Eagle Rock Energy Partners L P (EROC) S-1 IPO registration

As filed with the Securities and Exchange Commission on July 27, 2007

Registration No.             

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

EAGLE ROCK ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	1311	69-0629883
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

16701 Greenspoint Park Drive, Suite 200

Houston, TX 77060

(281) 408-1200

(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)

Alfredo Garcia

16701 Greenspoint Park Drive, Suite 200

Houston, Texas 77060

(281) 408-1200

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Barry Davis

Thomas R. Lamme

Thompson & Knight LLP

333 Clay Street, Suite 3300

Houston, TX 77002

(713) 654-8111

Approximate date of commencement of proposed sale to the public:  As soon as practicable after this Registration Statement is declared effective

If any securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), check the following box.  þ

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box.  o

		Proposed	Proposed Maximum	Amount of
Title of Class of	Amount	Maximum Price	Aggregate Offering	Registration
Securities to be Registered	to be Registered	Per Unit(1)	Price(1)	Fee
Common units representing limited partner interests	14,803,789	$25.90	$383,418,136	$11,771

(1) Calculated in accordance with Rule 457(c) on the basis of the average of the high and low sales price of the common units on July 25, 2007.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

EXPLANATORY NOTE

This Registration Statement incorporates by reference the Registrant’s Annual Report onForm 10-K for the year ended December 31, 2006, as filed with the Securities and Exchange Commission on April 2, 2007, amended Annual Report onForm 10-K/A for the year ended December 31, 2006, as filed with the Securities and Exchange Commission on July 26, 2007, Current Report onForm 10-Q filed with the Securities and Exchange Commission on May 15, 2007, and Current Reports onForms 8-K as filed with the Securities and Exchange Commission on January 12, 2007, January 29, 2007, February 1, 2007, February 14, 2007, April 4, 2007, May 4, 2007, May 18, 2007, May 22, 2007, July 17, 2007, and July 18, 2007.

The information in this prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where such offer or sale is not permitted.

SUBJECT TO COMPLETION

PRELIMINARY PROSPECTUS DATED JULY 27, 2007

PROSPECTUS

14,803,789 Common Units
Representing Limited Partner Interests

This prospectus relates to up to 14,803,789 common units of limited partner interests of Eagle Rock Energy Partners, L.P., which may be offered for sale by the selling unitholders named in this prospectus. The selling unitholders acquired the common units offered by this prospectus in private equity purchases. We are registering the offer and sale of the common units to satisfy registration rights we have granted.

We are not selling any common units under this prospectus and will not receive any proceeds from the sale of common units by the selling unitholders. The common units to which this prospectus relates may be offered and sold from time to time directly from the selling unitholders or alternatively through underwriters or broker-dealers or agents. The common units may be sold in one or more transactions, at fixed prices, at prevailing market prices at the time of sale or at negotiated prices. Please read “Plan of Distribution.”

Because all of the common units being offered under this prospectus are being offered by selling unitholders, we cannot currently determine the price or prices at which our shares of common stock may be sold under this prospectus. Our common units are traded on the NASDAQ Global Market under the trading symbol “EROC.” The last reported sale of our common units on the NASDAQ Global Market on July 25, 2007 was at a price of $25.74 per common unit. Future prices will likely vary from that price and these sales may not be indicative of prices at which our common units will trade.

Investing in our common units involves risks. You should read the section entitled “Risk Factors” beginning on page 9 of this prospectus, for a discussion of certain risk factors that you should consider when investing in our common stock.

You should rely only on the information contained in or incorporated by reference into this prospectus or any prospectus supplement or amendment. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is          , 2007.

TABLE OF CONTENTS

	Page
SUMMARY		1
Eagle Rock Energy Partners, L.P.		1
The Offering		6
RISK FACTORS		9
USE OF PROCEEDS		32
CAPITALIZATION		33
Price Range of Common Units and Distribution		33
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		34
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS		37
SELECTED HISTORICAL FINANCIAL DATA		46
Non-GAAP Financial Measures		48
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS		51
BUSINESS		55
MANAGEMENT		70
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		74
SELLING UNITHOLDERS		75
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		78
Formation Stage		78
Operational Stage		78
Liquidation Stage		79
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		82
DESCRIPTION OF THE COMMON UNITS		88
THE PARTNERSHIP AGREEMENT		90
UNITS ELIGIBLE FOR FUTURE SALE		101
MATERIAL TAX CONSEQUENCES		103
INVESTMENT IN EAGLE ROCK ENERGY PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS		116
PLAN OF DISTRIBUTION		117
VALIDITY OF THE COMMON UNITS		118
EXPERTS		119
INDEPENDENT ENGINEERS		119
WHERE YOU CAN FIND MORE INFORMATION		119
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		120
Partnership Interests Purchase and Contribution Agreement
Partnership Interests Contribution Agreement
Asset Contribution Agreement
Registration Rights Agreement
Opinion of Thompson & Knight LLP
Common Unit Purchase Agreement
List of Subsidiaries
Consent of Deloitte & Touche LLP
Consent of Deloitte & Touche LLP
Consent of Deloitte & Touche LLP
Consent of Cawley, Gillespie & Associates

SUMMARY

This summary highlights information contained herein and incorporated by reference in this prospectus. It is not complete and does not contain all of the information you may wish to consider before investing in our common units. We urge you to read this entire prospectus and the information incorporated herein by reference carefully, including the “Risk Factors” beginning on page 8 of this prospectus and the financial statements incorporated by reference in this prospectus from our amended Annual Report onForm 10-K/A for the year ended December 31, 2006.

References in this prospectus to “Eagle Rock Energy Partners, L.P.,” “we,” “our,” “us” or like terms, when used in a historical context, refer to both Eagle Rock Pipeline, L.P. and its subsidiaries. When used in the present tense or prospectively, those terms refer to Eagle Rock Energy Partners, L.P. and its subsidiaries. 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 Natural Gas Partners and members and former members of our management team.

In connection with our recently completed Montierra Acquisition, described below, J.A. Mills became the Chief Executive Officer and Chairman of the Board of Eagle Rock Energy G&P, LLC, which is the general partner of our general partner. Mr. Mills remains as chief executive officer of Montierra, which is controlled by Natural Gas Partners. When we refer to “affiliates of our general partner”, we are not referring to Montierra, which is under common control with us through Natural Gas Partners’ control of Montierra. Any percentage of limited partner interests with respect to our general partner and affiliates of our general partner described in this prospectus do not include interest owned by Montierra. Additionally, any description of incentive distribution rights in this prospectus is qualified by the fact that, in connection with the Montierra Acquisition, Holdings transferred the economic equivalent interests in certain of the incentive distribution rights to Montierra. See “Certain Relationships and Related Party Transactions — Montierra and Co-Invest Agreement” for a discussion of the transaction.

We have provided definitions for some of the industry terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” beginning in Appendix A of this prospectus.

Eagle Rock Energy Partners, L.P.

General

We are a growth-oriented Delaware limited partnership engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs, what we call our midstream business, and the business of acquiring, developing and producing oil and natural gas properties interests, what we call our upstream business. Our midstream assets are strategically located in four significant natural gas producing regions in the Texas Panhandle, south Texas, southeast Texas and Louisiana. Our upstream assets include interests in over 2,500 wells located in multiple producing trends across 17 states. Currently, based on revenues generated during the second quarter 2007, our midstream business comprises approximately 87% of our business and our upstream business comprises approximately 13%. We intend to acquire and construct additional assets in both our midstream and upstream businesses and 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, as well as in the operation of oil and natural gas properties and assets.

We completed the acquisition of certain fee minerals, royalties, overriding royalties and working interest properties from Montierra Minerals & Production, L.P. (a Natural Gas Partners VII, L.P. portfolio company)

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and NGP-VII Income Co-Investment Opportunities, L.P. (a Natural Gas Partners affiliate) (“the Montierra Acquisition”) on April 30, 2007. The assets conveyed include interests in approximately 5.6 million gross mineral acres or 430,000 net mineral acres, and interests in over 2,500 wells with net proved producing reserves of approximately 4.5 billion cubic feet of natural gas and 2.5 million barrels of crude oil. Additionally, on May 3, 2007, we completed our acquisition of Laser Midstream Energy, L.P. and certain of its subsidiaries (“Laser”). The assets include over 405 miles of gathering systems and related compression and processing facilities in South Texas, East Texas and North Louisiana. Concurrent with the Laser transaction, we completed a private placement of 7,005,495 common units to third-party investors. The units were purchased at a price of $18.20 per unit resulting in gross proceeds of approximately $127.5 million.

On October 24, 2006, we completed our initial public offering, or IPO. We issued 12,500,000 common units to the public, representing a 29.6% limited partner interest. Eagle Rock Holdings, L.P., upon contribution of certain assets and ownership of operating subsidiaries, received 3,459,236 common units and 20,691,495 subordinated units, totaling an aggregate initially of 57.2% limited partner interest (which reduced to 54.0% after the exercise of the overallotment option and including restricted common units issued to employees under our Long Term Incentive Plan in connection with our IPO), and all of the equity interests in the Partnership’s general partner, Eagle Rock Energy GP, L.P., which initially owned a 2% general partner interest. Additional private investors, after conversion of their ownership in Eagle Rock Pipeline, L.P., received 4,732,259 common units, representing initially an 11.2% limited partner interest in the Partnership (which reduced to 10.7% after the exercise of the overallotment option and including restricted common units issued to employees in connection with our IPO). On November 21, 2006, 1,463,785 common units were redeemed as part of the exercise of the underwriters’ overallotment option we granted in conjunction with our IPO. In connection with the IPO, Eagle Rock Pipeline, L.P. was merged with and into our newly formed subsidiary with Eagle Rock Pipeline, L.P. being the surviving entity.

As a result of the initial public offering, our partnership structure is such that Eagle Rock Energy G&P, LLC is the general partner of Eagle Rock Energy GP, L.P., which is the general partner of Eagle Rock Energy Partners, L.P. Eagle Rock Holdings, L.P., which is owned by members of management and private equity funds controlled by Natural Gas Partners, is the sole member of Eagle Rock G&P, LLC.

We commenced operations in 2002 when certain current and former members of our management team formed Eagle Rock Energy, Inc., an affiliate of our predecessor, to provide midstream services to natural gas producers. Since 2002, we have grown through a combination of organic growth and acquisitions. In connection with the acquisition in 2003 of the Dry Trail plant, a CO₂ tertiary recovery plant located in the Oklahoma panhandle, members of our management team formed Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy, Inc., to own, operate, acquire and develop complementary midstream energy assets. Eagle Rock Holdings, L.P., has benefited from the equity sponsorship of Natural Gas Partners, one of the largest private equity fund sponsors of companies in the energy sector, which since 2003 has provided us with significant support in pursuing acquisitions.

Risk Factors

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 Risk Factors, starting on page 8 of this prospectus.

Management of Eagle Rock Energy Partners, L.P.

Eagle Rock Energy GP, L.P., our general partner, has sole responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, Eagle Rock Energy G&P, LLC, conducts our business and operations, and the board of directors and executive officers of Eagle Rock Energy G&P, LLC makes decisions on our behalf. Neither our general partner, nor any of its affiliates, receive any management fee or other compensation in connection with the management of our business, but they are entitled to reimbursement for all direct and indirect expenses they incur on our behalf.

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Neither our general partner nor the board of directors of Eagle Rock Energy G&P, LLC is elected by our unitholders. Unlike shareholders in a publicly traded corporation, our unitholders are not entitled to elect the directors of Eagle Rock Energy G&P, LLC. 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. References herein to the officers or directors of our general partner refer to the officers and directors of Eagle Rock Energy G&P, LLC. In addition, certain references to our general partner refer to Eagle Rock Energy GP, L.P. and Eagle Rock Energy G&P, LLC, collectively.

As is common with publicly traded limited partnerships and in order to maximize operational flexibility, we conduct our operations through subsidiaries. We have one direct subsidiary, Eagle Rock Pipeline, L.P., a limited partnership that will conduct business through itself and its subsidiaries.

Natural Gas Partners, which controls our general partner, is headquartered in Irving, Texas. 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 eight institutionally-backed investment funds, Natural Gas Partners has sponsored over 100 portfolio companies and has controlled invested capital and additional commitments totaling $2.9 billion.

Our General Partner’s Rights to Receive Distributions

1.46% General Partner Interest.  Our general partner is currently entitled to receive 1.46% of our declared quarterly cash distributions. The general partner’s interest in these distributions is reduced when we issue additional units and our general partner does not elect to contribute a proportionate amount of capital to us to maintain its then current general partner interest. All references in this prospectus to the general partner’s 2% general partner interest assume that the general partner has elected to make these additional capital contributions to maintain its initial right to receive 2% of these cash distributions.

Incentive Distributions.  In addition to its 1.46% general partner interest, our general partner holds the incentive distribution rights, which are non-voting limited partner interests that represent the right to receive an increasing percentage of quarterly distributions of available cash as higher target distribution levels of cash have been distributed to the unitholders. The following table shows how our available cash from operating surplus is allocated among our unitholders and the general partner as higher target distribution levels are met:

	Total Quarterly	Marginal Percentage
	Distribution per Unit	Interest in Distributions*
					General Partner
	Target Distribution Level	Unitholders			Interest
Minimum Quarterly Distribution	$0.3625		98	%		2	%
First Target Distribution	up to $0.4169		98	%		2	%
Second Target Distribution	Above $0.4169 up to $0.4531		85	%		15	%
Third Target Distribution	Above $0.4531 up to $0.5438		75	%		25	%
Thereafter	above $0.5438		50	%		50	%

* Assuming there are no arrearages on common units and that our general partner maintains its 2% initial general partner interest and continues to own the incentive distribution rights.

For a more detailed description of the incentive distribution rights, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner Interest and Incentive Distribution Rights.”

Summary of Conflicts of Interest and Fiduciary Duties

General.  Eagle Rock Energy GP, L.P., our general partner, has a legal duty to manage us in a manner beneficial to holders of our common units and subordinated units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” The officers and directors of Eagle Rock Energy G&P, LLC also have fiduciary duties to manage Eagle Rock Energy G&P, LLC and our general partner in a manner beneficial to their owners. As a result of this relationship, conflicts of interest may arise in

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the future between us and holders of our common units and subordinated units, on the one hand, and our general partner and its affiliates on the other hand. For example, our general partner will be entitled to make determinations that affect our ability to make cash distributions, including determinations related to:

•  the manner in which our business is operated;

•  the level and amount of our borrowings;

•  the amount, nature and timing of our capital expenditures;

•  asset purchases and sales and other acquisitions and dispositions; and

•  the amount of cash reserves necessary or appropriate to satisfy general, administrative and other expenses and debt service requirements, and otherwise provide for the proper conduct of our business.

These determinations will have an effect on the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether our general partner receives incentive cash distributions as discussed above.

Partnership Agreement Modifications to Fiduciary Duties.  Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to holders of our common units and subordinated units. Our partnership agreement also restricts the remedies available to holders of our common units and subordinated units for actions that might otherwise constitute a breach of our general partner’s fiduciary duties owed to holders of our common units and subordinated units. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, each holder of common units consents to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

Our general partner’s affiliates may engage in competition with us.  Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in our partnership agreement, Eagle Rock Holdings and the NGP Investors are not prohibited from engaging in, and are not required to offer us the opportunity to engage in, other businesses or activities, including those that might be in direct competition with us.

For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties.”

Recent Developments

During the first and second quarters of 2007, we entered into several significant transactions, which closed during the second and third quarters of 2007. Those transactions are described below.

Laser Acquisition.  On March 30, 2007, Eagle Rock Energy Partners, L.P. entered into a Partnership Interest Purchase and Contribution Agreement with Laser Midstream Energy II, LP, a Delaware limited partnership, Laser Gas Company I, LLC, a Delaware limited liability company, Laser Midstream Company, LLC, a Texas limited liability company, and Laser Midstream Energy, LP, a Delaware limited partnership. Pursuant to the Purchase and Contribution Agreement, we acquired all of the non-corporate interests of Laser Midstream Energy, LP and certain subsidiaries, for a total purchase price of approximately $136.8 million, consisting of $110.0 million in cash and 1,407,895 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 and North Louisiana. The Laser acquisition closed May 3, 2007.

Montierra Acquisition.  On March 31, 2007, we entered into a Partnership Interest Contribution Agreement to acquire certain fee minerals, royalties and working interest properties from Montierra Minerals & Production, L.P., a Texas limited partnership, and NGP-VII Income Co-Investment Opportunities, L.P., a Delaware limited partnership, for an aggregate purchase price of $127.4 million, subject to price adjustments.

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Upon closing on April 30, 2007, Montierra and NGP received as consideration a total of 6,390,400 of our common units and $6.0 million in 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 Minerals & Production, L.P.

The assets conveyed in the Montierra acquisition include fee mineral acres and royalty overriding royalty interests in oil and natural gas producing wells with net proved producing reserves of approximately 4.5 billion cubic feet of natural gas and 2.5 million barrels of oil.

EAC Acquisition.  On July 11, 2007, Eagle Rock Energy Partners, L.P., a Delaware limited partnership (“Eagle Rock,” or the “Partnership”) announced it had signed a definitive purchase agreement with AmGu Holdings, LLC to acquire Escambia Asset Co., LLC and Escambia Operating Company, LLC (collectively, “EAC”) for an aggregate purchase price of approximately $220.0 million, comprised of approximately $203.5 million in cash and 689,857 in Eagle Rock common units, subject to working capital and other price adjustments, in a privately negotiated transaction. The assets subject to this transaction include 33 operated wells in Escambia County, Alabama with net production of approximately 3,300 Boepd and proved reserves of approximately 12.2 MMBoe, of which 89% is proved developed producing. The transaction also includes two treating facilities with 100 MMcfd of capacity, one natural gas processing plant with 40 MMcfd of capacity and related gathering systems. The acquisition has an effective date of April 1, 2007, and is subject to customary closing conditions. The EAC acquisition is expected to contribute approximately $58.1 million of annual adjusted EBITDA with maintenance capital estimated to be approximately $11.0 million on an annual basis.

Redman Acquisition.  On July 11,2007, Eagle Rock signed definitive purchase agreements to acquire 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”) in a privately negotiated transactions. For a combined value of $180.0 million, Redman will receive as consideration a total of 4,426,591 newly-issued Eagle Rock common units and $74.1 million in cash, subject to working capital and other customary closing adjustments. The assets conveyed in the Redman transaction include 76 operated and 95 non-operated wells mainly located in East and South Texas with a net production of 1,810 Boepd and combined proved reserves of 8.3 MMBoe, of which 78% is proved developed producing. This acquisition is expected to generate approximately $24.8 million of annual adjusted EBITDA, with $1.5 million in maintenance capital requirements on an annual basis.

One or more Natural Gas Partners private equity funds (“NGP”) directly or indirectly owns a majority of the equity interests in Eagle Rock and Redman. 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, 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.

Private Placement of Equity.  On July 11, 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 million if the Partnership closes both the EAC acquisition and the Redman acquisition. The Partnership also has agreed to file a registration statement with the Securities and Exchange Commission registering for resale the newly-issued common units within 90 days after the closing. The Partnership anticipates that the private placement will close simultaneously with the EAC and Redman acquisitions.

Common Unit Purchase Agreement.  On March 30, 2007, we entered into a Common Unit Purchase Agreement with several institutional purchasers in connection with the private placement of 7,005,495

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common units. The units were purchased at a price of $18.20 per unit resulting in 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 simultaneously with the Laser acquisition.

As part of this transaction, we agreed to file a registration statement with the SEC registering for resale the common units within 90 days after the closing of the issuance of the common units.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 16701 Greenspoint Park Drive, Suite 200, Houston, TX 77060 and our telephone number is(281) 408-1200. Our website is located atwww.eaglerockenergy.com. We make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

The Offering

Common units offered by selling unitholders	14,803,789 common units.
Units outstanding after this offering	36,284,759 common units, including 450,021 restricted common units issued under our Long-Term Incentive Plan, and 20,691,495 subordinated units.
Use of proceeds	We will not receive any proceeds from sales of common units by the selling unitholders.
Cash distributions	Our general partner has adopted a cash distribution policy that requires us to pay cash distributions at an initial distribution rate of $0.3625 per common unit per quarter ($1.45 per common unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates, such as general and administrative expenses associated with being a publicly traded partnership. Our ability to pay cash distributions at this initial distribution rate is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.”
	Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement and in the glossary of terms attached as Appendix A. Our partnership agreement also requires that we distribute all of our available cash from operating surplus each quarter in the following manner:
	• first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.3625 plus any arrearages from prior quarters;

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	• second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.3625; and
	• third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.4169.
	If cash distributions to our unitholders exceed $0.4169 per common unit in any quarter, our general partner will receive, in addition to distributions on its 2% general partner interest, increasing percentages, up to 50%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”
Subordinated units	Eagle Rock Holdings, L.P. owns all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution of $0.3625 per unit only after the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.
Conversion of subordinated units	The subordination period will end on the first business day after we have earned and paid at least $1.45 (the minimum quarterly distribution on an annualized basis) on each outstanding limited partner unit and general partner unit for any three consecutive, non-overlapping four quarter periods ending on or after September 30, 2009. Alternatively, the subordination period will end on the first business day after we have earned and paid at least $0.5438 per quarter (150% of the minimum quarterly distribution, which is $2.175 on an annualized basis) on each outstanding limited partner unit and general partner unit for any four consecutive quarters ending on or after September 30, 2007.
	In addition, the subordination period will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.
	When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.
Issuance of additional units	We can issue an unlimited number of units without the consent of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”
Limited voting rights	Our general partner manages and operates us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Our general partner and its

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	affiliates own an aggregate of 40.2% of our common and subordinated units. This gives our general partner the ability to prevent its involuntary removal. Please read “The Partnership Agreement — Voting Rights.”
Limited call right	If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of the common units.
Estimated ratio of taxable income to distributions	We estimate that if you owned the common units from the date of our initial public offering, October 24, 2006, through the record date for distributions for the period ending December 31, 2009, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.45 per unit, we estimate that your average allocable federal taxable income per year will be no more than $0.29 per unit. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions.”
Material tax consequences	For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”
Exchange listing	Our common units are listed on the NASDAQ Global Market under the symbol “EROC.”

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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. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

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 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 and transportation pipeline 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 and transportation pipeline 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 rolling twelve-month average NYMEX daily settlement price of natural gas has increased from $5.49 per MMBtu as of December 31, 2003 to $7.23 per MMBtu as of December 31, 2006. 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 exploration and development activities in our fields and the fields served by our gathering and pipeline transportation 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 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 exploration and production business in addition to our midstream 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

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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 operators 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 2006 ranged from a high of $9.87 per MMBtu to a low of $3.63 per MMBtu. The NYMEX daily settlement price for crude oil for the prompt month contract in 2006 ranged from a high of $77.03 per barrel to a low of $55.81 per barrel. The markets and prices for 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:

•  the impact of weather or force majeure events on the demand for oil and natural gas;

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

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

•  the level of consumer product demand;

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

•  overall domestic and global economic conditions;

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

•  the availability and marketing of competitive fuels;

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

•  the impact of energy conservation efforts, including technological advances affecting energy consumption; and

•  the extent of governmental regulation and taxation.

Lower oil or natural gas prices may not only decrease our revenues and net proceeds, but also reduce the amount of oil or natural gas that we can economically produce. As a result, the operator of any of the properties could determine 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 our having to make 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

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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 two types of contractual arrangements that expose our cash flows to increases and decreases in the price of natural gas and NGLs: percentage-of-proceeds 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 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. For a detailed discussion of these arrangements, please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations in our annual report onForm 10-K for the year ended December 31, 2006.

Our hedging activities may have a material adverse effect on our earnings, profitability, cash flows and financial condition.

We are exposed to risks associated with fluctuations in commodity prices. The extent of our commodity price risk is related largely to the effectiveness and scope of our hedging activities. In order to reduce our exposure to commodity price risk, we directly hedged substantially all of our share of expected NGL volumes in 2006 and 2007 under percent-of-proceed and keep-whole contracts. This has been accomplished primarily through the purchase of NGL put contracts but also through executing NGL costless collar contracts and swap contracts. We have also hedged substantially all of our share of expected NGL volumes from 2008 through 2010 under percent-of-proceed contracts through a combination of direct NGL hedging as well as indirect hedging through crude oil costless collars. Additionally, to mitigate the exposure to natural gas prices from keep-whole volumes, we have purchased natural gas calls from 2006 to 2007 to cover our short natural gas position. Finally, we have entered into hedging arrangements for a significant portion of our oil and natural gas production. Our management will evaluate whether to enter into any new hedging arrangements, but there can be no assurance that we will enter into any new hedging arrangement or that our future hedging arrangements will be on terms similar to our existing hedging arrangements.

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

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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, 2006, we experienced positive movements in our underlying commodities’ prices which led to an unrealized derivative loss of $26.3 million. This $26.3 million loss had a direct impact on our net income (loss) line resulting in a net loss of $23.1 million. For additional information regarding our hedging activities, please read Item 7A. Quantitative and Qualitative Disclosures about Market Risk in our annual report onForm 10-K for the year ended December 31, 2006.

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.

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

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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:

•  volume throughput through our pipelines and processing facilities;

•  the estimated quantities of our oil and natural gas reserves;

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

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

•  our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. 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 producer’s natural gas reserves dedicated to our gathering and pipeline 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 producer’s natural gas reserves connected to our systems due to the unwillingness of producers to provide reserve information as well as the 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. Themake-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

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agreements and acquisition of new systems. As of December 31, 2006, our two largest suppliers were affiliates of Chesapeake Energy Corporation and Prize Operating Company, accounting for approximately 12% and 10% 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.  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.

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

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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, except for Section 311 as discussed below, 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.

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 in our annual report onForm 10-K for the year ended December 31, 2006, and “Business — Regulation of Operations” in this prospectus.

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

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipelines and facilities and the imposition of substantial liabilities for pollution resulting from our operations. Failure or delay in obtaining regulatory approvals or drilling permits by us or our operators could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection or correlative rights affect our operations by limiting the quantity of oil and natural gas that may be produced and sold.

Numerous governmental authorities, such as the U.S. Environmental Protection Agency, also known as the “EPA,” and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, assessment of monetary penalties and the issuance of injunctions limiting or preventing some or all of our operations.

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

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

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

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

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

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

There is inherent risk of incurring significant environmental costs and liabilities in connection with our operations due to our handling of petroleum hydrocarbons and wastes, operation of our wells, gathering systems and other facilities, air emissions and water discharges related to our operations and historical industry operations and waste disposal practices. Joint and several, strict liability may be incurred under these environmental laws and regulations in connection with discharges or releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for

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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 — Environmental Matters in our annual report onForm 10-K for the year ended December 31, 2006, and “Business — Environmental Matters” in this prospectus.

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, 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,

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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 or upstream, involves potential risks, including, among other things:

•  mistaken assumptions about future prices, volumes, revenues and costs of oil and natural gas, including synergies and estimates of the oil and natural gas reserves attributable to a property we acquire;

•  an inability to integrate successfully the businesses we acquire;

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

•  the assumption of unknown liabilities;

•  limitations on rights to indemnity from the seller;

•  mistaken assumptions about the overall costs of equity or debt;

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

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

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

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

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

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

Achieving the anticipated benefits from acquisitions depends in part upon whether we are able to integrate the assets or businesses of these acquisitions, in an efficient and effective manner. We may not be able to accomplish the integration process smoothly or successfully. The difficulties combining businesses or assets potentially will include, among other things:

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

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

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

•  the demands of managing new lines of business acquired.

Any inability to realize the potential benefits of the acquisition, as well as any delays in integration, could have an adverse effect upon the revenues, level of expenses and operating results of the company, after the acquisitions, which may affect the value of our common units after the acquisition.

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

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

Our operations are subject to many hazards inherent in the drilling, producing, gathering, compressing, treating, processing and transporting of oil, natural gas and NGLs, including:

•  damage to production equipment, pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;

•  inadvertent damage from construction, farm and utility equipment;

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

•  fires and explosions; and

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

These risks could result in substantial losses due to personal injuryand/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and attorney’s fees and other expenses incurred in the prosecution or defense of litigation and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations and ability to pay distributions to our unitholders.

As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We are not fully insured against all risks inherent to our business. For example, we 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.

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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 2005, we entered into up to a $475.0 million senior secured credit facility, consisting of up to a $400.0 million term loan facility and up to a $75.0 million revolving credit facility for our acquisition of the ONEOK Texas natural gas gathering and processing assets. The revolver facility was increased to $100.0 million in June 2006. On August 31, 2006, we entered into an amended and restated credit facility that provided for an aggregate of approximately $500.0 million borrowing capacity. Concurrent with the Laser and Montierra acquisitions, the revolver facility was again increased by $100 million to an aggregate of $600.0 million. Our level of debt could have important consequences to us, including the following:

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

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

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

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

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our amended and restated 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 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.

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

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

•  unexpected drilling conditions;

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

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

•  adverse weather conditions;

•  compliance with environmental and governmental requirements;

•  title problems;

•  unusual or unexpected geological formations;

•  pipeline ruptures;

•  fires, blowouts, craterings and explosions; and

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

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

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

Restrictions in our amended and restated credit facility limit our ability to make distributions and limit our ability to capitalize on acquisitions and other business opportunities.

Our amended and restated 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 amended and restated credit facility contains covenants requiring us to maintain certain financial ratios and tests. Any subsequent replacement of our credit facility or any new indebtedness could have 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.

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Due to our lack of industry and geographic diversification in our midstream operations, 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 upstream properties are well diversified geographically, all of our midstream assets are located in the Texas Panhandle, southeast and south Texas and Louisiana. Due to our lack of 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 producer customers, and any material nonpayment or nonperformance by our key producer 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 producer customers. Any material nonpayment or nonperformance by our key producer customers could reduce our ability to make distributions to our unitholders. Furthermore, some of our producer customers may be highly leveraged and subject to their own operating and regulatory risks, which could increase the risk that they may default on their obligations to us.

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

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

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

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 have been a private company and have not filed reports with the SEC. We produce our consolidated financial statements in accordance with the requirements of GAAP, but our internal accounting controls may not currently 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 will require 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 must comply with Section 404 for our fiscal year ending December 31, 2007. Any 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.

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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 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 unit per year, we will require available cash of approximately $20.8 million per quarter, or $83.3 million per year, based on the common units, restricted units under our Long Term Incentive Plan and subordinated units outstanding as of the date of this prospectus. 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:

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

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

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

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

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

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

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

•  prevailing economic conditions.

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

•  the level of capital expenditures we make;

•  the cost of acquisitions;

•  our debt service requirements and other liabilities;

•  fluctuations in our working capital needs;

•  our ability to borrow funds and access capital markets;

•  restrictions contained in our debt agreements; and

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

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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.

The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common units and granted restricted units under our Long Term Incentive Plan is $53.3 million and $1.2 million as a full distribution on our general partner units and a full distribution on our subordinated units is $30.0 million, totaling $84.5 million. The amount of our available cash generated during the year ended December 31, 2005 and the twelve months 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. For the February 15, 2007 cash distribution, the common units received their full distribution for the December 2006 quarter on an adjusted basis to reflect the timing on the initial public offering. No distributions were made to the general partner or subordinated units for the period. For the May 15, 2007 cash distribution, the common units received their full distribution for the March 2007 quarter. No distributions were made to the general partner or subordinated units for the period.

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 a 40.2% limited partner interest in us and will control 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, owns and controls our general partner. Holdings is owned and controlled by the NGP Investors. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners, the NGP Investors. Conflicts of interest may arise between the NGP Investors and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Our general partner intends to limit its liability under contractual arrangements so that the other party has 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.

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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 amended and restated credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

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

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

•  its limited call right;

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

•  its registration rights; and

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

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

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

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

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

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

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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:

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

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

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

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

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

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

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

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

The unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. Our general partner and its affiliates own 40.2% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period (which in general is expected to end in early 2010, unless we distribute at least $2.175 for the period ending September 30, 2007) and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

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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:

•  our unitholders’ proportionate ownership interest in us will decrease;

•  the amount of cash available for distribution on each unit may decrease;

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

•  the ratio of taxable income to distributions may increase;

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

•  the market price of the common units may decline.

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

Management of Eagle Rock Energy G&P, LLC, the general partner of our general partner and the NGP Investors and their affiliates (both through their interests in Eagle Rock Holdings), certain private investors, including the selling unitholders, and certain employees of Eagle Rock Energy G&P, LLC hold an aggregate of 22,770,995 common units, including 450,021 common units which are subject to an overall three-year vesting requirement, and 20,691,495 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. 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. In addition, we have entered into a registration rights agreement with Eagle Rock Holdings, which requires us to file with the SEC a registration statement within 90 days of our receipt of a request from Eagle Rock Holdings to file a registration statement and to have such registration statement become effective within 180 days of receipt of such request. Following the effective date of the registration statement and the expiration of anylock-up agreements applicable to the selling unitholders and Eagle Rock Holding, these holders may sell their common units into the public markets.

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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. Our general partner and its affiliates own approximately 6.0% 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 40.2% 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:

•  a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•  the right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. UnderSection 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.

The price of our common units may fluctuate significantly.

Prior to October 24, 2006, there was no public market for the common units. The lack of a liquid market in our common units may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The market price of our common units may be influenced by many factors, some of which are beyond our control, including:

•  our quarterly distributions;

•  our quarterly or annual earnings or those of other companies in our industry;

•  loss of a large customer;

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•  announcements by us or our competitors of significant contracts or acquisitions or change in management;

•  changes in accounting standards, policies, guidance, interpretations or principles;

•  general economic conditions;

•  the failure of securities analysts to cover our common units or changes in financial estimates by analysts;

•  future sales of our common units; and

•  other factors described in these “Risk Factors.”

We will incur increased costs as a result of being a publicly traded partnership.

We have little history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and the NASDAQ Global Market, have required changes in corporate governance practices of publicly traded companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded company reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and it may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. We estimate that we incur approximately $3.0 million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

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. 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

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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 1.0% 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. 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 andnon-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 tonon-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, andnon-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.

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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.

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 the States of Louisiana, Texas, Oklahoma and [upstream locations]. Each of these states, other than Texas, currently imposes 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.

USE OF PROCEEDS

We will not receive any proceeds from the sale of common units offered under this prospectus. Any proceeds from the sale of common units offered under this prospectus will be received by the selling unitholders.

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CAPITALIZATION

The following table shows the historical cash and capitalization of Eagle Rock Energy Partners, L.P. as of March 31, 2007;

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	As of March 31,
	2007
	Historical
Cash	$	2.1
Debt	$	405.7
Total partners’ capital	$	266.3
Total capitalization	$	672.0

Price Range of Common Units and Distributions

Our common units have been listed on the NASDAQ Global 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 Market, as well as the amount of cash distributions paid per quarter from our initial public offering date, October 24, 2006, through the date of this prospectus.

					Distribution
Quarter Ended	High		Low		per Unit			Record Date	Payment Date
December 31, 2006	$	20.70	$	17.50	$	0.27	(1)	Feb. 7, 2007	Feb. 15, 2007
March 31, 2007	$	20.88	$	18.56	$	0.3625		May 4, 2007	May 15, 2007
June 30, 2007	$	25.62	$	20.50	$	0.3625		August 6, 2007(2)	Aug. 15, 2007(2)

(1)	Represents a prorated distribution to the common unitholders from the IPO date of October 24, 2006 through December 31, 2006.
(2)	Estimated, to be determined by the Board of Directors.

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 Market on July 25, 2007, was $25.74. As of that date, there were 49 holders of record and approximately 8,100 beneficial owners of our common units.

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “Summary of Significant Accounting Policies and Forecast Assumptions” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” starting on page 8 for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical operating results, you should refer to our historical financial statements for the years ended December 31, 2004, 2005 and 2006 in our Annual Report onForm 10-K for the year ended December 31, 2006 and onForm 10-K/ for the year ended December 31, 2006 and our Current Report onForm 10-Q for the quarter ended March 31, 2007, incorporated by reference into this prospectus.

General

Rationale for Our Cash Distribution Policy.  Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing our cash available after expenses and reserves rather than retaining it. Because we believe we will generally finance any capital investments from external financing sources, we believe that our unitholders are best served by our distributing all of our available cash. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case were we subject to tax. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly.

Limitations on Cash Distributions; Our Ability to Change Our Cash Distribution Policy.  There is no guarantee that unitholders will receive quarterly distributions from us. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:

•  Restrictions contained in our amended and restated credit facility limit our ability to make distributions. Specifically, our amended and restated credit facility contains material financial tests and covenants that we must satisfy. These financial tests and covenants are described in this prospectus under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Requirements” in our Annual Report onForm 10-K for the year ended December 31, 2006. Should we be unable to satisfy these restrictions or if we are otherwise in default under our amended and restated credit facility, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.

•  The board of directors of our general partner will have the authority to make all determinations related to the reimbursement of expenses incurred by the general partner and its affiliates and the establishment of reserves for the prudent conduct of our business and for future cash distributions to our unitholders. Our partnership agreement provides that our general partner will be entitled to make these determinations subject only to the requirement that it act in good faith. The reimbursement of expenses incurred by our general partner and its affiliates and the establishment of those reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy.

•  Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

•  UnderSection 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.

•  We may lack sufficient cash to pay distributions to our unitholders due to increases in our general and administrative expense, principal and interest payments on our outstanding debt, tax expenses including

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the new entity-level taxation in the State of Texas, working capital requirements and anticipated cash needs.

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital.  Our intention is to distribute all of our available cash to our unitholders; however, from time to time Holdings, the holder of our subordinated units, may waive its right to distributions on the subordinated units. 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. 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 amended and restated 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 Initial Distribution Rate

Our board of directors of our general partner has adopted a policy pursuant to which, provided we have sufficient available cash, we will declare an initial quarterly distribution equal to the minimum quarterly distribution of $0.3625 per unit per complete quarter (or $1.45 per unit per year on an annualized basis), which quarterly distribution will be paid no later than 45 days after the end of each fiscal quarter, beginning with the quarter ending December 31, 2006.

Available cash, for any quarter, consists of all cash on hand at the end of that quarter:

•  less the amount of cash reserves established by our general partner to:

•  provide for the proper conduct of our business;

•  comply with applicable law, any of our debt instruments or other agreements; or

•  provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

•  plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter.

Our ability to make cash distributions at the initial distribution rate pursuant to this policy will be subject to the factors described above under the caption “— Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

A quarterly distribution of $0.3625 per unit equates to an aggregate cash distribution of $21.1 million per quarter or $84.5 million per year, in each case based on the number of common units, subordinated units, restricted units issued under our Long Term Incentive Plan and general partner units outstanding as of the date of this prospectus.

The table below sets forth the number of outstanding common units, subordinated units, restricted units issued under our Long Term Incentive Plan and general partner units as of the date of this prospectus and the aggregate distribution amounts payable on such units during the year following the closing of our initial public offering at our initial distribution rate of $0.3625 per common unit per quarter ($1.45 per common unit on an annualized basis).

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			Minimum Quarterly
	Number of		Distributions
	Units		One Quarter		Four Quarters
	($ in thousands)
Publicly held common units		13,963,785	$	5,062	$	20,247
Common units held by private investors, including the selling unitholders		20,133,103		7,298		29,193
Common units held by Eagle Rock Holdings, L.P.		2,187,871		793		3,172
Subordinated units held by Eagle Rock Holdings, L.P.		20,691,495		7,501		30,003
Restricted units issued under LTIP		450,021		163		653
1.46% general partner interest(a)		844,551		306		1,225
Total		58,270,826	$	21,123	$	84,493

(a) Assumes the general partner’s current 1.46% interest remains the same. The general partner’s current 1.46% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not elect to contribute a proportionate amount of capital to us to maintain its current 1.46% general partner interest.

The subordination period will end on the first business day after we have earned and paid at least $1.45 (the minimum quarterly distribution on an annualized basis) on each outstanding limited partner unit and general partner unit for any three consecutive, non-overlapping four quarter periods ending on or after September 30, 2009.

Alternatively, the subordination period will end on the first business day after we have earned and paid at least $0.5438 per quarter (150% of the minimum quarterly distribution, which is $2.175 on an annualized basis) on each outstanding limited partner unit and general partner unit for any four consecutive quarters ending on or after September 30, 2007.

In addition, the subordination period will end if our general partner is removed without cause and the units held by our general partner and its affiliates are not voted in favor of such removal. When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages. Please read the “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”

If distributions on our common units are not paid with respect to any fiscal quarter at the minimum distribution rate, our unitholders will not be entitled to receive such payments in the future except that, to the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to make cash distributions to holders of our common units at the minimum distribution rate, we will use this excess available cash to pay these deficiencies related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”

We do not have a legal obligation to pay distributions at our minimum distribution rate or at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves our general partner determines is necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the upcoming four quarters. Our general partner has the authority to determine the amount of our available cash for any quarter. Our partnership agreement provides that certain determination made by our general partner in its capacity as our general partner, including determinations of available cash and expenses and the establishment of reserves, must be made in good faith and that such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or principles of equity. Our partnership agreement provides that, in order for a determination by our general

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partner to be made in “good faith,” our general partner must believe that the determination is in our best interests. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

The provisions of our partnership agreement relating to our cash distribution policy may not be modified or repealed without amending our partnership agreement; however, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. Our partnership agreement may be amended with the approval of our general partner and holders of a majority of our outstanding common units voting together as a class.

Our general partner is currently entitled to 1.46% of all distributions that we make prior to our liquidation. The general partner’s current 1.46% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not elect to contribute a proportionate amount of capital to us to maintain its current 1.46% general partner interest.

We will pay our distributions on or about the 15th of each February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date.

PROVISIONS OF OUR PARTNERSHIP

AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General.  Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2006, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash.  Available cash, for any quarter, consists of all cash on hand at the end of that quarter:

•  less the amount of cash reserves established by our general partner to:

•  provide for the proper conduct of our business;

•  comply with applicable law, any of our debt instruments or other agreements; or

•  provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

•  plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter.

Intent to Distribute the Minimum Quarterly Distribution.  We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.3625 per unit, or $1.45 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. We anticipate that we will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our amended and restated credit agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Requirements — Senior Secured Credit Facility” in our Annual Report on

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Form 10-K for the year ended December 31, 2006, for a discussion of the restrictions included in our amended and restated credit agreement that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights.  Currently, our general partner will be entitled to 1.46% of all quarterly distributions that we make prior to our liquidation. This general partner interest will be represented by 844,551 general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s current 1.46% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 1.46% general partner interest.

Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, of the cash we distribute from operating surplus (as defined below) in excess of $0.4169 per unit per quarter. The maximum distribution of 50% includes distributions paid to our general partner on its 1.46% general partner interest and assumes that our general partner maintains its general partner interest at 1.46%. The maximum distribution of 50% does not include any distributions that our general partner may receive on units that it owns.

Operating Surplus and Capital Surplus

General.  All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus.  Operating surplus consists of:

•  an amount equal to four times the amount needed for any one quarter for us to pay a distribution on all of our units (including the general partner units) and the incentive distribution rights at the sameper-unit amount as was distributed in the immediately preceding quarter (or with respect to the period commencing on the closing of our initial public offering and ending on December 31, 2006, it means the product of (a)(i) $1.45 multiplied by (ii) a fraction of which the numerator is the number of days in such period and the denominator is 92 multiplied by (b) the number of common units, subordinated units and general partner units outstanding on the record date with respect to such period, and with respect to the quarter ending March 31, 2007, it means the product of (a) $1.45 and (b) the number of common units, subordinated units and general partner units outstanding on the record date with respect to such quarter); plus

•  all of our cash receipts after the closing of our initial public offering, excluding cash from borrowings, sales of equity and debt securities, sales or other dispositions of assets outside the ordinary course of business, the termination of interest rate swap agreements, capital contributions or corporate reorganizations or restructurings; less

•  all of our operating expenditures after the closing of our initial public offering, including maintenance capital expenditures, but excluding the repayment of borrowings (other than working capital borrowings) and growth capital expenditures or transaction expenses (including taxes) related to interim capital transactions; less

•  the amount of cash reserves established by our general partner to provide funds for future operating expenditures.

Any increase in operating surplus pursuant to the first bullet point under the caption “— Operating Surplus” above in respect of an increase in the quarterly distribution rate per unit, an increase in the number of units outstanding or other action with respect to outstanding units shall only be effective from and after the quarter in which such increase or other action occurs, and shall not be effective retroactively. In addition, the maximum amount included in operating surplus pursuant to such first bullet point during the term of the partnership shall not exceed four times the amount needed for any one quarter to pay a distribution on all of our units (including general partner units) and the incentive distribution rights at the highest distribution rate per unit (as adjusted for any split or combination of units) paid on outstanding units as of the date such determination is made.

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Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets, to maintain the existing production levels or operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing equity or system volumes and related cash flows. Growth capital expenditures represent capital expenditures made to expand or to increase the efficiency of the existing production or operating capacity of our assets or to expand the operating capacity or revenues of existing or new assets, whether through construction or acquisition. Costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets or lease operating costs associated with our upstream operations will be treated as operations and maintenance expenses as we incur them. Our partnership agreement provides that our general partner determines how to allocate a capital expenditure for the acquisition or expansion of our assets between maintenance capital expenditures and expansion capital expenditures.

Capital Surplus.  Capital surplus consists of:

•  borrowings;

•  sales of our equity and debt securities; and

•  sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions.  Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of our initial public offering equals the operating surplus as of the most recent date of determination of available cash. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes an amount equal to four times the amount needed for any one quarter for us to pay a distribution on all of our units (including the general partner units and restricted units granted under our Long Term Incentive Plan) and the incentive distribution rights at the sameper-unit amount as was distributed in the immediately preceding quarter. This amount, which equals $83.3 million, does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to this amount of cash we receive in the future from non-operating sources, such as borrowings, issuances of securities, and asset sales, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus. The characterization of cash distributions as operating surplus versus capital surplus does not result in a different impact to unitholders for federal tax purposes. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Treatment of Distributions” for a discussion of the tax treatment of cash distributions.

Subordination Period

General.  Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.3625 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

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Subordination Period.  The subordination period will extend until the first business day after each of the following tests are met:

•  distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

•  the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common and subordinated units and general partner units during those periods on a fully diluted basis during those periods; and

•  there are no arrearages in payment of the minimum quarterly distribution on the common units.

Alternatively, the subordination period will end the first business day after the following tests are met:

•  distributions of available cash from operating surplus on each of the outstanding common and subordinated units equaled or exceeded $0.5438 per quarter (150% of the minimum quarterly distribution) for the four-quarter period immediately preceding the date;

•  the “adjusted operating surplus” (as defined below) generated during the four-quarter period immediately preceding the date equaled or exceeded the sum of $0.5438 (150% of the minimum quarterly distribution) on each of the outstanding common and subordinated units during that period on a fully diluted basis and on the related general partner interest during those periods; and

•  there are no arrearages in payment of the minimum quarterly distributions on the common units.

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro-rata with the other common units in distributions of available cash. Further, if the unitholders remove our general partner other than for cause and no units held by our general partner and its affiliates are voted in favor of such removal:

•  the subordination period will end and each subordinated unit will immediately convert into one common unit;

•  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

•  our general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Adjusted Operating Surplus.  Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus consists of:

•  operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet point under “— Operating Surplus and Capital Surplus — Operating Surplus” above); plus

•  any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to that period; less

•  any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

•  any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

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Distributions of Available Cash from Operating Surplus during the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner (assuming a 2% general partner interest):

•  first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

•  second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

•  third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

•  thereafter, in the manner described in “General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its initial 2% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus after the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner (assuming a 2% general partner interest):

•  first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

•  thereafter, in the manner described in “General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its initial 2% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 2% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2% general partner interest if we issue additional units. Our general partner’s initial 2% interest, and the percentage of our cash distributions to which it is entitled, has been proportionately reduced as we issued additional units and as we continue to do so in the future and as our general partner does not contribute a proportionate amount of capital to us in order to maintain its then current general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its then current general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

Incentive distribution rights represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

The following discussion assumes that the general partner maintains its initial 2% general partner interest, that there are no arrearages on common units and that the general partner continues to own the incentive distribution rights.

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If for any quarter:

•  we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

•  we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution; then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner (assuming a 2% general partner interest):

•  first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.4169 per unit for that quarter (the “first target distribution”);

•  second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.4531 per unit for that quarter (the “second target distribution”);

•  third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives a total of $0.5438 per unit for that quarter (the “third target distribution”); and

•  thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its initial 2% general partner interest and assume our general partner has contributed any additional capital to maintain its initial 2% general partner interest and has not transferred its incentive distribution rights.

	Total Quarterly	Marginal Percentage
	Distribution per Unit	Interest in Distributions*
	Target Amount	Unitholders			General Partner
Minimum Quarterly Distribution	$0.3625		98	%		2	%
First Target Distribution	up to $0.4169		98	%		2	%
Second Target Distribution	above $0.4169 up to $0.4531		85	%		15	%
Third Target Distribution	above $0.4531 up to $0.5438		75	%		25	%
Thereafter	above $0.5438		50	%		50	%

* Assuming there are no arrearages on common units and that our general partner maintained its initial 2% general partner interest and continues to own the incentive distribution rights.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made.  Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:

•  first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in our initial public offering, an amount of available cash from capital surplus equal to the initial public offering price;

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•  second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

•  thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a Distribution from Capital Surplus.  Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in our initial public offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 50% being paid to the holders of units and 50% to the general partner. The percentage interests shown for our general partner assumes its initial 2% general partner interest and assume the general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:

•  the minimum quarterly distribution;

•  target distribution levels;

•  the unrecovered initial unit price;

•  the number of common units issuable during the subordination period without a unitholder vote; and

•  the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, the number of common units issuable during the subordination period without unitholder vote would double and each subordinated unit would be convertible into two common units. Our partnership agreement provides that we not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus the general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General.  If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of

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our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.

Manner of Adjustments for Gain.  The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner (assuming a 2% general partner interest):

•  first, to the general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

•  second, 98% to the common unitholders, pro rata, and 2% to the general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

•  third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

•  fourth, 98% to all unitholders, pro rata, and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to the general partner, for each quarter of our existence;

•  fifth, 85% to all unitholders, pro rata, and 15% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to the general partner for each quarter of our existence;

•  sixth, 75% to all unitholders, pro rata, and 25% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to the general partner for each quarter of our existence; and

•  thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

The percentage interests set forth above for our general partner assume its initial 2% general partner interest and assume the general partner has not transferred the incentive distribution rights.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

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Manner of Adjustments for Losses.  If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to the general partner and the unitholders in the following manner (assuming a 2% general partner interest):

•  first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

•  second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the common unitholders have been reduced to zero; and

•  thereafter, 100% to the general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable. The percentage interests set forth above for our general partner assume its initial 2% general partner interest.

Adjustments to Capital Accounts.  Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

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SELECTED HISTORICAL FINANCIAL DATA

The following table shows selected historical financial data of 1) our predecessor, ONEOK Texas Field Services L.P. and 2) Eagle Rock Pipeline, L.P. and Eagle Rock Energy Partners, L.P. and 3) unaudited financial data of Eagle Rock Energy Partners, L.P. for the periods and as of the dates indicated. 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 prospectus 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 prospectus 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 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 southeast 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. For a description of these acquisitions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

•  In June 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 1,125,416 common units in Eagle Rock Pipeline.

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The selected historical financial data 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, 2005 and 2006 are derived from the audited financial statements of Eagle Rock Energy Partners, L.P. The selected historical financial data as of and for the year ended December 31, 2002 and as of December 31, 2003 are derived from the unaudited financial statements of Eagle Rock Predecessor. The selected historical financial data for the quarters ended March 31, 2006 and 2007 are derived from the unaudited financial statements of Eagle Rock Energy Partners, L.P.

The following table includes the non-GAAP financial measures of Adjusted EBITDA and segment gross margin. We define Adjusted EBITDA as net income plus interest expense, net, provision for income taxes and depreciation and amortization expense, less the impact of unrealized derivatives gains (losses), less income from discontinued operations. By excluding unrealized derivative gains (losses), a non-cash charge that represents the change in fair market value of our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, 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. 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 discounted 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 that are no longer a part of our operations. We define segment gross margin as total revenues less cost of natural gas and NGLs and other cost of sales. For a reconciliation of Adjusted EBITDA and segment gross margin to their 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.”

	Eagle Rock Predecessor												Eagle Rock Pipeline, L.P.									Eagle Rock Energy Partners, L.P.
	Period from
	January 1,			Year			Year						Year			Year						Year			Quarter			Quarter
	2005 to			Ended			Ended			Year Ended			Ended			Ended			Year Ended			Ended			Ended			Ended
	November 30,			December 31,			December 31,			December 31,			December 31,			December 31,			December 31,			December 31,			March 31,			March 31,
	2005			2004			2003			2002			2005 (1)			2004			2003			2006			2006			2007
	($ in thousands, except per unit)
Statement of Operations Data:
Operating revenues	$	396,953		$	335,519		$	297,290		$	194,898		$	66,382		$	10,636		$	—		$	502,394		$	116,388		$	114,404
Unrealized derivative gains/(losses)		—			—			—			—			7,308			—			—			(26,306	)		(20,070	)		(7,642	)
Realized derivative gains		—			—			—			—			—			—			—			2,302			—			—
Total operating revenues		396,953			335,519			297,290			194,898			73,690			10,636			—			478,390			96,318			106,762
Cost of natural gas and NGLs		316,979			263,840			249,284			155,757			55,272			8,811			—			377,580			91,991			90,636
Operating and maintenance expense		27,518			27,427			23,905			22,276			2,955			34			—			32,905			5,682			7,923
General and administrative expense		—			—			—			—			4,765			2,406			144			13,161			2,453			6,634
Advisory termination fee		—			—			—			—			—			—			—			6,000			—			—
Depreciation and amortization expense		8,157			8,268			7,187			7457			4,088			619			—			43,220			9,214			11,630
Operating Income (loss)		44,299			35,984			16,914			9,408			6,610			(1,234	)		(144	)		5,524			(13,022	)		(10,061	)
Interest (income) expense		(859	)		(646	)		(189	)		—			4,031			—			—			28,604			2,535			9,567
Other (income)		(17	)		(23	)		(52	)		(944	)		(171	)		(24	)		—			(996	)		(40	)		(124	)
Income (loss) before income taxes		45,175			36,653			17,155			10,352			2,750			(1,210	)		(144	)		(22,084	)		(15,517	)		(19,504	)
Income tax provision		15,811			12,731			6,071			(6,465	)		—			—			—			1,230			—			164
Income (loss) from continuing operations		29,364			23,922			11,084			16,817			2,750			(1,210	)		(144	)		(23,314	)		(15,517	)		(19,668	)
Discontinued operations		—			—			—			—			—			22,192			533			—			—			—
Cumulative effect of change in accounting principle		—			—			227			—			—			—			—			—			—			—
Net income (loss)	$	29,364		$	23,922		$	10,857		$	16,817		$	2,750		$	20,982		$	389		$	(23,314	)	$	(15,517	)	$	(19,668	)
Loss per common unit	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	(1.26	)	$	(0.63	)	$	(0.28	)

47

	Eagle Rock Predecessor												Eagle Rock Pipeline, L.P.									Eagle Rock Energy Partners, L.P.
	Period from
	January 1,			Year			Year						Year			Year						Year			Quarter			Quarter
	2005 to			Ended			Ended			Year Ended			Ended			Ended			Year Ended			Ended			Ended			Ended
	November 30,			December 31,			December 31,			December 31,			December 31,			December 31,			December 31,			December 31,			March 31,			March 31,
	2005			2004			2003			2002			2005 (1)			2004			2003			2006			2006			2007
	($ in thousands, except per unit)
Balance Sheet Data (at period end):
Property plant and equipment, net	$	242,487		$	243,939		$	246,640		$	248,624		$	441,588		$	19,564		$	18,529		$	554,063		$	510,388		$	569,147
Total assets		376,447			304,631			259,577			339,489			700,659			28,017			21,379			779,901			777,480			772,820
Long-term debt		—			—			—			—			408,466			—			14,221			405,731			403,600			405,731
Net equity		233,708			204,344			180,422			159,281			208,096			27,655			6,629			291,987			290,968			266,316
Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	47,603		$	41,813		$	32,219		$	13,326		$	(1,667	)	$	3,652		$	(337	)	$	54,992		$	4,893		$	14,181
Investing activities		(6,708	)		(5,567	)		(5,203	)		(12,992	)		(543,501	)		16,918			(18,282	)		(134,873	)		(74,946	)		(16,658	)
Financing activities		(40,895	)		(36,246	)		(27,016	)		(334	)		556,304			(13,955	)		20,240			71,088			95,998			(6,045	)
Other Financial Data:
Cash distributions per Common unit (declared)	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	0.2679
Adjusted EBITDA(2)	$	52,473		$	44,275		$	23,926		$	17,809		$	3,390		$	(591	)	$	(144	)	$	81,192		$	17,112		$	14,093
Segment gross margin(3)	$	79,974		$	71,679		$	48,006		$	39,141		$	18,418		$	1,825		$	—		$	100,810		$	4,327		$	16,126

(1)	Includes historical financial and operating data for Eagle Rock Predecessor for the period from December 1, 2005 to December 31, 2005.
(2)	Excludes $7.3 million in unrealized derivative gains for the year ended December 31, 2005 and $21.3 million in unrealized derivative losses for the year ended December 31, 2006, $20.1 million for the quarter ended March 31, 2006 and $7.6 million for the quarter ended March 31, 2007. Excludes $0.5 million in 2003 and $22.2 million in 2004 of income from discontinued operations.
(3)	Defined as operating revenues minus the cost of natural gas and NGLs and other cost of sales. Operating revenues include both realized and unrealized risk management activities.

Non-GAAP Financial Measures

We include in this prospectus the following non-GAAP financial measures: Adjusted EBITDA and segment gross margin. We provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures as calculated and presented in accordance with GAAP.

We define Adjusted EBITDA as net income plus interest expense, net, provision for income taxes and depreciation and amortization expense, less the non-cash, mark-to-market impact of unrealized derivatives gains (losses), less income from discontinued operations deemed as non-recurring impacts. Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash charge that represents the change in fair market value of our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, 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. 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 that are no longer a part of our operations.

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

48

of our costs and our ability to generate segment gross margins. 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.

We define segment gross margin as total revenues less cost of natural gas and NGLs and other cost of sales. Segment gross margin is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales and purchases, a key component of our operations. As an indicator of our operating performance, segment gross margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our segment gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate segment gross margin in the same manner.

	Eagle Rock Predecessor												Eagle Rock Pipeline, L.P.									Eagle Rock Energy Partners, L.P.
	Period
	from																								Three			Three
	January 1,			Year			Year			Year			Year			Year			Year			Year			Months			Months
	2005 to			Ended			Ended			Ended			Ended			Ended			Ended			Ended			Ended			Ended
	November 30,			December 31,			December 31,			December 31,			December 31,			December 31,			December 31,			December 31,			March 31,			March 31,
	2005			2004			2003			2002			2005(1)			2004			2003			2006			2006			2007
Reconciliation of “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		$	13,326		$	(1,667	)	$	3,652		$	(337	)	$	54,992		$	4,893		$	14,181
Add (deduct):
Depreciation and amortization		(8,157	)		(8,268	)		(7,187	)		(7,457	)		(4,088	)		(1,174	)		(98	)		(43,220	)		(9,214	)		(11,630	)
Amortization of debt issue cost		—			—			—			—			(76	)		—			—			(1,114	)		(229	)		(416	)
Risk management portfolio value changes		—			—			—			—			5,709			—			—			(23,531	)		(15,905	)		(12,254	)
Advisory termination fee																							(6,000	)		—			—
Net realized gain on derivatives		—			—			—			—			—			—			—			978			—			—
Other		—			—			—			—			(6	)		—			—			(1,566	)		793			(193	)
Gain on sale of Dry Trail plant		—			—			—			—			—			19,465			—			—			—			—
Provision for deferred income taxes		(1,559	)		(7,325	)		(10,943	)		(596	)		—			—			—			—			—			—
Accounts receivable and other current assets		56,599			30,905			23,791			(15,246	)		43,179			(901	)		883			1,432			3,696			443
Accounts payable and accrued liabilities		(64,320	)	��	(34,705	)		(21,363	)		26,790			(40,197	)		(169	)		(192	)		(8,777	)		1,209			(9,875	)
Other assets and liabilities		(802	)		1,502			(5,660	)					(104	)		109			133			3,492			(760	)		76
Net income (loss)		29,364			23,922			10,857			16,817			2,750			20,982			389			(23,314	)		(15,517	)		(19,668	)
Add:
Interest (income) expense, net		(859	)		(646	)		(189	)		—			4,031			—			—			(30,383	)		2,535			9,443
Depreciation and amortization		8,157			8,268			7,187			7,457			4,088			619			—			43,220			9,214			11,630
Income tax provision (benefit)		15,811			12,731			6,071			(6,465	)		—			—			—			1,230			—			124
EBITDA(2)	$	52,473		$	44,275		$	23,926		$	17,809		$	10,869		$	21,601		$	389		$	51,519		$	(3,768	)	$	1,529
Adjusted EBITDA(3)	$	52,473		$	44,275		$	23,926		$	17,809		$	3,561		$	(591	)	$	(144	)	$	81,192		$	17,112		$	14,093

49

	Eagle Rock Predecessor												Eagle Rock Pipeline, L.P.									Eagle Rock Energy Partners, L.P.
	Period
	from																								Three			Three
	January 1,			Year			Year			Year			Year			Year			Year			Year			Months			Months
	2005 to			Ended			Ended			Ended			Ended			Ended			Ended			Ended			Ended			Ended
	November 30,			December 31,			December 31,			December 31,			December 31,			December 31,			December 31,			December 31,			March 31,			March 31,
	2005			2004			2003			2002			2005(1)			2004			2003			2006			2006			2007
Reconciliation of net income (loss) to total segment gross margin:
Net income (loss)	$	29,364		$	23,922		$	10,857		$	16,817		$	2,750		$	20,982		$	389		$	(23,314	)	$	(15,517	)	$	(19,668	)
Add (deduct):
Operating expenses		27,518			27,427			23,905			22,276			2,955			34			—			32,905			5,682			7,923
General and administrative expense		—			—			—			—			4,765			2,406			144			13,161			2,453			6,634
Depreciation and amortization expense		8,157			8,268			7,187			7,457			4,088			619			—			43,220			9,214			11,630
Interest expense, Net		(859	)		(646	)		(189	)		—			4,031			—			—			(30,383	)		2,495			9,443
Other income and deductions, net		(17	)		(23	)		(52	)		(944	)		(171	)		(24	)		—			3,225			—			—
Income tax provision		15,811			12,731			6,071			(6,465	)		—			—			—			1,230			—			164
Discontinued operations		—			—			—			—			—			(22,192	)		(533	)		—			—			—
Cumulative effect of change in accounting principle		—			—			227			—			—			—			—			—			—			—
Total segment gross margin	$	79,974		$	71,679		$	48,006		$	39,141		$	18,418		$	1,825		$	—		$	100,810		$	4,327		$	16,126

(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 and $21.3 million in unrealized derivative losses for the year ended December 31, 2006, $20.1 million for the quarter ended March 31, 2006 and $7.6 million for the quarter ended March 31, 2007. Excludes $0.5 million in 2003 and $22.2 million in 2004 of income from discontinued operations.
(3)	Excludes $7.3 million in unrealized derivative gains for the year ended December 31, 2005 and $21.3 million in unrealized derivative losses for the year ended December 31, 2006, $20.1 million for the quarter ended March 31, 2006 and $7.6 million for the quarter ended March 31, 2007. Excludes $0.5 million in 2003 and $22.2 million in 2004 of income from discontinued operations.

50

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS

General

Please read our Annual Report onForm 10-K andForm 10-K/A for the year ended December 31, 2006 and our quarterly report onForm 10-Q for the three months ended March 31, 2007 for a complete discussion of our management’s discussion and analysis of financial condition and results of operations. The discussion in those reports is supplemented and modified by the information included in this prospectus.

Segment Reporting

Based on our approach to managing our assets, we believe our operations consist of three geographic segments in its midstream business, one upstream segment and one functional (corporate) segment:

Midstream Segment:

(i) gathering, processing, transportation and marketing of natural gas in the Texas Panhandle System;

(ii) gathering, natural gas processing and related NGL transportation in the southeast Texas and Louisiana System;

(iii) gathering, processing, transportation and marketing of natural gas in the south Texas System;

Upstream Segment:

(iv) crude oil and natural gas production, fee minerals, royalties and working interest ownership and

Corporate Segment:

(v) risk management and other corporate activities.

Our chief operating decision-maker currently reviews our operations using these segments. We evaluate segment performance based on segment margin before depreciation and amortization. Transactions between reportable segments are conducted on a basis believed to be at market values. We anticipate that, in the future, beginning with quarterly report onForm 10-Q for the quarter ended June 30, 2007, we will report our financial data according to the segments described above.

Critical Accounting Policies

Except as set forth in this section, we continue to apply to our financial statements the critical accounting policies described in our annual report onForm 10-K for the year ended December 31, 2006 and as further described in our quarterly report onForm 10-Q for the three months ended March 31, 2007. In addition to those critical accounting policies included in those reports and because of our recent Montierra acquisition, which marks our entry into a new line of business, the upstream business, we will apply to our financial statements the following additional critical accounting policies.

Oil and Natural Gas Accounting Policies

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

51

are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.

We utilize the successful efforts method of accounting for our oil and natural gas properties. Leasehold costs are capitalized when incurred. 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. Drilling costs are 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.

Depreciation and 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.

Geological, geophysical and dry hole costs on oil and natural gas properties relating to unsuccessful wells are charged to expense as incurred.

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 recoverable. We recognize an impairment loss as a result of a triggering event and when the estimated undiscounted future cash flows from a property are less than the carrying value. If an impairment is indicated, the cash flows are discounted at a rate approximate to our cost of capital and 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. The impairment expense is included in depreciation, depletion and amortization on the consolidated statement of operations.

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

Oil and Natural Gas Reserve Quantities

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 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

52

data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

The Company’s 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.

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 for our unitholders.

Cash Flows and Capital Expenditures

Since our inception in 2003 through June 30, 2007, there have been several key events that have had major impacts on our cash flows. They are:

•  the acquisition of the Dry Trail plant on December 5, 2003 in the amount of approximately $18.0 million which was financed through equity of $6.0 million and debt of $14.0 million;

•  the acquisition of a 20% interest in the Camp Ruby gathering system and a 25% interest in the Indian Springs processing plant on July 1, 2004 for approximately $20.0 million, consisting of proceeds achieved with the sale of the Dry Trail plant;

•  the acquisition of the midstream assets in the Texas Panhandle on December 1, 2005 for approximately $531.0 million, which was financed through an additional equity contribution of $133 million and debt of $400 million, not including $27.5 million in risk management costs related to option premiums financed entirely with equity;

•  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 approximately $25.0 million which we financed with $4.7 million in cash and $21.3 million in Eagle Rock Pipeline, L.P. units;

•  the acquisition of certain fee minerals, royalties and working interest properties from Montierra Minerals & Production, L.P., and NGP-VII Income Co-Investment Opportunities, L.P. on April 30, 2007 for an aggregate purchase price of $127.4 million financed with 6,390,400 of our common units and $6.0 million in cash;

•  the acquisition of all of the non-corporate interests 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 a total purchase price of $136.8 million, consisting of $110.0 million in cash and 1,407,895 of our common units; and

•  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.

53

On January 26, 2007, Eagle Rock Energy declared a cash distribution of $0.3625 per unit for the fourth quarter of 2006, prorated to $0.2679 per common unit, to its common unitholders of record as of February 7, 2007, 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 subordinated or general partners for the quarter.

On May 4, 2007, Eagle Rock Energy expanded its revolver commitment level under its Amended and Restated Credit Agreement by $100.0 million to $300.0 million in total. No incremental funding under the Amended and Restated Credit Agreement was needed for the Laser and Montierra acquisitions. As of June 30, 2007, under the Amended and Restated Credit Agreement, we have total borrowing availability of $600 million and we have $422.1 million drawn down under the facility.

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 unitholders who acquired units in either the Montierra Acquisition or the Laser Acquisition.

On July 11, 2007, Eagle Rock Energy announced three acquisitions in its midstream and upstream businesses for a combined purchase price of approximately $420.0 million. In aggregate the transactions will result in the payment of $277.6 million in cash and the issuance of 5,905,922 newly-issued common units. Additionally, Eagle Rock Energy entered into a 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 (upon closing the three transactions). The proceeds from this equity private placement will be used to partially fund the cash portion of these acquisitions. Eagle Rock Energy anticipates that the private placement will close simultaneously with the acquisitions.

With the Laser and Montierra transactions, as well as the acquisitions announced on July 11, the Partnership expects to be able to make its distributions to all unitholders, including subordinated unitholders, for the fourth quarter ending December 31, 2007.

As we continue to expand our midstream and upstream businesses, our needs for capital, both as acquisition capital and as maintenance capital, continue to grow. We anticipate that we will have sufficient access to capital to complete the transactions described above and to maintain and commercially exploit the midstream and upstream assets being acquired in connection with these transactions.

In connection with the Montierra acquisition and the acquisitions announced on July 11, 2007, we are expanding our upstream line of business further, including becoming an operator of upstream 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 resource. We anticipate that we will meet these requirements through cash generated from operations, equity issuances, or incurring debt; however, we cannot provide assurances that we will be able to obtain the necessary capital under terms acceptable to us.

Our current capital budget anticipates that we will spend approximately $58.3 million in total in 2007 on our existing assets. To date, we have spent approximately $40.7 million primarily in the Tyler County Pipeline Extension and Red Deer Processing Plant projects. Upon the completion of the proposed transactions described above, we anticipate that our capital budget will be increased by $12.5 million on an annual basis. This increase results primarily from our anticipated drilling efforts and required cost-sharing arrangements as a working interest owner of oil and natural gas properties. Although we cannot provide assurances, we expect to be able to fund this increase in the capital budget through cash from operations.

54

BUSINESS

Our Partnership

We are a growth-oriented Delaware limited partnership engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs, what we call our midstream business, and the business of acquiring, developing and producing oil and natural gas interests, what we call our upstream business. Our midstream assets are strategically located in four significant natural gas producing regions: (i) Texas Panhandle, (ii) south Texas, (iii) southeast Texas and (iv) Louisiana.

Our upstream assets include royalty and overriding royalty interests in over 2,500 oil and natural gas wells located in multiple producing trends across 17 states. Currently, based on revenues generated during the second quarter 2007, our midstream business comprises approximately 87% of our business and our upstream business comprises approximately 13%.

We intend to acquire and construct additional assets in both our midstream and upstream businesses and we have an experienced management team dedicated to growing, operating and maximizing the profitability of our assets.

As a result of the Montierra acquisition, as well as the acquisition of MacLondon Energy, L.P. for approximately $18.8 million in June 2007, our assets now include fee mineral, royalties, overriding royalty and working interests in oil and natural gas properties. Although we did not own those interests on December 31, 2006, they had proved reserves of 2,588 Mbbls of crude and condensate and 5,988 Mmcfe of natural gas, with a Standardized Measure of $60.6 million. All of these reserves (100%) were classified as proved developed.

These interests are almost exclusively mineral, royalty and overriding royalty interests (only two wells had working interests), and we do not operate any of them. Because of this, we are generally not a cost bearing owner and rarely pay any drilling or development costs or lease operating expenses associated with the production we receive today. In addition, we do not control if, or when, possible future exploration and development activities will occur on these properties. In consideration of this lack of control, we do not believe it is appropriate to book proved undeveloped reserves on these properties. Nevertheless, we expect the operators of the properties to continue to conduct exploration and development activities on them, at no additional cost to us. We will receive a portion of the future production from those activities, and in those cases, we will book proved developed reserves when the engineering and geological data supports doing so.

Our average proved reserves-to-production ratio, or average reserve life, is approximately 12 years based on the December 31, 2006 reserve report for the interests we acquired in the first half of 2007. This value does not include potential future reserves or production that may be added as a result of the exploration and development activities of the operators on the properties.

Our upstream business also includes approximately 430,000 net mineral acres in 10 states.

In our midstream business, our Texas Panhandle operations cover ten counties in Texas and one county in Oklahoma, consisting of our East Panhandle System and our West Panhandle System. The facilities that comprise our East Panhandle System are primarily located in Wheeler, Hemphill and Roberts Counties in the eastern Texas Panhandle and consist of:

•  approximately 800 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with 35,000 horsepower of associated pipeline compression;

•  four active natural gas processing plants with an aggregate capacity of 110 MMcf/d; and

•  two natural gas treating facilities with an aggregate capacity of 75 MMcf/d.

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The facilities that comprise our West Panhandle System are primarily located in Moore, Potter, Hutchinson, Carson, Roberts, Gray, Wheeler and Collingsworth Counties in the western Texas Panhandle and consist of:

•  approximately 2,700 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with approximately 81,500 horsepower of associated pipeline compression;

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

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

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

•  a condensate collection facility.

Our south Texas operations are primarily located in Hidalgo, Willacy, Brooks, Zapata, Starr, Cameron, Colorado, Fort Bend, McMullen and San Patricio Counties and consist of:

•  approximately 160 miles of natural gas gathering pipelines, ranging from two inches to 20 inches in diameter, with 8,100 horsepower of associated pipeline compression; and

•  11 active refrigeration skids with an aggregate capacity of 80 MMcf/d.

Our southeast Texas and Louisiana operations are primarily located in Polk, Tyler, Jasper, Newton, Upshur, Gregg, Wood and Panola Counties, Texas and Vernon, DeSoto, Lincoln, Jackson, Bienville, Caldwell and Bossier Parishes, Louisiana. The facilities that comprise our southeast Texas and Louisiana operations consist of:

•  approximately 1,300 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with approximately 12,500 horsepower of associated pipeline compression;

•  a 100 MMcf/d cryogenic processing plant;

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

•  five refrigeration skids with 45 MMcf/d of capacity; and

•  a19-mile NGL pipeline.

Our Assets

Midstream Business

We own strategically positioned natural gas gathering and processing assets in four significant natural gas producing regions, the Texas Panhandle, south Texas, southeast Texas and Louisiana.

Texas Panhandle Operations

Our Texas Panhandle operations cover ten counties in Texas and one county in Oklahoma and consist of our East Panhandle System and our West Panhandle System. Through these systems, we offer producers a complete set of midstream wellhead-to-market services, including gathering, compressing, treating, processing, transportation and selling of natural gas and fractionating and transporting NGLs.

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, there were approximately 5.4 Tcfe of total proved we natural gas reserves at year-end 2005 in District 10. This area has experienced significant drilling activity during the last three years.

Our Texas Panhandle Systems collectively include approximately 3,500 miles of gathering pipeline, eight active gas processing plants with an aggregate capacity of approximately 211 MMcf/d, three inactive plants with an aggregate capacity of approximately 50 MMcf/d. Our Texas Panhandle Systems had an average

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throughput of 139 MMcf/d and an average NGL and condensate production of approximately 13,100 Bbls/d for the first quarter of 2007.

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 a10-mile pipeline from the West Panhandle System to the East Panhandle System, and have refurbished and restarted a 20MMcfd processing plant. We are also looking to activate inactive processing plants located in the West Panhandle System and relocate those processing plants in the East Panhandle System or connect the processing plants to existing pipeline connections, and to utilize unused capacity at existing processing plants.

System Description.  The East Panhandle System consists of:

•  approximately 800 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with approximately 35,000 horsepower of associated pipeline compression;

•  four active natural gas processing plants with an aggregate capacity of 110 MMcf/d; and

•  two natural gas treating facilities with an aggregate capacity of 75 MMcf/d.

The average throughput of the gathering system was approximately 92.6 MMcf/d for the first quarter of 2007.

Natural Gas Supply.  As of March 31, 2007, approximately 600 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 gas is produced, extends from the western portion of the Texas Panhandle through most of central Oklahoma.

Natural gas production from wells located within the area served by the East Panhandle System generally have steep rates of decline during the first few years of production. Approximately 69% 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 for this processed natural gas. Approximately 31% 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 purchased at the wellhead primarily under percent-of proceeds and fee-based arrangements that primarily range from one to five years in term. As of March 31, 2007, approximately 74%, 20%, 5% and 1% of our total throughput in the East Panhandle System was under percent-of-proceeds, fee-based, fixed recovery and keep-whole arrangements, respectively. For a more complete discussion of our natural gas purchase contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations.”

Competition.  Our primary competitor in this area is Enbridge, Inc.

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.

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System Description.  The West Panhandle System consists of:

•  approximately 2,700 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with approximately 81,500 horsepower of associated pipeline compression;

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

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

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

•  a condensate collection facility.

The average throughput of the gathering system was approximately 46.4 MMcf/d for the first quarter of 2007.

Natural Gas Supply.  As of March 31, 2007, approximately 1,900 wells and central delivery points were connected to our West Panhandle System. There are approximately 156 producers with the primary producers connected to the East Panhandle System being Chesapeake Energy Marketing, Inc., Excel Production Company, and W.O. Operating Company. The West Panhandle field, from where this gas is produced, extends through the western and southern part of the panhandle.

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. This gas is processed to recover the NGL content which generally ranges from 8.0 to 18.0 gpm.

On the West Panhandle System, natural gas is purchased at the wellhead primarily under keepwhole arrangements, fixed recovery and percent-of proceeds arrangements that primarily range from one to five years in term with the keepwhole arrangements being primarily life of lease term. As of March 31, 2007, approximately 41%, 35%, and 24% 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. For a more complete discussion of our natural gas purchase contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations.”

Competition.  Our primary competition in this area is Duke Energy Field Services, L.P.

Texas Panhandle Markets

Our residue gas is marketed primarily to large trading companies who buy the gas at the tailgate of our plants. Our primary purchaser of the residue gas was ONEOK Energy Services, which represented approximately 71% of residue revenues on the system for the twelve months ended December 31, 2006. Our NGLs are marketed primarily to ONEOK Hydrocarbons, which represented approximately 97% of NGL revenues on the system for the twelve months ended December 31, 2006. 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 Conoco Phillips. Petro Source Partners, LP represented approximately 43% of the condensate revenues on the system for the twelve months ended December 31, 2006. The condensate is sold under contract terms of one year or less.

South Texas Operations

With the Laser acquisition, we expanded the footprint of our midstream business into South Texas. The south Texas systems primarily gather natural gas and recovers NGLs and condensate from 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.

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Description

The south Texas Operations consist of:

•  Approximately 170 miles of natural gas pipeline ranging in size from two inches to 20 inches in diameter.

•  Three main compressor stations with approximately 8100 aggregate horsepower.

•  Three processing stations consisting of 11 active skids and related facilities for an aggregate capacity of 92 MMcf/d.

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

The average throughput of the south Texas Operation was approximately 201.5 MMcf/d for the first quarter of 2007. The throughput consisted of 101.5 MMcf/d through Company pipeline facilities and 99.7 MMcf/d for Producer Services.

Natural Gas Supply

As of December 31, 2006, the south Texas Operations provide gatheringand/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.

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 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 gas deliveries from the south Texas systems go to Tennessee Gas Pipeline Company or Enterprise Pipeline. The 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. We also compete against various natural gas marketing companies for the purchase of wellhead production.

Southeast Texas and Louisiana Operations

Our southeast Texas and 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 southeast Texas and Louisiana Systems, we offer producers natural gas gathering, treating, processing and transportation and NGL transportation.

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

•  approximately 1,300 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with approximately 12,500 horsepower of associated pipeline compression;

•  a 100 MMcf/d cryogenic processing plant;

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

•  five refrigeration skids with 45 MMcf/d of capacity; and

•  a19-mile NGL pipeline.

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Natural Gas Supply.  As of March 31, 2007, approximately 220 wells and central delivery points were connected to our systems in the southeast Texas and Louisiana regions. The number increases by approximately 120 wells when including the Laser transaction. Our southeast Texas and Louisiana operations are located in an area experiencing an increase in drilling activity and production. The average throughput of the gathering system was approximately 68.9 MMcf/d for the first quarter of 2007. The Laser transaction added additional throughput of approximately 23.0 MMcf/d beginning in May 2007.

The natural gas supplied to us under our southeast Texas and 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. For a more complete discussion of our natural gas purchase contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations.”

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 and Enterprise Products Partners, L.P.

Upstream Business

Natural Gas and Oil Data

Proved Reserves

The following table presents, on a pro forma basis for the interests we have recently acquired, the estimated net proved natural gas and oil reserves, and their present value for the Montierra and MacLondon acquisitions at December 31, 2006. These values are based on reserve reports prepared by Cawley, Gillespie and Associates. The estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the Securities and Exchange Commission in connection with this offering. The Standardized Measure values shown in the table are not intended to represent the current market value of our estimated natural gas and oil reserves.

	As of
	December 31,
	2006
Reserve Data:
Estimated net proved reserves:
Natural gas (Bcf)		5,988
Oil (Bcfe)		2,588
Total (Bcfe)		21,516
Proved developed (Bcfe)		21,516
Proved undeveloped (Bcfe)		0.00
Proved developed reserves as% of total proved reserves		100	%
Standardized Measure (in millions)		60.6
Representative Natural Gas and Oil Prices:
Natural gas — Henry Hub per MMBtu	$	5.50
Oil — WTI per Bbl	$	61.05

(1)	Does not give effect to hedging transactions.
(2)	Natural gas and oil prices as of each period end were based on spot prices per MMBtu and Bbl at such date, with these representative prices adjusted by region to arrive at the appropriate net price.

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Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

The data in the above table represents estimates only. Natural gas and oil reserve engineering is inherently a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of natural gas and oil that are ultimately recovered. Please read “Risk Factors.”

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standard Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

From time to time, we engage Cawley, Gillespie & Associates to prepare a reserve and economic evaluation of properties that we are considering purchasing. Neither Cawley, Gillespie & Associates nor any of their respective employees has any interest in those properties and the compensation for these engagements is not contingent on their estimates of reserves and future net revenues for the subject properties.

Productive Wells

The interests that we have purchased are substantially all mineral, royalty and overriding royalty interests. We have interests in over 2,500 producing wells, yet own working interests in only two productive wells.

Developed and Undeveloped Acreage

Because substantially all of our interests are in the form of mineral, royalty, and overriding royalties, we currently have very minor amounts of leasehold acreage. The following table sets forth information as of December 31, 2006 on a pro forma basis relating to the leasehold acreage we acquired in the first half of 2007.

	Developed Acreage(1)				Undeveloped Acreage(2)				Total Acreage
	Gross(3)		Net(4)		Gross(3)		Net(4)		Gross		Net
Operated		0		0		0		0		0		0
Non-operated		0		0		40		31		40		31
Total		0		0		40		31		40		31

(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 expressed as whole numbers and fractions thereof.

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Drilling Activity

We are not the operator in any of the wells in which we have a royalty or working interest. As a result, we do not conduct any drilling activity. To the extent that this activity occurs on properties in which we have a mineral, royalty, overriding royalty, or non-operated working interest, it is conducted by the operator of the property.

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, although subject to these federal and state laws and regulations, are not directly impacted by them as we are not the operators of record on our leases. Indirectly, however, these laws and regulations may impose burdens on our operators and thus affect the operation of our leases.

Regulation of Operations

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 Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of FERC under the Natural Gas Act. We believe that 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.

Our Camp Ruby gathering system does provide limited interstate transportation services pursuant to Section 311 of the NGPA. The rates, terms and conditions of such transportation service are subject to FERC jurisdiction. Under Section 311, intrastate pipelines providing interstate service may avoid jurisdiction that would otherwise apply under the Natural Gas Act. Section 311 regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. Additionally, the terms and conditions of service set forth in the intrastate pipeline’s Statement of Operating Conditions are subject to FERC approval. Failure to observe the service limitations applicable to transportation services provided under Section 311, failure to comply with the rates approved by FERC for Section 311 service, and

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failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved Statement of Operating Conditions could result in the assertion of federal Natural Gas Act jurisdiction by FERCand/or the imposition of administrative, civil and criminal penalties.

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.

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 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

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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

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 the operators on our properties are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, posting of drilling bonds and filing reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

•  the location of wells;

•  the method of drilling and casing wells;

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

•  the plugging and abandoning of wells; and

•  notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In

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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.

Derivative Instruments and Hedging Activities

We periodically use derivative financial instruments to achieve a more predictable cash flow from our natural gas and oil production by reducing our exposure to price fluctuations. Currently, these transactions are swaps, collars and puts. We account for these activities pursuant to SFAS No. 133 —Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.

The accounting for changes in the fair market value of a derivative instrument depends on the intended use of the derivative instrument and the resulting designation, which is established at the inception of a derivative instrument. SFAS No. 133 requires that a company formally document, at the inception of a hedge, the hedging relationship and the company’s risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.

For derivative instruments designated as cash flow hedges, changes in fair market value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative instrument’s

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fair market value. Any ineffective portion of the derivative instrument’s change in fair market value is recognized immediately in earnings.

In addition to the derivatives previously entered into related to our midstream business, we entered into the following derivative transactions related to our upstream business in association with the Montierra acquisition.

					Price
			Monthly		($/mmbtu or $/bbl)
Period	Commodity		Volumes	Index	Floor		Ceiling
Jan-Dec 2007		Gas	20,000 MMBtu	NYMEX		8.00		12.95
Jan-Dec 2007		Gas	15,000 MMBtu	NYMEX		7.00		10.40
Jan-Dec 2007		Gas	10,000 MMBtu	NYMEX		6.25		8.00
Jan-Dec 2007		Oil	500 Bbl	NYMEX WTI		60.00		75.00
Jan-Dec 2007		Oil	2,500 Bbl	NYMEX WTI		60.00		72.55
Jan-Dec 2007		Oil	500 Bbl	NYMEX WTI		60.00		75.00
Jan-Dec 2007		Oil	2,500 Bbl	NYMEX WTI		60.00		72.55
Jan-Dec 2007		Oil	2,000 Bbl	NYMEX WTI		60.00		75.15
Jan-Dec 2008		Gas	15,000 MMBtu	NYMEX		6.25		11.15
Jan-Dec 2008		Gas	15,000 MMBtu	NYMEX		6.25		11.15
Jan-Dec 2008		Oil	3,000 Bbl	NYMEX WTI		60.00		71.65
Jan-Dec 2008		Oil	3,000 Bbl	NYMEX WTI		60.00		71.65
Jan-Dec 2009		Gas	10,000 MMbtu	NYMEX		6.25		11.20
Jan-Dec 2009		Gas	10,000 MMBtu	NYMEX		6.25		11.20

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

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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. 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.

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 withon-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 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, and Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. 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

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not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Upstream 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.

Because we own primarily minerals, royalties, and overriding royalty interests, and these interests are non-costbearing, 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 properties.

General.  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. Their operations are subject to the same environmental laws and regulations as other companies in the natural gas and oil industry. These laws and regulations may:

•  require the acquisition of various permits before drilling commences;

•  require the installation of expensive pollution control equipment;

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

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

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

•  impose substantial liabilities for pollution resulting from our operations; and

•  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 andclean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs. We believe that our operators substantially comply with all current applicable environmental laws and regulations and that their 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.

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

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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

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 March 31, 2007, Eagle Rock Energy G&P, LLC or its affiliates employed approximately 166 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.

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 insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

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MANAGEMENT

Management 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. Please read “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.

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 board of directors and executive officers of Eagle Rock Energy G&P, LLC makes 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. Please read “The Partnership Agreement — Withdrawal or Removal of the General Partner.”

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 six directors, two of whom are independent as defined under the independence standards established by the NASDAQ Global Market. In compliance with the rules of the NASDAQ Global Market, one additional independent director will be appointed to the board of directors of Eagle Rock Energy G&P, LLC within twelve months of our initial listing. The NASDAQ Global 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.

Eagle Rock Energy G&P, LLC has an audit committee of two directors, Philip B. Smith, and William K. White who meet the independence and experience standards established by the NASDAQ Global Market and the Securities Exchange Act of 1934, as amended. The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee. Eagle Rock Energy G&P, LLC also has a compensation committee, which among other things, oversees the compensation plans described below.

Additionally, Eagle Rock Energy G&P, LLC has a conflicts committee, which currently consists of two members of its board of directors who meet the independence described above for members of the audit committee. The conflicts committee reviews specific matters that the board believes may involve conflicts of interest. Currently, William K. White and Philip B. Smith, who both meet the independence standards, serve on the conflicts committee. At the time that a third member of the audit committee is appointed, as described

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above, that independent director will be appointed to the conflicts committee. 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.

Directors and Executive Officers and Former Officers

The following table shows information regarding the current directors and executive officers of Eagle Rock Energy G&P, LLC.

Name	Age		Position with Eagle Rock Energy G&P, LLC
Joseph A. Mills		47	Chairman and Chief Executive Officer, Director
Richard W. FitzGerald(1)		52	Senior Vice President, Chief Financial Officer and Treasurer
Alfredo Garcia(1)		41	Acting Chief Financial Officer and Senior Vice President, Corporate Development
Steven G. Hendrickson		45	Senior Vice President, Technical Evaluations
William E. Puckett		51	Senior Vice President, Midstream Commercial Operations
Joseph E. Schimelpfening		45	Senior Vice President, E&P Operations and Development
J. Stacy Horn		45	Vice President, Midstream Commercial Development
Stephen O. McNair		44	Vice President, Midstream Operations
William J. Quinn		36	Director
Kenneth A. Hersh		43	Director
Philip B. Smith		55	Director
John A. Weinzierl		38	Director
William K. White		64	Director

(1) Per ourForm 8-K filed on July 17, 2007, Mr. Garcia has been appointed Acting Chief Financial Officer until Mr. FitzGerald is able to resume his duties and responsibilities.

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 executive officers of Eagle Rock Energy G&P, LLC will devote substantially all of their time to our business and operations.

Joseph A. Millswas elected Chairman of the Board and Chief Executive Officer of Eagle Rock Energy G&P, LLC in May 2007. From April 2006 to May 2007, Mr. Mills was President and Chief Executive Officer of Montierra Minerals & Production, LP. Prior to Montierra, Mr. Mills was the Senior Vice President of Operations for a privately held minerals company. Prior to that, Mr. Mills was a Senior Vice President of El Paso Corporation.

Richard W. FitzGeraldwas elected Senior Vice President, Chief Financial Officer and Treasurer of Eagle Rock Energy G&P, LLC and Eagle Rock Pipeline, L.P. in August 2006. From May 2003 to August 2006, Mr. FitzGerald was Senior Vice President and Chief Financial Officer of Natco Group, Inc. From April 1999 to April 2003, Mr. FitzGerald was Senior Vice President and Chief Financial Officer of Universal Compression Inc. Prior to that, Mr. FitzGerald was Vice President of Financial Planning and Services for KN Energy from January 1998 to April 1999.

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Alfredo Garciawas appointed Acting Chief Financial Officer of Eagle Rock Energy G&P, LLC in July 2007 in addition to his current role of Senior Vice President, Corporate Development of Eagle Rock Energy G&P, LLC which he was appointed to in August 2006. Mr. Garcia served as Senior Vice President and Chief Financial Officer of Eagle Rock Energy G&P, LLC from March 2006 until August 2006, 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 softwarestart-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.

Steven G. Hendricksonwas 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, LP. From 2005 to 2006 he was in private practice. From 1999 to 2005, Mr. Hendrickson was Director of Reservoir Engineering and other various management positions with El Paso Corporation. Mr. Hendrickson is a registered Petroleum Engineer in the State of Texas.

William E. Puckettwas elected Senior Vice President, Commercial Operations of Eagle Rock Energy G&P, LLC in March 2006. Mr. Puckett has been Vice President, Commercial Operations of Eagle Rock Pipeline, L.P. since December 2005. From September 1999 until November 2005, Mr. Puckett was Vice President, Technical Services for Dynegy, Inc., a gas gathering and processing company. Mr. Puckett has also served in a variety of positions in marketing, processing and operations.

Joseph E. Schimelpfeningwas 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, LP. Prior to May 2006, Mr. Schimelpfening was Division Operations Manager for El Paso Corporation.

J. Stacy Hornwas 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.

Stephen McNairwas elected Vice President of Operations of Eagle Rock Energy G&P, LLC in August 2006. Mr. McNair has been Vice President of Natural Gas Services for TEPPCO in Denver, Colorado from March 2005 to July 2006. From September 2002 to January 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 J. Quinnwas appointed Chairman of the Board of Eagle Rock Energy G&P, LLC in January 2007. Mr. Quinn served as chairman 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 has been a director of Eagle Rock Pipeline, L.P. since December 2005 and Eagle Rock Energy, Inc. from December 2003 through December 2005. Mr. Quinn is the Executive Vice President of NGP Energy Capital Management and is a managing partner of the Natural Gas Partners private equity funds and has served in those or similar capacities since 1998. He currently serves on the investment committee of NGP Capital Resources Company, a business development company that focuses on the energy industry.

Kenneth A. Hershwas elected Director of Eagle Rock Energy G&P, LLC in March 2006. Mr. Hersh has been a director of Eagle Rock Pipeline, L.P. since December 2005 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

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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.

Philip B. Smithwas elected Director of Eagle Rock Energy G&P, LLC in October 2006 and serves as a member of the audit committee, the conflicts 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, he served as a director of HS Resources, Inc. and of Pioneer Natural Resources Company and its predecessor, MESA, Inc.

John A. Weinzierlwas elected Director of Eagle Rock Energy G&P, LLC in March 2006. Mr. Weinzierl has been a director of Eagle Rock Pipeline, L.P. since December 2005 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 an 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. Whitewas elected Director of Eagle Rock Energy G&P, LLC in October 2006 and serves as Chairman of the audit committee and as Chairman of the conflicts committee of the board of directors of Eagle Rock Energy G&P, LLC. Mr. White is President of Amado Energy Management, LLC, a position he has held since December 2002. He is also 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. From January 1995 to July 1996, Mr. White was a Senior Vice President for TCW Asset Management Company.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our units as of June 30, 2007 held by:

•  each person or group of persons who then will beneficially own 5% or more of the then outstanding units;

•  each member of the board of directors of Eagle Rock Energy G&P, LLC;

•  each named executive officer of Eagle Rock Energy G&P, LLC; and

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

											Percentage of
											Total
			Percentage of					Percentage of			Common and
	Common		Common			Subordinated		Subordinated			Subordinated
	Units to be		Units to be			Units to be		Units to be			Units to be
	Beneficially		Beneficially			Beneficially		Beneficially			Beneficially
Name of Beneficial Owner(1)	Owned		Owned			Owned		Owned			Owned
Eagle Rock Holdings, L.P.(2)		2,187,871		6.0	%		20,691,495		100.0	%		39.8	%
Montierra Minerals & Production, L.P.(3)		2,820,578		7.7	%		—		—	%		4.9	%
Lehman Brothers Holdings, Inc(4)		2,559,122		7.0	%		—		—	%		4.5	%
Joseph A. Mills(6)		154,185		*	%		—		—	%		*	%
Richard W. FitzGerald(2)(6)		56,715		*	%		205,361		1.0	%		*	%
Alfredo Garcia(2)(6)		80,691		*	%		763,122		3.7	%		1.5	%
William E. Puckett(2)(6)		39,214		*	%		181,714		*	%		*	%
Joseph E. Schimelpfening(6)		29,425		*	%		—		—	%		*	%
Steven G. Hendrickson(6)		27,366		*	%		—		—	%		*	%
J. Stacy Horn(2)(6)		37,551		*	%		132,887		*	%		*	%
Stephen O. McNair(2)(6)		34,782		*	%		116,164		*	%		*	%
Kenneth A. Hersh(5)		—		—	%		—		—	%		—	%
William J. Quinn		10,000		*	%		—		*	%		*	%
John A. Weinzierl		8,800		*	%		—		*	%		*	%
William K. White		14,700		*	%		—		*	%		*	%
Philip B. Smith		10,000		*	%		—		*	%		*	%
All directors and executive officers as a group (13 persons)		503,429		1.4	%		1,399,248		6.8	%		2.8	%

* Less than 1%

(1)	Unless otherwise indicated, the address for all beneficial owners in this table is 16701 Greenspoint Park Drive, Suite 200 Houston, Texas 77060.
(2)	Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., Richard W. FitzGerald, Alfredo Garcia, William E. Puckett, J. Stacy Horn and Stephen O. McNair have approximately a 31.35%, 48.33%, 1.00%, 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. FitzGerald, Mr. McNair and Mr. Horn in proportion to their beneficial ownership in Eagle Rock Holdings, L.P.
(3)	NGP VII owns a 97.561% LP interest in Montierra Management, which serves as the general partner of Montierra, and 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 1,156,501 Common Units reported herein. Lehman Brothers, Inc. is a wholly-owned subsidiary of Lehman Brothers Holdings, Inc. Lehman Brothers Holdings, Inc. may

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	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 1,098,901 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, 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 303,720 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. that are attributable to Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. 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 a 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, the units. Mr. Hersh disclaims any deemed beneficial ownership of the units held by Eagle Rock Holdings, L.P.
(6)	In addition to the units he holds through his ownership of Eagle Rock Holdings, L.P., Richard W. FitzGerald also beneficially owns 5,000 units through our directed unit program, plus 30,000 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.

SELLING UNITHOLDERS

This prospectus covers the offering for resale of up to 13,391,028 common units by selling unitholders. Unless otherwise indicated, each of the selling unitholders acquired its common units in connection with private placements of securities by our predecessor Eagle Rock Pipeline, L.P. in March 2006 and June 2006 that were exchanged for our common units upon the closing of our initial public offering on October 24, 2006, and private placement by us in May 2007. We entered into registration rights agreements with the selling unitholders in connection with the private placements. We are registering the common units described below pursuant to such registration rights agreement.

No offer or sale may be made by a unitholder unless that unitholder is listed in the table below. The selling unitholders may sell all, some or none of the common units covered by this prospectus. Please read “Plan of Distribution.” We will bear all costs, fees and expenses incurred in connection with the registration of

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the common units offered by this prospectus. Brokerage commissions and similar selling expenses, if any, attributable to the sale of common units will be borne by the selling unitholders.

No such sales may occur unless the selling unitholder has notified us of his or her intention to sell our common units and this prospectus has been declared effective by the SEC, and remains effective at the time such selling unitholder offers or sells such common units. We are required to update this prospectus to reflect material developments in our business, financial position and results of operations.

The following table sets forth, the name of each selling unitholder, the number of common units beneficially owned and the percentage of units outstanding owned by each selling unitholder prior to the offering, the number of common units being offered for each selling unitholder’s account, and the amount to be owned and the percentage of common units outstanding owned by each selling unitholder following the completion of the offering (assuming each selling unitholder sells all of the common units covered by this prospectus). The percentages of common units outstanding have been calculated based on 36,284,759 units outstanding as of June 30, 2007. Unless otherwise indicated, the selling unitholders have held no position or office or had any other material relationship with us or any of our affiliates or predecessors, other than as a unitholder, during the past three years.

We have prepared the table and the related notes based on information supplied to us by the selling unitholders. We have not sought to verify such information. Additionally, some or all of the selling unitholders may have sold or transferred some or all of the units listed below in exempt or non-exempt transactions since the date on which the information was provided to us. Other information about the selling unitholders may change over time.

						Number of		Percentage of
	Number of		Percentage			Units		Units
	Units		of			Outstanding		Outstanding
	that		Units			after		after
Selling Unitholder	may be Sold		Outstanding			Offering		Offering
Agile Performance Fund, LLC(1)		9,230			*
Credit Suisse Management LLC		900,000		2.5	%
Curtis Stevens		14,967			*		—		—
Dale Harper		68,512			*		—		—
Gary Hollowell		36,822			*		—		—
GPS High Yield Equities Fund, L.P.(2)		34,725			*		—		—
GPS MLP Fund, L.P.(2)		98,885			*		—		—
GPS New Equity Fund, L.P.(2)		708,790		2.0	%		—		—
Greg Montgomery		44,748			*		—		—
I.J. “Chip” Berthelot, II		447,610		1.2	%		—		—
I.J. “Chip” Berthelot, II as Custodian for Amanda Marie Berthelot under the Texas Uniform Transfer to Minors Act(3)		5,672			*		—		—
I.J. “Chip” Berthelot, II as Custodian for Iris J. Berthelot III under the Texas Uniform Transfer to Minors Act(3)		5,672			*		—		—
I.J. “Chip” Berthelot, II as Custodian for Jennifer Lynn Berthelot under the Texas Uniform Transfer to Minors Act(3)		5,672			*		—		—
I.J. “Chip” Berthelot, II as Custodian for Lauren Nicole Berthelot under the Texas Uniform Transfer to Minors Act(3)		5,672			*		—		—
Ladonna M. Combs		2,836			*		—		—
Laser Midstream Energy II, L.P.(4)		631,579		1.8	%		—		—
Laser Midstream Energy Spectrum, LLC(5)		21			*		—		—
Lehman Brothers Inc.(6)		1,156,501		3.2	%		—		—
Lehman Brothers MLP Opportunity Fund L.P.(7)		4,972,062		13.8	%
Montierra Management, LLC(8)		28,491			*		—		—

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						Number of		Percentage of
	Number of		Percentage			Units		Units
	Units		of			Outstanding		Outstanding
	that		Units			after		after
Selling Unitholder	may be Sold		Outstanding			Offering		Offering
Montierra Minerals & Production, L.P.(9)		2,820,578		7.4	%		—		—
New Mountain Vantage, L.P.(10)		402,000		1.1	%		—		—
New Mountain Vantage (California), L.P.(10)		400,600		1.1	%		—		—
New Mountain Vantage (Texas), L.P.(10)		371,200		1.0	%		—		—
NGP 2004 Co-Investment Income, L.P.		3,433,674		9.6	%
NGP Co-Investment Income Capital Corp.		107,657			*
Randy Newcomer, Jr.		18,441			*		—		—
RCH Energy MLP Fund, L.P.(11)		1,098,901		3.1	%		—		—
Royal Bank of Canada(12)		1,207,710		3.4	%		—		—
Steve Loy		36,822			*		—		—
Structured Finance Americas LLC		384,617		1,1	%
Thomas K. Odenwelder		62,498			*		—		—
W. Tim Sexton		6,917			*		—		—
ZLP Fund, L.P.(13)		164,835			*		—		—

*	Less than one percent.
(1)	Neal R. Greenberg is deemed to hold investment power and voting control over the units held by this unitholder.
(2)	Brett S. Messing and Steven A. Sugarman are members of GPS Partners L.L.C., which is the General Partner of and investment advisor to this selling unitholder. By virtue of their position with GPS Partners L.L.C., Mr. Messing and Mr. Sugarman are deemed to hold investment power and voting control over the units held by this unitholder.
(3)	I.J. “Chip” Berthelot, II is deemed to hold shared investment power and voting control over the units held by this selling unitholder.
(4)	Laser Gas Company, LLC is the managing general partner of Laser Midstream Energy II, L.P. I.J. “Chip” Berthelot is the president of Laser Gas Company, LLC and is deemed to hold investment power and voting control over the units held by this selling unitholder.
(5)	I.J. “Chip” Berthelot is the president of Laser Midstream Energy Spectrum, LLC and is deemed to hold investment power and voting control over the units held by this selling unitholder.
(6)	Walter Maloney, Managing Director; Tom Regazzi, Vice President, and Matias Bercun, associate, are deemed to hold investment power and voting control over the units held by this unitholder. This unitholder is a broker-dealer registered under Section 15 of the Securities and Exchange Act of 1934, as amended.
(7)	Michael Cannon, Kyriacos Loupis, Jeffrey Wood and Ethan Bellamy are deemed to hold investment power and voting control over the units held by this unitholder.
(8)	Joseph A. Mills, Chief Executive Officer, of Montierra Management, LLC holds voting, dispositive, and other investment power over the common units.
(9)	Joseph A. Mills, Chief Executive Officer, of Montierra Minerals & Production, LP holds voting, dispositive, and other investment power over the common units.
(10)	New Mountain Vantage Advisors, L.L.C. acts as the investment advisor and manager of this unitholder. By virtue of this relationship, Steven B. Klinsky, managing member of New Mountain Vantage Advisors, L.L.C., is deemed to hold investment power and voting control over the units held by this unitholder.
(11)	Robert Raymond is the sole member of RR Advisors, L.L.C. which is the investment advisor and General Partner to RCH Energy MLP Fund, L.P.; RCH Energy MLP Fund A, L.P.; and RCH Energy Opportunity Fund I, L.P. By virtue of his position with RR Advisors, L.L.C., Mr. Raymond is deemed to hold investment power and voting control over the units held by this unitholder.

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(12)	David Weiner, Managing Director, is deemed to hold investment power and voting control over the units held by this unitholder. This unitholder is an affiliate with the following Broker-Dealers registered under Section 15 of the Securities Exchange Act of 1934, as amended: RBC Capital Markets Corporation and RBC Dain Rauscher Inc.
(13)	Stuart Zimmer and Craig Lucas as managing members are deemed to share investment power and voting control over the units held by this unitholder.

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Eagle Rock Holdings, L.P. owns 2,187,871 common units and 20,691,495 subordinated units representing an aggregate 40.2% limited partner interest in us. In addition, our general partner owns 844,551 general partner units representing a 1.46% general partner interest in us and the incentive distribution rights.

Distributions and Payments to Our General Partner and its Affiliates

The following table summarizes the distributions and payments made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Eagle Rock Energy Partners, L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

The consideration received by Eagle Rock Holdings, L.P. and its subsidiaries and the Private Investors for the contribution of the assets and liabilities to us	• 3,459,236 common units (1,463,785 common units were redeemed on November 21, 2006 in connection with exercise by the underwriters of their over-allotment option);
	• 20,691,495 subordinated units;
	• 844,551 general partner units;
	• the incentive distribution rights;
	• cash payment of approximately $35.0 million from the proceeds of our initial public offering to replenish working capital that will be distributed to certain subsidiaries of Eagle Rock Holdings, L.P. and certain of the selling unitholders prior to the consummation of our initial public offering;
	• cash payment of approximately $184.8 million from the proceeds of our initial public offering as reimbursement for capital expenditures incurred by Eagle Rock Holdings, L.P. and certain of the selling unitholders prior to the closing of our initial public offering related to the assets to be contributed to us upon the closing of our initial public offering;
	• cash payment of approximately $11.0 million from the proceeds of our initial public offering in respect of arrearages on the existing subordinated and general partner units of Eagle Rock Pipeline, L.P. owned by Eagle Rock Holdings, L.P.

Operational Stage

Distributions of available cash to our general partner and its affiliates We will generally make cash distributions 98% to our unitholders pro rata, including Eagle Rock Holdings, L.P. as the holder of an aggregate 2,187,871 common units and 20,691,495 subordinated

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	units, and 2% to our general partner, assuming it makes any capital contributions necessary to maintain its initial 2% interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level.
	Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $1.2 million on their general partner units and $33.2 million on their common and subordinated units.
Payments to our general partner and its affiliates	Our general partner and its affiliates will be entitled to reimbursement for all expenses it incurs on our behalf, including salaries and employee benefit costs for its employees who provide services to us, and all other necessary or appropriate expenses allocable to us or reasonably incurred by our general partner and its affiliates in connection with operating our business. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith.
Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The A Partnership Agreement — Withdrawal or Removal of the General Partner.”

Liquidation Stage

Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Transactions

We and other parties entered into various documents and agreements that effected the offering transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of the initial public offering. These agreements were not the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, were not effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, were paid from the proceeds of the initial public offering.

Omnibus Agreement

In connection with the closing of our initial public offering, on October 24, 2006, we entered into an omnibus agreement with Eagle Rock Energy G&P, LLC, Eagle Rock Holdings, L.P. and our general partner that addresses the following matters:

•  our obligation to reimburse Eagle Rock Energy G&P, LLC and Eagle Rock Holdings, L.P. the payment of operating expenses, including salary and benefits of operating personnel, they incur on our behalf in connection with our business and operations;

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•  our obligation to reimburse Eagle Rock Energy G&P, LLC and Eagle Rock Holdings, L.P. for insurance coverage expenses they incur with respect to our business and operations and with respect to director and officer liability coverage; and

•  the obligation of Eagle Rock Energy G&P, LLC, Eagle Rock Holdings, L.P. and our general partner to indemnify us for certain environmental and other liabilities.

We are obligated to reimburse Eagle Rock Energy G&P, LLC and Eagle Rock Holdings, L.P. for operating expenses, general and administrative expenses and public company expenses pursuant to the omnibus agreement.

Any or all of the provisions of the omnibus agreement will be terminable by Eagle Rock Energy G&P, LLC and Eagle Rock Holdings, L.P. at their option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The omnibus agreement will also terminate in the event of a change of control of us, our general partner or the general partner of our general partner.

Reimbursement of Operating and General and Administrative Expense

Under the omnibus agreement, we reimburse Eagle Rock Energy G&P, LLC and Eagle Rock Holdings, L.P. for the payment of certain operating expenses and for the provision of various general and administrative services for our benefit with respect to the assets contributed to us at the closing of our initial public offering. The omnibus agreement will further provide that we will reimburse Eagle Rock Energy G&P, LLC and Eagle Rock Holdings, L.P. for our allocable portion of the premiums on insurance policies covering our assets.

Pursuant to these arrangements, Eagle Rock Energy G&P, LLC and Eagle Rock Holdings, L.P. performed centralized corporate functions for us, such as legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. We reimbursed them for the direct expenses to provide these services as well as other direct expenses it incurs on our behalf, such as salaries of operational personnel performing services for our benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits.

Indemnification

Under the omnibus agreement, Eagle Rock Holdings, L.P., Eagle Rock Energy G&P, LLC and our general partner indemnified us for two years after the closing of our initial public offering against certain potential environmental claims, losses and expenses associated with the operation of the assets contributed to us and occurring before the closing date of our initial public offering. The maximum liability for this indemnification obligation will not exceed $7.5 million, and the indemnifying parties do not have any obligation under this indemnification until our aggregate losses exceed $750,000. The indemnifying parties have no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of the initial public offering.

Additionally, Eagle Rock Holdings, L.P., Eagle Rock Energy G&P, LLC and our general partner indemnified us for certain liabilities, other than environmental liabilities and other than liabilities incurred in the ordinary course of business conducted in compliance with applicable laws, that arise out of the operation of the assets contributed to us and occur before the closing date of our initial public offering. The indemnifying parties’ maximum liability for this indemnification obligation will not exceed $5.0 million, and Eagle Rock Holdings, L.P. do not have any obligation under this indemnification until our aggregate losses exceed $500,000. In addition, this indemnification obligation will be reduced by any amounts we reserved or accrued for such losses as of December 31, 2005. The indemnifying parties also indemnify us for losses attributable to title defects, the failure to obtain certain consents and permits, retained assets and liabilities and any unaccrued income taxes attributable to pre-closing operations.

The indemnifying parties’ liability for any of the foregoing is subject to reduction for (i) any insurance proceeds realized by us with respect to the indemnified matter, net of any premium that becomes due and

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payable as a result of such claim, (ii) any amounts recovered by us under contractual indemnities from third parties and (iii) up to $2.1 million of costs incurred by us to conduct environmental investigations, implement SPCC plans and perform selected cavern closures on 11 properties, in each case as described under the heading “Business — Environmental Matters.”

Competition

None of Eagle Rock Holdings, L.P. or Natural Gas Partners nor any of their affiliates is restricted, under either our partnership agreement or the omnibus agreement, from competing with us. Eagle Rock Holdings, L.P., Montierra Minerals & Production, LP and Natural Gas Partners and any of their affiliates may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer us the opportunity to purchase, construct or develop those assets.

MGS Purchase Agreement

On June 2, 2006, we entered into a sale, contribution and exchange agreement relating to our acquisition of Midstream Gas Services, L.P. with the owners of MGS, including Natural Gas Partners VII, L.P. Pursuant to the sale, contribution and exchange agreement, we purchased all of the partnership interests in MGS for approximately $4.7 million in cash and 1,125,416 common units in Eagle Rock Pipeline. We will issue up to 798,155 of our common units, which we refer to as the Deferred Common Units, to Natural Gas Partners VII, L.P., the primary equity owner of MGS, as a contingent earn-out payment if MGS achieves certain financial objectives for the year ending December 31, 2007. The Deferred Common Units, if any, will be issued in the form of common units in us. Prior to the acquisition, Natural Gas Partners VII, L.P. owned a 95% limited partnership interest in MGS and a 95% interest in its general partner, which owned a 1% general partner interest, in MGS. Upon completion of the initial public offering, the 1,125,416 common units in Eagle Rock Pipeline were converted into common units in us on approximately a1-for-0.719 common unit basis.

Montierra and Co-Invest Agreement

On April 30, 2007, Eagle Rock Energy Partners, L.P., a Delaware limited partnership (“Eagle Rock,” or “Contributee”) completed the acquisition of certain fee minerals, royalties and working interest properties from Montierra Minerals & Production, L.P., a Delaware limited partnership (“Montierra”), and NGP-VII Income Co-Investment Opportunities, L.P., a Texas limited partnership (“Co-Invest”) for an aggregate purchase price of $127.4 million (the “Montierra Acquisition”). Moniterra and NGP received as consideration a total of 6,390,400 Eagle Rock common units and $6.0 million in 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 Minerals & Production, L.P.

Registration Rights Agreement

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. For a description of this registration rights agreement, please read “Units Eligible for Future Sale.”

In connection with the closing of the Montierra acquisition, we entered into a registration rights agreement with Montierra Minerals & Production, L.P. In the registration rights agreement, we agreed, for the benefit of Montierra Minerals & Production, 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. For a description of this registration rights agreement, please read “Units Eligible for Future Sale.”

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Other

During 2005, we declared and accrued a $5.0 million distribution to Natural Gas Partners. This distribution was included in the balance sheet at December 31, 2005, in distributions payable — affiliate.

On July 1, 2006, we entered into a month-to-month contract for the marketing of natural gas with Odyssey Energy Services, LLC, an affiliate of Natural Gas Partners, under which we have the option, but not the obligation, to sell to Odyssey a portion of our gas supply from our Texas Panhandle systems. Each month we evaluate whether or not we will sell gas to Odyssey under this contract and if we determine to do so, we then specify the volume of gas to be sold to Odyssey. July 2006 is the first month we used this contract, and to date in any given month we have sold no more than 25% of our gas supply to Odyssey. The price of gas being sold to Odyssey is the price listed in the “Gas Daily” publication for the relevant day applicable to the geographic location closest in proximity to the delivery point of the gas, less actual transportation costs, and is competitive with our other gas sales contracts. There is an outstanding letter of credit issued by Odyssey on our behalf related to the agreement.

Members of our management own unitsand/or options in Eagle Rock Holdings, L.P. These units and options vest upon the achievement of certain financial performance objectives and time vesting restrictions. Upon the completion of our initial public offering, our management received the benefit of the vesting of the so-called “Tier I Options” which increased the overall ownership by our management in Eagle Rock Holdings, L.P., which owns 2,187,871 of our common units and 20,691,495 of our subordinated units, to 20.2%.

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Eagle Rock Holdings, L.P. and its owners) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of Eagle Rock Energy G&P, LLC have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, Eagle Rock Energy G&P, LLC and our general partner have a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

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 the conflict is:

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

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

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

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

Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. 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

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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. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to reasonably believe he is acting in the best interests of the partnership.

Conflicts of interest could arise in the situations described below, among others.

Transactions with NGP Affiliates.

Our general partner’s affiliates may engage in competition with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in our partnership agreement, the owners of our general partner are not prohibited from engaging in, and are not required to offer us the opportunity to engage in, other businesses or activities, including those that might be in direct competition with us.

Our general partner and its affiliates are allowed to take into account the interests of parties other than us in resolving conflicts of interest.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. 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. This entitles our general partner and its affiliates to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

We will not have any employees and will rely on the employees of Eagle Rock Energy G&P, LLC and its affiliates.

Affiliates of our general partner and Eagle Rock Energy G&P, LLC may conduct businesses and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to Eagle Rock Energy G&P, LLC and its affiliates.

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 such limitations, might otherwise constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:

•  provides that the general partner shall 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, meaning it believed that the decision was in the best interests of our partnership;

•  generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of Eagle Rock Energy G&P, LLC and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or

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available from unrelated third parties or be “fair and reasonable” to us, as determined by the general partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” Eagle Rock Energy G&P, LLC may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

•  provides that our general partner and Eagle Rock Energy G&P, LLC and their 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 our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

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 including, but not limited to, the following:

•  the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

•  the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;

•  the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

•  the negotiation, execution and performance of any contracts, conveyances or other instruments;

•  the distribution of our cash;

•  the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

•  the maintenance of insurance for our benefit and the benefit of our partners;

•  the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships;

•  the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

•  the indemnification of any person against liabilities and contingencies to the extent permitted by law;

•  the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

•  the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

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. Please read “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.

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Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

•  amount and timing of asset purchases and sales;

•  cash expenditures;

•  borrowings;

•  the issuance of additional units; and

•  the creation, reduction or increase of reserves in any quarter.

In addition, our general partner may use an amount, initially equal to $62.8 million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and the general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owned by the general partner to our unitholders, including borrowings that have the purpose or effect of:

•  enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

•  hastening the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permit us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “Provisions of Our Partnership Agreement Related to Cash Distributions — Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, our operating company, or its operating subsidiaries.

Our general partner determines which costs incurred by it or Eagle Rock Energy G&P, LLC are reimbursable by us.

We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith.

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

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts or arrangements between us, on the one hand, and our general partner and its affiliates, on the other hand, that went into effect as of the closing of our initial public offering were the result of arm’s-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into in the future will not be required to be negotiated on an arm’s-length basis; although, in some circumstances, our general partner may determine that the conflicts committee

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of our general partner may make a determination on our behalf with respect to one or more of these types of situations.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner or its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

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

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. 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 general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement — Limited Call Right.”

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

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

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board

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of directors will have fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to you. Without these modifications, the general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable the general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

State-law fiduciary duty standards	Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.
	The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.
Partnership agreement modified standards	Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.
	In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further 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 errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct.

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Special provisions regarding affiliated transactions.  Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be:

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

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

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 bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, 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. These standards reduce the obligations to which our general partner would otherwise be held.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

We must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement — Indemnification.”

DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

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Transfer Agent and Registrar

Duties.  American Stock Transfer & Trust Company serves as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:

•  surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

•  special charges for services requested by a common unitholder; and

•  other similar fees or charges.

There is no charge to unitholders for disbursements of our cash distributions. We indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal.  The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Each transferee:

•  represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

•  automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

•  gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and our initial public offering.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is filed as an exhibit with the registration statement of which this prospectus is a part. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

•  with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions;”

•  with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties;”

•  with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units;” and

•  with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences.”

Organization and Duration

Our partnership was organized in May 2006 and will have a perpetual existence.

Purpose

Our purpose under the partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that the general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of acquiring, drilling, producing, gathering, compressing, treating, processing, transporting and selling natural gas and the business of transporting and selling NGLs, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement.

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”

Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its initial 2% general partner interest if we issue additional units. Our general partner’s

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initial 2% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its initial 2% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require:

•  during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and

•  after the subordination period, the approval of a majority of the common units voting as a class.

In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.

Issuance of additional units	No approval right.
Amendment of the partnership agreement	Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement.”
Merger of our partnership or the sale of all or substantially all of our assets	Unit majority in certain circumstances. Please read “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”
Dissolution of our partnership	Unit majority. Please read “— Termination and Dissolution.”
Continuation of our business upon dissolution	Unit majority. Please read “— Termination and Dissolution.”
Withdrawal of the general partner	Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to September 30, 2016 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of the General Partner.”
Removal of the general partner	Not less than 662/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of the General Partner.”
Transfer of the general partner interest	Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets, to such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to September 30, 2016. See “— Transfer of General Partner Units.”
Transfer of ownership interests in our general partner	No approval required at any time. Please read “— Transfer of Ownership Interests in the General Partner.”

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Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

•  to remove or replace the general partner;

•  to approve some amendments to the partnership agreement; or

•  to take other action under the partnership agreement; constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business in three states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a limited partner of the operating partnership may require compliance with legal requirements in the jurisdictions in which the operating partnership conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of our partnership interest in our operating partnership or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

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It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.

Upon issuance of additional partnership securities (other than the issuance of partnership securities issued in connection with a reset of the incentive distribution target levels relating to our general partner’s incentive distribution rights or the issuance of partnership securities upon conversion of outstanding partnership securities), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its initial 2% general partner interest in us. Our general partner’s initial 2% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

General.  Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments.  No amendment may be made that would:

•  enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

•  enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, our general partner and its affiliates will own approximately 40.2% of the outstanding common and subordinated units.

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No Unitholder Approval.  Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:

•  a change in our name, the location of our principal place of our business, our registered agent or our registered office;

•  the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

•  a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating partnership nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

•  an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

•  an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities, including any amendment that our general partner determines is necessary or appropriate in connection with:

•  the adjustments of the minimum quarterly distribution, first target distribution, second target distribution and third target distribution in connection with the reset of our general partner’s incentive distribution rights as described under “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels;”

•  any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities, provided that, any such modifications and related issuance of partnership securities have received approval by a majority of the members of the conflicts committee of our general partner;

•  any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

•  an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

•  any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

•  a change in our fiscal year or taxable year and related changes;

•  conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

•  any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

•  do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;

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•  are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

•  are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

•  are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

•  are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval.  Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

In addition, the partnership agreement generally prohibits our general partner without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement, each of our units will be an identical unit of our partnership following the transaction, and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in the partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide the limited partners and the general partner with the same rights and obligations as contained in the partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under

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the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

•  the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

•  there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

•  the entry of a decree of judicial dissolution of our partnership; or

•  the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

•  the action would not result in the loss of limited liability of any limited partner; and

•  neither our partnership, our operating partnership nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of the General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to September 30, 2016 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after September 30, 2016, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than the general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “— Transfer of General Partner Units” and “— Transfer of Incentive Distribution Rights.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is

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elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “— Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units voting as a separate class, and subordinated units, voting as a separate class. The ownership of more than 331/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. Our general partner and its affiliates own 40.2% of the outstanding common and subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal:

•  the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

•  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

•  our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Units

Except for transfer by our general partner of all, but not less than all, of its general partner units to:

•  an affiliate of our general partner (other than an individual); or

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•  another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity, our general partner may not transfer all or any of its general partner units to another person prior to September 30, 2016 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in the General Partner

At any time, Eagle Rock Holdings, L.P. and its affiliates may sell or transfer all or part of its partnership interests in our general partner, or its membership interest in Eagle Rock Energy G&P, LLC, the general partner of our general partner, to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest in the holder or the sale of all or substantially all of its assets to, that entity without the prior approval of the unitholders; provided that, in the case of the sale of ownership interests in the holder, the initial holder of the incentive distribution rights continues to remain the general partner following such sale. Prior to September 30, 2016, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after September 30, 2016, the incentive distribution rights will be freely transferable.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Eagle Rock Energy GP, L.P. as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

•  the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

•  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

•  our general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

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Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:

•  the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

•  the current market price as of the date three days before the date the notice is mailed.

•  As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences — Disposition of Common Units.”

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units and as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

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Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in-kind upon our liquidation.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

•  our general partner;

•  any departing general partner;

•  any person who is or was an affiliate of a general partner or any departing general partner;

•  any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

•  any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

•  any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The general partner is entitled to determine in good faith the expenses that are allocable to us.

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Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

•  a current list of the name and last known address of each partner;

•  a copy of our tax returns;

•  information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;

•  copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

•  information regarding the status of our business and financial condition; and

•  any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Eagle Rock Energy GP, L.P. as general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and fees. Please read “Units Eligible for Future Sale.”

UNITS ELIGIBLE FOR FUTURE SALE

Eagle Rock Holdings holds an aggregate of 2,187,871 common units and 20,691,495 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. Effective April 30, 2007, we issued 1,407,895 common units in connection with the

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acquisition of Laser Midstream Energy, L.P. In connection with the acquisition of certain assets from Montierra Minerals & Production, L.P. (“Montierra”), we issued 6,390,400 common units, subject to adjustments. We have issued 7,005,495 common units to third-party investors in a private placement. Pursuant to registration rights of Laser and Montierra, as well as the holders in the private placement, we are required to register these common units for resale. The registration statement to which this prospectus relates has been filed to fulfill those registration rights. In addition to the above, we anticipate issuing 1,239,495 common units in connection with various transactions (including restricted units to employees which are subject to forfeiture). The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold hereunder will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•  1% of the total number of the securities outstanding; or

•  the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least two years, would be entitled to sell common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

The partnership agreement does not restrict our ability to issue any partnership securities at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement — Issuance of Additional Securities.”

We entered into a registration rights agreement with Eagle Rock Holdings 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, 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. Specifically, we agreed:

•  subject to certain restrictions to file with the SEC, within 90 days after the receipt of a request by Eagle Rock Holdings, a registration statement (a “shelf registration statement”);

•  to use our commercially reasonable efforts to cause the shelf registration statement to become effective under the Securities Act within 180 days after the receipt of a request by Eagle Rock Holdings;

•  to continuously maintain the effectiveness of the shelf registration statement under the Securities Act until the common units covered by the shelf registration statement have been sold, transferred or otherwise disposed of:

•  pursuant to the shelf, or any other, registration statement;

•  pursuant to Rule 144 under the Securities Act;

•  to us or any of our subsidiaries; or

•  in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the common units.

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Additionally, in connection with the Laser acquisition and Montierra acquisition and the related private placement of our common units, we agreed to register such units for resale by filing the registration statement to which this prospectus relates within 90 days of closing. We are required to have the registration statement declared effective within 120 days of the closing with penalties being incurred after 165 days.

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and state securities laws the offer and sale of any common units, subordinated units or other partnership securities that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and fees. Except as described below, our general partner and its affiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

MATERIAL TAX CONSEQUENCES

This section is a discussion of the material U.S. federal income tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Thompson & Knight LLP, counsel to our general partner and us, as to all material tax matters and all legal conclusions insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Eagle Rock Energy Partners, L.P. and our operating company.

The following discussion does not comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Thompson & Knight LLP and are, to the extent noted herein, based on the accuracy of the representations made by us.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Thompson & Knight LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

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For the reasons described below, Thompson & Knight LLP has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. For our only previous tax year, 2006, not less than 90% of our gross income was qualifying income. We estimate that not less than 90% of our current gross income is qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Thompson & Knight LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Thompson & Knight LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and our operating company will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Thompson & Knight LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Thompson & Knight LLP has relied are:

(a) Neither we nor our operating companies have elected or will elect to be treated as a corporation; and

(b) For each taxable year of the Partnership beginning with 2006, 90% or more of our gross income has been or will be income that Thompson & Knight LLP will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

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If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Thompson & Knight LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Eagle Rock Energy Partners, L.P. will be treated as partners of Eagle Rock Energy Partners, L.P. for federal income tax purposes. Also:

•  assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and

•  unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units,

will be treated as partners of Eagle Rock Energy Partners, L.P. for federal income tax purposes. As there is no direct or indirect controlling authority addressing assignees of common units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, Thompson & Knight LLP’s opinion does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

A beneficial owner of common units whose units have been loaned to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gains, losses or deductions would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in Eagle Rock Energy Partners, L.P. for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income.  We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions.  Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common

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units, taxable in accordance with the rules described under “— Disposition of Common Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture,and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Basis of Common Units.  A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses.  The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded

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partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions.  The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

•  interest on indebtedness properly allocable to property held for investment;

•  our interest expense attributed to portfolio income; and

•  the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections.  If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction.  In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of property contributed to us by the general partner and its affiliates, referred to in this discussion as “Contributed Property.” The effect of these allocations to a unitholder purchasing common units in our initial offering of common units or their assignees will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of such offering. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in

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the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in such amount and manner as is needed to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect.

In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

•  his relative contributions to us;

•  the interests of all the partners in profits and losses;

•  the interest of all the partners in cash flow; and

•  the rights of all the partners to distributions of capital upon liquidation.

Thompson & Knight LLP is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales.  A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

•  any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

•  any cash distributions received by the unitholder as to those units would be fully taxable; and

•  all of these distributions would appear to be ordinary income.

Thompson & Knight LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax.  Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates.  In general, the highest effective United States federal income tax rate for individuals is currently 35.0% and the maximum United States federal income tax rate for net capital gains of an individual is currently 15.0% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election.  We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal

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Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Where the remedial allocation method is adopted (which we will adopt as to property other than certain goodwill properties), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury RegulationSection 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, the general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with the Treasury Regulations. Please read “— Uniformity of Units.”

Although Thompson & Knight LLP is unable to opine as to the validity of this approach because there is no controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion asnon-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 of the Internal Revenue Code but is arguably inconsistent with TreasuryRegulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets, and TreasuryRegulation 1.197-2(g)(3). To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek

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permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year.  We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization.  The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to our initial offering of common units will be borne by partners who held interests in us prior to such offering or their assignees. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We are not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and fees we have incurred will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties.  The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss.  Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized

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will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash or other property received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than one year will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•  a short sale;

•  an offsetting notional principal contract; or

•  a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

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Allocations Between Transferors and Transferees.  In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury Regulations. Accordingly, Thompson & Knight LLP is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements.  A unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination.  We will be considered to have been terminated for 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. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury RegulationSection 1.167(c)-1(a)(6) and TreasuryRegulation Section 1.197-2(g)(3). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury RegulationSection 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets, and Treasury

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Regulation Section 1.197-2(g)(3). Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on aForm W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Because a foreign unitholder is considered to be engaged in business in the United States by virtue of the ownership of units, under this ruling a foreign unitholder who sells or otherwise disposes of a unit generally will be subject to federal income tax on gain realized on the sale or disposition of units. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned

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less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures.  We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including aSchedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will in all cases yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Thompson & Knight LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting.  Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b) whether the beneficial owner is:

1. a person that is not a United States person;

2. a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

3. a tax-exempt entity;

(c) the amount and description of units held, acquired or transferred for the beneficial owner; and

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(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties.  An additional tax equal to 20% of the amount of any portion of an under payment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(1) for which there is, or was, “substantial authority”; or

(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable Transactions.  If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:

•  accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties,”

•  for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability and

•  in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

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State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We own property or do business in the States of Louisiana, Texas and Oklahoma. Each of these states, other than Texas, currently imposes a personal income tax on individuals. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Thompson & Knight LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

INVESTMENT IN EAGLE ROCK ENERGY PARTNERS, L.P.
BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

•  whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

•  whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

•  whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences — Tax-Exempt Organizations and Other Investors.”

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

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Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by employee benefit plans are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(b) the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

PLAN OF DISTRIBUTION

We are registering the common units on behalf of the selling unitholders as required pursuant to a registration rights agreement between us and the selling unitholders. A selling unitholder reserves the right to accept and, together with their agents, to reject, any proposed purchases of common units to be made directly through agents. As used in this prospectus, “selling unitholders” includes donees and pledgees selling common units received from a named selling unitholder after the date of this prospectus.

Under this prospectus, the selling unitholders intend to offer our securities to the public:

•  through one or more broker-dealers;

•  through underwriters; or

•  directly to investors.

The selling unitholders may price the common units offered from time to time:

•  at fixed prices;

•  at market prices prevailing at the time of any sale under this registration statement;

•  at prices related to prevailing market prices;

•  varying prices determined at the time of sale; or

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•  at negotiated prices.

We will pay the costs and expenses of the registration and offering of the common units offered hereby. We will not pay any underwriting fees, discounts and selling commissions allocable to each selling unitholder’s sale of its respective common units, which will be paid by the selling unitholders. We will not receive any proceeds from the sale of common units offered hereby. Broker-dealers may act as agent or may purchase securities as principal and thereafter resell the securities from time to time:

•  in or through one or more transactions (which may involve crosses and block transactions) or distributions;

•  on the NASDAQ Global Market;

•  through the writing of options;

•  in theover-the-counter market; or

•  in private transactions.

Broker-dealers or underwriters may receive compensation in the form of underwriting discounts or commissions and may receive commissions from purchasers of the securities for whom they may act as agents. If any broker-dealer purchases the securities as principal, it may effect resales of the securities from time to time to or through other broker-dealers, and other broker-dealers may receive compensation in the form of concessions or commissions from the purchasers of securities for whom they may act as agents.

To the extent required, the names of the specific managing underwriter or underwriters, if any, as well as other important information, will be set forth in prospectus supplements. In that event, the discounts and commissions the selling unitholders will allow or pay to the underwriters, if any, and the discounts and commissions the underwriters may allow or pay to dealers or agents, if any, will be set forth in, or may be calculated from, the prospectus supplements. Any underwriters, brokers, dealers and agents who participate in any sale of the securities may also engage in transactions with, or perform services for, us or our affiliates in the ordinary course of their businesses.

In addition, the selling unitholders have advised us that they may sell common units in compliance with Rule 144, if available, or pursuant to other available exemptions from the registration requirements under the Securities Act, rather than pursuant to this prospectus.

To the extent required, this prospectus may be amended or supplemented from time to time to describe a specific plan of distribution.

In connection with offerings under this resale registration and in compliance with applicable law, underwriters, brokers or dealers may engage in transactions which stabilize or maintain the market price of the securities at levels above those which might otherwise prevail in the open market. Specifically, underwriters, brokers or dealers may over-allot in connection with offerings, creating a short position in the securities for their own accounts. For the purpose of covering a syndicate short position or stabilizing the price of the securities, the underwriters, brokers or dealers may place bids for the securities or effect purchases of the securities in the open market. Finally, the underwriters may impose a penalty whereby selling concessions allowed to syndicate members or other brokers or dealers for distribution the securities in offerings may be reclaimed by the syndicate if the syndicate repurchases previously distributed securities in transactions to cover short positions, in stabilization transactions or otherwise. These activities may stabilize, maintain or otherwise affect the market price of the securities, which may be higher than the price that might otherwise prevail in the open market, and, if commenced, may be discontinued at any time.

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Thompson & Knight, LLP, Houston, Texas.

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EXPERTS

The financial statements of ONEOK Texas Field Services, L.P. as of December 31, 2003 and 2004 and November 30, 2005 and the years ended December 31, 2003 and 2004 and for the eleven months ended November 30, 2005 incorporated in this prospectus from the Eagle Rock Energy Partners, L.P. annual report onForm 10-K/A for the year ended December 31, 2006, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report, which is incorporated herein by reference, and have been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The balance sheet of Eagle Rock Energy GP, L.P. as of December 31, 2006, incorporated in this prospectus from the Eagle Rock Energy Partners, L.P. current report onForm 8-K filed on July 18, 2007, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report, which is incorporated herein, and have been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The consolidated financial statements of Eagle Rock Energy Partners, L.P. as of December 31, 2006 and 2005 and for each of the three years in the period ended December 31, 2006 incorporated in this prospectus from the Partnership’sForm 10-K/A for the year ended December 31, 2006, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report, which is incorporated herein by reference, and have been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

INDEPENDENT ENGINEERS

The information included in this prospectus or incorporated by reference into this prospectus regarding estimated quantities of proved reserves and their present value is based, in part, on estimates of the proved reserves and present values of proved reserves as of December 31, 2006 based on a reserve report as of December 31, 2006 prepared on July 21, 2007 by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. These estimates are included in this prospectus in reliance upon the authority of the firm as experts in these matters.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC, under the Securities Act of 1933, as amended (the “Securities Act”), a registration statement onForm S-1(No. 333-140370) with respect to the common units offered by this prospectus. This prospectus, which constitutes part of the registration statement, does not contain all the information set forth in the registration statement or the exhibits and schedules which are part of the registration statement, portions of which are omitted as permitted by the rules and regulations of the SEC. Statements made in this prospectus regarding the contents of any contract or other documents are summaries of the material terms of the contract or document. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this document. Our business, financial condition, results of operations and prospects may have changed since that date. Any information we have incorporated by reference is accurate only as of the date of the document incorporated by reference. With respect to each contract or document filed as an exhibit to the registration statement, reference is made to the corresponding exhibit. For further information pertaining to us and to the common units offered by this prospectus, reference is made to the registration statement, including the exhibits and schedules thereto, copies of which may be inspected without charge at the public reference facilities of the SEC at 100 F Street, N.E., Washington, D.C. 20549. Copies of all or any portion of the registration statement may be obtained from the SEC at prescribed rates. Information on the public reference facilities may be obtained by calling the SEC at1-800-SEC-0330. In addition, the SEC maintains a web site that contains reports, proxy and information statements and other information that is filed electronically with the SEC. The web site can be accessed atwww.sec.gov.

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We are required to comply with the informational requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and, accordingly, we file current reports onForm 8-K, quarterly reports onForm 10-Q, annual reports onForm 10-K, proxy statements and other information with the SEC. Those reports, proxy statements and other information will be available for inspection and copying at the public reference facilities and internet site of the SEC referred to above.

We have elected to “incorporate by reference” certain information into this prospectus, which means we can disclose important information to you by referring you to another document filed with the SEC. The information incorporated by reference is deemed to be part of this prospectus. Please read “Incorporation by Reference.” You should only rely on the information contained in this prospectus and incorporated by reference in it. We have not authorized anyone to provide you with any additional information.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements, other than statements of historical fact, included in this prospectus, are forward-looking statements. In some cases, you can identify a forward-looking statement by terminology such as “may”, “could”, “should”, “expect”, “plan”, “project”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “pursue”, “target” or “continue”, the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed or incorporated by reference in the “Risk Factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf.

We are incorporating by reference into this prospectus the following documents filed with the SEC (excluding any portions of such documents that have been “furnished” but not “filed” for purposes of the Exchange Act, such as under Items 2.02 or 7.01 on current reports onForm 8-K):

•  Our Annual Report onForm 10-K for the fiscal year ended December 31, 2006, filed with the SEC on April 2, 2007;

•  Our amended Annual Report onForm 10-K/A for the fiscal year ended December 31, 2006, filed with the SEC on July 26, 2007.

•  Our quarterly report onForm 10-Q for the quarter ended March 31, 2007, filed with the SEC on May 15, 2007; and

•  Our current reports onForms 8-K, filed with the SEC on January 12, 2007, January 29, 2007, February 14, 2007, April 4, 2007, May 4, 2007, May 18, 2007, May 22, 2007, July 17, 2007 and July 18, 2007.

Any statement contained in this prospectus or a document incorporated by reference in this prospectus will be deemed to be modified or superseded for purposes of this prospectus to the extent that a statement contained in this prospectus or in any other subsequently filed document that is incorporated by reference in this prospectus modifies or supersedes the statement. Any statement so modified or superseded will not be deemed, except as so modified or superseded, to constitute a part of this prospectus.

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The documents incorporated by reference in this prospectus are available from us upon request. We will provide a copy of any and all of the information that is incorporated by reference in this prospectus to any person, without charge, upon written or oral request. Requests for such copies should be directed to the following:

Eagle Rock Energy Partners, L.P.
16701 Greenspoint Park Drive, Suite 200
Houston, Texas 77060
Telephone Number:(281) 408-1200
Attention: Chief Financial Officer

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APPENDIX A

GLOSSARY OF TERMS

adjusted operating surplus:  For any period, operating surplus generated during that period is adjusted to:

(a) increase operating surplus by any net decreases made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period;

(b) decrease operating surplus by any net decrease in cash reserves for operating expenditures during that period not relating to an operating expenditure made during that period; and

(c) increase operating surplus by any net increase in cash reserves for operating expenditures during that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus does not include the portion of operating surplus described in subpart (a)(2) of the definition of “operating surplus” in this Appendix B.

available cash:  For any quarter ending prior to liquidation:

(a) the sum of:

(1) all cash and cash equivalents of Eagle Rock Energy Partners, L.P. and its subsidiaries on hand at the end of that quarter; and

(2) if our general partner so determines all or a portion of any additional cash or cash equivalents of Eagle Rock Energy Partners, L.P. and its subsidiaries on hand on the date of determination of available cash for that quarter;

(b) less the amount of cash reserves established by our general partner to:

(1) provide for the proper conduct of the business of Eagle Rock Energy Partners, L.P. and its subsidiaries (including reserves for future capital expenditures and for future credit needs of Eagle Rock Energy Partners, L.P. and its subsidiaries) after that quarter;

(2) comply with applicable law or any debt instrument or other agreement or obligation to which Eagle Rock Energy Partners, L.P. or any of its subsidiaries is a party or its assets are subject; and

(3) provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;

provided, however,that our general partner may not establish cash reserves pursuant to clause (b)(3) immediately above unless our general partner has determined that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for that quarter; andprovided, further,that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if our general partner so determines.

Bbls:  Barrels.

Bbls/d:  Barrels per day.

Btu:  British thermal unit.

capital account:  The capital account maintained for a partner under the partnership agreement. The capital account of a partner for a common unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that common unit, subordinated

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unit, incentive distribution right or other partnership interest were the only interest in Eagle Rock Energy Partners, L.P. held by a partner.

capital surplus:  All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of the initial public offering equals the operating surplus from the closing of the initial public offering through the end of the quarter immediately preceding that distribution. Any excess available cash distributed by us on that date will be deemed to be capital surplus.

closing price:  The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way, in either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in theover-the-counter market, as reported by the Nasdaq Global Market or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by the our board of directors. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by our board of directors.

condensate:  Similar to crude oil and produced in association with natural gas gathering and processing.

cumulative common unit arrearage:  The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.

current market price:  For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

interim capital transactions:  The following transactions if they occur prior to liquidation:

(a) borrowings, refinancings or refundings of indebtedness and sales of debt securities (other than for items purchased on open account in the ordinary course of business) by Eagle Rock Energy Partners, L.P. or any of its subsidiaries;

(b) sales of equity interests by Eagle Rock Energy Partners, L.P. or any of its subsidiaries;

(c) sales or other voluntary or involuntary dispositions of any assets of Eagle Rock Energy Partners, L.P. or any of its subsidiaries (other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements);

(d) the termination of interest rate swap agreements;

(e) capital contributions; and

(f) corporate reorganizations or restructurings.

gal:  Gallon.

gpm:  Gallon per one thousand cubic feet of gas.

MMBbls:  One million barrels.

MMBtu:  One million British thermal units.

MMcf:  One million cubic feet of natural gas.

MBbls/d:  One thousand barrels per day.

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MMBtu/d:  One million British Thermal Units per day.

MMcf/d:  One million cubic feet per day.

NGLs:  Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane and natural gasoline.

operating expenditures:  All of our expenditures and expenditures of our subsidiaries, including, but not limited to, taxes, reimbursements of our general partner, non-pro rata repurchase of units, interest payments and maintenance capital expenditures, subject to the following:

(a) Payments (including prepayments) of principal of and premium on indebtedness (other than working capital borrowings) will not constitute operating expenditures.

(b) Operating expenditures will not include:

(1) expansion capital expenditures;

(2) payment of transaction expenses relating to interim capital transactions; or

(3) distributions to unitholders.

Where capital expenditures consist of both maintenance capital expenditures and expansion capital expenditures, the general partner, with the concurrence of the conflicts committee, shall determine the allocation between the amounts paid for each.

operating surplus:  For any period prior to liquidation, on a cumulative basis and without duplication:

(a) the sum of:

(1) all cash receipts of Eagle Rock Energy Partners, L.P. and our subsidiaries for the period beginning on the closing date of our initial public offering and ending with the last day of that period, other than cash receipts from interim capital transactions; and

(2) an amount equal to four times the amount needed for any one quarter for us to pay a distribution on all units (including general partner units) and incentive distribution rights at the sameper-unit amount as was distributed in the immediately preceding quarter (or with respect to the period commencing on the closing of this offering and ending on December 31, 2006, it means the product of (a)(i) $1.45 multiplied by (ii) a fraction of which the numerator is the number of days in such period and the denominator is 92 multiplied by (b) the number of common units, subordinated units and general partner units outstanding on the record date with respect to such period, and with respect to the quarter ending March 31, 2007, it means the product of (a) $1.45 and (b) the number of common units, subordinated units and general partner units outstanding on the record date with respect to such quarter); less

(b) the sum of:

(1) operating expenditures for the period beginning on the closing date of our initial public offering and ending with the last day of that period; and

(2) the amount of cash reserves that is established by our general partner to provide funds for future operating expenditures.

Any increase in operating surplus pursuant to (a)(2) under the caption “operating surplus” above in respect of an increase in the quarterly distribution rate per unit, an increase in the number of units outstanding or other action with respect to outstanding units shall only be effective from and after the quarter in which such increase or other action occurs, and shall not be effective retroactively. In addition, the maximum amount included in operating surplus pursuant to (a)(2) during the term of the partnership shall not exceed four times the amount needed for any one quarter to pay a distribution on all of our units (including general partner units) and the incentive distribution rights at the highest distribution rate per unit (as adjusted for any split or combination of units) paid on outstanding units as of the date such determination is made.

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residue gas:  The pipeline quality natural gas remaining after natural gas is processed.

subordination period:  The subordination period will extend from the closing of the initial public offering until the first to occur of the following dates:

(a) The first day of any quarter beginning after September 30, 2009 in respect of which each of the following tests are met:

(1) distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

(2) the adjusted operating surplus generated during each of the three consecutive, non-overlapping four quarter periods, immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the common units and subordinated units that were outstanding during those periods on a fully diluted basis; and

(3) there are no outstanding cumulative common units arrearages.

(b) The first day after we have earned and paid at least $0.5438 per quarter (150% of the minimum quarterly distribution of $0.3625 per quarter, which is $2.175 on an annualized basis) on each outstanding limited partner unit and general partner unit for any four consecutive quarters ending on or after September 30, 2007; and

(c) the date on which the general partner is removed as our general partner upon the requisite vote by the limited partners under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of the removal.

When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.

Tcfe:  One trillion cubic feet of gas equivalent.

throughput:  The volume of natural gas or NGLs transported or passing through a pipeline, plant, terminal or other facility in an economically meaningful period of time.

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PART II

INFORMATION REQUIRED IN THE REGISTRATION STATEMENT

Item 13.   Other Expenses of Issuance and Distribution.

Set forth below are the expenses expected to be incurred in connection with the registration of the securities registered offered hereby. With the exception of the Securities and Exchange Commission registration fee and the NASDAQ additional listing fee, the amounts set forth below are estimates.

SEC registration fee	$	—
Printing and engraving expenses		5,000
NASDAQ Additional Listing Fee		5,000
Fees and expenses of legal counsel		50,000
Accounting fees and expenses		50,000
Transfer agent and registrar fees		5,000
Miscellaneous		5,000
Total	$	120,000

Item 14.   Indemnification of Officers and Members of Our Board of Directors.

The section of the prospectus entitled “The Partnership Agreement — Indemnification” discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to Section 10 of the Underwriting Agreement to be filed as an exhibit to this registration statement in which we and our general partner will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the partnership agreement,Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.

Item 15.   Recent Sales of Unregistered Securities.

On May 3, 2007, Eagle Rock completed the sale of 7,005,495 common units (the “Offering”) to several institutional purchasers in a private offering exempt from registration pursuant to Section 4(2) and Regulation D (Rule 506) under the Securities Act of 1933, as amended (the “Securities Act”). The units were purchased at a price of $18.20 per unit resulting in gross proceeds of $127.5 million. The proceeds from the Offering were used to fully fund the cash portion of the purchase price of the Laser Acquisition and other general company purposes.

On May 3, 2007, Eagle Rock completed the acquisition of all of the non-corporate interests of Laser Midstream Energy, LP, including its subsidiaries Laser Quitman Gathering Company, LP, Laser Gathering Company, LP, Hesco Gathering Company, LLC, and Hesco Pipeline Company, LLC (the “Laser Acquisition”) for a total purchase price of $136.8 million, consisting of $110.0 million in cash and 1,407,895 of Eagle Rock common units, subject to customary post-closing adjustments.

On April 30, 2007, Eagle Rock Energy Partners, L.P., a Delaware limited partnership (“Eagle Rock,” or “Contributee”) completed the acquisition of certain fee minerals, royalties and working interest properties from Montierra Minerals & Production, L.P., a Delaware limited partnership (“Montierra”), and NGP-VII Income Co-Investment Opportunities, L.P., a Texas limited partnership (“Co-Invest”) for an aggregate purchase price of $127.4 million (the “Montierra Acquisition”). Moniterra and NGP received as consideration a total of 6,390,400 Eagle Rock common units and $6.0 million in cash.

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On May 25, 2006, in connection with the formation of Eagle Rock Energy Partners, L.P. (the “Partnership”), the Partnership issued to (i) its general partner the 2% general partner interest in the Partnership for $20 and (ii) Eagle Rock Holdings, L.P. the 98% limited partner interest in the Partnership for $980. The issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

In March 2006, certain private investors contributed $98.3 million to Eagle Rock Pipeline, L.P., which became our operating partnership, in exchange for 5,455,050 common units in Eagle Rock Pipeline, L.P. In June 2006, we purchased all of the partnership interests in Midstream Gas Services, L.P. for approximately $4.7 million in cash and 1,125,416 common units in Eagle Rock Pipeline, L.P. In addition, if Midstream Gas Services, L.P. achieves certain financial objectives for the year ending December 31, 2007, we will issue up to 798,155 of our common units as a contingent earn-out payment to Natural Gas Partners VII, L.P., as the primary equity owner of Midstream Gas Services. Upon completion of our initial public offering, the 6,580,466 common units in Eagle Rock Pipeline, L.P. were converted into common units in Eagle Rock Energy Partners, L.P. on approximately a1-for-0.719 common unit basis. All of these interests in Eagle Rock Pipeline were converted into common units in us upon consummation of our initial public offering.

Laser, Montierra, MacLondon and PIPE transactions

Item 16.   Exhibits.

The following documents are filed as exhibits to this registration statement:

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.
	2	.2*	Partnership Interests Contribution Agreement By and Among Montierra Minerals and Production, L.P., NGP Minerals, L.L.C. and Eagle Rock Energy Partners, L.P., dated as of March 31, 2007
	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., dated as of March 31, 2007
	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 Herein, dated July 11, 2007
	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 Herein, dated July 11, 2007
	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
	2	.7**	Purchase, Sale and Contribution Agreement Between AmGu Holdings LLC, as seller and Eagle Rock Energy Partners, L.P., as purchaser, dated July 11, 2007
	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 onForm S-1 (FileNo. 333-134750))
	3	.2	Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.2 of the registrant’s registration statement onForm S-1(File No. 333-134750))
	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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 333-134750))
	3	.6	Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.6 of the registrant’s registration statement onForm S-1(File No. 333-134750))

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Exhibit
Number			Description
	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 onForm S-1 (FileNo. 333-134750))
	4	.2	Tag Along Agreement dated March 27, 2006, among Eagle Rock Pipeline, L.P., Eagle Rock Pipeline GP, LLC, Eagle Rock Holdings, L.P. and the Purchasers listed thereto. (incorporated by reference to Exhibit 4.2 of the registrant’s registration statement onForm S-1 (FileNo. 333-134750))
	4	.3	Form of Registration Rights Agreement between Eagle Rock Energy Partners, L.P. and Eagle Rock Holdings, L.P. (incorporated by reference to Exhibit 4.3 of the registrant’s registration statement onForm S-1 (FileNo. 333-134750))
	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 onForm S-1 (FileNo. 333-134750))
	4	.5*	Registration Rights Agreement dated May 2, 2007, among Eagle Rock Energy Partners, L.P. and the purchasers listed thereto.
	5	.1*	Opinion of Thompson & Knight LLP as to the legality of the securities being registered.
	8	.1**	Opinion of Thompson & Knight LLP relating to tax matters.
	10	.1	Amended and Restated Credit and Guaranty Agreement (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement onForm S-1 (FileNo. 333-134750))
	10	.2	Form of Omnibus Agreement (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement onForm S-1 (FileNo. 333-134750))
	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 onForm S-1 (FileNo. 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, LP. (incorporated by reference to Exhibit 10.4 of the registrant’s registration statement onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 333-134750))
	10	.11	Form of Contribution, Conveyance and Assumption Agreement (incorporated by reference to Exhibit 10.11 of the registrant’s registration statement onForm S-1 (FileNo. 333-134750))
	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 onForm S-1 (FileNo. 333-134750))

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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 onForm S-1 (FileNo. 333-134750))
	10	.14*	Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The Purchasers Named Herein, dated March 30, 2007.
	10	.15**	Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The Purchasers Named Herein, dated July 11, 2007
	21	.1*	List of Subsidiaries of Eagle Rock Energy Partners, L.P.
	23	.1*	Consent of Deloitte & Touche LLP
	23	.2*	Consent of Deloitte & Touche LLP
	23	.3*	Consent of Deloitte & Touche LLP
	23	.4**	Consent of Thompson & Knight LLP (contained in Exhibit 5.1)
	23	.5*	Consent of Cawley, Gillespie & Associates
	24	.1	Powers of Attorney (contained on the signature page)

†	Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
*	Filed herewith.
**	To be filed by amendment.

Item 17.   Undertakings.

The undersigned registrant hereby undertakes:

(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) To include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement.

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

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(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on July 27, 2007.

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:  Chairman and Chief Executive Officer

POWERS OF ATTORNEY

Each person whose signature appears below appoints Joseph A. Mills and Alfredo Garcia, and each of them, any of whom may act without the joinder of the other, as his true and lawfulattorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto saidattorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that saidattorneys-in-fact and agents or any of them of their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

Signature	Title	Date
/s/  Joseph A. Mills Joseph A. Mills	Chairman and Chief Executive Officer (Principal Executive Officer)	July 27, 2007
/s/  Alfredo Garcia Alfredo Garcia	Senior Vice President, Corporate Development and Acting Chief Financial Officer (Principal Accounting Officer)	July 27, 2007
/s/  Kenneth A. Hersh Kenneth A. Hersh	Director	July 27, 2007
/s/  William J. Quinn William J. Quinn	Director	July 27, 2007
/s/  John A. Weinzierl John A. Weinzierl	Director	July 27, 2007

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Signature		Title	Date
/s/  Philip B. Smith Philip B. Smith		Director	July 27, 2007
/s/  William K. White William K. White		Director	July 27, 2007
*	/s/  Alfredo Garcia Attorney-in-Fact

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EXHIBIT INDEX

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.
	2	.2*	Partnership Interests Contribution Agreement By and Among Montierra Minerals and Production, L.P., NGP Minerals, L.L.C. and Eagle Rock Energy Partners, L.P., dated as of March 31, 2007
	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., dated as of March 31, 2007
	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 Herein, dated July 11, 2007
	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 Herein, dated July 11, 2007
	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
	2	.7**	Purchase, Sale and Contribution Agreement Between AmGu Holdings LLC, as seller and Eagle Rock Energy Partners, L.P., as purchaser, dated July 11, 2007
	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 onForm S-1 (FileNo. 333-134750))
	3	.2	Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.2 of the registrant’s registration statement onForm S-1(File No. 333-134750))
	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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 333-134750))
	3	.6	Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.6 of the registrant’s registration statement onForm S-1(File No. 333-134750))
	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 onForm S-1 (FileNo. 333-134750))
	4	.2	Tag Along Agreement dated March 27, 2006, among Eagle Rock Pipeline, L.P., Eagle Rock Pipeline GP, LLC, Eagle Rock Holdings, L.P. and the Purchasers listed thereto. (incorporated by reference to Exhibit 4.2 of the registrant’s registration statement onForm S-1 (FileNo. 333-134750))
	4	.3	Form of Registration Rights Agreement between Eagle Rock Energy Partners, L.P. and Eagle Rock Holdings, L.P. (incorporated by reference to Exhibit 4.3 of the registrant’s registration statement onForm S-1 (FileNo. 333-134750))
	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 onForm S-1 (FileNo. 333-134750))
	4	.5*	Registration Rights Agreement dated May 2, 2007, among Eagle Rock Energy Partners, L.P. and the purchasers listed thereto.
	5	.1*	Opinion of Thompson & Knight LLP as to the legality of the securities being registered.
	8	.1**	Opinion of Thompson & Knight LLP relating to tax matters.
	10	.1	Amended and Restated Credit and Guaranty Agreement (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement onForm S-1 (FileNo. 333-134750))

Exhibit
Number			Description
	10	.2	Form of Omnibus Agreement (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement onForm S-1 (FileNo. 333-134750))
	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 onForm S-1 (FileNo. 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, LP. (incorporated by reference to Exhibit 10.4 of the registrant’s registration statement onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 333-134750))
	10	.11	Form of Contribution, Conveyance and Assumption Agreement (incorporated by reference to Exhibit 10.11 of the registrant’s registration statement onForm S-1 (FileNo. 333-134750))
	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 onForm S-1 (FileNo. 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 onForm S-1 (FileNo. 333-134750))
	10	.14*	Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The Purchasers Named Herein, dated March 30, 2007.
	10	.15**	Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The Purchasers Named Herein, dated July 11, 2007
	21	.1*	List of Subsidiaries of Eagle Rock Energy Partners, L.P.
	23	.1*	Consent of Deloitte & Touche LLP
	23	.2*	Consent of Deloitte & Touche LLP
	23	.3*	Consent of Deloitte & Touche LLP
	23	.4**	Consent of Thompson & Knight LLP (contained in Exhibit 5.1)
	23	.5*	Consent of Cawley, Gillespie & Associates
	24	.1	Powers of Attorney (contained on the signature page)

†	Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
*	Filed herewith.
**	To be filed by amendment.