periodically, and contains other cost sharing feature such as deductibles and coinsurance. Nonbargaining employees retiring between the ages of 50 and 55 who elect postretirement medical coverage and all nonbargaining employees hired on or after January 1, 1999 who elect postretirement medical coverage, pay 100 percent of the retiree premium for participation in the plan. Additionally, any employee who came to us through various acquisitions may be further limited in their eligibility to participate or receive any contributions from us for postretirement medical benefits.

Thrift Plan—ONEOK has a Thrift Plan covering substantially all employees. Employee contributions are discretionary. Subject to certain limits, we match employee contributions. the Company’s income statements reflect the estimated annual expenses that ONEOK incurred on our behalf associated with the thrift plan by allocation.

F-47

Index to Financial Statements

Profit Sharing Plan—ONEOK has a profit sharing plan for all nonbargaining unit employees hired after December 31, 2004. Nonbargaining unit employees who were employed prior to January 1, 2005, were given a one-time opportunity to make an irrevocable election to participate in the profit sharing plan and not accrue any additional benefits under the defined benefit pension plan after December 31, 2004. ONEOK made a contribution to the profit sharing plan each quarter equal to one percent of each participant’s compensation during the quarter. Additional discretionary employer contributions may be made at the end of each year. Employee contributions are not allowed under the plan. The Company’s income statements reflect the estimated annual expenses that ONEOK incurred on our behalf associated with the profit sharing plan by allocation.

7. SUBSEQUENT EVENT

On December 1, 2005 Eagle Rock Field Services, L.P. (a subsidiary of Eagle Rock Midstream Resources, L.P.) acquired ONEOK Texas Field Services, L.P. for $528 million. In association with the purchase, prior to November 30, 2005, the Company received merger consideration earnest money of $15 million from Eagle Rock Pipeline, L.P.

* * * *

F-48

Index to Financial Statements

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))

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 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 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))

Index to Financial Statements


Exhibit Number		Description
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**		Form of 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))

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))

Index to Financial Statements


Exhibit Number		Description

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)

14.1		Code of Ethics for Chief Financial 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. (incorporated by reference to Exhibit 21.1 of the registrant’s registration statement on Form S-1 (File No. 333-144938))

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 Alfredo Garcia 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 Alfredo Garcia in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002

*	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.