Eagle Rock Energy Partners L P S1/A IPO registration (amended)

As filed with the Securities and Exchange Commission on September 12, 2006

Registration No. 333-134750

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 3

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	68-0629883
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

14950 Heathrow Forest Parkway, Suite 111

Houston, Texas 77032

(832) 327-8000

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

Alfredo Garcia

14950 Heathrow Forest Parkway, Suite 111

Houston, Texas 77032

(832) 327-8000

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

Copies to:


Thomas P. Mason Douglas E. McWilliams Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2300 Houston, Texas 77002 (713) 758-2222		G. Michael O’Leary Andrews Kurth LLP 600 Travis Street, Suite 4200 Houston, Texas 77002 (713) 220-4200

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

If any of the 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, check the following box. o

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

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 of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary 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 preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION DATED SEPTEMBER 12, 2006

PROSPECTUS

12,500,000 Common Units

Representing Limited Partner Interests

This is the initial public offering of our common units. We currently estimate that the initial public offering price will be between $19.00 and $21.00 per common unit. Prior to this offering, there has been no public market for the common units. We have applied to list our common units on the Nasdaq Global Market under the symbol “EROC.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 23.

These risks include the following:


	•	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.


	•	On a pro forma basis, we would not have generated available cash sufficient for us to pay the full minimum quarterly distribution on all of our common units and subordinated units for the year ended December 31, 2005 and the twelve months ended June 30, 2006. In addition, our operating subsidiary did not generate available cash sufficient for it to pay the full minimum quarterly distribution for the three months ended June 30, 2006 on all of its outstanding equity interests.


	•	Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of supplies of natural gas and natural gas liquids, which are dependent on certain factors beyond our control. Any decrease in supplies of natural gas or natural gas liquids could adversely affect our business and operating results.

	•	Natural gas, natural gas liquids and other commodity prices are volatile, and a reduction in these prices could adversely affect our cash flow and our ability to make distributions to you.

	•	We depend on certain natural gas producer customers for a significant portion of our supply of natural gas and natural gas liquids. The loss of any of these customers could result in a decline in our volumes, revenues and cash available for distribution.


	•	Eagle Rock Holdings, L.P., a partnership formed by Natural Gas Partners and certain co-investors, including certain of our directors and management, will own a 57.2% 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 to your detriment.


	•	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 to you.

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

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

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


	•	You will experience immediate and substantial dilution of $16.16 in tangible net book value per common unit.


	•	You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.


	Per Common Unit	Total

Initial public offering price	$	$
Underwriting discount	$	$
Proceeds, before expenses, to Eagle Rock Energy Partners, L.P.	$	$

We have granted the underwriters a30-day option to purchase up to an additional 1,875,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 12,500,000 common units in this offering.

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 underwriters expect to deliver the common units on or about , 2006.


UBS Investment Bank	Lehman Brothers	Goldman, Sachs & Co.


A.G. Edwards	Wachovia Securities

Credit Suisse


	Raymond James


	RBC Capital Markets

, 2006

TABLE OF CONTENTS


SUMMARY		1
	Business Strategies	2
	Competitive Strengths	3
	Summary of Risk Factors	4
	Formation Transactions and Partnership Structure	8
	General	8
	Management of Eagle Rock Energy Partners	11
	Principal Executive Offices and Internet Address	11
	Our General Partner’s Rights to Receive Distributions	11
	Summary of Conflicts of Interest and Fiduciary Duties	12
	The Offering	14
	Summary Historical and Pro Forma Financial Data	18
	Non-GAAP Financial Measures	21
RISK FACTORS		23
	Risks Related to Our Business	23
	Risks Inherent in an Investment in Us	33
	Tax Risks to Common Unitholders	40
USE OF PROCEEDS		43
CAPITALIZATION		44
DILUTION		45
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		47
	General	47
	Our Initial Distribution Rate	48
	Unaudited Pro Forma Available Cash for Year Ended December 31, 2005	51
	Financial Forecast for the Twelve Months Ending September 30, 2007	54
EAGLE ROCK ENERGY PARTNERS, L.P. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND FORECAST ASSUMPTIONS		59
	Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2007	66
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS		68
	Distributions of Available Cash	68
	Operating Surplus and Capital Surplus	69
	Subordination Period	70
	Distributions of Available Cash from Operating Surplus during the Subordination Period	71
	Distributions of Available Cash from Operating Surplus after the Subordination Period	72
	General Partner Interest and Incentive Distribution Rights	72
	Percentage Allocations of Available Cash from Operating Surplus	73
	Distributions from Capital Surplus	73
	Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels	74
	Distributions of Cash Upon Liquidation	75
SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA		77
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		80
	Overview	80
	Our Operations	80
	How We Evaluate Our Operations	82
	General Trends and Outlook	82


	Formation, Acquisitions and Asset Dispositions	83
	Financial Statement Presentation and Comparability of Financial Results	86
	Critical Accounting Policies and Estimates	88
	Eagle Rock Predecessor Results of Operations	90
	Eagle Rock Pipeline Results of Operations	93
	Other Matters	95
	Liquidity and Capital Resources	96
	Capital Requirements	100
	Recent Accounting Pronouncements	103
	Quantitative and Qualitative Disclosures About Market Risk	104
BUSINESS		110
	Our Partnership	110
	Business Strategies	111
	Competitive Strengths	112
	Industry Overview	113
	Our Assets	115
	Texas Panhandle Operations	115
	Southeast Texas and Louisiana Operations	120
	Safety and Maintenance Regulation	122
	Regulation of Operations	122
	Environmental Matters	124
	Title to Properties and Rights-of-Way	126
	Employees	126
	Legal Proceedings	126
MANAGEMENT		127
	Management of Eagle Rock Energy Partners, L.P.	127
	Directors and Executive Officers	128
	Reimbursement of Expenses of Our General Partner	130
	Executive Compensation	130
	Compensation of Directors	131
	Long-Term Incentive Plan	131
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		134
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		135
	Distributions and Payments to Our General Partner and its Affiliates	135
	Agreements Governing the Transactions	136
	Omnibus Agreement	137
	Agreements with Affiliates	138
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		140
	Conflicts of Interest	140
	Fiduciary Duties	144
DESCRIPTION OF THE COMMON UNITS		147
	The Units	147
	Transfer Agent and Registrar	147
	Transfer of Common Units	147
THE PARTNERSHIP AGREEMENT		149
	Organization and Duration	149
	Purpose	149
	Power of Attorney	149
	Cash Distributions	149


	Capital Contributions	149
	Voting Rights	150
	Limited Liability	151
	Issuance of Additional Securities	152
	Amendment of the Partnership Agreement	152
	Merger, Consolidation, Conversion, Sale or Other Disposition of Assets	154
	Termination and Dissolution	155
	Liquidation and Distribution of Proceeds	155
	Withdrawal or Removal of the General Partner	156
	Transfer of General Partner Units	157
	Transfer of Ownership Interests in the General Partner	157
	Transfer of Incentive Distribution Rights	157
	Change of Management Provisions	158
	Limited Call Right	158
	Meetings; Voting	158
	Status as Limited Partner	159
	Non-Citizen Assignees; Redemption	159
	Indemnification	160
	Reimbursement of Expenses	160
	Books and Reports	160
	Right to Inspect Our Books and Records	161
	Registration Rights	161
UNITS ELIGIBLE FOR FUTURE SALE		162
MATERIAL TAX CONSEQUENCES		164
	Partnership Status	164
	Limited Partner Status	165
	Tax Consequences of Unit Ownership	166
	Tax Treatment of Operations	171
	Disposition of Common Units	172
	Uniformity of Units	173
	Tax-Exempt Organizations and Other Investors	174
	Administrative Matters	175
	State, Local, Foreign and Other Tax Considerations	177
INVESTMENT IN EAGLE ROCK ENERGY PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS		178
UNDERWRITING		179
	Option to Purchase Additional Common Units	179
	Commissions and Discounts	180
	No Sales of Similar Securities	180
	Indemnification	180
	Directed Unit Program	181
	Nasdaq Global Market	181
	Price Stabilization, Short Positions	181
	Determination of Offering Price	182
	Electronic Distribution	182
	Discretionary Sales	182
	Stamp Taxes	183
	Affiliations	183
	NASD Conduct Rules	183

iii


VALIDITY OF THE COMMON UNITS			183
EXPERTS			183
WHERE YOU CAN FIND MORE INFORMATION			184
FORWARD-LOOKING STATEMENTS			184
INDEX TO FINANCIAL STATEMENTS			F-1
APPENDIX A — FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF EAGLE ROCK ENERGY PARTNERS, L.P.			A-1
APPENDIX B — GLOSSARY OF TERMS			B-1
Form of Underwriting Agreement
Amended and Restated Limited Liability Company Agreement
Opinion of Vinson & Elkins L.L.P.
Amended and Restated Credit and Guaranty Agreement
Form of Omnibus Agreement
Form of Contribution, Conveyance and Assumption Agreement
Employment Agreement
Consent of Deloitte & Touche LLP
Consent of Director Nominee
Consent of Director Nominee

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

Until , 2006 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary may not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements. The information presented in this prospectus assumes (1) an initial public offering price of $20.00 per common unit and (2) unless otherwise indicated, that the underwriters’ option to purchase additional units is not exercised. You should read “Risk Factors” beginning on page 23 for more information about important risks that you should consider carefully before buying our common units. We include a glossary of some of the terms used in this prospectus as Appendix B.

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 members of our management team.

Eagle Rock Energy Partners, L.P.

We are a growth-oriented Delaware limited partnership engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas and fractionating and transporting natural gas liquids, or NGLs. Our assets are strategically located in three significant natural gas producing regions in the Texas Panhandle, southeast Texas and Louisiana. We intend to acquire and construct additional assets and we have an experienced management team dedicated to growing and maximizing the profitability of our assets.

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 769 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with 33,726 horsepower of associated pipeline compression;

	•	two active natural gas processing plants with an aggregate capacity of 65 MMcf/d; and

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

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 2,556 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with 81,178 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.

Our southeast Texas and Louisiana operations are primarily located in Polk, Tyler, Jasper and Newton Counties, Texas and Vernon Parish, Louisiana. The facilities that comprise our southeast Texas and Louisiana operations consist of:


	•	approximately 850 miles of natural gas gathering pipelines, ranging from four inches to 12 inches in diameter, with 5,200 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; and

	•	a19-mile NGL pipeline.

We commenced operations in 2002 when certain 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, including its equity investment of approximately $191 million to help facilitate our acquisition of the Texas Panhandle Systems and other assets.

Business Strategies

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


	•	Maximizing the profitability of our existing assets. We intend to maximize the profitability of our existing assets by adding new volumes of natural gas and undertaking additional initiatives to enhance utilization and improve operating efficiencies. For example, we recently constructed a10-mile pipeline that connects our East and West Panhandle Systems. This allows us to flow gas from our East Panhandle System, which is capacity- constrained due to high levels of natural gas production, to our West Panhandle System, which currently has excess processing capacity. In addition, we plan to:


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

	•	improve the operations of our existing assets by relocating idle processing plants to areas experiencing increased processing demand, reconfiguring compression facilities, improving processing plant efficiencies and capturing lost and unaccounted for natural gas.


	•	Expanding our operations through organic growth projects. We intend to leverage our existing infrastructure and customer relationships by expanding our existing asset base to meet new or increased demand for midstream services. For example, we recently completed the construction of our Tyler County pipeline and subsequently commenced construction on a16-mile extension that will allow for the delivery of dedicated natural gas volumes to our Brookeland processing plant.

	•	Pursuing complementary acquisitions. We have grown significantly through acquisitions and will continue to employ a disciplined acquisition strategy that capitalizes on the operational experience of our management team. We believe that the extensive experience of our management team in acquiring and operating natural gas gathering and processing assets will enable us to continue to


		successfully identify and complete acquisitions that will enhance our profitability and increase our operating capacity. In pursuing this strategy, our management team seeks to identify:


	•	assets that are complementary to our existing facilities and provide opportunities for us to extract operational efficiencies and the potential to expand or increase the utilization of the acquired assets as well as our existing facilities;

	•	acquisitions in areas in which we do not currently operate that have significant natural gas reserves and are experiencing high levels of drilling activity; and

	•	acquisitions of mature assets with excess capacity that will allow us to capitalize on existing infrastructure, personnel and producer and customer relationships to provide an integrated package of services.



	•	Continuing to reduce our exposure to commodity price risk. We intend to continue to operate our business in a manner that reduces our exposure to commodity price risk. For example, we instituted a hedging program related to our NGL business and have hedged substantially all of our share of expected NGL volumes through 2007 through the purchase of NGL put contracts, costless collar contracts and swap contracts, and substantially all of our share of expected NGL volumes related to our percentage-of-proceeds contracts from 2008 through 2010 through a combination of direct NGL hedging as well as indirect hedging through crude oil costless collars. We have also hedged substantially all of our share of our short natural gas position associated with our keep-whole volumes for 2006 and 2007. We anticipate that after 2007, our short natural gas position will become a long natural gas position because of our increased volumes in the Texas Panhandle and the volumes contributed from our acquisition of the Brookeland and Masters Creek systems. In addition, where market conditions permit, we intend to pursue fee-based arrangements and to increase retained percentages of natural gas and NGLs underpercent-of-proceeds arrangements.


	•	Maintaining a disciplined financial policy. We will continue to pursue a disciplined financial policy by maintaining a prudent capital structure, managing our exposure to interest rate and commodity price risk and conservatively managing our cash reserves. We are committed to maintaining a balanced capital structure, which will allow us to use our available capital to selectively pursue accretive investment opportunities.

Competitive Strengths

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


	•	Our assets are strategically located in major natural gas supply areas. Our assets are strategically located in the Texas Panhandle, southeast Texas and Louisiana. Our Texas Panhandle Systems are located in areas that produce natural gas with high NGL content, especially in the West Panhandle System. Our East Panhandle System is experiencing significant drilling activity related to the Granite Wash play and our West Panhandle System is connected to wells that generally have long lives with predictable, steady flow rates and minimal decline. Additionally, our southeast Texas and Louisiana assets, specifically in Tyler and Polk Counties, are located in areas characterized by high volumes of natural gas and significant drilling activity, which provides us with attractive opportunities to access newly developed natural gas supplies. We believe that our extensive existing presence in these regions, together with our available capacity and the limited alternatives available to local producers, provide us with a competitive advantage in capturing new supplies of natural gas.

	•	We provide a distinct and integrated package of midstream services. We provide a broad range of midstream services to natural gas producers, including gathering, compressing, treating, processing, transporting and selling natural gas and fractionating and transporting NGLs. For example, in the Texas Panhandle, we treat natural gas to extract impurities such as carbon dioxide and hydrogen sulfide and we fractionate NGLs to extract propane. Our competitors in this area do not provide these services. Additionally, many of our gathering systems, including our Texas Panhandle


		Systems, operate at lower inlet pressures, which allows us to provide gathering services to customers at a lower cost and on a more timely basis than our competitors, who are often required to add compression to provide gathering services to new wells.


	•	We have the financial flexibility to pursue growth opportunities. We currently have a $500 million amended and restated credit facility, under which we have approximately $89 million in available borrowing capacity for general partnership purposes, including capital expenditures and acquisitions. We believe the available capacity under this credit facility, combined with our expected ability to access the capital markets, will provide us with a flexible financial structure that will facilitate our strategic expansion and acquisition strategies.


	•	We have an experienced, knowledgeable management team with a proven record of performance. Our management team has a proven record of enhancing value through the investment in, and the acquisition, exploitation and integration of, natural gas midstream assets. Our senior management team has an average of over 22 years of industry-related experience. Our team’s extensive experience and contacts within the midstream industry provide a strong foundation for managing and enhancing our operations, accessing strategic acquisition opportunities and constructing new assets. After giving effect to this offering, members of our senior management team will have a substantial economic interest in us.


	•	We are affiliated with Natural Gas Partners, a leading private equity capital source for the energy industry. Natural Gas Partners, a leading private equity firm focused on the energy industry, owns a significant equity position in Eagle Rock Holdings, L.P., which will own 3,459,236 common and 20,691,495 subordinated units and all of the equity interests in our general partner upon completion of this offering. We expect that our relationship with Natural Gas Partners will provide us with several significant benefits, including increased exposure to acquisition opportunities and access to a significant group of transactional and financial professionals with a successful track record of investing in midstream assets. 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.

Summary of 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. The following list of risk factors is not exhaustive. Please read carefully these and other risks described under “Risk Factors.”


	*Risks Related to Our Business*


	•	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.

	•	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 assumptions underlying the forecast of cash available for distributions we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

	•	Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of supplies of natural gas and natural gas liquids, which are dependent on


		certain factors beyond our control. Any decrease in supplies of natural gas or natural gas liquids could adversely affect our business and operating results.

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

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

	•	We typically do not obtain independent evaluations of 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 depend on certain natural gas producer customers for a significant portion of our supply of natural gas. The loss of any of these customers could result in a decline in our volumes, revenues and cash available for distribution.

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

	•	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.

	•	Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

	•	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.

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

	•	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.

	•	If we do not make acquisitions on economically acceptable terms, our future growth will be limited.

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

	•	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, our operations and financial results could be adversely affected.

	•	Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

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

	•	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.

	•	Due to our lack of industry and geographic diversification, adverse developments in our midstream operations or operating areas would reduce our ability to make distributions to our unitholders.


	•	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.

	•	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.

	•	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.


	*Risks Inherent in an Investment in Us*



	•	Eagle Rock Holdings, L.P. will own a 57.2% 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 to your detriment.


	•	The NGP Investors and their affiliates and certain private investors are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

	•	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 to you.

	•	Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

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

	•	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.

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

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

	•	Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

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


	•	You will experience immediate and substantial dilution of $16.16 in tangible net book value per common unit.


	•	We may issue additional units without your approval, which would dilute your existing ownership interests.

	•	Affiliates of our general partner, the NGP Investors and their affiliates, and the Private Investors may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

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


	•	Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

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

	•	There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

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


	*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 (the “IRS”) 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 to you.

	•	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 to you.

	•	You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

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

	•	Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

	•	We will treat each purchaser of 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.

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

	•	You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

Formation Transactions and Partnership Structure

General

We are a Delaware limited partnership formed in May 2006 to own and operate the assets that have historically been owned and operated by Eagle Rock Holdings, L.P. and its subsidiaries. In 2002, certain members of our management team formed Eagle Rock Energy, Inc. to provide midstream services to natural gas producers. In connection with the acquisition of the Dry Trail plant in 2003, members of our management team and Natural Gas Partners formed Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy, Inc., to own, operate, acquire and develop complementary midstream energy assets.

In March 2006, certain private investors, which we refer to as the March 2006 Private Investors, contributed $98.3 million to Eagle Rock Pipeline, L.P., which will become our operating partnership and which we refer to as Eagle Rock Pipeline, in exchange for 5,455,050 common units in Eagle Rock Pipeline.

In June 2006, we purchased all of the partnership interests in Midstream Gas Services, L.P., which we refer to as MGS, for approximately $4.7 million in cash and 1,125,416 common units in Eagle Rock Pipeline from a group of private investors, including Natural Gas Partners VII, L.P. 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. 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. We refer to the private investors who received common units in Eagle Rock Pipeline as partial consideration for the MGS acquisition as the June 2006 Private Investors. The March 2006 Private Investors and the June 2006 Private Investors are collectively referred to in this prospectus as the “Private Investors.” Each of the Private Investors’ common units in Eagle Rock Pipeline will be converted into common units in us upon consummation of this offering on approximately a 1-for-0.719 common unit basis. Because of the contingent nature of the earn-out provision, the information in this prospectus assumes that the Deferred Common Units are not issued.

On August 31, 2006, we entered into an amended and restated credit facility that provides for an aggregate of $500 million in borrowing capacity. At the closing of this offering:



	•	we will issue 12,500,000 common units to the public in this offering, representing a 29.6% limited partner interest in us;



	•	Eagle Rock Holdings, L.P. will own 3,459,236 common units and 20,691,495 subordinated units, totaling an aggregate 57.2% limited partner interest in us and all of the equity interests in our general partner, Eagle Rock Energy GP, L.P.;



	•	the Private Investors will own 4,732,259 common units, representing an 11.2% limited partner interest in us;



	•	Eagle Rock Energy GP, L.P. will own 844,551 general partner units representing an initial 2% general partner interest in us as well as the incentive distribution rights;


	•	we will own all of the ownership interests in Eagle Rock Pipeline, our operating partnership, and its operating subsidiaries, which will own and operate our assets;

	•	we will enter into a registration rights agreement with Eagle Rock Holdings, L.P.;


	•	we will enter into an Omnibus Agreement with Eagle Rock Energy G&P, LLC, Eagle Rock Holdings, L.P. and our general partner that will address our reimbursement to Eagle Rock Energy G&P, LLC and Eagle Rock Holdings, L.P. for the payment of certain operating expenses and insurance coverage expenses incurred on our behalf and certain indemnification obligations of Eagle Rock Holdings, L.P. to us; and

	•	Eagle Rock Holdings, L.P. will pay $6.0 million to Natural Gas Partners as consideration for the termination of an advisory services, reimbursement and indemnification agreement between Natural Gas Partners and Eagle Rock Holdings, L.P.

The diagram on the following page depicts our organization and ownership after giving effect to the offering and the related formation transactions.

Ownership of Eagle Rock Energy Partners, L.P.


Public Common Units		29.6	%
Private Investors Common Units		11.2	%
Eagle Rock Holdings, L.P. Common and Subordinated Units		57.2	%
General Partner Interest		2.0	%

	Total	100.0	%

Management of Eagle Rock Energy Partners

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, will conduct our business and operations, and the board of directors and executive officers of Eagle Rock Energy G&P, LLC will make decisions on our behalf. The senior executives who currently manage our business will continue to do so following the completion of this offering. Neither our general partner, nor any of its affiliates, will receive any management fee or other compensation in connection with the management of our business, but they will be entitled to reimbursement for all direct and indirect expenses they incur on our behalf.

Neither our general partner nor the board of directors of Eagle Rock Energy G&P, LLC will be elected by our unitholders. Unlike shareholders in a publicly traded corporation, our unitholders will not be 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 will have the right to elect all of the members of the board of directors of Eagle Rock Energy G&P, LLC at the closing of this offering. 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 will conduct our operations through subsidiaries. We will initially 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 will control 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.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 14950 Heathrow Forest Parkway, Suite 111, Houston, Texas 77032 and our telephone number is (832) 327-8000. Our website is located at www.eaglerockenergy.com. We expect to 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.

Our General Partner’s Rights to Receive Distributions

2% General Partner Interest. Our general partner initially will be entitled to receive 2% of our quarterly cash distributions. The general partner’s initial 2% 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 initial 2% general partner interest. All references in this prospectus to the general partner’s 2% general partner interest assumes that the general partner will elect to make these additional capital contributions in order to maintain its right to receive 2% of these cash distributions.

Incentive Distributions. In addition to its 2% 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:


		Marginal Percentage
		Interest in
		Distributions*
	Total Quarterly Distribution
	Per Unit			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% 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 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, L.P. 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.”

The Offering


Common units offered to the public		12,500,000 common units.

		14,375,000 common units, if the underwriters exercise their option to purchase additional units in full.


Units outstanding after this offering		20,691,495 common units and 20,691,495 subordinated units, each representing a 49% limited partner interest in us. We also intend to grant 130,000 restricted units under our Long-Term Incentive Plan.


Use of proceeds		We intend to use the net proceeds of approximately $230.8 million from this offering, after deducting underwriting discounts and fees and offering expenses, to:

		• replenish approximately $35.0 million of working capital that will be distributed prior to the consummation of this offering to the existing equity owners of Eagle Rock Pipeline, L.P., which consist of subsidiaries of Eagle Rock Holdings, L.P. and the Private Investors;


		• satisfy our obligation to reimburse Eagle Rock Holdings, L.P. and the Private Investors for approximately $184.8 million of capital expenditures incurred prior to this offering related to the assets to be contributed to us upon the closing of this offering, as partial consideration for the contribution to us of those assets; and



		• distribute approximately $11.0 million to Eagle Rock Holdings, L.P. as a cash distribution from Eagle Rock Pipeline, L.P. 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.


		If the underwriters’ option to purchase additional common units is exercised, we will use the net proceeds to redeem from Eagle Rock Holdings, L.P. and the Private Investors a number of common units equal to the number of common units issued upon exercise of the underwriters’ option, at a price per common unit equal to the proceeds per common unit before estimated offering expenses but after underwriting discounts and fees, and to reimburse Eagle Rock Energy Holdings, L.P. and the Private Investors for capital expenditures incurred indirectly by them.

Cash distributions		Our general partner will adopt a cash distribution policy that will require 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 B. 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;

		• 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.”


		The amount of pro forma available cash generated during the year ended December 31, 2005 and the twelve months ended June 30, 2006 would not have been sufficient to allow us to pay the full minimum quarterly distribution on all of 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 and 21.6% and 19.4%, respectively, of the minimum quarterly distribution on our subordinated units for those periods. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”


		We believe that, based on the Statement of Forecasted Results of Operations and Cash Flows for the Twelve Months Ending September 30, 2007 included under the caption “Our Cash Distribution Policy and Restrictions on Distributions,” we will have sufficient cash available for distribution to make cash distributions for the four quarters ending September 30, 2007 at the initial distribution rate of $0.3625 per common unit per quarter ($1.45 per common unit on an annualized basis) on all common units and subordinated units.

Subordinated units		Eagle Rock Holdings, L.P. will initially own 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 will manage and operate 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. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of 58.4% of our common and subordinated units. This will give 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 own the common units you purchase in this offering 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		We have applied to list our common units on the Nasdaq Global Market under the symbol “EROC.”

Summary Historical and Pro Forma Financial Data

The following table shows summary historical financial data of our predecessor, ONEOK Texas Field Services L.P., and Eagle Rock Pipeline, L.P. and unaudited pro forma 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 this 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 on 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 usingmark-to-market accounting. The amounts related to commodity hedges are included in unrealized/realized derivatives gains (losses) and the amounts related to interest rate swaps are included in interest expense (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).


	•	We completed construction of the23-mile Tyler County pipeline on February 28, 2006, which was flowing 34 MMcf/d of natural gas to the Indian Springs processing plant as of June 30, 2006. As a result, neither our historical financial results for periods prior to December 31, 2005 nor our unaudited pro forma financial data include the full financial results from the operation of this asset, which we expect to flow 64 MMcf/d by the end of 2006.


	•	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.

The summary 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 and 2005 are derived from the audited financial statements of Eagle Rock Pipeline. The summary historical financial data as of December 31, 2003 is derived from the unaudited financial statements of Eagle Rock Predecessor. The summary historical financial data for the six months ended June 30, 2005 and as of and for the six months ended June 30, 2006 are derived from the unaudited financial statements of Eagle Rock Pipeline. The summary pro forma financial data for the year ended December 31, 2005 and as of and for the six months ended June 30, 2006 are derived from the unaudited pro forma financial statements of Eagle Rock Energy Partners, L.P. The pro forma adjustments have been prepared as if this offering and certain transactions to be effected at the closing of this offering had taken place as of June 30, 2006 in the case of the pro forma balance sheet or as of January 1, 2005, in the case of the pro forma statements of operations for the year ended December 31, 2005 and the six months ended June 30, 2006. For a description of the pro forma adjustments included in the following table, please read the pro forma financial statements included in this prospectus.


																											Eagle Rock Energy
			Eagle Rock Predecessor																								Partners, L.P.
												Eagle Rock Pipeline, L.P.
									Period from																					Six
									January 1,												Six Months			Six Months						Months
			Year Ended			Year Ended			2005 to			Year Ended			Year Ended			Year Ended			Ended			Ended			Year Ended			Ended
			December 31,			December 31,			November 30,			December 31,			December 31,			December 31,			June 30,			June 30,			December 31,			June 30,
			2003			2004			2005			2003			2004			2005(1)			2005			2006			2005			2006

			($ in thousands except per unit data)																								(Unaudited Pro Forma)
Statement of Operations Data:
	Operating revenues		$	297,290		$	335,519		$	396,953		$	—		$	10,636		$	66,382		$	10,294		$	246,445		$	501,596		$	260,374
	Unrealized derivative gains/(losses)			—			—			—			—			—			7,308			—			(35,811	)		7,308			(35,811	)
	Realized derivative gains/(losses)			—			—			—			—			—			—			—			570			—			570

		Total operating revenues		297,290			335,519			396,953			—			10,636			73,690			10,294			211,204			508,904			225,133
	Purchases of natural gas and NGLs			249,284			263,840			316,979			—			8,811			55,272			8,845			188,236			394,333			198,140
	Operating and maintenance expense			23,905			27,427			27,518			—			34			2,955			340			14,798			36,260			17,133
	General and administrative expense			—			—			—			144			2,406			4,765			926			6,010			5,526			6,179
	Depreciation and amortization expense			7,187			8,268			8,157			—			619			4,088			520			20,215			42,708			22,386

Operating Income (loss)				16,914			35,984			44,299			(144	)		(1,234	)		6,610			(337	)		(18,055	)		30,077			(18,705	)
	Interest (income) expense			(189	)		(646	)		(859	)		—			—			4,031			(49	)		5,963			31,706			6,360
	Other (income)			(52	)		(23	)		(17	)		—			(24	)		(171	)		—			(40	)		(188	)		(40	)

Income before income taxes				17,155			36,653			45,175			(144	)		(1,210	)		2,750			(288	)		(23,978	)		(1,441	)		(25,025	)
	Income tax provision			6,071			12,731			15,811			—			—			—			—			508			—			508

Income (loss) from continuing operations				11,084			23,922			29,364			(144	)		(1,210	)		2,750			(288	)		(24,486	)		(1,441	)		(25,533	)
	Discontinued operations			—			—			—			533			22,192			—			—			—			—			—
	Cumulative effect of change in accounting principle			227			—			—			—			—			—			—			—			—			—

Net income (loss)			$	10,857		$	23,922		$	29,364		$	389		$	20,982		$	2,750		$	(288	)	$	(24,486	)	$	(1,441	)	$	(25,533	)

	General partner interest in pro forma net income (loss)																										$	(29	)	$	(511	)
	Limited partner interest in pro forma net income (loss)																										$	(1,412	)	$	(25,022	)
	Pro forma net income per limited partner unit — dilutive																										$	(0.07	)	$	(1.21	)
Balance Sheet Data (at period end):
	Property plant and equipment, net		$	246,640		$	243,939		$	242,487		$	18,529		$	19,564		$	441,588					$	532,938					$	532,938
	Total assets			259,577			304,631			376,447			21,379			28,017			700,659						769,121						768,056
	Long-term debt			—			—			—			14,221			—			408,466						398,220						397,155
	Net equity			180,422			204,344			233,708			6,629			27,655			208,096						301,447						301,447
Cash Flow Data:
	Net cash flows provided by (used in):
		Operating activities	$	32,219		$	41,813		$	47,603		$	(337	)	$	3,652		$	(1,667	)	$	275		$	15,047
		Investing activities		(5,203	)		(5,567	)		(6,708	)		(18,282	)		16,918			(543,501	)		(5	)		(107,997	)
		Financing activities		(27,016	)		(36,246	)		(40,895	)		20,240			(13,955	)		556,304			(6,120	)		80,682
Other Financial Data:
EBITDA(2)			$	23,926		$	44,275		$	52,473		$	389		$	21,601		$	10,869		$	183		$	2,200		$	72,973		$	3,213

Adjusted EBITDA(3)			$	23,926		$	44,275		$	52,473		$	(144	)	$	(591	)	$	3,561		$	183		$	38,011		$	65,665		$	39,024

Segment gross margin			$	48,006		$	71,679		$	79,974		$	—		$	1,825		$	18,418		$	1,449		$	22,968		$	114,571		$	26,993


(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 $35.8 million in unrealized derivative losses for the six months ended June 30, 2006. Includes $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 $35.8 million in unrealized derivative losses for the six months ended June 30, 2006. Excludes $0.5 million in 2003 and $22.2 million in 2004 of income from discontinued operations.

Non-GAAP Financial Measures

We include in this prospectus the following non-GAAP financial measures: EBITDA, 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 EBITDA as net income plus interest expense, net, provision for income taxes and depreciation and amortization expense. EBITDA is used as a supplemental liquidity measure by our management team and by external users of our financial statements such as investors, commercial banks, research analysts and others to assess the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, make cash distributions to our unitholders and general partner and finance maintenance capital expenditures. EBITDA is also used as a supplemental measure by management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:


	•	financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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.

Neither EBITDA nor Adjusted EBITDA should 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.

Neither EBITDA nor Adjusted EBITDA includes interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate 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 EBITDA, to evaluate our liquidity. Our EBITDA and Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among companies. Therefore, our EBITDA and 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.


																																Pro Forma Eagle Rock
		Eagle Rock Predecessor															Eagle Rock Pipeline, L.P.															Energy Partners, L.P.

														Period from
														January 1,												Six Months			Six Months						Six Months
		Year Ended			Year Ended			Year Ended			Year Ended			2005 to			Year Ended			Year Ended			Year Ended			Ended			Ended			Year Ended			Ended
		December 31,			December 31,			December 31,			December 31,			November 30,			December 31,			December 31,			December 31,			June 30,			June 30,			December 31,			June 30,
		2001			2002			2003			2004			2005			2003			2004			2005(1)			2005			2006			2005			2006

																																(Unaudited Pro Forma)
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		$	127,977		$	13,326		$	32,219		$	41,813		$	47,603		$	(337	)	$	3,652		$	(1,667	)	$	275		$	15,047
Add (deduct):
	Depreciation and amortization		(7,538	)		(7,457	)		(7,187	)		(8,268	)		(8,157	)		(98	)		(1,174	)		(4,088	)		(520	)		(20,215	)
Amortization of debt issue cost			—			—			—			—			—			—			—			(76	)		—			(432	)
Risk management portfolio value changes			—			—			—			—			—			—			—			5,709			—			(26,724	)
Net realized gain on derivatives			—			—			—			—			—			—			—			—			—			500
Other			—			—			—			—			—			—			—			(6	)		—			(34	)
Gain on sale of Dry Trail plant			—			—			—			—			—			—			19,465			—			—			—
Provision for deferred income taxes			(58,770	)		(596	)		(10,943	)		(7,325	)		(1,559	)		—			—			—			—			—
Accounts receivable and other current assets			87,428			(15,246	)		23,791			30,905			56,599			883			(901	)		43,179			14			(1,568	)
Accounts payable and accrued liabilities			(147,631	)		26,790			(21,363	)		(34,705	)		(64,320	)		(192	)		(169	)		(40,197	)		(55	)		9,264
Other assets and liabilities									(5,660	)		1,502			(802	)		133			109			(104	)		(2	)		(324	)

Net income (loss)			1,466			16,817			10,857			23,922			29,364			389			20,982			2,750			(288	)		(24,486	)		(1,441	)		(25,533	)
Add:
Interest (income) expense, net			—			—			(189	)		(646	)		(859	)		—			—			4,031			(49	)		5,963			31,706			6,360
Depreciation and amortization			7,538			7,457			7,187			8,268			8,157			—			619			4,088			520			20,215			42,708			22,386
Income tax provision (benefit)			803			(6,465	)		6,071			12,731			15,811			—			—			—			—			508			—			—

EBITDA(2)		$	9,807		$	17,809		$	23,926		$	44,275		$	52,473		$	389		$	21,601		$	10,869		$	183		$	2,200		$	72,973		$	3,213

Adjusted EBITDA(3)		$	9,807		$	17,809		$	23,926		$	44,275		$	52,473		$	(144	)	$	(591	)	$	3,561		$	183		$	38,011		$	65,665		$	39,024

Reconciliation of net income (loss) to total segment gross margin:
Net income (loss)		$	1,466		$	16,817		$	10,857		$	23,922		$	29,364		$	389		$	20,982		$	2,750		$	(288	)	$	(24,486	)	$	(1,441	)	$	(25,533	)
Add (deduct):			—			—			—			—			—			—			—			—			—			—			—			—
Operating expenses			24,406			22,276			23,905			27,427			27,518			—			34			2,955			340			14,798			36,260			17,133
General and administrative expense			—			—			—			—			—			144			2,406			4,765			926			6,010			5,526			6,179
Depreciation and amortization expense			7,538			7,457			7,187			8,268			8,157			—			619			4,088			520			20,215			42,708			22,386
Interest expense, net			—			—			(189	)		(646	)		(859	)		—			—			4,031			(49	)		5,963			31,706			6,360
Other income and deductions, net			51			(944	)		(52	)		(23	)		(17	)		—			(24	)		(171	)		—			(40	)		(188	)		(40	)
Income tax provision			803			(6,465	)		6,071			12,731			15,811			—			—			—			—			508			—			508
Discontinued operations			—			—			—			—			—			(533	)		(22,192	)		—			—			—			—			—
Cumulative effect of change in accounting principle			—			—			227			—			—			—			—			—			—			—			—			—

Total segment gross margin		$	34,264		$	39,141		$	48,006		$	71,679		$	79,974		$	—		$	1,825		$	18,418		$	1,449		$	22,968		$	114,571		$	26,993


(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 $35.8 million in unrealized derivative losses for the six months ended June 30, 2006. Includes $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 $35.8 million in unrealized derivative losses for the six months ended June 30, 2006. Excludes $0.5 million in 2003 and $22.2 million in 2004 of income from discontinued operations.

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.

Risks Related to Our Business


	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 $15.3 million per quarter, or $61.2 million per year, based on the common units and subordinated units outstanding immediately after completion of this offering, whether or not the underwriters exercise their option to purchase additional common units. We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy. 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 of, level of production of, and demand for, natural gas, NGLs and condensate;

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

	•	the relationship between natural gas and NGL prices;

	•	the level of competition from other midstream energy companies;

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

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions.”


	*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.*

You should be aware that 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 all of our units to be outstanding immediately after this offering is approximately $61.2 million. The amount of our pro forma available cash generated during the year ended December 31, 2005 and the twelve months ended June 30, 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 and 21.6% and 19.4%, respectively, of the minimum quarterly distribution on our subordinated units for those periods. For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2005, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

Since the March 2006 private placement of common units of Eagle Rock Pipeline, L.P., Eagle Rock Pipeline, L.P. did not generate available cash sufficient to pay the minimum quarterly distribution for the three months ended June 30, 2006 on all of the outstanding equity interests held by Eagle Rock Holdings, L.P. The accrued arrearages on such interests total approximately $11.0 million because Eagle Rock Pipeline, L.P. elected not to pay the distribution and preserve cash. If Eagle Rock Pipeline, L.P. had fully distributed its distributable cash flow, its accrued arrearage would have totaled approximately $2.0 million.

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 assumptions underlying the forecast of cash available for distribution we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

The forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, EBITDA and cash available for distribution for the twelve months ending September 30, 2007. The financial forecast has been prepared by management and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.


	Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of supplies of natural gas and NGLs, which are dependent on certain factors beyond our control. Any decrease in supplies of 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 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 $8.89 per MMBtu as of December 31, 2005. 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 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, 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 to you.


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

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. The NYMEX daily settlement price for natural gas for the prompt month contract in 2005 ranged from a high of $15.39 per MMBtu to a low of $5.50 per MMBtu and, in the first six months of 2006, the same index ranged from a high of $10.63 per MMBtu to a low of $5.89 per MMBtu. The NYMEX daily settlement price for crude oil for the prompt month contract in 2005 ranged from a high of $69.81 per barrel to a low of $42.12 per barrel and, in the first six months of 2006, the same index ranged from a high of $75.17 per barrel to a low of $57.65 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 on the demand for oil and natural gas;

	•	the level of domestic oil and natural gas production;

	•	the availability of imported oil and natural gas;

	•	actions taken by foreign oil and gas producing nations;

	•	the availability of local, intrastate and interstate transportation systems;

	•	the availability and marketing of competitive fuels;

	•	the impact of energy conservation efforts; and

	•	the extent of governmental regulation and taxation.

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. Underpercentage-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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations.”

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 underpercent-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 underpercent-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. For periods after 2010, 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 will 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 natural gas supply and production of NGLs and condensate from our processing plants, we will continue to have direct commodity price risk to the unhedged portion. Our actual future supply and production may be significantly higher or lower than we estimate at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimate, we will have less commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the underlying physical commodity, resulting in a reduction of our liquidity.

As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, even though our management monitors our hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or our hedging policies and procedures are not properly followed or do not work as planned. The steps we take to monitor our hedging activities may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. For additional information regarding our hedging activities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”


	We typically do not obtain independent evaluations of 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 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 to you.


	We depend on certain natural gas producer customers for a significant portion of our supply of natural gas. The loss of any of these customers could result in a decline in our volumes, revenues and cash available for distribution.

We rely on certain natural gas producer customers for a significant portion of our natural gas and NGL supply. Our two largest suppliers for the year ended December 31, 2005, affiliates of Chesapeake Energy Corporation and Devon Energy Corporation, accounted for approximately 18.9% and 9.2%, respectively, of our 2005 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.


	*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 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 to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.


	*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. Some of these competitors may expand or construct gathering, processing and transportation systems that would create additional competition for the services we provide to our

customers. In addition, our customers who are significant producers of natural gas may develop their own gathering, processing and transportation systems in lieu of using ours. Likewise, our customers who produce NGLs may develop their own processing facilities in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.


	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 “Business — Regulation of Operations.”


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

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities for pollution resulting from our operations. 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, and the issuance of injunctions limiting or preventing some or all of our operations.

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, air emissions and water discharges related to our operations, and historical industry operations and waste disposal practices. Joint and several, strict liability may be incurred under these environmental laws and regulations in connection with discharges or releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover some or any of these costs from insurance. See “Business — Environmental Matters.”


	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 involves 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. Since we are not engaged in the exploration for and development of natural gas and oil reserves, 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 newrights-of-way prior to constructing new pipelines. We may be unable to obtain suchrights-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 newrights-of-way or to renew existingrights-of-way. If the cost of renewing or obtaining newrights-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 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.

Any acquisition involves potential risks, including, among other things:


	•	mistaken assumptions about volumes, revenues and costs, including synergies;

	•	an inability to integrate successfully the businesses we acquire;

	•	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; and

	•	customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you 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 acquisition strategy is based, in part, on our expectation of ongoing divestitures of energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our operations and cash flows available for distribution to our unitholders.


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

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or if such rights of way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renewright-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 to you.


	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, our operations and financial results could be adversely affected.

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


	•	damage to 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 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.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. 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.


	*Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.*

In December 2005, we entered into up to a $475 million senior secured credit facility, consisting of up to a $400 million term loan facility and up to a $75 million revolving credit facility for our acquisition of the ONEOK Texas natural gas gathering and processing assets. The revolver facility was increased to $100 million in June 2006. On August 31, 2006, we entered into an amended and restated credit facility that provides for an aggregate of $500 million borrowing capacity, of which we have the ability to incur up to $89 million of additional debt, subject to limitations in our credit facility. 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.


	*Restrictions in our amended and restated credit facility limit our ability to make distributions to you 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. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Requirements.”


	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 experienced50-year record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will continue to tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, to incur debt to make acquisitions or for other purposes or to make cash distributions at our intended levels.


	*Due to our lack of industry and geographic diversification, adverse developments in our midstream operations or operating areas would reduce our ability to make distributions to our unitholders.*

We rely on the revenues generated from our midstream energy businesses, and as a result, our financial condition depends upon prices of, and continued demand for, natural gas, NGLs and condensate. Furthermore, all of our assets are located in the Texas Panhandle, southeast 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 or the recent attacks in London, 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 this offering, we have been a private company and have not filed reports with the SEC. We will become subject to the public reporting requirements of the Securities Exchange Act of 1934 upon the completion of this offering. 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. 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


	Eagle Rock Holdings, L.P. will own a 57.2% 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 to your detriment.

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


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

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

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

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

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


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

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

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

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

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

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

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

Please read “Conflicts of Interest and Fiduciary Duties.”


	The NGP Investors and their affiliates and the March 2006 Private Investors are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

The NGP Investors and their affiliates and the March 2006 Private Investors are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, the NGP Investors and their affiliates and the March 2006 Private Investors may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. The NGP Investors and the March 2006 Private Investors also have no obligation to provide us access to operational, transactional or financial resources. Certain of the June 2006 Private Investors have agreed not to compete with us in specified counties in the Texas Panhandle for a period of four years.


	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 to you.

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.*

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. Furthermore, we anticipate using the net proceeds of this offering to replenish working capital and to satisfy our obligation to reimburse Eagle Rock Holdings, L.P. and the Private Investors for capital expenditures previously made on our behalf. As a result, the net proceeds of this offering will not be used to grow our business.

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.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”


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

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


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

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

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

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


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

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

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

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

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


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

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors, and will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of

directors of Eagle Rock Energy G&P, LLC will be 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 will own sufficient units upon completion of this offering 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. Following the closing of this offering, our general partner and its affiliates will own 58.4% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period 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.


	*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.


	*You will experience immediate and substantial dilution of $16.16 in tangible net book value per common unit.*

The initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $3.84 per unit. Based on the initial public offering price of $20.00 per unit, you will incur immediate and substantial dilution of $16.16 per common unit after giving effect to the offering of common units and the

application of the related net proceeds and assuming the underwriters’ option to purchase additional common units is not exercised. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read “Dilution.”


	*We may issue additional units without your approval, which would dilute your existing 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, the NGP Investors and their affiliates, and the Private Investors may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered hereby, management of our general partner and the NGP Investors and their affiliates (through their interests in Eagle Rock Holdings, L.P.) and the Private Investors will hold an aggregate of 8,191,495 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. 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 the March 2006 Private Investors and we intend to enter into a registration rights agreement with Eagle Rock Holdings, L.P. The registration rights agreement with the March 2006 Private Investors requires us to file with the SEC a registration statement within 90 days of the closing of this offering and to have such registration statement become effective within 180 days of the closing of this offering. We anticipate that the registration rights agreement with Eagle Rock Holdings, L.P. will require us to file with the SEC a registration statement within 90 days of our receipt of a request from Eagle Rock Holdings, L.P. 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 any lock-up agreements applicable to the March 2006 Private Investors and Eagle Rock Holding, L.P., these holders may sell their common units into the public markets. For a description of the registration rights agreements, please read “Units Eligible for Future Sale.”


	*Our general partner has a limited call right that may require you to sell your 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, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering and assuming no exercise of the

underwriters’ option to purchase additional common units, our general partner and its affiliates will own approximately 16.7% 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 58.4% of our outstanding common units. For additional information about this right, please read “The Partnership Agreement — Limited Call Right.”


	*Your liability 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. You could be liable for any and all of our obligations as if you were 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

	•	your 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.

For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement — Limited Liability.”


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

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you 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.


	There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to the offering, there has been no public market for the common units. After the offering, there will be only 12,500,000 publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity 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 initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the

initial public offering price. The market price of our common units may also 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;

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

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

	•	general economic conditions;

	•	the failure of securities analysts to cover our common units after this offering 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 no 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 have included $2.5 million of estimated incremental costs per year associated with being a publicly traded partnership for purposes of our financial forecast included elsewhere in this prospectus; 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

In addition to reading the following risk factors, you should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

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 to you.

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 to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you 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 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 to you. 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 to you.

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 prospectus 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.


	*You may be required to pay taxes on your share of our income even if you 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, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your 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 you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive 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 you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.


	We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. For a further discussion of the effect of the depreciation and amortization positions we will adopt, please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election.”


	*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. Please read “Material Tax Consequences — Disposition of Common Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.


	*You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.*

In addition to federal income taxes, you 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 you do not live in any of those jurisdictions. You 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, you may be subject to penalties for failure to comply with those requirements. We will initially own assets and conduct business in the States of Louisiana, Texas and Oklahoma. 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 your 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 expect to receive net proceeds of approximately $230.8 million from the sale of 12,500,000 common units offered by this prospectus, after deducting underwriting discounts and fees and paying offering expenses. Our estimates assume an initial public offering price of $20.00 per common unit and no exercise of the underwriters’ option to purchase additional common units. An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts and fees and offering expenses payable by us, to increase or decrease by $11.7 million (or $13.4 million assuming full exercise of the underwriters’ option to purchase additional common units). If the initial public offering price were to exceed $20.00 per common unit or if we were to increase the number of common units in this offering, the additional proceeds would be distributed to Eagle Rock Holdings, L.P. for reimbursement of capital expenditures. We anticipate using the aggregate net proceeds of this offering to:


	•	replenish approximately $35.0 million of working capital that will be distributed prior to the consummation of this offering to the existing equity owners of Eagle Rock Pipeline, L.P., which consist of subsidiaries of Eagle Rock Holdings, L.P. and the Private Investors;


	•	satisfy our obligation to reimburse Eagle Rock Holdings, L.P. and the Private Investors for approximately $184.8 million of capital expenditures incurred prior to this offering related to the assets to be contributed to us upon the closing of this offering, as partial consideration for the contribution to us of those assets; and



	•	distribute approximately $11.0 million to Eagle Rock Holdings, L.P. as a cash distribution from Eagle Rock Pipeline, L.P. in respect of arrearages on the subordinated and general partner units of Eagle Rock Pipeline, L.P. owned by Eagle Rock Holdings, L.P.

If the underwriters’ option to purchase additional common units is exercised, we will use the net proceeds to redeem from Eagle Rock Holdings, L.P. and the Private Investors a number of common units equal to the number of common units issued upon exercise of the underwriters’ option, at a price per common unit equal to the proceeds per common unit before expenses but after underwriting discounts and fees, and to reimburse Eagle Rock Energy Holdings, L.P. and the Private Investors for capital expenditures incurred indirectly by them.

CAPITALIZATION

The following table shows:


	•	the historical cash and capitalization of Eagle Rock Pipeline, L.P. as of June 30, 2006;

	•	our pro forma as adjusted cash and capitalization as of June 30, 2006, reflecting this offering, the other transactions described under “Summary — Formation Transactions and Partnership Structure — General” and the application of the net proceeds from this offering as described under “Use of Proceeds.”

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma 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 June 30, 2006

						Pro Forma
				Historical		As Adjusted

				($ in millions)
Cash(1)				$	7.1	$	33.8

Debt					398.2		397.2

Total partners’ capital/net parent equity:
	Net parent equity				301.4		—
	Common units — Public(2)				—		89.2
	Common units — Private Investors				—		33.8
	Common units — Eagle Rock Holdings, L.P.(2)				—		24.7
	Subordinated units — Eagle Rock Holdings, L.P.				—		147.7
	General partner interest				—		6.0

		Total partners’ capital/net parent equity			301.4		301.4

			Total capitalization	$	699.6	$	698.6



(1)	Pro forma as adjusted cash and cash equivalents increases by $30.0 million as a result of the replenishment of non-cash working capital distributed to certain subsidiaries of Eagle Rock Holdings, L.P. and the Private Investors prior to this offering and is net of the principal amortization on our term loan of $3.3 million in August 2006.



(2)	A 1,000,000 unit increase in the number of common units issued to the public would result in a $7.2 million increase in the public common unitholders’ partners’ capital and a $7.2 million decrease in the partners’ capital of Eagle Rock Holdings, L.P. and the Private Investors.

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of June 30, 2006, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $162.0 million, or $3.84 per common unit. Net tangible book value excludes $139.4 million of net intangible assets. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:


Initial public offering price per common unit				$	20.00
	Net tangible book value per common unit before the offering(1)	5.45
	Decrease in net tangible book value per common unit attributable to purchasers in the offering	(1.61	)

Less: Pro forma net tangible book value per common unit after the offering(2)					3.84

Immediate dilution in tangible net book value per common unit to purchasers in the offering(3)				$	16.16



(1)	Determined by dividing the number of units (8,191,495 common units, 20,691,495 subordinated units and 844,551 general partner units) to be issued to Eagle Rock Holdings, L.P. and the Private Investors for their contribution of assets and liabilities to Eagle Rock Energy Partners, L.P. into the net tangible book value of the contributed assets and liabilities.



(2)	Determined by dividing the total number of units to be outstanding after the offering (20,691,495 common units, 20,691,495 subordinated units and 844,551 general partner units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.



(3)	If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $17.16 and $15.16, respectively.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by affiliates of our general partner, its affiliates and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:


		Units Acquired					Total Consideration

		Number		Percent			Amount		Percent

		(in thousands)
General partner and affiliates and the Private Investors(1)(2)			29,728		70.4	%	$	70,697		22.0	%
Purchasers in the offering			12,500		29.6	%		250,000		78.0	%

	Total		42,228		100.0	%	$	320,697		100.0	%


(1)	The units acquired by our general partner and its affiliates and the Private Investors consist of 8,191,495 common units, 20,691,495 subordinated units and 844,551 general partner units.


(2)	The assets contributed by our general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates, as of June 30, 2006, after giving effect to the application of the net proceeds of this offering and the retention of accounts receivable, is as follows:


		($ in thousands)

Book value of net assets contributed		$	301,447
Less: Distribution to Eagle Rock Holdings, L.P. and the Private Investors from net proceeds of the offering			(195,750	)
Distribution of working capital to Eagle Rock Holdings, L.P. and the Private Investors			(35,000	)

	Total consideration	$	70,697

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” 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 and pro forma operating results, you should refer to our historical financial statements for the years ended December 31, 2003, 2004 and 2005 and our unaudited pro forma condensed consolidated financial statements for the year ended December 31, 2005, and for the six months ended June 30, 2006 included elsewhere in 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.” 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.

	•	Under Section 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 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. We expect that we will distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our 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

Upon completion of this offering, the board of directors of our general partner will adopt 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 September 30, 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 $15.3 million per quarter or $61.2 million per year, in each case based on the number of common units, subordinated units and general partner units outstanding immediately after completion of this offering. If the underwriters’ option to purchase additional common units is exercised, an equivalent number of common units will be redeemed from Eagle Rock Holdings, L.P. and the Private Investors. Accordingly, the exercise of the underwriters’ option will not affect the total amount of units outstanding or the amount of cash needed to pay the initial distribution rate on all units.

at which such units would be issued), our aggregate cash distribution following such issuance would be $15.6 million per quarter or $62.4 million per year.

The table below sets forth the assumed number of outstanding common units, subordinated units and general partner units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our initial distribution rate of $0.3625 per common unit per quarter ($1.45 per common unit on an annualized basis).


				Minimum Quarterly
				Distributions

		Number of Units		One Quarter		Four Quarters

				($ in thousands)
Publicly-held common units			12,500,000	$	4,531	$	18,125
Common units held by the Private Investors			4,732,259		1,715		6,862
Common units held by Eagle Rock Holdings, L.P.			3,459,236		1,254		5,016
Subordinated units held by Eagle Rock Holdings, L.P.			20,691,495		7,501		30,003
2% general partner interest (a)			844,551		306		1,225

	Total		42,227,541	$	15,307	$	61,230


(a)	Assumes the general partner’s 2% interest remains the same. The general partner’s initial 2% 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 initial 2% 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 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.

As of the date of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. The general partner’s initial 2% 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 initial 2% 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. We will adjust the quarterly distribution for the period from the closing of this offering through September 30, 2006 based on the actual length of the period.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our initial distribution rate of $0.3625 per unit each quarter through the quarter ending September 30, 2007. In those sections, we present three tables, consisting of:


	•	“Unaudited Pro Forma Available Cash,” in which we present the amount of cash we would have had available for distribution for our fiscal year ended December 31, 2005 and for the twelve months ended June 30, 2006, derived from our unaudited pro forma financial statements that are included in this prospectus beginning on page F-2, which unaudited pro forma financial statements are based on our audited historical financial statements for the year ended December 31, 2005, as adjusted to give pro forma effect to:


	•	the transactions to be completed as of the closing of this offering; and

	•	this offering and the application of the net proceeds as described under “Use of Proceeds.”


	•	“Statement of Forecasted Results of Operations for the Twelve Months Ending September 30, 2007,” in which we present our financial forecast of our results of operations and the minimum estimated EBITDA necessary for us to pay distributions at the initial distribution rate on all units for the twelve months ending September 30, 2007, and the significant assumptions upon which the forecast is based; and

	•	“Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2007,” in which we present our estimate of the minimum amount of EBITDA necessary for us to pay distributions at the initial distribution rate on all units for the twelve months ending September 30, 2007.

Unaudited Pro Forma Available Cash for Year Ended December 31, 2005

If we had completed the transactions contemplated in this prospectus on January 1, 2005, pro forma available cash generated during the year ended December 31, 2005 and the twelve months ended June 30, 2006 would have been approximately $37.4 million and $35.5 million, respectively. These amounts would not have been sufficient to make a cash distribution for the year ended December 31, 2005 and the twelve months ended June 30, 2006 at the initial rate of $0.3625 per unit per quarter (or $1.45 per unit on an annualized basis) on all of the common units and subordinated units; however, these amounts would have been sufficient to make a cash distribution at the initial rate on all of the common units for these two periods and 21.6% and 19.4%, respectively, of the distribution at the initial rate on the subordinated units for these two periods.

Unaudited pro forma available cash from operating surplus includes an incremental general and administrative expense we will incur as a result of being a publicly traded limited partnership, including compensation and benefit expenses of our executive management personnel, costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, Sarbanes-Oxley Act compliance, SEC reporting and filing requirements, incremental director and officer liability insurance costs and director compensation. We expect this incremental general and administrative expense initially to total approximately $2.5 million per year. In addition, approximately $0.9 million is a non-cash expense related to awards to be granted under our Long-Term Incentive Plan.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2005 and for the twelve months ended June 30, 2006, the amount of available cash that would have been available for distributions to our unitholders, assuming that this offering had been consummated at the beginning of such period. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma available cash only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in earlier periods.

Eagle Rock Energy Partners, L.P.

Unaudited Pro Forma Available Cash


		Year Ended			Twelve Months
		December 31,			Ended June 30,
		2005(a)			2006(b)

		($ in thousands, except per unit data)
Net Cash Provided by Operating Activities(c)		$	45,936		$	34,597
	Interest expense, net(c)(d)		3,172			9,144
	Income tax provisions, net(c)(e)		15,811			16,319
	Non-cash derivatives portfolio value changes(c)(f)		(1,598	)		7,532
	Net changes in working capital accounts and other assets(c)(g)		(7,287	)		129

EBITDA(c)			56,034			67,721
Pro forma adjustments						—
	Brookeland asset purchase pro forma(h)		10,392			7,568
	Adjustments for offering transactions(i)		(761	)		(761	)

Pro forma EBITDA			65,667			74,529


			Year Ended			Twelve Months
			December 31,			Ended June 30,
			2005(a)			2006(b)

			($ in thousands, except per unit data)
Less:
	Incremental general and administrative expense of being a public company(j)			2,500			2,500
	Pro forma interest expense, net(k)			31,113			32,115
	Maintenance capital expenditures(l)			5,348			6,624
	Growth capital expenditures(m)			5,514			14,760
	Net debt repayment(n)			—			4,000
	Brookeland/Masters Creek acquisition(o)			95,724			95,724
	MGS acquisition(p)			4,716			4,716
	Net changes in working capital accounts and other assets(c)(g)			(7,287	)		129
Plus:
	Borrowings for growth capital expenditures(q)(r)			5,514			14,760
	Borrowings for principal repayments on debt(q)(r)			—			4,000
	Borrowings to replenish working capital and other assets(q)(r)			—			129
	Borrowings for the MGS acquisition(r)			4,716			4,716
	Equity contribution for Brookeland/Masters Creek acquisition(s)			98,300			98,300
	Non-cash LTIP expenses(t)			867			867

Pro Forma Available Cash			$	37,434		$	36,732

	Pro forma distribution associated with non-vested restricted units(u)			189			189
Pro forma cash distributions:
	Distributions to public common unitholders		$	18,125		$	18,125
	Distributions to the Private Investors — common units			6,862			6,862
	Distributions to Eagle Rock Holdings, L.P. — common units			5,016			5,016
	Distributions to Eagle Rock Holdings, L.P. — subordinated units			6,494			5,806
	Distributions on 2% general partner interest			749			735

		Total distributions to unitholders	$	37,245		$	36,544

	Annualized initial quarterly distribution per unit		$	1.45		$	1.45
	Aggregate distribution payable at annualized initial quarterly(v) distribution			61,230			61,230
Excess (shortfall)			$	(23,985	)	$	(24,688	)
Percent of distributions payable to common unitholders				100.0%			100.0%
Percent of distributions payable to subordinated unitholders				21.6%			19.4%


(a)	Reconciled to pro forma as if the December 1, 2005 acquisition of ONEOK Texas Field Services, L.P. occurred on January 1, 2005, and as if the pro forma adjustments for this offering had been included.


(b)		Reconciled to include pro forma adjustments for this offering.

(c)		Represents the combined historical operations of ONEOK Texas Field Services, L.P. and Eagle Rock Pipeline, L.P.

(d)		Amount represents incremental historical interest expense, net, incurred to fund the acquisition of ONEOK Texas Field Services, L.P. and to fund the earnest money deposited with Duke Energy Field Services for the Brookeland/Masters Creek acquisition.


(e)		Amount represents income tax provisions included in net cash provided by operating activities but not included in EBITDA.

(f)		Represents the non-cash value changes to derivative portfolio including the net impact of commodity hedges in operating revenues and the impact of interest rate swaps in interest expense.

(g)		Represents actual net changes in working capital accounts and other assets incurred for the periods indicated.

(h)		The twelve months ended December 31, 2005 and the twelve months ended June 30, 2006 include the twelve months ended December 31, 2005 pro forma adjustments and the nine months ended March 31, 2006 pro forma adjustments, respectively, for the Brookeland/Masters Creek acquisition excluding depreciation and interest expense, which are not components of EBITDA. These pro forma components are listed in the table below.


	Twelve Months Ended			Nine Months Ended
	December 31, 2005			March 31, 2006

	($ in thousands)
Total operating revenue	$	38,261		$	35,022
Total cost of sales		(22,082	)		(22,702	)
Operating expenses		(5,787	)		(4,752	)

Pro forma adjustment	$	10,392		$	7,568

(i)

Represents the inclusion of pro forma adjustments for (i) compensation expenses related to distributions or unit distribution rights associated with the 130,000 restricted units that we expect to grant under our Long-Term Incentive Plan upon the consummation of this offering and (ii) the elimination of the management fees payable to Natural Gas Partners that will be terminated upon the closing of the offering in accordance with an agreement between us and Natural Gas Partners. Please read “Use of Proceeds.”


(j)		Includes incremental general and administrative expenses we will incur as a result of being a publicly traded limited partnership, such as costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, Sarbanes-Oxley Act compliance, SEC reporting and filing requirements, incremental director and officer liability insurance costs and director compensation. We expect these incremental general and administrative expenses to total approximately $2.5 million per year.

(k)		Amount represents pro forma interest expense, net incurred to fund growth capital expenditures, principal repayments on term debt and decreases in working capital accounts. This amount is deducted from pro forma EBITDA since it decreases pro forma available cash.

(l)		Represents actual maintenance capital expenditures incurred for the periods indicated.

(m)		Represents actual growth capital expenditures for the periods indicated, excluding the growth capital expenditures associated with the ONEOK acquisition, the Brookeland/ Masters Creek acquisition and the MGS acquisition.

(n)		Represents actual principal repayments on debt for the periods indicated.

(o)		Represents actual purchase price paid for the Brookeland/ Masters Creek acquisition.

(p)		Represents actual cash purchase price paid for the MGS acquisition.


(q)		Our amended and restated credit facility provides for an aggregate of $500 million in borrowing capacity of which approximately $397 million is funded and $89 million is available for borrowing, net of approximately $14 million in outstanding letters of credit. We intend to use our amended and restated credit facility to satisfy our working capital needs, fund principal payments on our long-term debt and finance growth capital expenditures. We also expect to fund growth capital expenditures and future acquisitions from borrowings and equity contributions.


(r)		For purposes of determining pro forma cash available for distribution, we have assumed that we are operating as a publicly traded partnership, including borrowing the amounts necessary to cover growth capital expenditures, principal repayments on debt, replenishment of working capital and other assets, as reflected in the table. Our historical borrowings were used to fund the ONEOK acquisition and the MGS acquisition, borrowings which would not have increased our cash available for distribution. Borrowings for the ONEOK acquisition on a pro forma basis would have occurred prior to the periods presented.

(s)		Equity investment by the March 2006 Private Investors to finance the Brookeland/ Masters Creek acquisition is assumed to have occurred on January 1, 2005.

(t)		Represents non-cash compensation expenses related to distributions on the unit distribution rights associated with the 130,000 restricted units that we expect to grant under our Long-Term Incentive Plan upon the consummation of this offering.

(u)		Reflects payments for distribution equivalent rights granted in connection with 130,000 restricted units that we expect to grant under our Long-Term Incentive Plan upon the consummation of this offering.

(v)		The table below sets forth the assumed number of outstanding common units and subordinated units upon the closing of this offering (assuming the underwriters’ option to purchase additional common units has not been exercised) and the aggregate distribution amounts payable on our common units, subordinated units and 2% general partner interest for four quarters at our initial distribution rate of $0.3625 per unit per quarter ($1.45 per unit on an annualized basis).


		Number of		Distributions for
		Units		Four Quarters

				($ in thousands)
Pro forma distributions on publicly-held common units			12,500,000	$	18,125
Pro forma distributions on common units held by Private Investors			4,732,259		6,862
Pro forma distributions on common units held by Eagle Rock Holdings, L.P.			3,459,236		5,016
Pro forma distributions on subordinated units held by Eagle Rock Holdings, L.P.			20,691,495		30,003
Pro forma distributions on 2% general partner interest			844,551		1,225

	Total distributions on units		42,227,541	$	61,230

Financial Forecast for the Twelve Months Ending September 30, 2007

Set forth below is a financial forecast of the expected results of operations, EBITDA and cash available for distribution for Eagle Rock Energy Partners, L.P. for the twelve months ending September 30, 2007. Our financial forecast presents, to the best of our knowledge and belief, the expected results of operations, EBITDA and cash available for distributions for Eagle Rock Energy Partners, L.P. for the forecast period. EBITDA is defined as net income, plus interest expense and depreciation and amortization expense.

Our financial forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending September 30, 2007. The assumptions disclosed below under “Summary of Significant Accounting Policies and Forecast Assumptions” are those that we believe are significant to our financial forecast. We believe our actual results of operations and cash flows will approximate those reflected in our financial forecast; however, we can give you no assurance that our forecast results will be achieved. There will likely be differences between our forecast and the actual results and those differences could be material. If the forecast is not achieved, we may not be able to pay cash distributions on our common units at the initial distribution rate stated in our cash distribution policy. In order to fund distributions to our unitholders at our initial rate of $1.45 per common unit for the twelve months ending September 30, 2007, our minimum estimated

EBITDA for the twelve months ending September 30, 2007 must be at least $99.5 million. As set forth in the table below, we forecast that our EBITDA for this period will be approximately $105.6 million.

We do not as a matter of course make public projections as to future operations, earnings or other results. However, management has prepared the prospective financial information set forth below to present the forecasted results of operations and cash flow for the twelve months ending September 30, 2007 in order to forecast the amount of cash available for distribution to our unitholders for that period. This forecast is a forward-looking statement and should be read together with the historical financial statements and the accompanying notes included elsewhere in this prospectus and together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and the expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither our independent auditors, nor any other independent accountants, have compiled, examined, or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus could cause our actual results of operations to vary significantly from the financial forecast.

We are providing the financial forecast to supplement our pro forma and historical financial statements in support of our belief that we will have sufficient available cash to allow us to pay cash distributions on all of our outstanding common and subordinated units for each quarter in the twelve-month period ending September 30, 2007 at our stated initial distribution rate. Please read below under “Summary of Significant Accounting Policies and Forecast Assumptions” for further information as to the assumptions we have made for the financial forecast.

Actual payments of distributions on common units, subordinated units and the general partner interest are expected to be $61.2 million for the twelve-month period ending September 30, 2007, or $15.3 million per quarter for the period. Quarterly distributions will be paid within 45 days after the close of each quarter.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

Eagle Rock Energy Partners, L.P.

Statement of Forecasted Results of Operations

and Minimum Estimated EBITDA


			Twelve Months
			Ending
			September 30,
			2007

			($ in millions)
Total operating revenues			$	975.4

Costs and expenses:
	Purchases of natural gas and NGLs			825.6
	Operating and maintenance expense			30.7
	Depreciation and amortization expense			45.3
	General and administrative expense, including public partnership expenses			13.5

		Total costs and expenses		915.1
Operating income				60.3
	Interest expense, net			29.6

		Net income		30.7

Adjustments to reconcile net income to cash available for distributions
	Depreciation and amortization expense			45.3
	Interest expense, net			29.6

Forecasted EBITDA(a)			$	105.6
Less:
	Interest expense, net			29.6
	Maintenance capital expenditures			9.6
	Growth capital expenditures			12.3
Plus:
	Non-cash general and administrative expenses			0.9
	Borrowings for growth capital expenditures			12.3

		Cash available for distributions	$	67.3
Total distributions to our unitholders and general partner at the initial distribution rate			$	61.2
	Excess of cash available for distributions over distributions at the initial distribution rate		$	6.1
Calculation of minimum estimated EBITDA necessary to pay cash distributions at the initial distribution rate:
	Forecasted EBITDA		$	105.6
	Excess of cash available for distributions over distributions at the initial distribution rate			6.1

		Minimum estimated EBITDA necessary to pay cash distributions at the initial distribution rate	$	99.5
Interest coverage ratio(b)				3.57	x
Leverage ratio(b)				3.79	x


(a)	The following table sets forth, on a quarterly basis, our forecast for each of the four quarters in the twelve-month period ending September 30, 2007. Our quarterly forecast is based on the same assumptions utilized for the preparation of the forecast for the twelve-month period ending September 30, 2007.


				Quarter Ending

				December 31,		March 31,		June 30,		September 30,
				2006		2007		2007		2007

Total operating revenues				$	226.8	$	264.4	$	232.7	$	251.5
Total costs and expenses					220.1		256.3		225.0		243.3

Net income				$	6.7	$	8.1	$	7.7	$	8.2

Adjustments to reconcile net income to cash available for distributions:
	Depreciation and amortization expense				11.3		11.2		11.3		11.5
	Interest expense, net				7.6		7.3		7.3		7.4

Forecasted EBITDA					25.6		26.6		26.3		27.1
Less:
	Interest expense, net				7.6		7.3		7.3		7.4
	Maintenance capital expenditures				2.4		2.5		2.3		2.4
	Growth capital expenditures				4.4		4.6		2.5		0.8
Plus:
	Non-cash general and administrative expenses				0.3		0.2		0.2		0.2
	Borrowings for growth capital expenses				4.4		4.6		2.5		0.8

		Cash available for distributions		$	15.9	$	17.0	$	16.9	$	17.5

Total distributions to our unitholders and general partner at the initial distribution rate					15.3		15.3		15.3		15.3
Excess of cash available for distributions over distributions at the initial distribution rate					0.6		1.7		1.6		2.2
Calculation of minimum estimated EBITDA necessary to pay cash distributions at the initial distribution rate:
		Forecasted EBITDA			25.6		26.6		26.3		27.1
		Excess of cash available for distributions over distributions at the initial distribution rate			0.6		1.7		1.6		2.2

			Minimum estimated EBITDA necessary to pay cash distributions at the initial distribution rate	$	25.0	$	24.9	$	24.7	$	24.9


(b)	We have entered into an amended and restated credit agreement in an aggregate principal amount of up to $500 million.


	Our amended and restated credit agreement contains financial covenants requiring us to maintain:


	•	an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, in each case as defined in the credit agreement) of not less than 2.5 to 1.0, determined as of the last day of each quarter for the four quarter period ending on the date of determination; and

	•	a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as defined in the credit agreement) of not more than 5.0 to 1.0 (or, on a temporary basis for not more than three consecutive quarters following the consummation of certain acquisitions, not more than 5.25 to 1.0).


	Based on our forecasted results of operations, we expect that we will be in compliance with these covenants for the 2006 forecast period.

Please read accompanying “Summary of Significant Accounting Policies and Forecast Assumptions.”

EAGLE ROCK ENERGY PARTNERS, L.P.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND FORECAST ASSUMPTIONS


Note 1.	Basis of Presentation

The accompanying financial forecast and related notes of Eagle Rock Energy Partners, L.P. present the forecasted financial results of operations and cash flows of Eagle Rock Energy Partners, L.P. for the twelve months ending September 30, 2007 based on the assumptions that, as of the closing of the offering contemplated by this prospectus, Eagle Rock Pipeline, L.P. will be contributed to Eagle Rock Energy Partners, L.P.

This financial forecast was prepared in connection with the proposed initial public offering of common units in Eagle Rock Energy Partners, L.P., which was formed in May 2006 and which will own Eagle Rock Pipeline, L.P. and its subsidiaries, as we describe elsewhere in this prospectus.


Note 2.	Summary of Significant Accounting Policies

Property, Plant and Equipment — Property, plant and equipment consist of intrastate gas gathering systems, gas processing, conditioning and treating facilities and other related facilities, which are carried at cost less accumulated depreciation. We charge repairs and maintenance against income when incurred and capitalize renewals and betterments, which extend the useful life or expand the capacity of the assets. We calculate depreciation on the straight-line method principally over20-year estimated useful lives of our assets. The weighted average useful lives are as follows:


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

We capitalize interest on major projects during extended construction time periods. Such interest is allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. We capitalized interest of $0.01 million related to the construction of our Tyler County pipeline in 2005.

The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets are capitalized.

We assess long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed by comparing the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured as the amount by which the carrying amounts exceed the fair value of the assets.

Intangible Assets — Intangible assets consist ofrights-of-way and easements and acquired customer contracts, which we amortize over the term of the agreement or estimated useful life. Amortization expense was approximately $1.2 million for the year ended December 31, 2005, and $7.5 million for the six months ended June 30, 2006. There was no amortization expense for any period prior to December 1, 2005. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2006 —

$14.6 million; 2007 — $14.6 million; 2008 — $14.6 million; 2009 — $14.6 million; and 2010 — $13.6 million. Intangible assets consisted of the following:


	December 31,		June 30,
	2005		2006

			(Unaudited)
Rights-of-way and easements — at cost	$	57,714,082	$	67,891,344
Contracts		58,498,534		80,207,494
Less: accumulated amortization		1,212,324		8,671,606

Net intangible assets	$	115,000,292	$	139,427,232

Other Assets — Other assets primarily consist of costs associated with debt issuance (and long-term contracts) and are carried on the balance sheet, net of related accumulated amortization. Amortization of other assets is calculated using the straight-line method over the maturity of the associated debt (or the expiration of the contract).

Transportation and Exchange Imbalances — In the course of transporting natural gas and NGLs for others, we may receive for redelivery different quantities of natural gas or NGLs than the quantities actually redelivered. These transactions result in transportation and exchange imbalance receivables or payables that are recovered or repaid through the receipt or delivery of natural gas or NGLs in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets andmarked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2005, we had imbalance receivables totaling $0.2 million and imbalance payables totaling $0.8 million, respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold.

Revenue Recognition. We earn revenues from domestic sales of natural gas and NGLs and by providing gathering, treating, compressing, processing, fractionating and transporting services. These sales arise from either gas gathering and processing or NGL pipeline transportation services. Revenues associated with these activities are recognized when natural gas products are delivered or at the time services are performed. Our gas purchase contracts are structured so that we earn margins on the resale of natural gas or NGLs reflecting the value added by gathering, processing, or transporting the products. We record revenue and cost of sales on a gross basis for those transactions when we act as the principal and take title to gas that is purchased for resale. When we act as an agent and our customers pay a fee for providing a service such as gathering or transportation, we record fees net in revenues and disclose them separately from sales of products.

Risk Management Activities. We deliver to fractionators the NGLs that are separated from the raw natural gas we gather and process. Under the terms of the contracts for fractionating services, we receive physical specification products which are then sold to third parties where we receive floating rate prices in exchange for title to the NGLs. Because these sales are settled with physical deliveries, these contracts are treated as normal sales and are not marked to market. This arrangement exposes us to NGL price volatility and creates the need to manage that risk.

We maintain a commodity risk management program with the objective of managing our exposure to commodity price risk with respect to natural gas and NGLs. From October through December of 2005, and as required by covenants in our credit agreements, we entered into certain NGLs put options, costless collars and swap contracts, crude oil costless collars and natural gas calls. In addition, in July 2006 we entered into additional crude oil costless collars benefitting from then current favorable pricing conditions and in order to increase our collar pricing from that of our originally executed collars. We do not enter into derivative contracts for trading purposes.

In addition, our previously existing credit agreement exposed us to interest rate risk due to the variable nature of the interest rates stated in the credit agreement. The credit agreement required us to enter into an interest rate swap with the objective of hedging a portion of our exposure to interest rate risk. In order to mitigate this exposure and to comply with these covenants, on December 5 and 6, 2005, we entered into an interest rate swap contract, effectively fixing the interest rate on a notional amount of $300 million of the term loan borrowings at an average fixed rate of 4.93% for a period of five years beginning in January 2006. Our amended and restated credit agreement exposes us to similar interest rate risk which we continue to hedge with our previously executed swaps.

Effective October 1, 2005, we elected to usemark-to-market accounting for our NGL, crude and natural gas derivatives, as well as for our interest rate swaps.

Benefits. Payroll and payroll related expenses are included within operating and general and administrative expenses. We provide a portion of medical, dental and other healthcare benefits to employees, as well as a 401(k) plan that provides for a dollar for dollar matching contribution by us of up to 3% of an employee’s contribution and 50% of additional contributions up to 5%. Additionally, we contribute 6% of a participating employee’s base salary annually. We have no pension obligations.

Income and Entity Taxes. We do not provide in our accounts for federal or state income taxes as such taxes are a liability of our partners. Beginning in June 2006, we will accrue the corresponding amounts related to the deferred tax liability generated by the new entity level tax laws in Texas. However, because we have estimated the total liability from the Texas entity level tax to be $0.1 million for 2007, and because the State of Texas will compensate this incremental tax by reducing property tax rates, we have not included the impact of the new entity level tax law in our forecast and we have kept our property tax liability constant in our forecast assumptions.

Note 3. Significant Forecast Assumptions

Panhandle Segment Revenue. We forecast revenue for our Panhandle segment for the twelve months ending September 30, 2007 based on the following significant assumptions:


	•	We will gather an average of 170 MMcf/d of natural gas for the twelve months ending September 30, 2007, as compared to gathering average volumes of 140 MMcf/d for the year ended December 31, 2005 and 141 MMcf/d for the twelve months ending June 30, 2006. Our assumption relating to gas gathering volumes for the twelve months ending September 30, 2007 is based on current operating levels and the expected drilling activity in the East Panhandle System, the proximity of our existing gathering system to these areas of drilling activity as compared to our competitors’ systems and the capital projects we have undertaken to capture additional volumes from the new drilling activity, as well as to capture production that is currently shut-in due to existing constraints on gathering or processing capacity. Our forecast assumes that 83.0% and 17.0% of the new volumes will be from existing well connects and new well connects, respectively. The capital projects we have undertaken to capture a significant portion of the increased volumes include:



	•	Installation of the Shrieke compressor on our Arrington system, which added 5 MMcf/d of capacity during the second quarter of 2006;


	•	Construction of the 10-mile pipeline linking our East and West Panhandle Systems, which provided 9 MMcf/d of incremental capacity beginning in the second quarter of 2006;

	•	Start-up of the Red Deer idle processing facility, which will add 11 MMcf/d of incremental capacity to our East Panhandle System starting in the fourth quarter of 2006; and

	•	Relocation andstart-up of our idle Kingsmill processing facility, which will add 20 MMcf/d of incremental capacity to our East Panhandle System starting in the second quarter of 2007.


	•	Incremental volumes were estimated to be added at an initial production rate per well of 2 MMcf/d with decline curves of 65%, 50% and 10% for the first, second and third year, respectively.


	•	Our forecast assumes we will not achieve the levels of gathering and processing from the gathering and processing facilities we acquired from MGS in June 2006 that would require us to issue any of the Deferred Common Units.


	•	The average natural gas price based on a 7.9% discount to the NYMEX forward price strip as of August 25, 2006 will range from $6.81/ MMBtu to $10.48/ MMBtu for the twelve months ended September 30, 2007. For the twelve months ended December 31, 2005, the average NYMEX daily settlement price of natural gas was $8.89/ MMBtu, and for the twelve months ended June 30, 2006, the average NYMEX daily settlement price of natural gas was $9.31/ MMBtu. Weighted average NGL prices, based upon projected production, will be on average $1.075/gal.



	•	Including the MGS acquisition, we will generate revenues of $645.4 million related to gathering and processing services for the twelve months ending September 30, 2007 as compared to $439.5 million and $454.9 million for the year ended December 31, 2005 and the twelve months ended June 30, 2006, on a pro forma basis, respectively. Higher volumes captured with theabove-mentioned projects represent the primary drivers of this increase in revenue. Of the $645.4 million, $380.3 million are from natural gas sales, $219.0 million are from NGL sales, $9.0 million are from gathering of transportation fees and $37.1 million are from condensate revenue.

Panhandle Segment Cost of Sales. Including the MGS acquisition, we forecast cost of sales for our Panhandle segment will be $532.4 million for the twelve months ending September 30, 2007, as compared to $351.7 million and $356.8 million for the twelve months ended December 31, 2005 and June 30, 2006, respectively. Cost of sales is primarily attributable to the purchase of gas and NGLs, but also includes certain third-party transportation and processing fees. Higher increased gathering volumes represent the drivers of this increase in cost of sales.

Panhandle Segment Gross Margin. We forecast segment gross margin for our Panhandle segment for the twelve months ending September 30, 2007 will be $113.0 million, after deducting cost of sales, as compared to $87.8 million and $98.1 million on a pro forma basis for the year ended December 31, 2005 and the twelve months ended June 30, 2006, respectively. Incremental volumes were assumed to be contracted under 92%-92% percentage-of-proceeds contracts for volumes from producers outside our dedicated acreages and 80%-80% percentage-of-proceeds contracts for producers under dedicated acreages.

We expect that our unit segment gross margins, including the impact of our hedging program, will remain stable because we have hedged substantially all of our equity NGL volumes (from both our percentage-of-proceeds and keep-whole contracts) and substantially all of our short natural gas position associated with our keep-whole volumes. See “Hedge Impact” below for discussion of this impact on our consolidated results.

Southeast Texas and Louisiana Segment Revenue. We forecast revenue for our Southeast Texas and Louisiana segment for the twelve months ending September 30, 2007 based on the following significant assumptions:


	•	Exclusive of our Tyler County pipeline and its extension, we will gather an average of 54.1 MMcf/d of natural gas (net to our interest in the Indian Springs facility) for the twelve month period ending September 30, 2007, as compared to the 46.7 MMcf/d and 50.5 MMcf/d of natural gas gathered for the twelve month period ended December 31, 2005 and June 30, 2006, respectively. We base this assumption upon current operating levels and drilling activity in the Brookeland and Masters Creek area. Our forecast assumes that 56.1% and 43.9% of the new volumes will be from existing well connects and new well connects, respectively.


	•	The extension of our Tyler County pipeline, which will be in service by November 1, 2006. For the incremental capacity created by the extension of our Tyler County pipeline, we will gather and process the following volumes:



	•	Volumes of 34.0 MMcf/d, which represent volumes currently flowing as a result of the completion of the first phase of the Tyler County pipeline; and.



	•	Average incremental volumes from acreage currently dedicated to our Tyler County pipeline of approximately 33.9 MMcf/d. This includes expected drilling activity of our current producers with dedicated acreage, which has Delta Petroleum Corp. and Black Stone Minerals Co. adding one well at 10 MMcf/d per well every three months, B.W.O.C. Inc. and Ergon Exploration Inc. adding one well at 3 MMcf/d per well every three months and Pogo Producing Company adding one well at 5 MMcf/d per well every four months.



	•	The average natural gas price, based on a 7.9% discount to the NYMEX forward price strip as of August 25, 2006, will range from $6.81/ MMBtu to $10.48/ MMBtu for the twelve months ended September 30, 2007. For the twelve months ended December 31, 2005, the average NYMEX daily settlement price of natural gas was $8.89/ MMBtu, and for the twelve months ended June 30, 2006, the average NYMEX daily settlement price of natural gas was $9.31/ MMBtu. Weighted average NGL prices, based upon projected production, will be on average $0.887/gal.



	•	We will, inclusive of our pro-rata interest in the Indian Springs/ Camp Ruby assets, generate revenues of $327.1 million related to services provided under gathering and processing agreements for the twelve months ending September 30, 2007, as compared to $79.4 million and $82.8 million on a pro forma basis for the year ended December 31, 2005 and the twelve months ended June 30, 2006, respectively. Our forecasted revenue is not directly comparable to historical numbers because Duke Energy Field Services recorded revenues and costs behind the Brookeland and Masters Creek Systems after the elimination of intercompany activity as sales were made to affiliates and we record and forecast revenues and cost of sales on a gross basis, therefore reporting larger revenues and costs than Duke Energy Field Services. The increase in volumes derived from our Tyler County pipeline, which was placed into service on December 31, 2005, and its extension into the Brookeland facility are the primary drivers of revenue growth.

Southeast Texas and Louisiana Segment Cost of Sales. We forecast cost of sales for our Southeast Texas and Louisiana segment for the twelve months ending September 30, 2007 will be $293.2 million, as compared to $42.6 million on a pro forma basis for the twelve months ended December 31, 2005 and $61.8 million for the twelve months ended June 30, 2006. Cost of sales is primarily attributable to the purchase of gas under ourpercentage-of-proceeds,percentage-of-liquids or keep-whole arrangements under which we gather and process natural gas. Our forecasted cost of sales is not directly comparable to historical numbers because Duke Energy Field Services recorded revenues and cost of sales behind the Brookeland and Masters Creek Systems after the elimination of intercompany activity as sales were made to affiliates and we book and forecast revenues and costs on a gross basis, therefore reporting larger revenues and costs than Duke Energy Field Services. Higher volumes derived from the Tyler County pipeline and its extension represent the primary drivers of this increase in cost of sales.

Southeast Texas and Louisiana Segment Gross Margin. We forecast segment gross margin for our Southeast Texas and Louisiana segment for the twelve months ending September 30, 2007 based on the forecasted increased volumes generated by our Tyler County pipeline and its extension. We forecast that we will, inclusive of our Indian Springs/Camp Ruby assets, receive segment gross margin of $33.9 million related to services provided under gathering and processing agreements for the twelve months ending September 30, 2007, as compared to $19.5 million and $21.0 million on a pro forma basis for the year ended December 31, 2005 and the twelve months ended June 30, 2006, respectively.

Based on our hedging program, our unit segment gross margin is expected to remain stable as we have hedged substantially all of our equity NGL volumes for 2006 and 2007, and substantially all of our

net short natural gas position associated with our keep-whole volumes. See “Hedge Impact” below for a discussion of a company-wide impact of our hedging strategy.

Hedge Impact. Our hedging strategy will contribute a $2.9 million realized gain reflected in our overall segment gross margin for the twelve months ending September 30, 2007, as compared to $0.0 million and $0.6 million gain for the year ended December 31, 2005 and the twelve months ending June 30, 2006, respectively. This is based on volumes, strike prices and terms of our current, executed hedges as compared to our pricing assumptions for natural gas, NGLs and condensate.

Operating Expenses. We forecast operating expenses for the twelve months ending September 30, 2007 will be $30.7 million, as compared to $36.3 million and $33.3 million on a pro forma basis for the year ended December 31, 2005 and the twelve months ended June 30, 2006, respectively. This includes $3.4 million in incremental expenses primarily related to the extension of our Tyler County pipeline and assumes $6.5 million of reductions to our existing operating expenses, based on initiatives currently in progress. These include the elimination of redundant compression and unused compressor leases, reduction in overtime, reduction in condensate hauling cost and savings achieved by exchanging the oversized Goad treating facility.

General and Administrative Expenses. We forecast general and administrative expenses for the twelve months ending September 30, 2007 based on the following significant assumptions:



	•	Our total general and administrative expenses will be $11.0 million for the twelve months ending September 30, 2007, including non-cash compensation expenses related to our long-term incentive plan, and excluding general and administrative expenses associated with being a publicly traded partnership, as compared to $5.5 million and $9.9 million on a pro-forma basis for the year ended December 31, 2005 and the twelve months ended June 30, 2006, respectively. These expenses reflect an 11.1% increase from our general and administrative expenses for the twelve months ended June 30, 2006.



	•	Our incremental general and administrative expenses associated with being a publicly traded partnership, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations, registrar and transfer agent fees, Sarbanes-Oxley Act compliance, SEC reporting and filing requirements, incremental director and officer liability insurance costs and director compensation, will be $2.5 million for the twelve months ending September 30, 2007.

Depreciation and Amortization Expenses. We forecast depreciation and amortization expenses for the twelve months ending September 30, 2007 to be $45.3 million as compared to $42.7 million and $44.7 million of depreciation and amortization expenses on a pro forma basis for the year ended December 31, 2005 and the twelve months ended June 30, 2006, respectively. We forecast depreciation and amortization expenses for the twelve months ending September 30, 2007 based on a number of specific assumptions, including:


	•	$42.8 million from existing fixed and intangible assets (not including capital expenditures or assets related to the extension of our Tyler County pipeline) based on a 15.2 year weighted average useful life.


	•	$2.5 million from fixed assets and capital expenditures associated with the extension of our Tyler County pipeline and our Texas Panhandle projects based on a 20 year weighted average useful life.

Capital Expenditures. We forecast capital expenditures for the twelve months ending September 30, 2007, based on the following significant assumptions:


	•	Our maintenance capital expenditures will be $9.6 million for the twelve months ending September 30, 2007. These expenditures will include $3.1 million in well connect costs and $6.5 million in various other expenditures, such as compressor overhauls. These expenditures do not include any maintenance capital expenditures in 2007 related to the extension of our Tyler County


		pipeline, as we do not expect to incur maintenance capital expenditures related to this project in 2007.

	•	Our growth capital expenditures will be $12.3 million for the twelve months ending September 30, 2007. Our growth capital expenditures for the twelve months ending September 30, 2007 relate to the following projects to be financed by funds available under our existing credit facilities:


	•	The Red Deer processing plantstart-up, with a total capital budget of $5.0 million, of which $3.6 million will have been spent prior to the forecast period;

	•	The Kingsmill processing plant relocation andstart-up, with a total capital budget of $8.0 million, of which $1.5 million will have been spent prior to the forecast period;

	•	The exchange of the Goad treater, with a total capital budget of $2.0 million; and

	•	The construction of lateral pipelines extending from the MGS assets to producers in the area, with a total capital budget of $3.2 million, of which $0.8 million will be spent after the forecast period.


	•	Consistent with our acquisition strategy, we intend to pursue strategic acquisitions that we expect to be accretive to our distributable cash flow; however, because of the uncertain nature of the acquisition environment, we have not included an estimate of future acquisition capital expenditure requirements. If we are successful in completing acquisitions, we anticipate that our primary source of financing for these acquisitions will be commercial bank borrowings and the issuance of debt and equity securities.

Financing. We forecast financing for the twelve months ending September 30, 2007 based on the following significant financing assumptions:



	•	Our average debt level under our amended and restated credit agreement will be $400.2 million, comprised of a $300 million first lien facility with an interest rate of London Interbank Offered Rate, or LIBOR, plus 2.25%, and $100.2 million outstanding on our $200 million revolving credit facility, which will have an interest rate of LIBOR plus 2.25% on borrowed funds and a commitment fee of 0.5% on un-borrowed funds.



	•	For calculating our floating interest rate exposure, we have assumed a 2007 LIBOR of 5.27% based on forward curves for 2007 as of May 21, 2006. This exposure is offset by our existing interest rate swaps which include $300 million of fixed-for-floating swaps at a weighted average rate of 4.93%. Based on these assumptions, our average interest rate will be 7.52%, and our interest expense will be $29.6 million for the twelve months ending September 30, 2007, as compared to $31.2 million and $30.9 million on a pro forma basis for the year ended December 31, 2005 and for the twelve months ended June 30, 2006, respectively.



	•	We will finance our expected growth capital expenditures using our amended and restated credit facility. We expect to have available borrowing capacity of $89 million based on our financial covenants as of September 30, 2006.

Payments of Distributions on Common Units, Subordinated Units and the 2% General Partner Interest During 2007. We forecast that distributions on common units, subordinated units and on the 2% general partner interest for the twelve months ending September 30, 2007 will be $61.2 million in the aggregate, which includes distributions for the period October 1, 2006 through September 30, 2007. Please see “— Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2007.”

Regulatory, Industry, Pricing and Economic Factors. Our forecast for the twelve months ending September 30, 2007 is based on the following significant assumptions related to regulatory, industry and economic factors:


	•	No material nonperformance or credit-related defaults by suppliers, customers or vendors will occur. There will not be any new federal, state or local regulation of the portions of the energy industry in which we operate or any interpretation of existing regulation that in either case will be materially adverse to our business.



	•	A difference in actual versus forecasted commodity prices would affect our cash flows. For the twelve months ending September 30, 2007, approximately $6.6 million of our forecasted segment gross margin is unhedged and therefore has commodity price sensitivity. If all other assumptions are held constant, a 42.6% decrease in actual natural gas, a 56.7% decrease in actual crude oil and a 53.2% decrease in actual NGL prices versus our forecasted prices for the unhedged portions of our forecasted volumes of natural gas, condensate and NGLs would result in a $6.8 million decline in cash available for distribution. For the twelve months ending September 30, 2007, our forecast market prices for the unhedged portions of our forecasted volumes of natural gas, condensate and NGLs are $8.71/MMBtu, $69.28/Bbl and $44.89/Bbl, respectively. These forecast prices for the unhedged portions of our forecasted volumes were based on 92.1% of the average price for natural gas/crude oil and NGLs pursuant to futures contracts for product delivery during the forecast period.



	•	If all other factors are held constant, a shortfall of 5.0% in our forecasted wellhead volumes on our Texas Panhandle System would result in a $4.3 million decline in our cash available for distribution. Similarly, if all other factors are held constant, a shortfall of 5.0% in our forecasted wellhead volumes on our southeast Texas and Louisiana Systems would result in a $1.2 million decline in our cash available for distribution.


	•	No material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated and material events will occur.

	•	There will not be any major adverse change in the midstream sector of the energy industry or in general economic conditions.

	•	Market, regulatory, insurance and overall economic conditions will not change substantially.

Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2007

In order to fund distributions to our unitholders at our initial distribution rate of $1.45 per common unit for the twelve months ending September 30, 2007, our minimum estimated EBITDA for the twelve months ending September 30, 2007 must be at least $99.5 million. EBITDA is defined as net income, plus net interest expense and depreciation and amortization expense.

EBITDA should not be considered an alternative to, or more meaningful than, net income, cash flows from operating activities, or any other measure of financial performance presented in accordance with GAAP, as those items are used as measures of operating performance, liquidity or ability to service debt obligations.

The table below entitled “Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2007” sets forth our calculation of the minimum estimated EBITDA necessary for us to generate $61.2 million of cash available to pay distributions at the initial distribution rate on all of our units. If we generate $61.2 million of cash available for distribution for the twelve months ending September 30, 2007, we will be able to fully fund distributions to our unitholders and general partner at the initial distribution rate of $0.3625 per common unit per quarter ($1.45 per common unit on an annualized basis).

You should read “Summary of Significant Accounting Policies and Forecast Assumptions” included as part of the financial forecast in the table above entitled “Statement of Forecasted Results of Operations and Minimum Estimated EBITDA” for a discussion of the material assumptions underlying such financial forecast. Our forecast is based on those material assumptions and reflects our judgment of conditions we expect to exist and the course of action we expect to take. The assumptions disclosed in our financial forecast are those that we believe are significant to our ability to generate the forecasted EBITDA. If our estimate is not achieved and we do not generate the minimum estimated EBITDA of $99.5 million, we may not be able to pay distributions on the common units at the initial distribution rate of $0.3625 per common unit per quarter ($1.45 per common unit on an annualized basis). Our financial forecast has been prepared by our management. Our independent auditors have not examined, compiled or otherwise applied procedures to our financial forecast and the forecast of cash available for distributions set forth below and, accordingly, do not express an opinion or any other form of assurance on it.

The table below includes maintenance capital expenditures for the twelve months ending September 30, 2007. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows.

When considering the table below, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” and elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our financial condition and consolidated results of operations to vary significantly from those set forth in the financial forecast above, which in turn would affect our ability to generate the minimum estimated EBITDA necessary for us to pay cash distributions at the initial distribution rate on all of our units in the estimated amounts reflected in the table below.

Eagle Rock Energy Partners, L.P.

Estimated Cash Available for Distributions

for the Twelve Months Ending September 30, 2007


Minimum estimated EBITDA necessary to pay cash distributions(a)		$	99.5
Less:
	Interest expense, net		29.6
	Maintenance capital expenditures		9.6
	Growth capital expenditures		12.3
Plus:
	Non-cash general and administrative expense		0.9
	Borrowings for growth capital expenditures		12.3

Cash Available for Distributions		$	61.2

Forecasted Cash Distributions(b)
	Forecasted distributions to our public common unitholders	$	18.1
	Forecasted distributions to common units held by the Private Investors		6.9
	Forecasted distributions to common units held by Eagle Rock Holdings, L.P.		5.0
	Forecasted distributions to subordinated units held by Eagle Rock Holdings, L.P.		30.0
	Forecasted distributions on general partner interest		1.2

	Total forecasted distributions to our unitholders and general partner	$	61.2

	Forecasted distribution per unit	$	1.45


(a)	This amount represents the minimum estimated amount of EBITDA that we will need to generate for the twelve months ending September 30, 2007 in order to pay cash distributions to our unitholders and our general partner at our initial distribution rate of $0.3625 per unit per quarter. We expect that our EBITDA for this period will exceed this amount as reflected in our financial forecast.


(b)		Represents the amount required to fund distributions to our unitholders and our general partner for four quarters based upon our initial distribution rate of $0.3625 per unit per quarter. If cash distributions to our unitholders exceed $0.4169 per common unit in any quarter, our general partner will receive 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.”

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 September 30, 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” 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. Initially, our general partner will be entitled to 2% of all quarterly distributions since inception 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 initial 2% 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 2% 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 2% general partner interest and assumes that our general partner maintains its general partner interest at 2%. 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 same per-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 September 30, 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 December 31, 2006, 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 this 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 this 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.

Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Growth capital expenditures represent capital expenditures made to expand or to increase the efficiency of the existing 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 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 this 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 the incentive distribution rights at the same per-unit amount as was distributed in the immediately preceding quarter. This amount, which initially equals $62.8 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.

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.

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:


	•	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 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:


	•	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 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 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 in order to maintain its 2% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 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.

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 2% general partner interest, that there are no arrearages on common units and that the general partner continues to own the incentive distribution rights.

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:


	•	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 2% general partner interest and assume our general partner has contributed any additional capital to maintain its 2% general partner interest and has not transferred its incentive distribution rights.


	Total Quarterly Distribution	Marginal Percentage Interest in
	Per Unit	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 maintains its 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 this offering, an amount of available cash from capital surplus equal to the initial public offering price;

	•	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 this 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 include its 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 will 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 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:


	•	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 include its 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.

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:


	•	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.

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.

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table shows selected historical financial data of our predecessor, ONEOK Texas Field Services L.P., and Eagle Rock Pipeline, L.P. and unaudited pro forma 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 this 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 usingmark-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).


	•	We completed construction of the23-mile Tyler County pipeline on February 28, 2006, which was flowing 34 MMcf/d of natural gas to the Indian Springs processing plant as of June 30, 2006. As a result, neither our historical financial results for periods prior to December 31, 2005 nor our unaudited pro forma financial data include the full financial results from the operation of this asset, which we expect to flow 64 MMcf/d by the end of 2006.


	•	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.

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 and 2005 are derived from the audited financial statements of Eagle Rock Pipeline. The selected historical financial data as of and for the years ended December 31, 2001 and 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 six months ended June 30, 2005 and as of and for the six months ended June 30, 2006 are derived from the unaudited financial statements of Eagle Rock Pipeline. The selected pro forma financial data for the year ended December 31, 2005 and as of and for the six months ended June 30, 2006 are derived from the unaudited pro forma financial statements of Eagle Rock Energy Partners, L.P. The pro forma adjustments have been prepared as if this offering and certain transactions to be effected at the closing of this offering had taken place as of June 30, 2006 in the case of the pro forma balance sheet or as of January 1, 2005 in the case of the pro forma statements of operations for the year ended December 31, 2005 and the six months ended June 30, 2006. For a description of the pro forma adjustments included in the following table, please read the pro forma financial statements in this prospectus.

The following table includes the non-GAAP financial measures of EBITDA, Adjusted EBITDA and segment gross margin. We define EBITDA as net income plus interest expense, net, provision for income taxes and depreciation and amortization expense. 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 EBITDA, 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 Energy
			Eagle Rock Predecessor															Eagle Rock Pipeline, L.P.																Partners, L.P.

															Period
															from
			Year			Year			Year			Year			January 1,			Year				Year			Year			Six Months						Year
			Ended			Ended			Ended			Ended			2005 to			Ended				Ended			Ended			Ended			Six Months			Ended			Six Months
			December 31,			December 31,			December 31,			December 31,			November 30,			December 31,				December 31,			December 31,			June 30,			Ended			December 31,			Ended
			2001			2002			2003			2004			2005			2003				2004			2005(1)			2005			June 30, 2006			2005			June 30, 2006

			($ in thousands except per unit data)																															(Unaudited Pro Forma)
Statement of Operations Data:
	Operating revenues		$	282,809		$	194,898		$	297,290		$	335,519		$	396,953			—			$	10,636		$	66,382		$	10,294		$	246,445		$	501,596		$	260,374
	Unrealized derivative gains/(losses)			—			—			—			—			—			—				—			7,308			—			(35,811	)		7,308			(35,811	)
	Realized derivative gains/(losses)			—			—			—			—			—			—				—			—			—			570			—			570

		Total operating revenues	$	282,809		$	194,898			297,290			335,519			396,953			—				10,636			73,690			10,294			211,204			508,904			225,133
	Purchases of natural gas and NGLs			248,545			155,757			249,284			263,840			316,979			—				8,811			55,272			8,845			188,236			394,333			198,140
	Operating and maintenance expense			24,406			22,276			23,905			27,427			27,518			—				34			2,955			340			14,798			36,260			17,133
	General and administrative expense			—			—			—			—			—			144				2,406			4,765			926			6,010			5,526			6,179
	Depreciation and amortization expense			7,538			7,457			7,187			8,268			8,157			—				619			4,088			520			20,215			42,708			22,386

Operating Income (loss)				2,320			9,408			16,914			35,984			44,299			(144	)			(1,234	)		6,610			(337	)		(18,055	)		30,077			(18,705	)
	Interest (income) expense			—			—			(189	)		(646	)		(859	)		—				—			4,031			(49	)		5,963			31,706			6,360
	Other expense (income)			51			(944	)		(52	)		(23	)		(17	)		—				(24	)		(171	)		—			(40	)		(188	)		(40	)

Income before income taxes				2,269			10,352			17,155			36,653			45,175			(144	)			(1,210	)		2,750			(288	)		(23,978	)		(1,441	)		(25,025	)
	Income tax provision (benefit)			803			(6,465	)		6,071			12,731			15,811			—				—			—						508			—			508

Income (loss) from continuing operations				1,466			16,817			11,084			23,922			29,364			(144	)			(1,210	)		2,750			(288	)		(24,486	)		(1,441	)		(25,533	)
	Discontinued operations			—			—			—			—			—			533				22,192			—			—			—			—			—

Net income (loss)			$	1,466		$	16,817		$	10,857		$	23,922		$	29,364		$	389		��	$	20,982		$	2,750		$	(288	)	$	(24,486	)	$	(1,441	)	$	(25,533	)

	General Partner interest in pro forma net income (loss)																																	$	(29	)	$	(511	)
	Limited partner interest in pro forma net income (loss)																																	$	(1,412	)	$	(25,022	)
	Pro forma net income per limited partner unit — dilutive																																	$	(0.07	)	$	(1.21	)
Balance Sheet Data (at period end):
	Property plant and equipment, net		$	242,671		$	248,624		$	246,640		$	243,939		$	242,487		$	18,529			$	19,564		$	441,588					$	532,938					$	532,938
	Total assets			348,866			339,489			259,577			304,631			376,447			21,379				28,017			700,659						769,121						786,056
	Long-term debt			—			—			—			—			—			14,221				—			408,466						398,220						397,155
	Net equity			142,464			159,281			180,422			204,344			233,708			6,629				27,655			208,096						301,447						301,447
Cash Flow Data:
	Net cash flows provided by (used in):
		Operating activities	$	127,977		$	13,326		$	32,219		$	41,813		$	47,603		$	(337	)		$	3,652		$	(1,667	)	$	275		$	15,047
		Investing activities		(274,142	)		(12,992	)		(5,203	)		(5,567	)		(6,708	)		(18,282	)			16,918			(543,501	)		(5	)		(107,997	)
		Financing activities		146,165			(334	)		(27,016	)		(36,246	)		(40,895	)		20,240				(13,955	)		556,304			(6,120	)		80,682
Other Financial Data:
EBITDA(2)			$	9,807		$	17,809		$	23,926		$	44,275		$	52,473		$	389			$	21,601		$	10,869		$	183		$	2,200		$	72,973		$	3,213

Adjusted EBITDA(3)			$	9,807		$	17,809		$	23,926		$	44,275		$	52,473		$	(144	)		$	(591	)	$	3,561		$	183		$	38,011		$	65,665		$	39,024

Segment gross margin			$	34,264		$	39,141		$	48,006		$	71,679		$	79,974		$	—			$	1,825		$	18,418		$	1,449		$	22,968		$	114,571		$	26,993


(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 $35.8 million in unrealized derivative losses for the six months ended June 30, 2006. Includes $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 $35.8 million in unrealized derivative losses for the six months ended June 30, 2006. Excludes $0.5 million in 2003 and $22.2 million in 2004 of income from discontinued operations.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The historical financial statements included in this prospectus beginning on page F-9 reflect the assets, liabilities and operations to be contributed to us by Eagle Rock Pipeline, L.P. and various wholly-owned subsidiaries upon the closing of this offering. You should read the following discussion of our financial condition and results of operations in conjunction with the historical and pro forma financial statements included elsewhere in this prospectus.

Overview

We are a growth-oriented Delaware limited partnership engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas and fractionating and transporting natural gas liquids, or NGLs. Our assets are strategically located in three significant natural gas producing regions, the Texas Panhandle, southeast Texas and Louisiana. We have grown significantly through acquisitions, including the acquisition of:


	•	our Texas Panhandle Systems from ONEOK Texas Field Services, L.P.;

	•	our Brookeland processing plant and system and Masters Creek System from Duke Energy Field Services, L.P. and Swift Energy Corporation;

	•	our pro-rata interests in the Indian Springs processing plant and Camp Ruby gathering system, both of which are operated by an affiliate of Enterprise Products Partners, L.P.; and

	•	Midstream Gas Services, L.P.

For additional information related to these acquisitions, please read “— Formation, Acquisitions and Asset Dispositions” below. We believe that we have significant opportunities to expand our existing gathering and processing systems to increase the capacity, efficiency and profitability of such systems through the implementation of commercial and operational development projects.

Our Operations

Our results of operations for our Panhandle segment and our southeast Texas and Louisiana segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed and transported through our gathering, processing and pipeline systems and the associated commodity price. We gather and process natural gas pursuant to a variety of arrangements generally categorized as “fee-based” arrangements,“percent-of-proceeds” arrangements and “keep-whole” arrangements. Under fee-based arrangements, we earn cash fees for the services that we render. Under the latter two types of arrangements, we generally purchase raw natural gas and sell processed natural gas and NGLs.

Percent-of-proceeds and keep-whole arrangements involve commodity price risk to us because our margin is based in part on natural gas and NGL prices. We seek to minimize our exposure to fluctuations in commodity prices in several ways, including managing our contract portfolio. In managing our contract portfolio, we classify our gathering and processing contracts according to the nature of commodity risk implicit in the settlement structure of those contracts.



	•	Fee-Based Arrangements. Under these arrangements, we generally are paid a fixed cash fee for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. A sustained decline, however, in commodity prices could result in a decline in volumes and, thus, a decrease in our fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. As of June 30, 2006, these arrangements accounted for about 13.9% of our natural gas volumes.


	•	Percent-of-Proceeds Arrangements. Under these arrangements, we generally gather raw natural gas from producers at the wellhead, transport the gas through our gathering system, process the gas and



		sell the processed gas and/or NGLs at prices based on published index prices. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under these arrangements, our margins cannot be negative. We regard the margin from this type of arrangement, that is, the sale proceeds less amounts remitted to the producers, as an important analytical measure of these arrangements. The price paid to producers is based on an agreed percentage of one of the following: (1) the actual sale proceeds; (2) the proceeds based on an index price; or (3) the proceeds from the sale of processed gas or NGLs or both. We refer to contracts in which we share only in specified percentages of the proceeds from the sale of NGLs and in which the producer receives 100% of the proceeds from natural gas sales, as“percent-of-liquids” arrangements. Underpercent-of-proceeds arrangements, our margin correlates directly with the prices of natural gas and NGLs and underpercent-of-liquids arrangements, our margin correlates directly with the prices of NGLs (although there is often a fee-based component to both of these forms of contracts in addition to the commodity sensitive component). As of June 30, 2006, these arrangements accounted for about 72.7% of our natural gas volumes. Approximately 76% of thesepercent-of-proceeds volumes also have fee components.



	•	Keep-Whole Arrangements. Under these arrangements, we process raw natural gas to extract NGLs and pay to the producer the full thermal equivalent volume of raw natural gas received from the producer in the form of either processed gas or its cash equivalent. We are generally entitled to retain the processed NGLs and to sell them for our account. Accordingly, our margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent value of those NGLs. The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs, but also to the price of natural gas relative to NGL prices. These arrangements can provide large profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many of our keep-whole contracts include provisions that reduce our commodity price exposure, including (1) conditioning floors that require the keep-whole contract to convert to a fee-based arrangement if the NGLs have a lower value than their thermal equivalent in natural gas, (2) embedded discounts to the applicable natural gas index price under which we may reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer, or (3) fixed cash fees for ancillary services, such as gathering, treating and compressing. As of June 30, 2006, these arrangements accounted for about 13.4% of our natural gas volumes. Approximately 84% of these keep-whole arrangements have fee components.

In addition, we are a seller of NGLs and are exposed to commodity price risk associated with downward movements in NGL prices. NGL prices have experienced volatility in recent years in response to changes in the supply and demand for NGLs and market uncertainty. In response to this volatility, we have instituted a hedging program to reduce our exposure to commodity price risk. Under this program, we have hedged substantially all of our share of NGL volumes underpercent-of-proceed and keep-whole contracts in 2006 and 2007 through the purchase of NGL put contracts, costless collar contracts and swap contracts. We have also hedged substantially all of our share of NGL volumes underpercent-of-proceed contracts from 2008 through 2010 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 substantially all of our short natural gas position associated with our keep-whole volumes. We anticipate that after 2007, our short natural gas position will become a long natural gas position because of our increased volumes in the Texas Panhandle and the volumes contributed from our Brookeland/ Masters Creek acquisition. In addition, we intend to pursue fee-based arrangements, where market conditions permit, and to increase retained percentages of natural gas and NGLs underpercent-of-proceed arrangements. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

How We Evaluate Our Operations

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

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

Margin. We calculate our margin as our revenue generated from our gathering and processing operations minus the cost of natural gas and NGLs purchased and other cost of sales, which also include third-party transportation and processing fees. Revenue includes revenue from the sale of natural gas and NGLs resulting from these activities and fixed fees associated with the gathering and processing of natural gas. Our contract portfolio impacts our segment margin. See “— Our Operations” for a discussion of our contract portfolio.

Operating Expenses. Operating expenses are a separate measure that we use to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. These expenses are largely independent of the volumes through our systems, but fluctuate depending on the activities performed during a specific period. We do not deduct operating expenses from total revenues in calculating segment margin because we separately evaluate commodity volume and price changes in segment margin.

EBITDA. We define EBITDA as net income plus interest expense, net, provision for income taxes and depreciation and amortization expense. EBITDA is used as a supplemental measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:


	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and general partner;

	•	our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and

	•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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.

General Trends and Outlook

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

Natural Gas Supply, Demand and Outlook. Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.4 trillion

cubic feet, or Tcf, in 2004 to approximately 26.5 Tcf in 2017, representing an annual growth rate of over 1.3%. During the five years ended December 31, 2005, the United States has on average consumed approximately 22.4 Tcf per year, while total marketed domestic production averaged approximately 19.9 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

We believe that current natural gas prices and the existing strong demand for natural gas will continue to result in relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. Although the natural gas reserves in the United States have increased overall in recent years, a corresponding increase in production has not been realized. We believe that this lack of increased production is attributable to insufficient pipeline infrastructure, the continued depletion of existing wells and a tight labor and equipment market. We believe that an increase in United States natural gas production, additional sources of supply such as liquid natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for natural gas in the United States.

All of the areas in which we operate are experiencing significant drilling activity. Although we anticipate continued high levels of exploration and production activities in substantially all of the areas in which we operate, fluctuations in energy prices can affect production rates over time and levels of investment by third parties in exploration for and development of new natural gas reserves. We have no control over the level of natural gas exploration and development activity in the areas of our operations.

Margins. As of June 30, 2006, our overall portfolio of processing contracts reflected a net short position in natural gas of approximately 6,168 MMBtu/d (meaning that we were a net buyer of natural gas) and a net long position in NGLs of approximately 7,287 Bbls/d (meaning that we were a net seller of NGLs). As a result, during this period, our margins were positively impacted to the extent the price of NGLs increased in relation to the price of natural gas and were adversely impacted to the extent the price of NGLs declined in relation to the price of natural gas. We refer to the price of NGLs in relation to the price of natural gas as the fractionation spread. This portfolio performed well in response to favorable fractionation spreads during these periods. Because of our hedging program, we have locked-in these favorable fractionation spreads and we anticipate that our unit margins will remain stable during the periods in which we have hedged our commodity risk.

Impact of Interest Rates and Inflation. The credit markets recently have experienced50-year record lows in interest rates. If the overall economy continues to strengthen, we believe that it is likely that monetary policy will 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. Although this could limit our ability to raise funds in the capital markets, we expect in this regard to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations in 2005. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by price changes in natural gas and NGLs. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

Formation, Acquisitions and Asset Dispositions


	*Our Formation and the Initial Public Offering*

recovery plant located in the Oklahoma panhandle, members of our management team and Natural Gas Partners formed Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy, Inc., to own, operate, acquire and develop complementary midstream energy assets. Natural Gas Partners is one of the largest private equity fund sponsors of companies in the energy sector and, since 2003, has provided us with significant support in pursuing acquisitions, including its equity investment of approximately $191 million to help facilitate our acquisition of the Texas Panhandle Systems and other assets.

On August 31, 2006, we entered into an amended and restated credit facility that provides for an aggregate of $500 million borrowing capacity. At the closing of this offering:



	•	we will issue 12,500,000 common units to the public in this offering, representing a 29.6% limited partner interest in us;



	•	Eagle Rock Holdings, L.P. will own 3,459,236 common units and 20,691,495 subordinated units, totaling an aggregate 57.2% limited partner interest in us and all of the equity interests in our general partner, Eagle Rock Energy GP, L.P.;



	•	the Private Investors will own 4,732,259 common units, representing a 11.2% limited partner interest in us;



	•	Eagle Rock Energy GP, L.P. will own 844,551 general partner units representing an initial 2% general partner interest in us as well as the incentive distribution rights;


	•	we will own all of the ownership interests in Eagle Rock Pipeline, our operating partnership, and its operating subsidiaries, which will own and operate our assets;

	•	we will enter into a registration rights agreement with Eagle Rock Holdings, L.P.;

	•	we will enter into an Omnibus Agreement with Eagle Rock Energy G&P, LLC, Eagle Rock Holdings, L.P. and our general partner that will address our reimbursement to Eagle Rock Energy G&P, LLC and Eagle Rock Holdings, L.P. for the payment of certain operating expenses and insurance coverage expenses incurred on our behalf and certain indemnification obligations of Eagle Rock Holdings, L.P. to us; and

	•	Eagle Rock Holdings, L.P. will pay $6.0 million to Natural Gas Partners as consideration for the termination of an advisory services, reimbursement and indemnification agreement between Natural Gas Partners and Eagle Rock Holdings, L.P.


	*Acquisition of Dry Trail Assets and Commencement of Operations*

On December 5, 2003, we commenced commercial operations by acquiring the Dry Trail plant from Williams Field Service Company for approximately $18.0 million. In July 2004, we sold the Dry Trail plant to Celero Energy, L.P. for approximately $37.4 million. The pre-tax realized gain on the disposition of the asset was approximately $19.5 million.


	*Acquisition of Camp Ruby Gathering System and Indian Spring Processing Plant and Expansion of System*

On July 28, 2004, we acquired certain minority-owned, non-operated undivided interests in natural gas gathering and processing assets from Black Stone Minerals for approximately $20.0 million, with proceeds from the sale of the Dry Trail plant. The assets consisted of a 20% undivided interest in the Camp Ruby gathering system and a 25% undivided interest in its related Indian Springs processing facility, both located in southeast Texas. An affiliate of Enterprise Products Partners, L.P. currently owns the remaining interests in the facilities and is the operator of each of the facilities, having taken over the ownership of the majority interest and operation of the assets from El Paso in January 2005.

Despite not being the operator of the assets, we immediately recommended significant operational and commercial changes designed to expand revenues, increase margins and limit exposure to market volatility. Prior to our acquisition, the assets had been experiencing gradual but steady decline in volume throughput. We promptly identified a large and growing area to the east/northeast of these assets experiencing significant exploration and increasing drilling activity that was not being serviced by the assets. In September 2005, we entered into a processing agreement under dedicated acreage with Ergon, an active producer with existing producing volumes in Tyler County, with the intention of constructing a wholly-owned, 23 mile gathering pipeline extending to its production area. This pipeline is now referred to as the Tyler County pipeline. In parallel, we negotiated a processing agreement with an affiliate of Enterprise Products Partners, L.P., the operator of the Indian Springs facility, to take the volumes dedicated to this pipeline to the Indian Springs processing facility under a favorable, fixed processing fee basis, of which we net back our 25% share. We began the construction of the Tyler County pipeline in September 2005 at an estimated cost of $7.6 million. During the construction phase, we were able to secure large dedication areas from three additional producers in the vicinity of the Tyler County pipeline increasing our expected volume from 15 MMcf/d to 71 MMcf/d. The Tyler County pipeline reached the first producer and began flowing natural gas on December 30, 2005. Construction of the pipeline was finished on February 28, 2006.


	*Acquisition of ONEOK Assets*

On December 1, 2005, we completed the purchase of ONEOK Texas Field Services, L.P., or ONEOK, for approximately $528 million of cash. The assets acquired in the transaction consisted of gathering and processing assets located in an eight county area in the Texas Panhandle and represent all of our assets in the Texas Panhandle.

Prior to our acquisition of these assets, they were operated as components of ONEOK’s much larger midstream operations. Immediately following our acquisition of these assets, we initiated, and continue to implement, a strategy to increase our gathered and processed volumes, to improve the efficiency and utilization of our installed capacity, and to reshape the contract mix of the acquired assets to expand revenues, increase margins and decrease exposure to market volatility. In particular, we are aggressively seeking new volumes on the East Panhandle System, where significant drilling activity is taking place along the Granite Wash play. ONEOK had historically not looked to attract a significant portion of new volumes or to gain market share from competitors in an effort to maintain its unit margins and to avoid capital expenditure requirements. In the first few months after the acquisition, we have attracted 20 MMcf/d of new volumes at attractive processing margins. We are in the process of expanding our processing capacity in this area by refurbishing and restarting an idle 11 MMcf/d processing plant by connecting the East with the West system, where excess capacity currently exists. We also intend to expand our processing capacity by relocating and restarting a 20 MMcf/d facility. On April 15, 2006, we

began construction of a10-mile pipeline to connect the gas in the east to the surplus plant capacity in the west. During ONEOK’s ownership of these assets, sales of natural gas, condensate and NGLs were typically made to affiliates of ONEOK, natural gas was typically transported from the assets on ONEOK affiliated pipelines under affiliate agreements and facilities and personnel were often shared. Furthermore, the scheduling and dispatch responsibilities for these assets were managed by ONEOK’s central control facility. We believe that, immediately prior to the acquisition, nearly 100% of the total revenues being generated by these assets was derived from transactions with affiliates of ONEOK. To the extent that these related party transactions were effected pursuant to contracts, we assumed these contracts only for a period of six months after the acquisition date. We have commenced an aggressive marketing program and expect that by the end of this six month period, we will have replaced part of this ONEOK affiliate revenue with revenue generated from many new third-party customers. We have also begun renegotiations of a significant portion of the producer supply contracts relating to these assets to decrease our exposure to commodity risk associated with keep-whole contracts.


	*Acquisition of Brookeland Assets*

On March 31, 2006, we purchased an 80% interest in the Brookeland gathering and processing facility, a 76.3% interest in the Masters Creek gathering system and 100% of the Jasper NGL line from Duke Energy Field Services, L.P. and on April 7, 2006 we purchased the remaining interest owned by Swift Energy Corporation in those same assets for an approximate total purchase price of $95.7 million. The acquired assets are located in southeast Texas and complement our existing southeast Texas assets. To motivate Swift Energy Corporation to enhance their drilling program, we have negotiated an incentive on all new well production. As such, they have resumed their drilling program.

As with the assets acquired from ONEOK, immediately following our acquisition of these assets, we implemented significant operational and commercial changes designed to expand revenues, increase margins and limit exposure to market volatility. Significantly, we began the construction of a 16-mile extension to our Tyler County pipeline to reach the Brookeland processing plant, which as of April 30, 2006, operated with 72.2 MMcf/d of excess capacity. This extension will allow us to deliver the Tyler County pipeline volumes to our wholly-owned Brookeland processing facility which will enable us to avoid the processing fee we currently pay at the Indian Springs processing facility on these volumes. We also expect that delivering these volumes to our Brookeland processing facility will allow us to achieve higher NGL recoveries as the Brookeland processing facility is more efficient than the Indian Springs processing facility.


	*Acquisition of MGS*

On June 2, 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. These common units in Eagle Rock Pipeline will be converted into common units in us upon consummation of this offering on approximately a 1-for-0.719 common unit basis. 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 acquired operations are located in Roberts County in the Texas Panhandle within our East Panhandle System. We expect this acquisition to provide significant synergies and gathering and processing capacity and to enhance our strategic presence in the area.

Financial Statement Presentation and Comparability of Financial Results

Our historical financial statements consist of:


	•	The financial statements of ONEOK Texas Field Services, L.P., as the accounting predecessor to Eagle Rock Energy Partners, L.P. which we refer to as “Eagle Rock Predecessor.” For a discussion of the results of operations of Eagle Rock Predecessor, please read “— Eagle Rock Predecessor


		Results of Operations.” The financials statements of Eagle Rock Predecessor, together with the notes thereto, are also included elsewhere in this prospectus.

	•	The financial statements of Eagle Rock Pipeline, L.P., as the accounting acquirer of Eagle Rock Predecessor and the entity contributed to Eagle Rock Energy Partners, L.P. in connection with this offering. For a discussion of the results of operations of Eagle Rock Pipeline, please read “— Eagle Rock Pipeline Results of Operations.” The financials statements of Eagle Rock Pipeline, together with the notes thereto, are also included elsewhere in this prospectus.

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


	•	As discussed above under “— Formation, Acquisition and Asset Dispositions,” we have grown rapidly through acquisitions. Our acquisitions were completed at different dates and with numerous sellers and were accounted for using the purchase method of accounting. Under the purchase method of accounting, results from such acquisitions are recorded in the financial statements only from the date of acquisition.

	•	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 on 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.

	•	In connection with our acquisition of Eagle Rock Predecessor on December 1, 2005, the book basis of the assets of Eagle Rock Predecessor was increased to reflect the purchase price, which had the effect of increasing the depreciation expense associated with the assets of Eagle Rock Energy Partners, L.P.

	•	As a result of our increased debt related to the acquisition of Eagle Rock Predecessor, our interest expense increased subsequent to December 1, 2005.

	•	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 usingmark-to-market accounting. These amounts are included in unrealized/realized gain (loss) from risk management activities.


	•	We completed construction of the Tyler County pipeline on February 28, 2006, which was flowing 34 MMcf/d of natural gas to the Indian Springs processing plant as of June 30, 2006. As a result, our historical financial results for periods prior to March 31, 2006 do not include the financial results from the operation of this asset.


	•	On March 27, 2006, Eagle Rock Pipeline completed a private placement of 5,455,050 common units for $98.3 million to fund our Brookeland/Masters Creek acquisition.

	•	On March 31, 2006, we purchased an 80% interest in the Brookeland gathering and processing facility, a 76.3% interest in the Masters Creek gathering system and 100% of the Jasper NGL line from Duke Energy Field Services. On April 7, 2006, we purchased the remaining interest in the Brookeland and Masters Creek facilities owned by Swift Energy Corporation for a total purchase price of approximately $95.7 million. The acquired assets are located in southeast Texas and complement our existing southeast Texas assets. As a result, our historical financial results for periods prior to March 31, 2006 do not include the financial results from our ownership of these assets.


	•	On June 2, 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. These common units in Eagle Rock Pipeline will be converted into common units in us upon


		consummation of this offering on approximately a 1-for-0.719 common unit basis. 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 acquired operations are located in Roberts County in the Texas Panhandle within our East Panhandle System. We expect this acquisition to provide significant synergies and gathering and processing capacity and to enhance our strategic presence in the area. As a result, our historical financial results for the periods prior to June 2, 2006, do not include the financial results from our ownership of these interests.

Critical Accounting Policies and Estimates

Conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates which by their nature bear the risk of change related to our inability to accurately forecast a future event and its potential impact. Given that a substantial portion of our operations were acquired within the past nine months, we have limited historical data with which to judge the accuracy of our current estimates. At this point in time, we do not foresee any reasonably likely changes to our current estimates and assumptions that would materially affect amounts reported in the financial statements and notes. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.

Revenue and Cost of Sales Recognition. We record revenue and cost of sales on the gross basis for those transactions where we act as the principal and take title to gas that is purchased for resale. When our customers pay us a fee for providing a service such as gathering or transportation we record the fees separately in revenues.

We currently record the monthly results of operations using actual results which include settling most of our volumes with producers, shippers and customers around the 25th of the month following the production month. This process results in a delay in reporting results.

Risk Management Activities. In order to protect ourselves from commodity and interest rate risk, we pursue hedging activities to minimize those risks. These hedging activities rely upon forecasts of our expected operations and financial structure over the next five years. If our operations or financial structure are significantly different from these forecasts, we could be subject to adverse financial results as a result of these hedging activities. We mitigate this potential exposure by retaining an operational cushion between our forecasted transactions and the level of hedging activity executed.

From the inception of our hedging program in October 2005 through June, 2006, we usedmark-to-market accounting for our commodity hedges and interest rate swaps. For the one month ended December 31, 2005, the amount of net unrealized gain was $5.7 million. For the six months ended June 30, 2006, we incurred $26.2 million of realized and unrealized losses, net, $0.5 million of which was a realized gain and $26.7 million of which was an unrealized loss, net. We record realized gains and losses on hedge instruments monthly based upon the cash settlements and the expiration of option premiums. The settlement amounts vary due to the volatility in the commodity market prices throughout each month. We also record unrealized gains and losses monthly based upon the future value of the hedges through their expiration dates. The expiration dates vary but are currently no later than December 2011 for our interest rate hedges, and December 2010 for our commodity hedges. We monitor and review hedging positions regularly.

Depreciation Expense and Cost Capitalization Policies. Our assets consist primarily of natural gas gathering pipelines, processing plants and transmission pipelines. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the costs of funds used in construction. The cost of funds used in construction

represents capitalized interest used to finance the construction of new facilities. These costs are then expensed over the life of the constructed asset through the recording of depreciation expense.

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

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

Impairment of Goodwill and Long-Lived Assets — We assess our goodwill for impairment at least annually based on Statement of Financial Accounting Standards (“SFAS”) No. 142,Goodwill and Other Intangible Assets. An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with SFAS No. 142, to the book value. If the fair value is less than the book value, an impairment is indicated and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, we will record an impairment charge. We performed our annual tests of goodwill as of January 1, 2004 and 2005, and there was no impairment indicated.

We assess our long-lived assets for impairment based on SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

Examples of long-lived asset impairment indicators include:


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

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

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

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

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

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

Environmental Remediation. Current accounting guidelines require us to recognize a liability and expense associated with environmental remediation if (i) government agencies mandate such activities or one of our properties were added to the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) database, (ii) the existence of a liability is probable and (iii) the amount can be reasonably estimated. To date, we have recorded a $300,000 liability for remediation expenses. If governmental regulations change, we could be required to incur additional remediation costs that might have a material impact on our profitability.

As a result of the adoption of Statement of Financial Accounting Standards, or SFAS, No. 143Accounting for Asset Retirement Obligations, Eagle Rock Pipeline recorded a long-term liability of approximately $0.7 million in 2005. The related depreciation and amortization expense is immaterial to its financial statements.

Eagle Rock Predecessor Results of Operations

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. The following table is a summary of the results of operations of Eagle Rock Predecessor for the two years ended December 31, 2003 and 2004 and the eleven months ended November 30, 2005.


	Year Ended			Year Ended			Eleven Months Ended
	December 31,			December 31,			November 30,
	2003			2004			2005

Operating revenues	$	297,289,534		$	335,518,977		$	396,953,100
Purchases of natural gas and NGLs		249,283,649			263,840,261			316,978,910

Segment gross margin(a)		48,005,885			71,678,716			79,974,190
Operating and maintenance expense(b)		23,904,472			27,426,941			27,518,496
Net other income		51,752			23,145			17,312
Cumulative effect changes in accounting policy		227,083

EBITDA(c)		23,926,082			44,274,920			52,473,006
Depreciation and amortization expense		7,187,244			8,267,893			8,157,159
Interest income		(189,598	)		(645,329	)		(858,793	)
Income taxes(d)		6,071,125			12,730,580			15,811,124

Net income	$	10,857,311		$	23,921,776		$	29,363,516

Operating Data:
Natural gas sales (MMBtu/d)		77,047			73,556			72,775
NGL sales (Bbls/d)		13,792			13,520			13,169


(a)	Segment gross margin consists of total revenues less cost of natural gas and NGLs. Please read “Summary — Non-GAAP Financial Matters.”


(b)		Operating and maintenance expense includes the “push-down” of corporate general & administrative expenses incurred and allocated to Eagle Rock Predecessor and ad valorem taxes.

(c)		EBITDA consists of net income plus depreciation and amortization expense. Please read “Summary — Non-GAAP Financial Measures.”

(d)		In 2001, Eagle Rock Predecessor elected to be treated as a C corporation. As a result, deferred income taxes are recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities.


	*Year Ended December 31, 2004 Compared with the Eleven Months Ended November 30, 2005*

Operating Revenues. Total operating revenues increased $61.4 million, or 18.3%, from $335.5 million for the year ended December 31, 2004 to $397 million for the eleven months ended November 30, 2005. This increase was primarily due to the following factors:


	•	The Oil Price Information Service average composite NGL pricing increased from $0.992/gal in 2004 to $1.241/gal for the first eleven months of 2005, an increase of $0.249/gal or 25.1%. The average NYMEX daily settlement price of natural gas increased from $5.90/MMBtu in 2004 to $8.51/MMBtu for the first eleven months of 2005, an increase of $2.61/MMBtu or 44.2%. The average NYMEX daily settlement price of crude oil, on which condensate prices are based, increased from $41.51/Bbl in 2004 to $56.34/Bbl for the first eleven months of 2005, an increase of $14.83/Bbl or 35.7%.

	•	NGL volumes were 13,520 Bbls/d in 2004 compared to 13,169 Bbls/d during the first eleven months of 2005, a decrease of 351 Bbls/d, or 2.6%. Natural gas sales volumes were 73,556 MMBtu/d in 2004 compared to 72,775 MMBtu/d during the first eleven months of 2005, a decrease of 781 MMBtu/d, or 1.1%. Condensate volumes were 1,186 Bbls/d in 2004 compared to 1,577 Bbls/d during the first eleven months of 2005, an increase of 391 Bbls/d, or 33.0%.

The change in operating revenues from the twelve months ended in December 31, 2004 to the eleven months ended November 30, 2005 was also affected by the difference in the number of months between the two periods. For the month of December 2005, operating revenues were $42.9 million.

Purchases of Natural Gas and NGLs. Purchases of natural gas and NGLs increased $53.1 million, or 20.1%, from $263.8 million as of December 31, 2004 to $317.0 million as of November 30, 2005. This increase was primarily due to the higher cost of natural gas and NGLs as described above, as volumes remained relatively stable from one period to the next. The change in the purchases of natural gas and NGLs from the twelve months ended December 31, 2005 to the eleven months ended November 30, 2005 was also affected by the difference in the number of months between the two periods. For the month of December 2005, purchases of natural gas and NGLs were $35.2 million.

Segment Gross Margin.As a result of the above changes in revenue and cost of sales, segment gross margin increased $8.3 million, or 11.6%, from $71.7 million as of December 31, 2004 to $80.0 million as of November 30, 2005. The change in segment gross margin from the twelve months ended December 31, 2005 to the eleven months ended November 30, 2005 was also affected by the difference in the number of months between the two periods. For the month of December 2005, segment gross margin was $7.7 million.

Operating and Maintenance Expense. Operating and maintenance expense increased $0.1 million, or 0.3%, from $27.4 million as of December 31, 2004 to $27.5 million as of November 30, 2005. General and administrative expense for the periods ended December 31, 2004 and November 30, 2005 was incurred at ONEOK’s corporate office and allocated to its different assets. As such, this allocation is made in the operating and maintenance expense section above. The change in operating and maintenance expense from the twelve months ended in December 31, 2005 to the eleven months ended November 30, 2005 was also affected by the difference in the number of months between the two periods. For the month of December 2005, operating and maintenance expense was $1.8 million.

Depreciation and Amortization Expense. Depreciation and amortization decreased $0.1 million, or 1.3%, from $8.3 million as of December 31, 2004 to $8.2 million as of November 30, 2005. The change in depreciation and amortization expense from the twelve months ended December 31, 2005 to the eleven months ended November 30, 2005 was also affected by the difference in the number of months between the two periods. For the month of December 2005, depreciation and amortization expense was $3.0 million.

Interest Income, Net. Net interest income increased $0.2 million, or 33.1%, from $0.6 million as of December 31, 2004 to $0.9 million as of November 30, 2005 due to higher cash generation during 2005.

Income Taxes. Federal income tax increased by $3.1 million, or 24.2%, from $12.7 million as of December 31, 2004 to $15.8 million as of November 30, 2005 as a result of higher pre-tax income.


	*Year Ended December 31, 2003 Compared with Year Ended December 31, 2004*

Operating Revenues. Total operating revenues increased $38.2 million, or 12.9%, from $297.3 million in 2003 to $335.5 million in 2004 . This increase was primarily due to the following factors:


	•	The Oil Price Information Service average composite NGL pricing increased from $0.764/gal in 2003 to $0.992/gal in 2004. The average NYMEX daily settlement price of natural gas increased from $5.49/MMBtu in 2003 to $5.90/ MMBtu in 2004, an increase of $0.41/MMBtu or 7.5%. The average NYMEX daily settlement price of crude oil, or which condensate prices are based, increased from $31.06/Bbl in 2003 to $41.51/Bbl in 2004, an increase of $10.45/Bbl or 33.6%.

	•	NGL volumes were 13,792 Bbls/d in 2003 compared to 13,520 Bbls/d in 2004, a decrease of 272 Bbls/d, or 2.0%. Natural gas sales volumes were 77,047 MMBtu/d in 2003 compared to 73,556 MMBtu/d in 2004, a decrease of 3,491 MMBtu/d, or 4.5%. Condensate volumes were 1,589 Bbls/d in 2003 compared to 1,186 Bbls/d in 2004, a decrease of 403 Bbls/d, or 25.4%.

Purchases of Natural Gas and NGLs. Purchases of natural gas and NGLs increased $14.6 million, or 5.8%, from $249.3 million in 2003 to $263.8 million in 2004. This increase was primarily due to the higher cost of natural gas and NGLs. See a description of the price changes above.

Segment Gross Margin. Segment gross margin increased $23.7 million, or 49.3%, from $48.0 million in 2003 to $71.7 million in 2004, primarily as a result of the above changes in revenue and cost of sales.

Operating and Maintenance Expense. Operating and maintenance expense increased $3.5 million, or 14.7%, from $23.9 million in 2003 to $27.4 million in 2004. This increase was primarily the result of higher utility costs, higher auto expense primarily as a result of higher fuel costs, higher compressor rental fees and increased parts costs and usage. General and administrative expense for the periods of 2003 and 2004 was incurred at ONEOK’s corporate office and allocated to its different assets. As such, this allocation is made in the operating and maintenance expense section above.

Depreciation and Amortization Expense. Depreciation and amortization increased $1.1 million, or 15.0%, from $7.2 million in 2003 to $8.3 million in 2004, primarily as a result of capitalized maintenance expenses and investment projects.

Interest Income, Net. Interest income, increased $0.5 million, or 240.4%, from $0.2 million in 2003 to $0.6 million in 2004 due to higher cash flow generation during 2004.

Income Taxes. Federal income tax increased by $6.7 million, or 109.7%, from $6.1 million in 2003 to $12.7 million in 2004 as a result of higher pre-tax income.

Eagle Rock Pipeline Results of Operations

The following table is a summary of the results of operations of Eagle Rock Pipeline for the three years ended December 31, 2003, 2004 and 2005 and the six months ended June 30, 2005 and 2006.


			Year Ended			Year Ended			Year Ended			Six Months			Six Months
			December 31,			December, 31,			December 31,			Ended June 30,			Ended June 30,
			2003			2004			2005			2005			2006

Operating revenues:
	Sales of natural gas, NGLs and condensate		$	—		$	9,837,322		$	59,920,664		$	9,620,044		$	240,171,539
	Compressing, gathering and processing services			—			798,847			6,247,438			469,264			5,946,157
	Gain (loss) on risk management instruments			—			—			7,308,130			—			(35,240,327	)
	Other			—			—			213,920			204,681			326,912

		Total operating revenues					10,636,169			73,690,152			10,293,989			211,204,281
	Purchases of natural gas and cost of natural gas and NGLs			—			8,811,311			55,271,501			8,845,312			188,235,809

Segment gross margin(a)							1,824,858			18,418,651			1,448,677			22,968,472
	Operating and maintenance expense			—			34,639			2,954,978			339,552			14,797,796
	General and administrative expense			144,045			2,405,658			4,765,420			926,118			6,010,748
	Depreciation and amortization expense			—			618,925			4,088,131			519,743			20,214,617
	Interest and other income			—			(24,224	)		(171,043	)		(48,326	)		(39,764	)
	Interest expense			—			—			4,031,369			—			5,962,994
	Income Tax Provision			—			—			—			—			507,855

(Loss) income from continuing operations				(144,045	)		(1,210,140	)		2,749,796			(288,410	)		(24,485,774	)
Income from discontinued operations				532,547			22,192,121			—			—			—

Net income (loss)			$	388,502		$	20,981,981		$	2,749,796		$	(288,410	)	$	(24,485,774	)

EBITDA(b)			$	388,502		$	21,600,906		$	10,869,296		$	183,007		$	2,199,692
Adjusted EBITDA(c)			$	(144,045	)	$	(591,215	)	$	3,561,166		$	183,007		$	38,010,800


(a)	Segment gross margin consists of total revenues less cost of natural gas and NGLs. Please read “Summary — Non-GAAP Financial Matters” on page .


(b)		EBITDA consists of net income plus depreciation and amortization expense. Please read “Summary — Non-GAAP Financial Measures.”

(c)		Adjusted EBITDA consists of net income plus depreciation and amortization expense minus non realized derivative gains (losses) minus net income from discontinued operations. Please read “Summary — Non-GAAP Financial Measures.”


	*Six Months Ended June 30, 2005 Compared with Six Months Ended June 30, 2006*

Financial results for the six months ended June 30, 2006 include six months of operations of the ONEOK Texas Field Services assets acquired on December 1, 2005, and are, therefore, not directly comparable to results for the six months ended June 30, 2005, which only include the operations of our pro-rata interests in the Indian Springs and Camp Ruby assets. With the ONEOK, Brookeland/Masters Creek and MGS acquisitions and the results of operations from the Tyler County pipeline, revenue increased by $200.9 million, or 1,951.7%, cost of sales increased $179.4 million, or 2,028.1%, and operating and maintenance expense increased by $14.5 million, or 4,258.0%. This significant increase in results is

directly attributable to the relative large scale of the assets acquired in relation to our previously existing business. As a result of our commodity hedging activities, total revenues include a loss of $35.2 million on risk management investments. As the forward curves for our hedged commodities shift in relation to the caps, floors, swap and strike prices at which we have executed our derivative instruments, the fair market value of such instruments changes through time. As of June 30, 2006, this change in market value translated into a $35.8 million non-cash, unrealized loss. In particular, forward curve movements for the period beginning with the execution of the hedges and ending December 31, 2005 produced an unrealized mark-to-market gain of $7.3 million. This gain reflects favorable price movements in natural gas which contributed $11.2 million in unrealized, mark-to-market gains, compensated by unfavorable price movements in NGLs and crude oil which contributed an $3.8 million unrealized, mark-to-market loss as of December 31, 2005. For the six months ended June 30, 2006, forward curve movements produced a $20.8 million unrealized, mark-to-market gain in natural gas and a $2.1 million unrealized, mark-to-market loss in NGLs and crude oil for a net unrealized, mark-to market loss of $18.7 million with respect to our original cost basis. This variance from a $7.3 million gain as of December 31, 2005, to a $18.7 million loss as of June 30, 2006 accounts for $26.0 million of the $35.8 million unrealized loss as of June 30, 2006. The $9.8 million remaining difference refers to the amortization of the premiums as the underlying options have expired, also a non-cash item. We had a $0.6 million realized gain on derivative activity for the six months ended June 30, 2006. Given the uncertainty surrounding future commodity prices and interest rates, and the general inability to predict these as they relate to the caps, floors, swaps and strike prices at which we have hedged our exposure, it is difficult to predict the magnitude and impact that marking our hedges to market will have on our income from operations in the future. Conversely, negative commodity price movements affecting our revenues and costs are expected to be compensated by our executed derivative instruments. For the six months ended June 30, 2005, we had no derivative instruments in place. General and administrative expense also increased by $5.1 million, or 5,490.3%, as Eagle Rock Pipeline built up its corporate infrastructure and personnel to manage the acquired assets. As the purchase price of the acquired assets was pushed down to Eagle Rock Pipeline’s balance sheet, depreciation and amortization expense also increased by $19.7 million, or 3,789.4%. As the acquisition was partly financed with a $400 million term loan facility, interest expense, net increased by $6.0 million, including interest swap unrealized gains of $9.1 million, whereas we were previously unleveraged as of June 30, 2005. In addition, we recorded $0.5 million of income taxes related to temporary differences caused by the Texas entity level tax that will become effective in 2008.


	*Year Ended December 31, 2004 Compared with Year Ended December 31, 2005*

Financial results as of December 31, 2005 include one month of operations of the ONEOK Texas Field Services assets acquired on December 1, 2005, and are, therefore, not directly comparable to results as of December 31, 2004. Prior to this acquisition, Eagle Rock Pipeline owned pro-rata, non-operated interests in the Indian Springs and Camp Ruby assets, and had begun construction of the Tyler County pipeline. With the ONEOK acquisition, revenue increased by $63.1 million, or 592.8%, cost of natural gas and NGLs increased by $46.5 million, or 527.3%, and operating and maintenance expense increased by $2.9 million, from December 31, 2004 to December 31, 2005. This significant increase in results is directly attributable to the relative large scale of the assets acquired in relation to our previously existing business. General and administrative expenses also increased by $2.4 million, or 98.1%, as Eagle Rock Pipeline built up its corporate infrastructure and personnel to manage the acquired assets. Depreciation and amortization expense increased by $3.5 million, or 560.5% as a result of the ONEOK acquisition. As the ONEOK acquisition was partly financed with a $400 million term loan facility, interest expense increased by $4.0 million, including interest rate swap unrealized losses of $1.6 million, whereas we were previously unleveraged as of December 31, 2004. During the year ended December 31, 2004, $22.2 million was recognized as income from discontinued operations related to the gain on the sale and the results of operations of the Dry Trail plant in 2004.


	*Year Ended December 31, 2003 Compared with Year Ended December 31, 2004*

Financial results as of December 31, 2004 include six months of operations of the Dry Trail plant sold in July 2004 as income from discontinued operations and six months of operations of the Indian Springs and Camp Ruby assets acquired in July 2004. As the Dry Trail plant was itself acquired on December 3, 2003, the results as of December 31, 2003 reflect only one month of operations as income from discontinued operations and, therefore, the financial results for the years ended December 31, 2004 and 2003 are also not directly comparable. General and administrative expense increased by $2.3 million due to increased corporate infrastructure as the company increased its activities and added personnel. Income from discontinued operations increased by $21.7 million as it included the gain on the sale of the Dry Trail plant in 2004.

Other Matters

Hurricanes Katrina and Rita. Hurricanes Katrina and Rita struck the Gulf Coast region of the United States on August 29, 2005 and September 24, 2005, respectively, causing widespread damage to the energy infrastructure in the region. The storms did not cause material direct damage to any of our assets in the region. The storms have negatively affected our nation’s short-term energy supply and natural gas and NGL prices have increased significantly. We expect these higher commodity prices to have a favorable net effect on our results of operations, as we are a net seller of NGLs.

While neither Hurricane Katrina nor Hurricane Rita caused material direct damage to our facilities, Hurricane Rita did disrupt the operations of NGL pipelines and fractionators in the Houston, Texas area and cause power outages to some of our producers in the southeast Texas area. As a result of these disruptions, we were forced to temporarily curtail certain of our producers in the region for approximately four days and to operate our Indian Springs facility in a reduced recovery mode for approximately six days. We do not expect ongoing effects from these temporary disruptions and neither hurricane altered our completion of the Tyler County pipeline.

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

Environmental. A Phase I environmental study was performed on our Texas Panhandle assets by an environmental consultant engaged by us in connection with our pre-acquisition due diligence process in 2005. As a result of performing the Phase I environmental study, we are planning to conduct environmental investigations at 11 properties, the costs of which are estimated to collectively range between $160,000 and $398,000 and for which we have accrued reserves in the amount of $300,000 as of December 31, 2005. Depending on the findings made during those investigations, and in anticipation of implementing amended SPCC plans at multiple locations as well as performing selected cavern closures, we estimate that an additional $1.2 million to $2.5 million in costs could be incurred by us in resolving environmental issues at those properties. We believe that the likelihood that we will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, (1) we are entitled to indemnification with respect to certain environmental liabilities retained by prior owners of these properties, and (2) we purchased an environmental pollution liability insurance policy. The policy pays foron-siteclean-up as well as costs and damages to third parties and currently has a one-year term with a $5.0 million limit subject to a $0.5 million deductible. We expect to renew this policy on an annual basis.

Liquidity and Capital Resources

Historically, our sources of liquidity have included cash generated from operations, equity investments by our owners and borrowings under our credit facilities.

Following the completion of this offering, we expect our sources of liquidity to include:


	•	cash generated from operations;

	•	borrowings under our credit facilities;

	•	debt offerings; and

	•	issuance of additional partnership units.

We believe that the cash generated from these sources will be sufficient to meet our minimum quarterly cash distributions and our requirements for short-term working capital and long-term capital expenditures for the next twelve months.


	*Cash Flows and Capital Expenditures*

Since our inception in 2003 through June 30, 2006, 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 an equity contribution from NGP 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 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 contributions from NGP; and


	•	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.

Working Capital (Deficit). Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. The working capital at Eagle Rock Pipeline was $8.1 million at December 31, 2004, $29.2 million at December 31, 2005 and $16.8 million as of June 30, 2006.

The net increase in working capital from December 31, 2004 to December 31, 2005 of $21.1 million resulted primarily from the following factors:


	•	cash balances increased by $11.1 million as a result of excess equity contributions from Natural Gas Partners made to finance the ONEOK transaction and for working capital purposes. Cash flow from operations before working capital changes accounted for $6.9 million of this increase;


	•	The outstanding balance of trade accounts receivable increased by $43.4 million at December 31, 2005 from ONEOK subsidiaries as a result of the operation of the ONEOK assets, as compared to a balance of $0.1 million at December 31, 2004;


	•	derivative assets increased by a net amount of $19.6 million as of December 31, 2005 as a result of the company’s hedging strategy implemented in relation to the ONEOK acquisition andmarket-to-market gains, as compared to a zero balance as of December 31, 2004;

	•	prepayments and other current assets increased by $1.2 million from December 31, 2004 to December 31, 2005 as a result of prepaid expenses incurred with the ONEOK acquisition; and

	•	current liabilities increased by $56.5 million from December 31, 2004 to December 31, 2005, $43.1 million of which is related to an increase in accounts payable related to the operation of the ONEOK assets, a $5.0 million increase related to Natural Gas Partner’s excess equity contribution described above which was not utilized by us for working capital purposes, $3.9 million is related to the short-term portion of our long-term debt and $2.3 million related to accrued liabilities.

With respect to the net risk management liabilities arising from hedging activities, our cash flows from the sale of products at their market prices will allow us to satisfy these obligations should they materialize.

The net decrease in working capital of $12.4 million from December 31, 2005 to June 30, 2006 resulted primarily from the following factors:



	•	cash balances decreased overall by $12.3 million as we used $108 million in cash for investing activities including the Brookeland/Masters Creek and the MGS acquisitions, as well as in the execution of several capital projects. These investment activities were primarily financed by the $98.3 million equity contribution of the Private Investors partially compensated with net uses for the repayment of our revolver facility and long-term debt, distributions to members and affiliates and other uses of $17.6 million for a net financing cash flow total of $80.7 million. Cash flow from operations generated an additional $15.0 million;


	•	trade accounts receivable decreased by $1.0 million as a result of normal operations;

	•	derivative assets decreased by a net $14.5 million as of June 30, 2006 as a result of the company’s hedging strategymark-to-market losses and premium amortization with respect to December 31, 2005;

	•	prepayments and other current assets decreased by $0.5 million from December 31, 2005 to June 30, 2006; and


	•	current liabilities decreased by $15.9 million from December 31, 2005 to June 30, 2006, $13.6 million of which is related to a decrease in accounts payable, the payment of $5.0 million to Natural Gas Partners, a $0.6 million decrease in risk management liabilities, and a $0.6 million decrease in current maturities on long-term debt offset by a $3.9 million increase in accrued liabilities.


	*Cash Flows*


	Eagle Rock Predecessor

Cash Flows from Operations. Cash flows from operations were $41.8 million at December 31, 2004 and $47.6 million at November 30, 2005. The increase in operating cash flows during the eleven months ended November 30, 2005 as compared to the twelve months ended December 31, 2004 resulted primarily from:


	•	an increase in segment gross margin by $8.3 million during the period resulting from a more favorable pricing environment;

	•	partially offset by higher income taxes paid of $3.1 million; and

	•	changes in working capital which contributed an additional $6.2 million.

For the twelve-months ended December 31, 2003, cash flows from operations were $32.2 million. The $9.6 million, or 29.8%, increase in cash flows from operations from the twelve-month period ended December 31, 2003 to the twelve-month period ended December 31, 2004 is mainly attributable to:


	•	favorable pricing environments, which increased segment gross margin by $23.7 million during the period;

	•	partially offset by higher operating and maintenance expenses, which increased by $2.8 million;

	•	partially offset by higher income taxes expense of $6.7 million; and

	•	changes in working capital, which decreased by $0.9 million.

Cash Flows Used in Investing Activities. Cash flows used in investing activities for the eleven months ended November 30, 2005 increased by $1.1 million, or approximately 20.5%, over the twelve-month period ended December 31, 2004.

Items comprising our investing activities during the eleven-month period ended November 30, 2005 include net maintenance and well-connect capital expenditures totaling $6.7 million, compared to $5.6 million for the twelve-month period ended December 31, 2004.

Cash flows used in investing activities during the twelve-month periods ended December 31, 2004 and December 31, 2003 were $5.6 million and $5.2 million, respectively, an increase of $0.4 million, or 7.0%. These figures are comprised mainly by net maintenance and well-connect capital expenditures.

Cash Flows Provided (Used) by Financing Activities. Cash flows used in financing activities for the eleven months ended November 30, 2005 increased by $4.6 million, or approximately 12.8%, over the twelve-month period ended December 31, 2004.

Our financing cash flows during the eleven months ended November 30, 2005 were $40.9 million, consisting of:


	•	the elimination of an intercompany note payable, as part of a balance sheet recapitalization, for an amount of $93.4 million. This was partially offset by an intercompany dividend, also part of the recapitalization transaction for $77.7 million, for net financing cash flows of $15.7 million; and

	•	offset by the $56.6 million effect of corporate cash management activities.

Financing cash flows during the twelve-month periods ended December 31, 2004 and December 31, 2003 were $36.2 million and $27.0 million, respectively, for an increase of $9.2 million, or 34.1%. During 2004, cash balances remitted to the parent company accounted for $50.6 million of positive cash flow, offset by a payoff of intercompany notes of $86.9 million. During 2003, cash balances remitted to the parent company accounted for a use of financing cash flow of $27.0 million.


	Eagle Rock Pipeline, L.P.

Cash Flows from Operations. Cash flows from operations were $3.7 million at December 31, 2004, ($1.7) million at December 31, 2005 and $15.0 million for the six months ended June 30, 2006. The decrease in operating cash flows during the twelve months ended December 31, 2005 as compared to the twelve months ended December 31, 2004 resulted primarily from:


	•	an increase in income from continuing operations to $2.7 million from a loss of $1.2 million reflecting the one month contribution from the ONEOK acquisition for December 2005;


	•	a net decrease in non-cash related items (depreciation, amortization and unrealized gains from derivative activity) to ($1.5) million of which ($5.7) million reflects a net unrealized gain from risk management activities and $4.2 million is related to depreciation and amortization; and



	•	changes in working capital used $2.9 million in cash flows reflecting an increase of $42.8 million in accounts receivable and an increase of $40.1 million in account payable as we took over the ONEOK acquisition without acquiring significant trade receivables and payables, resulting in a significant investment in working capital post acquisition.

The increase in operating cash flows during the six months ended June 30, 2006 as compared to the twelve months ended December 31, 2005 resulted primarily from:


	•	a decrease in income from continuing operations to ($24.5) million reflecting a loss of $26.7 million from risk management instruments. As a result of our commodity hedging activities, total revenues include a loss of $35.2 million on risk management investments. As the forward curves for our hedged commodities shift in relation to the caps, floors, swap and strike prices at which we have executed our derivative instruments, the fair market value of such instruments changes through time. As of June 30, 2006, this change in market value translated into a $35.8 million non-cash, unrealized loss. In particular, forward curve movements for the period beginning with the execution of the hedges and ending December 31, 2005 produced an unrealized mark-to-market gain of $7.3 million. This gain reflects favorable price movements in natural gas which contributed $11.2 million in unrealized, mark-to-market gains, compensated by unfavorable price movements in NGLs and crude oil which contributed an $3.8 million unrealized, mark-to-market loss as of December 31, 2005. For the six months ended June 30, 2006, forward curve movements produced a $20.8 million unrealized, mark-to-market gain in natural gas and a $2.1 million unrealized, mark-to-market loss in NGLs and crude oil for a net unrealized, mark-to market loss of $18.7 million with respect to our original cost basis. This variance from a $7.3 million gain as of December 31, 2005, to a $18.7 million loss as of June 30, 2006 accounts for $26.0 million of the $35.8 million unrealized loss as of June 30, 2006. The $9.8 million remaining difference refers to the amortization of the premiums as the underlying options have expired, also a non-cash item;

	•	a net increase in non-cash related items (depreciation, amortization and non-realized gains from derivative activity) to $47.4 million of which $20.6 million relates to depreciation and amortization and $26.7 million to mark-to-market value loss on risk management instruments, as described above; and

	•	changes in working capital which used $7.4 million in cash flow reflecting an increase of $1.9 million in accounts receivable, other current assets and other assets and a decrease of $9.3 million in accounts payable and accrued liabilities.

For all periods, we used our cash flows from operating activities primarily to fund our working capital requirements, which include operating expenses, maintenance capital expenditures and repayment of working capital borrowings. The maximum amounts of revolving line of credit borrowings outstanding during the twelve-months ended December 31, 2005 and the six months ended June 30, 2006 were $7.6 million and $7.6 million, respectively. We had no revolving line of credit borrowings during the twelve-months ended December 31, 2004. This $7.6 million draw under our revolver facility was used entirely to finance the earnest money deposit on the Brookeland/ Masters Creek acquisition from Duke Energy Field Services, L.P.

Cash Flows Used in Investing Activities. Our cash flows used in investing activities for the twelve months ended December 31, 2005 increased by $560.4 million over the twelve-month period ended December 31, 2004 from a net positive cash flow of $16.9 million in 2004 related to the sale of the Dry Trail plant to a negative $543.5 million in 2005.

Items comprising our investing activities during the twelve-month period ended December 31, 2005 include:



	•	the acquisition of the ONEOK assets, including intangible assets and transaction costs, for a total of $531.0 million;


	•	the construction of the Tyler County pipeline for $4.2 million; and

	•	the deposit of $7.6 million as earnest money on the Brookeland/Masters Creek acquisitions.

Our cash flows used in investing activities for the six months ended June 30, 2006 decreased by $435.5 million over the twelve-month period ended December 31, 2005 from a net use of $543.5 million in 2005 to a net use of $108.0 million in the six months ended June 30, 2006.

Items comprising our investing activities during the six-month period ended June 30, 2006 include:


	•	the acquisition of Duke Energy Field Services’ and Swift Energy Corporation’s interest in the Brookeland, Masters Creek and Jasper NGL pipeline for a total of $95.8 million;

	•	the acquisition of MGS’s partnership interest for a total consideration of $25 million of which $4.7 million was paid in cash.

	•	maintenance and growth capital expenditures in the Texas Panhandle for $5.4 million; and

	•	growth capital expenditures related to the Tyler County pipeline and corporate offices for $7.5 million.

Cash Flows Provided by Financing Activities. Our cash flows provided by financing activities for the twelve months ended December 31, 2005 increased by $570.3 million over the twelve-month period ended December 31, 2004, from a net negative financing cash flow of $14.0 million in 2004 related to the pre-payment of the Dry Trail plant credit facility, to a net positive financing cash flow of $556.3 million in 2005.

Our financing cash flows during the twelve months ended December 31, 2005 were $556.3 million, consisting primarily of:


	•	equity infusion by Natural Gas Partners and management of $192.4 million;

	•	the establishment and use of our $400 million credit facility to purchase the ONEOK assets;

	•	the draw of $7.6 million from our revolver facility to finance the earnest money deposit on the Brookeland and Masters Creek assets acquired from Duke Energy Field Services;

	•	the payment of $6.5 million in debt issuance cost; and

	•	the payment of $27.5 million in derivative contract premiums.

Our cash flows provided by financing activities for the six months ended June 30, 2006 decreased by $475.6 million over the twelve-month period ended December 31, 2005, from financing cash flows of $556.3 million in 2005, to positive financing cash flows of $80.7 million in the six months ended on June 30, 2006.

Our financing cash flows during the six months ended June 30, 2006 were $80.7 million, consisting primarily of:


	•	a $98.3 million equity infusion by the March 2006 Private Investors to finance the Brookeland/Masters Creek acquisition; and

	•	the net repayment of $7.6 million in revolver loans, $2.6 million in scheduled amortization of our term loan credit facility and other debt, $0.5 million in proceeds from derivative contracts, $0.9 million related to payments of debt issuance cost, and $1.3 million in deferred offering costs.

	•	Distributions to NGP of $5.0 million and tax distributions related to 2005 of $0.8 million.

Capital Requirements

The midstream energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as either:


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

	•	maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to meet regulatory requirements, to maintain the existing operating capacity of our assets and extend their useful lives or to maintain existing system volumes and related cash flows.

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We have budgeted $37.2 million in capital expenditures for the year ending December 31, 2006, of which $30.8 million represents growth capital expenditures and $6.3 million represents maintenance capital expenditures. For the twelve months ended December 31, 2005, our growth capital expenditures were $4.8 million and our maintenance capital expenditures were $0.0 million, including non-cash expenditures in accounts payable.

Since our inception in 2002, we have made substantial growth capital expenditures, including those relating to the acquisition of the Dry Trail plant, the Camp Ruby gathering system, the Indian Springs processing plant, the ONEOK assets and the Brookeland and Masters Creek gathering and processing assets. We anticipate that we will continue to make significant growth capital expenditures. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives.

Our forecast for the twelve months ending September 30, 2007 includes $12.3 million of identified organic growth capital expenditures. These expenditures relate to several projects, including the 10-mile East-West pipeline, the Red Deer processing plant start-up, the Kingsmill processing plant relocation andstart-up and the extension of our Tyler County pipeline. We expect that these growth capital expenditures will be funded by borrowings under our amended and restated credit facility.

We continually review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Because we will distribute most of our available cash to our unitholders, we will depend on borrowings under our amended and restated credit facility and the incurrence of debt and equity securities to finance any future growth capital expenditures or acquisitions. The upward trend in interest rates experienced recently will increase our borrowing costs on additional debt financing incurred to finance future acquisitions, as compared to our borrowing costs under our currently hedged credit facility.


	*Senior Secured Credit Facility*

On December 1, 2005, in connection with our acquisition of the ONEOK assets we, through our subsidiary Eagle Rock Gas Gathering & Processing, Ltd., entered into a $475 million credit agreement with a syndicate of commercial and investment banks, including Goldman Sachs Credit Partners L.P., as the administrative agent. The credit agreement originally provided for $400 million aggregate principal amount of series A term loans and up to $75.0 million aggregate principal amount of revolving commitments. The revolver facility was increased to $100 million in June 2006. The credit agreement included a sub-limit for the issuance of standby letters of credit for the lesser of $55.0 million or the aggregate unused amount of the revolver. At June 30, 2006, we had $398 million outstanding under the term loan and $0.0 million outstanding under the revolver.

The principal amount due under the term loan was required to be repaid in consecutive quarterly installments on the four quarterly scheduled interest payment dates per year applicable to the term loan, commencing April 1, 2006 and ending January 1, 2012, in an amount equal to one-quarter percent (0.25%) of the original principal amount outstanding with the remaining outstanding principal amount due December 1, 2012. The revolver matures on December 1, 2010.

The credit agreement contained covenants, which, among other things, required us, on a consolidated basis, to maintain specified ratios or conditions as follows:


	•	EBITDA (as defined) to interest expense of not less than 2.0 to 1.0 through December 31, 2006 and 2.5 to 1.0 thereafter; and

	•	Total senior debt to EBITDA of not more than 6.0 to 1.0 through December 31, 2006 and 5.0 to 1.0 thereafter;

We believe that we were in compliance with the financial covenants under the credit agreement as of June 30, 2006.

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At our election, the term loan and the revolver would bear interest on the unpaid principal amount either at a base rate plus the applicable margin (defined as 1.50% per annum); or at the adjusted eurodollar rate plus the applicable margin (defined as 2.50% per annum). The applicable margin would increase permanently by 0.50% per annum on September 1, 2006 if by such date the loans under this credit agreement have not obtained a rating by both Moody’s and Standard & Poor’s, and (b) each applicable margin set forth would decrease by 0.25% per annum on the date that the loans under the credit agreement obtain ratings equal to or greater than Ba3 by Moody’s and BB- by S&P, which decrease would remain in effect so long as such ratings were maintained.

Our obligations under the credit agreement were secured by first priority liens on substantially all of our assets, including a pledge of all of the outstanding interests of each of our subsidiaries.

On March 31, 2006, in connection with a private equity financing round and the acquisition of the Brookeland and Masters Creek assets from Duke Energy Field Services and Swift Energy Corporation, we amended the credit agreement to allow us to make quarterly cash distributions to the Private Investors prior to excess cash flow being swept to reduce principal. In addition, our capital expenditure and permitted acquisition baskets were increased to $28.0 million and $150 million, respectively, in 2006.


	*Amended and Restated Credit Agreement*

On August 31, 2006, we entered into an amended and restated credit facility that provides for $300 million aggregate principal amount of Series B Term Loans and up to $200 million aggregate principal amount of revolving commitments. The amended and restated credit agreement includes a sub limit for the issuance of standby letters of credit for the aggregate unused amount of the revolver. At August 31, 2006, we had $300 million outstanding under the term loan, $97.0 million outstanding under the revolver and $13.7 million of outstanding letters of credit. At our election, the term loan and the revolver bear interest on the unpaid principal amount either at a base rate plus the applicable margin (defined as 1.25% per annum, reducing to 1.00% when consolidated funded debt to EBITDA (as defined) is less than 3.5 to 1); or at the adjusted eurodollar rate plus the applicable margin (defined as 2.25% per annum, reducing to 2.00% when consolidated funded debt to EBITDA (as defined) is less than 3.5 to 1). At August 31, 2006, we elected the eurodollar rate plus the applicable margin (defined as 2.25%) for a cumulative rate of 7.65%. The applicable margin will increase permanently by 0.50% per annum on January 31, 2007 if by such date the loans under this amended and restated credit agreement have not obtained a rating by both S&P and Moody’s, and (b) each applicable margin set forth shall decrease by 0.25% per annum on the date that the loans under the amended and restated credit agreement obtain ratings equal to or greater than Ba3 by Moody’s and BB- by S&P, which decrease shall remain in effect so long as such ratings are maintained.

Base rate interest loans are paid the last day of each March, June, September and December. eurodollar rate loans are paid the last day of each interest period, representing one-, two-, three- or six-, nine- or twelve-months, as selected by us. Interest on the term loans is paid each December 31, March 31, June 30 and September 30 of each year, commencing on September 30, 2006. We pay a commitment fee equal to (1) the average of the daily difference between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding revolver loans plus the aggregate principal amount of all outstanding swing loans times (2) 0.50% per annum; provided, that the commitment fee percentage shall increase permanently by 0.25% per annum on January 31, 2007 if the loans under the amended and restated credit agreement have not obtained a rating by both S&P and Moody’s. We also pay a letter of credit fee equal to (1) the applicable margin for revolving loans that are eurodollar rate loans times (2) the average aggregate daily maximum amount available to be drawn under all such letters of credit (regardless of whether any conditions for drawing could then be met and determined as of the close of business on any date of determination). Additionally, we pay a fronting fee equal to 0.125%, per annum, times the average aggregate daily maximum amount available to be drawn under all letters of credit.

The obligations under the amended and restated credit agreement are secured by first priority liens on substantially all of our assets, including a pledge of all of the capital stock of each of our subsidiaries. In

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addition, the credit facility contains various covenants limiting our ability to incur indebtedness, grant liens and make distributions and certain financial covenants requiring us to maintain:


	•	an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, in each case as defined in the credit agreement) of not less than 2.5 to 1.0, determined as of the last day of each quarter for the four quarter period ending on the date of determination; and

	•	a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as defined in the credit agreement) of not more than 5.0 to 1.0 (or, on a temporary basis for not more than three consecutive quarters following the consummation of certain acquisitions, not more than 5.25 to 1.0).

We will use the available borrowing capacity under our amended and restated credit facility for working capital purposes, maintenance and growth capital expenditures and future acquisitions.

Off-Balance Sheet Transactions and Guarantees. We have no off-balance sheet transactions or obligations.

Debt Covenants. At June 30, 2006, we were in compliance with the covenants of the credit facilities.

Total Contractual Cash Obligations. The following table summarizes our total contractual cash obligations as of June 30, 2006. All of the $397 million of term loans outstanding on June 30, 2006 are scheduled for interest rate resets on three-month intervals. Interest rates were last reset for all amounts outstanding on August 31, 2006.


	Payments Due by Period

Contractual Obligations	Total		2005		2006		2007		2008-2009		Thereafter

	($ Millions)
Long-term debt (including interest)(1)	$	566.3	$	2.3	$	24.5	$	28.5	$	57.0	$	454.0
Operating leases		1.0		0.1		0.2		0.2		0.4		0.1
Purchase obligations(2)		—		—		—		—		—		—
Total contractual obligations	$	567.3	$	2.4	$	24.7	$	28.7	$	57.4	$	454.1



(1)	Assumes our fixed swapped average interest rate of 4.93% plus the applicable margin under our amended and restated credit agreement, which remains constant in all periods.


(2)	Excludes physical and financial purchases of natural gas, NGLs, and other energy commodities due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.

Recent Accounting Pronouncements

On October 6, 2005, Financial Accounting Standards Board, or the FASB, issued Staff Position FAS 13-1 concerning the accounting for rental expenses associated with operating leases for land or buildings that are incurred during a construction period. We considered how this might apply to our payment forrights-of-way associated with the construction of pipelines, and we do not anticipate any changes to our accounting practices or impacts on our results of operations or financial condition in light of the recently issued Staff Position FAS 13-1.

In May 2005, the FASB issued Statement of Financial Accounting Standard No. 154,Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3. This accounting standard is effective for fiscal years beginning after December 15, 2005. We do not believe the adoption of this accounting standard had a material adverse effect on our results of operations or financial condition.

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A significant portion of the Partnership’s sale and purchase arrangements are accounted for on a gross basis in the statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements that establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location at the same or at another specified date. These arrangements are detailed either jointly, in a single contract or separately, in individual contracts that are entered into concurrently or in contemplation of one another with a single or multiple counterparties. Both transactions require physical delivery of the natural gas and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk. In accordance with the provision of Emerging Issues Task Force Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (“EITF 04-13”), the Partnership reflects the amounts of revenues and purchases for these transactions as a net amount in its consolidated statements of operations beginning with April 2006. For the six month period ended June 30, 2006, the Partnership did not enter into any purchase and sale agreements with the same counterparty. As a result, the adoption of EITF 04-13 had no effect on operating income, net income or cash flows for the six months ended June 30, 2006.

Quantitative and Qualitative Disclosures About Market Risk


	*Risk and Accounting Policies*

We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Upon the closing of this offering, our management will establish comprehensive risk management policies and procedures to monitor and manage these market risks. Our general partner will be responsible for delegation of transaction authority levels, and the Risk Management Committee of our general partner will be responsible for the overall approval of market risk management policies. The Risk Management Committee will be composed of directors (including, on an ex officio basis, our chief executive officer) who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee will be responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.

See “— Critical Accounting Policies and Estimates — Risk Management Activities” for further discussion of the accounting for derivative contracts.


	*Commodity Price Risk*

We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and other commodities as a result of our gathering, processing and marketing activities, which produce a naturally long position in NGLs and a natural short position in natural gas. We attempt to mitigate commodity price risk exposure by matching pricing terms between our purchases and sales of commodities. To the extent that we market commodities in which pricing terms cannot be matched and there is a substantial risk of price exposure, we attempt to use financial hedges to mitigate the risk. It is our policy not to take any speculative marketing positions.

Both our profitability and our cash flow are affected by volatility in prevailing natural gas and NGL prices. Natural gas and NGL prices are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. Historically, changes in the prices of heavy NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil. For a discussion of the volatility of natural gas and NGL prices, please read “Risk Factors.” Adverse effects on our cash flow from increases in natural gas prices and decreases in NGL product prices could adversely affect our ability to make distributions to unitholders. We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in our areas of operations, and the use of derivative contracts. Our overall direct exposure to movements in natural gas prices is managed to minimize the risk of our natural short position for 2006 and 2007, the periods for which we have hedged our natural gas exposure to this point, as well as a result of natural hedges inherent

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in our contract portfolio. Natural gas prices, however, can also affect our profitability indirectly by influencing the level of drilling activity and related opportunities for our service. We are a seller of NGLs and are exposed to commodity price risk associated with downward movements in NGL prices. NGL prices have experienced volatility in recent years in response to changes in the supply and demand for NGLs and market uncertainty. In response to this volatility, we have instituted a hedging program to reduce our exposure to commodity price risk. Under this program, we have hedged substantially all of our share of expected NGL volumes underpercent-of-proceed and keep-whole contracts in 2006 and 2007 through the purchase of NGL put contracts, costless collar contracts and swap contracts. We have also hedged substantially all of our share of expected NGL volumes underpercent-of-proceed contracts from 2008 through 2010 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 and entered into swaps for the months of August and September 2006 to cover substantially all of our short natural gas position associated with ourkeep-whole volumes. We anticipate that after 2007, our short natural gas position will become a long natural gas position because of our increased volumes in the Texas Panhandle and the volumes contributed from our Brookeland/ Masters Creek acquisition. In addition, we intend to pursue fee-based arrangements, where market conditions permit, and to increase retained percentages of natural gas and NGLs underpercent-of-proceed arrangements. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

We have not designated our contracts as accounting hedges under Statement of Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities. As a result, we mark our derivatives to market with the resulting change in fair value included in our statement of operations.

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The following table sets forth certain information regarding our NGL options, valued as of December 31, 2005:


						Cap Strike		Floor Strike
			Notional			Price		Price		Fair Value
			Volumes
Commodity	Period		(Bbls)		Type	($/Bbl)		($/Bbl)		($)

Ethane		Jan-Dec 2006		144,000	Costless Collar	$	0.8200	$	0.6500	$	(148,817	)
		Jan-Dec 2006		288,000	Puts				0.6550		1,497,974
		Jan-Dec 2007		408,000	Puts				0.5396		1,797,085
		Jan-Dec 2008		102,000	Costless Collar		0.6500		0.5500		(332,765	)
		Jan-Dec 2009		120,000	Costless Collar		0.5800		0.4800		(653,362	)
		Jan-Dec 2010		108,000	Costless Collar		0.5300		0.4300		(735,429	)
Propane		Jan-Dec 2006		216,000	Costless Collar	$	1.1100	$	0.9500	$	(433,534	)
		Jan-Dec 2006		456,000	Puts				0.9864		4,443,302
		Jan-Dec 2007		636,000	Puts				0.9000		6,272,012
		Jan-Dec 2009		126,000	Costless Collar		0.8700		0.7650		(788,753	)
		Jan-Dec 2010		120,000	Costless Collar		0.8100		0.7050		(953,554	)
Normal Butane		Jan-Dec 2006		144,000	Costless Collar	$	1.2350	$	1.1250	$	(654,915	)
		Jan-Dec 2006		264,000	Puts				1.1575		2,713,315
		Jan-Dec 2007		384,000	Puts				1.0900		3,898,185
		Jan-Dec 2009		66,000	Costless Collar		1.0350		0.9350		(579,534	)
		Jan-Dec 2010		132,000	Costless Collar		1.0200		0.8200		(1,385,432	)
IsoButane		Jan-Dec 2006		48,000	Costless Collar	$	1.2250	$	1.1250	$	(270,728	)
		Jan-Dec 2006		120,000	Puts				1.1620		1,105,602
		Jan-Dec 2007		156,000	Puts				1.0888		1,839,885
		Jan-Dec 2009		30,000	Costless Collar		1.0350		0.9350		(292,822	)
		Jan-Dec 2010		60,000	Costless Collar		1.0200		0.8200		(683,518	)
Natural Gasoline		Jan-Dec 2006		216,000	Costless Collar	$	1.4100	$	1.2600	$	(670,817	)
		Jan-Dec 2006		384,000	Puts				1.3100		5,228,366
		Jan-Dec 2007		564,000	Puts				1.2413		9,937,493

Total										$	30,149,239

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The following table sets forth certain information regarding our NGL fixed swaps, valued as of December 31, 2005:


				Notional
				Volumes		Wt. Avg. $/Gallon				Fair Market Value

Commodity		Period		(MBbls)		We Receive		We Pay		($)

Ethane			Jan-Dec 2006		96	$	0.7750		OPIS avg	$	340,826
			Jan-Dec 2007		96		0.6950		OPIS avg		31,071
			Jan-Dec 2008		102		0.6000		OPIS avg		(328,700	)
			Jan-Dec 2009		120		0.5300		OPIS avg		(665,796	)
			Jan-Dec 2010		108		0.4800		OPIS avg		(752,220	)
Propane			Jan-Dec 2006		72	$	1.0000		OPIS avg	$	42,137
			Jan-Dec 2007		60		0.9300		OPIS avg		(147,866	)
			Jan-Dec 2009		126		0.8150		OPIS avg		(795,004	)
			Jan-Dec 2010		120		0.7550		OPIS avg		(963,172	)
Normal Butane			Jan-Dec 2006		24	$	1.1800		OPIS avg	$	(41,224	)
			Jan-Dec 2007		24		1.1400		OPIS avg		(87,784	)
			Jan-Dec 2009		66		0.9850		OPIS avg		(581,414	)
IsoButane			Jan-Dec 2006		12	$	1.1800		OPIS avg	$	(39,784	)
			Jan-Dec 2007		12		1.1400		OPIS avg		(57,509	)
			Jan-Dec 2009		30		0.9850		OPIS avg		(295,190	)

	Total									$	(4,341,629	)

The following table sets forth certain information regarding our crude oil options, valued as of December 31, 2005:


										Floor
								Cap Strike		Strike
				Notional				Price		Price		Fair Market Value
				Volumes
Period		Commodity		(Bbls)		Type		($/Bbl)		($/Bbl)		($)

Jan-Dec 2006			NYMEX WTI		552,000		Put			$	55.00	$	3,603,267
Jan-Dec 2007			NYMEX WTI		528,000		Put				50.00		4,338,814
Jan-Dec 2008			NYMEX WTI		960,000		Costless Collar	$	67.39		50.00		(3,485,465	)
Jan-Dec 2009			NYMEX WTI		480,000		Costless Collar		66.40		50.00		(1,401,027	)
Jan-Dec 2010			NYMEX WTI		480,000		Costless Collar		67.86		50.00		(826,858	)

	Total											$	2,228,731

In July, we entered into additional crude oil costless collars, as follows:

Floor

Notional

Cap Strike

Strike

Fair Market

Volumes

Price

Value

Period

Commodity

(Bbls)

Type

($Bbl)

(Thousands)

Oct-Dec 2006

NYMEX WTI

150,000

Costless Collar

88.38

70.00

Jan-Dec 2007

NYMEX WTI

720,000

Costless Collar

81.66

75.00


*	Denotes hedges that were executed in July 2006 and, therefore, cannot be valued as of December 31, 2005.

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Additionally, we entered into a swap agreement to hedge our WTS-WTI basis differential for a portion of our crude oil volumes, as follows:

Notional

Fair Market

Volumes

Wt. Avg. $/Bbl

Value

Period

Commodity

(Bbls)

Type

We Pay

We Receive

(Thousands)

Oct-Dec 2006

NYMEX WTI - WTS Differential

60,000

Swap

WTS

WTI - $

6.55

Jan-Dec 2007

NYMEX WTI - WTS Differential

240,000

Swap

WTS

WTI - $

6.05


*	Denotes hedges that were executed in July 2006 and, therefore, cannot be valued as of December 31, 2005.

The following table sets forth certain information regarding our natural gas options, valued as of December 31, 2005:

Wt. Avg.

Fair Market

Notional Volumes

Strike Price

Value

Period

Commodity

(MMBtu)

Type

($/MMBtu)

($)

Jan-Dec 2006

NYMEX Henry Hub

1,200,000

Calls

11.25

2,854,858

Jan-Dec 2007

NYMEX Henry Hub

1,200,000

Calls

9.63

3,868,443

Total

6,723,301

Additionally, we entered into swap agreements to hedge our short natural gas position for the months of August and September 2006 as follows:

Notional

Wt. Avg.

Fair Market

Volumes/month

$/MMBtu

Value

Period

Commodity

MMBtu

Type

We Pay

We Receive

(Thousands)

Aug-Sep 2006

Northern Demarcation Point

50,000

Swap

5.64

Northern Demarcation

Aug-Sep 2006

NGPL - Texok

50,000

Swap

5.72

NGPL - Texok


*	Denotes hedges executed in July 2006 and, therefore, cannot be valued as of December 31, 2005.

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


	Year Ended		Quarter Ending
	12/31/2005		6/30/2006

	($)		($)

Net risk management assets at beginning of period	$	—	$	33,160,420
Investment premiums		27,451,512		—
Cash received from settled contracts		—		(570,778	)
Settlements of positions		—		570,778
Unrealized mark-to-market valuations of positions		5,708,908		(26,723,498	)

Balance of risk management assets at end of period	$	33,160,420	$	6,436,922


	*Credit Risk*

Our purchase and resale of natural gas exposes us to credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss can be very large relative to our overall profitability. We are diligent in attempting to ensure that we issue credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral such as a letter of credit or parental guarantees.

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	*Interest Rate Risk*

The credit markets recently have experienced50-year record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will 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. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

We are exposed to variable interest rate risk as a result of borrowings under our existing credit agreement.

In December 2005, we entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into this swap is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments for a period of five years from January 1, 2006 to January 1, 2011. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense. The table below summarizes the terms, amounts received or paid and the fair values of the various interest swaps:


									Amounts		Fair Value
				Notional		Fixed			Paid in		December 31,
Effective Date		Expiration Date		Amount		Rate			2005		2005

				(Millions)
	01/03/2006		01/03/2011	$	100		4.9500	%		0.00	$	(610,724	)
	01/03/2006		01/03/2011		100		4.9625	%		0.00		(666,723	)
	01/03/2006		01/03/2011		50		4.8800	%		0.00		(173,247	)
	01/03/2006		01/03/2011		50		4.8800	%		0.00		(148,528	)

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BUSINESS

Our Partnership


	•	approximately 769 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with 33,726 horsepower of associated pipeline compression;

	•	two active natural gas processing plants with an aggregate capacity of 65 MMcf/d; and

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


	•	approximately 2,556 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with 81,178 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.

Our southeast Texas and Louisiana operations are primarily located in Polk, Tyler, Jasper and Newton counties, Texas and Vernon Parish, Louisiana. The facilities that comprise our southeast Texas and Louisiana operations consist of:


	•	approximately 850 miles of natural gas gathering pipelines, ranging from four inches to 12 inches in diameter, with 5,200 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; and

	•	a19-mile NGL pipeline.

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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, including its equity investment of approximately $191 million to help facilitate our acquisition of the Texas Panhandle Systems and other assets.

Business Strategies

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


	•	Maximizing the profitability of our existing assets. We intend to maximize the profitability of our existing assets by adding new volumes of natural gas and undertaking additional initiatives to enhance utilization and improve operating efficiencies. For example, we recently constructed a10-mile pipeline that connects our East and West Panhandle Systems. This allows us to flow gas from our East Panhandle System, which is capacity- constrained due to high levels of natural gas production, to our West Panhandle System, which currently has excess processing capacity. In addition, we plan to:


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

	•	improve the operations of our existing assets by relocating idle processing plants to areas experiencing increased processing demand, reconfiguring compression facilities, improving processing plant efficiencies and capturing lost and unaccounted for natural gas.


	•	Expanding our operations through organic growth projects. We intend to leverage our existing infrastructure and customer relationships by expanding our existing asset base to meet new or increased demand for midstream services. For example, we recently completed the construction of our Tyler County pipeline and subsequently commenced construction on a16-mile extension that will allow for the delivery of dedicated natural gas volumes to our Brookeland processing plant.

	•	Pursuing complementary acquisitions. We have grown significantly through acquisitions and will continue to employ a disciplined acquisition strategy that capitalizes on the operational experience of our management team. We believe that the extensive experience of our management team in acquiring and operating natural gas gathering and processing assets will enable us to continue to successfully identify and complete acquisitions that will enhance our profitability and increase our operating capacity. In pursuing this strategy, our management team seeks to identify:


	•	assets that are complementary to our existing facilities and provide opportunities for us to extract operational efficiencies and the potential to expand or increase the utilization of the acquired assets as well as our existing facilities;

	•	acquisitions in areas in which we do not currently operate that have significant natural gas reserves and are experiencing high levels of drilling activity; and

	•	acquisitions of mature assets with excess capacity that will allow us to capitalize on existing infrastructure, personnel and producer and customer relationships to provide an integrated package of services.


	•	Continuing to reduce our exposure to commodity price risk. We intend to continue to operate our business in a manner that reduces our exposure to commodity price risk. For example, we instituted a hedging program related to our NGL business and have hedged substantially all of our share of expected NGL volumes through 2007 through the purchase of NGL put contracts, costless collar contracts and swap contracts, and substantially all of our share of expected NGL volumes related to our percentage-of-proceeds contracts from 2008 through 2010 through a combination of direct NGL hedging as well as indirect hedging through crude oil costless collars. We have also hedged substantially all of our share of our short natural gas position for 2006 and 2007. We anticipate that

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		after 2007, our short natural gas position will become a long natural gas position because of our increased volumes in the Texas Panhandle and the volumes contributed from our acquisition of the Brookeland and Masters Creek systems. In addition, where market conditions permit, we intend to pursue fee-based arrangements and to increase retained percentages of natural gas and NGLs underpercent-of-proceeds arrangements.

	•	Maintaining a disciplined financial policy. We will continue to pursue a disciplined financial policy by maintaining a prudent capital structure, managing our exposure to interest rate and commodity price risk and conservatively managing our cash reserves. We are committed to maintaining a balanced capital structure, which will allow us to use our available capital to selectively pursue accretive investment opportunities.

Competitive Strengths

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


	•	Our assets are strategically located in major natural gas supply areas. Our assets are strategically located in the Texas Panhandle, southeast Texas and Louisiana. Our Texas Panhandle Systems are located in areas that produce natural gas with high NGL content, especially in the West Panhandle System. Our East Panhandle System is experiencing significant drilling activity related to the Granite Wash play and our West Panhandle System is connected to wells that generally have long lives with predictable, steady flow rates and minimal decline. Additionally, our southeast Texas and Louisiana assets, specifically in Tyler and Polk Counties, are located in areas characterized by high volumes of natural gas and significant drilling activity, which provides us with attractive opportunities to access newly developed natural gas supplies. We believe that our extensive existing presence in these regions, together with our available capacity and the limited alternatives available to local producers, provide us with a competitive advantage in capturing new supplies of natural gas.

	•	We provide a distinct and integrated package of midstream services. We provide a broad range of midstream services to natural gas producers, including gathering, compressing, treating, processing, transporting and selling natural gas and fractionating and transporting NGLs. For example, in the Texas Panhandle, we treat natural gas to extract impurities such as carbon dioxide and hydrogen sulfide and we fractionate NGLs to extract propane. Our competitors in this area do not provide these services. Additionally, many of our gathering systems, including our Texas Panhandle Systems, operate at lower inlet pressures, which allows us to provide gathering services to customers at a lower cost and on a more timely basis than our competitors, who are often required to add compression to provide gathering services to new wells.


	•	We have the financial flexibility to pursue growth opportunities. We currently have a $500 million amended and restated credit facility, under which we have approximately $89 million in available borrowing capacity for general partnership purposes, including capital expenditures and acquisitions. We believe the available capacity under this credit facility, combined with our expected ability to access the capital markets, will provide us with a flexible financial structure that will facilitate our strategic expansion and acquisition strategies.


	•	We have an experienced, knowledgeable management team with a proven record of performance. Our management team has a proven record of enhancing value through the investment in, and the acquisition, exploitation and integration of, natural gas midstream assets. Our senior management team has an average of over 22 years of industry-related experience. Our team’s extensive experience and contacts within the midstream industry provide a strong foundation for managing and enhancing our operations, accessing strategic acquisition opportunities and constructing new assets. After giving effect to this offering, members of our senior management team will have a substantial economic interest in us.

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	•	We are affiliated with Natural Gas Partners, a leading private equity capital source for the energy industry. Natural Gas Partners, a leading private equity firm focused on the energy industry, owns a significant equity position in Eagle Rock Holdings, L.P., which will own 3,459,236 common and 20,691,495 subordinated units and all of the equity interests in our general partner upon completion of this offering. We expect that our relationship with Natural Gas Partners will provide us with several significant benefits, including increased exposure to acquisition opportunities and access to a significant group of transactional and financial professionals with a successful track record of investing in midstream assets. 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.

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.”

Industry Overview

The midstream natural gas industry is the link between exploration and production of natural gas and the delivery of its components to end-use markets, and consists of the gathering, compressing, treating, processing, transportation and selling of natural gas, and the transportation and selling of NGLs.

Natural Gas Demand and Production. Natural gas is a critical component of energy consumption in the United States. According to the Energy Information Administration, or the EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.1 trillion cubic feet, or Tcf, in 2004 to approximately 25.4 Tcf in 2010, representing an average annual growth rate of over 2.3% per year. The industrial and electricity generation sectors are the largest users of natural gas in the United States. During the last three years, these sectors accounted for approximately 61% of the total natural gas consumed in the United States. In 2004, natural gas represented approximately 24% of all end-user domestic energy requirements. During the last five years, the United States has on average consumed approximately 22.5 Tcf per year, with average annual domestic production of approximately 19.1 Tcf during the same period. Driven by growth in natural gas demand and high natural gas prices, domestic natural gas production is projected to increase from 18.9 Tcf per year to 20.4 Tcf per year between 2004 and 2010.

Midstream Natural Gas Industry. Once natural gas is produced from wells, producers then seek to deliver the natural gas and its components to end-use markets. The following diagram illustrates the natural gas gathering, processing, fractionation, storage and transportation process, which ultimately results in natural gas and its components being delivered to end-users.

Natural Gas Gathering and Treating. The natural gas gathering process begins with the drilling of wells into gas-bearing rock formations. Once the well is completed, the well is connected to a gathering system. Onshore gathering systems generally consist of a network of small diameter pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission.

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Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations can be high in carbon dioxide or hydrogen sulfide. Natural gas with high carbon dioxide or hydrogen sulfide levels may cause significant damage to pipelines and is generally not acceptable to end-users. To alleviate the potential adverse effects of these contaminants, many pipelines regularly inject corrosion inhibitors into the gas stream.

Natural Gas Compression. Gathering systems are operated at pressures that will maximize the total throughput from all connected wells. Since wells produce at progressively lower field pressures as they age, it becomes increasingly difficult to deliver the remaining production from the ground against a higher pressure that exists in the connecting gathering system. Natural gas compression is a mechanical process in which a volume of wellhead gas is compressed to a desired higher pressure, allowing gas flow into a higher pressure downstream pipeline to be brought to market. Field compression is typically used to lower the pressure of a gathering system to operate at a lower pressure or provide sufficient pressure to deliver gas into a higher pressure downstream pipeline. If field compression is not installed, then the remaining natural gas in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production that otherwise would not be produced.

Natural Gas Processing. Natural gas is described as lean or rich depending on its content of heavy components or liquids content. These are relative terms, but as generally used, rich natural gas may contain as much as five to six gallons or more of NGLs per Mcf, whereas lean natural gas usually contains one to two gallons of NGLs per Mcf. NGLs have economic value and are utilized as a feedstock in the petrochemical and oil refining industries or directly as heating, engine or industrial fuels. Long-haul natural gas pipelines have specifications as to the maximum NGL content of the gas to be shipped. In order to meet quality standards for long-haul pipeline transportation, natural gas collected through a gathering system must be processed to separate hydrocarbon liquids that can have higher values as mixed NGLs from the natural gas.

The principal component of natural gas is methane, but most natural gas also contains varying amounts of NGLs including ethane, propane, normal butane, isobutane and natural gasoline. NGLs are typically recovered by cooling the natural gas until the mixed NGLs become separated through condensation. Cryogenic recovery methods are processes where this is accomplished at temperatures lower than -150°. These methods provide higher NGL recovery yields. After being extracted from natural gas, the mixed NGLs are typically transported via NGL pipelines or trucks to a fractionator for separation of the NGLs into their component parts.

In addition to NGLs, natural gas collected through a gathering system may also contain impurities, such as water, sulfur compounds, nitrogen or helium. As a result, a natural gas processing plant will typically provide ancillary services such as dehydration and condensate separation prior to processing. Dehydration removes water from the natural gas stream, which can form ice when combined with natural gas and cause corrosion when combined with carbon dioxide or hydrogen sulfide. Condensate separation involves the removal of hydrocarbons from the natural gas stream. Once the condensate has been removed, it may be stabilized for transportation away from the processing plant. Natural gas with a carbon dioxide or hydrogen sulfide content higher than permitted by pipeline quality standards requires treatment with chemicals called amines at a separate treatment plant prior to processing.

Natural Gas Fractionation. Fractionation is the process by which NGLs are further separated into individual, more valuable components. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane and natural gasoline. Ethane is primarily used in the petrochemical industry to produce ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used in the production of ethylene and propylene and as a heating fuel, an engine fuel and an industrial fuel. Isobutane is used principally to enhance the octane content of motor gasoline. Normal butane is used in the production of ethylene, butadiene (a key ingredient in synthetic rubber), motor gasoline and isobutane. Natural gasoline, a

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mixture of pentanes and heavier hydrocarbons, is used primarily to produce motor gasoline and petrochemicals.

Fractionation takes advantage of the differing boiling points of the various NGL products. NGLs are fractionated by heating mixed NGL streams and passing them through a series of distillation towers. As the temperature of the NGL stream is increased, the lightest (lowest boiling point) NGL product boils off the top of the tower where it is condensed and routed to storage. The mixture from the bottom of the first tower is then moved into the next tower where the process is repeated, and a different NGL product is separated and stored. This process is repeated until the NGLs have been separated into their components. Because the fractionation process uses large quantities of heat, energy costs are a major component of the total cost of fractionation.

Natural Gas and NGL Transportation. Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the processed natural gas to industrial end-users and utilities and to other pipelines. NGLs are transported to market by means of pipelines, pressurized barges, rail car and tank trucks. The method of transportation utilized depends on, among other things, the existing resources of the transporter, the locations of the production points and the delivery points, cost-efficiency and the quantity of NGLs being transported. Pipelines are generally the most cost-efficient mode of transportation when large, consistent volumes of NGLs are to be delivered.

Our Assets

We own strategically positioned natural gas gathering and processing assets in three significant natural gas producing regions, the Texas Panhandle, 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 midstreamwellhead-to-market services, including gathering, compressing, treating, processing, transportation and selling of natural gas and fractionating and transporting NGLs.

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Our Texas Panhandle Systems are located in the Texas Railroad Commission, or the TRRC, District 10, which has experienced significant growth activity since 2002. According to the EIA, there were approximately 5.4 Tcfe of total proved natural gas reserves at year-end 2004 in District 10. This area has experienced significant drilling activity during the last three years, and more than 531 new wells were completed in the counties served by our Texas Panhandle Systems during 2005. The following table sets forth, for the periods indicated, information regarding the number of natural gas wells started, the average drilling rig count and the average permit count in the TRRC District 10.

Our Texas Panhandle Systems collectively include 3,325 miles of gathering pipeline, six active gas processing plants with an aggregate capacity of approximately 166 MMcf/d, four inactive plants with an aggregate capacity of approximately 70 MMcf/d. In 2005, our Texas Panhandle Systems had an average throughput of 137 MMcf/d and an average NGL and condensate production of approximately 15,000 Bbls/d for the last three months of 2005.


	*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 intend to construct a10-mile pipeline from the West Panhandle System to the East Panhandle System, 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 769 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with 33,726 horsepower of associated pipeline compression;

	•	two active natural gas processing plants with an aggregate capacity of 65 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 84.5 MMcf/d for the twelve months ended December 31, 2005.

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The Arrington processing plant is a refrigerated, lean oil absorption facility located in Hemphill County, Texas. The processing plant has seven compressors with an aggregate of approximately 6,000 horsepower and approximately 40 MMcf/d of processing capacity. During the twelve months ended December 31, 2005, the facility processed approximately 27.0 MMcf/d of natural gas and produced approximately 1,500 Bbls/d of NGLs. The Arrington processing plant was built in 1974.

The Canadian processing plant is a turbo expander cryogenic facility located in Hemphill County, Texas. The plant has nine compressors with an aggregate of approximately 7,900 horsepower and approximately 25 MMcf/d of processing capacity. During the twelve months ended December 31, 2005, the facility processed approximately 25 MMcf/d of natural gas and produced approximately 2,100 Bbls/d of NGLs. As part of our Canadian processing plant, we own a 25 MMcf/d treating facility that removes carbon dioxide and small amounts of hydrogen sulfide from the natural gas. The Canadian processing plant was built in 1977.

Our Goad treating facility is a 50 MMcf/d treating facility that removes carbon dioxide and hydrogen sulfide from the natural gas.

In addition, we recently purchased Midstream Gas Services, L.P., which consists of facilities located in Roberts County within our East Panhandle System. The facilities consist of approximately four miles of natural gas gathering pipelines with associated pipeline compression and an active natural gas processing plant with aggregate capacity of 25 MMcf/d. The processing plant was constructed by Engineering, Construction and Procurement, Inc. in late 2005 and early 2006, and was successfully started in the second quarter of 2006. The plant is currently processing approximately 3 MMcf/d of natural gas produced by Chesapeake Inc. The area in which the processing plant is located is currently experiencing significant leasing and drilling activity related to the Granite Wash play by a number of oil and gas companies, including Chesapeake, J-BREX Company, Latigo Petroleum Texas, L.P., Prospective Investment & Trading Co. & Ltd., Altrav Petroleum Co. and Grayhawk Operating Inc. This facility will be connected to our East Panhandle System, allowing additional natural gas supply from nearby Hemphill County to be processed through this facility. The residue gas is currently being delivered to the ANR pipeline.

Natural Gas Supply. As of December 31, 2005, 589 wells and central delivery points were connected to our East Panhandle System. There are approximately 84 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 62% 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 38% 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 underpercent-of-proceeds and fee-based arrangements that primarily range from one to five years in term. As of June 30, 2006, approximately 69%, 30% and 1% of our total throughput in the East Panhandle System was underpercent-of-proceeds, fee-based 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.”

The East Panhandle System is located in an area characterized by significant growth in drilling activity and production. Over the last two years, approximately 1,820 wells have been permitted and 933 wells have been drilled in the area. We believe that this higher level of exploration and development

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activity will continue and we expect that an additional 60 MMcf/d of natural gas supply will be connected to the East Panhandle System over the next 24 months as planned plant expansion projects continue to be completed. In line with our expectations, 35 MMcf/d of first flow metered volumes have been added to the system in the six months ending June 30, 2006.

Markets. Our primary purchaser of the residue natural gas and the NGLs on the East Panhandle System is currently ONEOK Energy Services, which represented approximately 99% of revenue on the system for the twelve months ended December 31, 2005. Interconnects exist with Northern Natural Gas Co. at the Canadian processing plant and Southern Star Central Gas Pipeline, Inc. These interconnects present enhanced opportunity to create additional value for our producer customers by offering better residue natural gas pricing and additional value for the equity natural gas owned by us. Opportunities to create additional interconnects with ANR, Kinder Morgan, Transwestern and Transok, Inc. also exist on the East Panhandle System. In addition, there are many industrial end users in the East Panhandle System who create a premium market for local natural gas versus transporting or purchasing it from interstate or affiliated marketing companies. Our exchange agreement with ONEOK Energy Services ended May 31, 2006, and we are currently in the process of expanding our portfolio of marketing outlets.

Pursuant to an exchange agreement, the NGLs from our East Panhandle System are currently transported to the ONEOK NGL pipeline at Mont Belvieu or Conway where the NGLs are being marketed by ONEOK. We recently began marketing these NGLs, which we believe will enhance the netback to us and the producers because of better market pricing and improved marketing fee arrangements.

The condensate from the East Panhandle System is transported by truck to central tank facilities and injected for sale into the ConocoPhillips Y-2 system.

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.

System Description. The West Panhandle System consists of:


	•	approximately 2,556 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with 81,178 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 55.5 MMcf/d for the twelve months ended December 31, 2005.

The Cargray processing plant is a turbo expander cryogenic facility located in Carson County, Texas. The plant has nine compressors with an aggregate of approximately 6,830 horsepower and approximately 30 MMcf/d of processing capacity. In addition to the cryogenic plant, the processing facility also includes a 30 MMcf/d dehydration unit, a 10 MMcf/d deoxygenation unit and a 1,000 Bbls/d propane fractionator, which also includes a deethanizer, a depropanizer, 167,500 gallons of storage capacity, loading pumps and a truck loading rack. During the twelve months ended December 31, 2005, the facility processed approximately 19 MMcf/d of natural gas and produced approximately 3,600 Bbls/d of NGLs. In addition, approximately 6 MMcf/d of the natural gas gathered by the Cargray plant is treated for the removal of hydrogen sulfide and carbon dioxide at the Shaefer treating facility in Carson County, Texas. The Cargray plant was built in 1974.

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The Gray processing plant is a turbo expander cryogenic facility located in Gray County, Texas. The plant has seven compressors with an aggregate of approximately 2,000 horsepower and approximately 20 MMcf/d of processing capacity. During the twelve months ended December 31, 2005, the facility processed approximately 14.2 MMcf/d of natural gas and produced approximately 3,000 Bbls/d of NGLs. This plant includes an inactive 12 gpm treating facility and a 20 MMcf/d dehydration unit. The Gray plant was built in 1984.

The condensate collection facility, which is located near the Gray processing plant, serves as a central collection point for the condensate produced on the West Panhandle System. The facility includes several horizontal feed tanks, a 1,500 Bbls/d condensate stabilizer, horizontal make tanks, truck loading and unloading facilities and a pipeline connection to ConocoPhillips. Condensate is transported by a pipeline from the Gray processing plant and by truck from other parts of the West Panhandle System.

The Lefors processing plant is a cryogenic processing facility located in Gray County, Texas. The plant has an aggregate of 1,225 horsepower of inlet compression and 400 horsepower of refrigeration compression and approximately 11 MMcf/d of processing capacity. The processing facility also includes a 5 gpm amine product treater. During the twelve months ended December 31, 2005, the facility processed approximately 7.9 MMcf/d of natural gas and produced approximately 2,000 Bbls/d of NGLs. The Lefors plant was originally constructed in 1928, converted in 1970 and was replaced in 1995.

The Stinnett processing plant is a turbo expander cryogenic facility located in Moore County, Texas. The plant has six compressors with an aggregate of approximately 4,150 horsepower and approximately 40 MMcf/d of processing capacity. The processing facility also includes a 14 gpm treating facility, a 25 MMcf/d dehydration unit, a 20 MMcf/d dehydrator and a condensate stabilizer. During the twelve months ended December 31, 2005, the facility processed approximately 12.5 MMcf/d of natural gas and produced approximately 2,200 Bbls/d of NGLs. The Stinnett plant was built in 1984.

We believe we have opportunities to increase the profitability of the West Panhandle System primarily by utilizing excess processing capacity on this system to process natural gas transported from our East Panhandle System as well as by rationalizing assets, reducing fuel expense and other operating costs and improving NGL recovery efficiency. Additionally, opportunities exist to capture additional natural gas production associated with the re-completion of existing wells that were not developed using advanced technology and infill drilling.

Natural Gas Supply. As of December 31, 2005, 1,833 wells and central delivery points were connected to the West Panhandle System. There are 180 producers connected to the West Panhandle System with Chesapeake, Excel Energy, Cabot Oil & Gas, Chevron, XTO Energy, Questa Energy Corporation, James Reneau Seed Corp. being the primary producers.

Wells located in the West Panhandle System produce natural gas associated with the crude oil production from the wells. These wells generally have long production lives with predictable production base decline rates of approximately 6% per year. These wells generally produce natural gas having an NGL content of between 6.5 and 13.0 gpm, a level that is considered extremely high in comparison to average levels of NGL content of between 1.0 and 2.0 gpm related to natural gas production that is not associated with crude oil production. Significant compression horsepower and significantly more pipeline capacity is required to move this natural gas to the processing facilities because of the high NGL content. Because of the complex level of service and high quality of the natural gas, the value of the natural gas produced and the margins associated with our services are typically higher for the West Panhandle System as compared to the East Panhandle System.

The West Panhandle System is located in a mature drilling area that produces high NGL content natural gas. New drilling activity around the West Panhandle System has been less active over the past several years. However, producers are continually re-working their existing properties to maintain productive reserves, which has resulted in a low natural gas production decline rate.

On the West Panhandle System, 38% of the natural gas is purchased at the wellhead primarily under keep-whole arrangements with a $3.0 million per year gathering demand fee. The remaining 62% of the natural gas purchased is primarily underpercent-of-proceeds contracts. The natural gas from this system is

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dedicated under long term contracts. 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. Our primary purchaser of the residue gas and NGLs on the West Panhandle System for 2005 was ONEOK Energy Services, which represented approximately 99% of revenues on the system for the twelve months ended December 31, 2005. Our exchange with ONEOK Energy Services ended May 31, 2006, and we are currently in the process of expanding our portfolio of marketing outlets. In addition, condensate produced on the system is trucked and purchased by SemCrude, L.P. and Petro Source Partners, LP.

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

Southeast Texas and Louisiana Operations

Our southeast Texas and Louisiana operations are located primarily in Polk, Tyler, Jasper and Newton Counties, Texas and Vernon Parish, 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 consist of:


	•	approximately 850 miles of natural gas gathering pipelines, ranging from four inches to 12 inches in diameter, with 5,200 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; and

	•	a19-mile NGL pipeline.

The Brookeland System is located in Jasper and Newton Counties, Texas and consists of approximately 650 miles of natural gas gathering pipelines, ranging from 4 inches to 12 inches in diameter, and the Brookeland processing plant. The gathering system has capacity of approximately 120 MMcf/d

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and average throughput was approximately 18.8 MMcf/d for the six months ended June 30, 2006. The gathering system utilizes approximately 1,100 horsepower to gather the natural gas from 156 wells and central delivery points.

The Brookeland processing plant is a cryogenic natural gas processing and treating facility located in Jasper County, Texas. The plant has processing capacity of approximately 100 MMcf/d. During the six months ended June 30, 2006, the facility processed approximately 27.7 MMcf/d of natural gas and produced approximately 2,120 Bbls/d of NGLs.

The Masters Creek System is located in Vernon, Beauregard and Rapides Parishes, Louisiana and consists of approximately 250 miles of natural gas gathering pipelines, ranging from two inches to 16 inches in diameter. The gathering system has capacity of approximately 200 MMcf/d and average throughput was approximately 8.9 MMcf/d for the six months ended June 30, 2006. The gathering system utilizes approximately 4,000 horsepower to gather natural gas from 52 wells and central delivery points.

The Camp Ruby System is located in Polk, Hardin and Tyler Counties, Texas and consists of approximately 126 miles of natural gas gathering pipelines, ranging from two inches to eight inches in diameter, and the Indian Springs processing plant. The gathering system average throughput was approximately 90 MMcf/d for the twelve months ended December 31, 2005. The system delivers all of the natural gas to the Indian Springs processing plant. We own a 20% undivided interest in the Camp Ruby System, and a subsidiary of Enterprise Products Partners, L.P. owns the remaining 80% and operates the system.

The Indian Springs processing plant is a cryogenic natural gas processing and treating plant located in Polk County, Texas. The Indian Springs processing plant is comprised of two cryogenic plants with total operational capacity of 150 MMcf/d. During the twelve months ended December 31, 2005, the facility processed approximately 81 MMcf/d of natural gas and produced approximately 5,100 Bbls/d of NGLs. We own a 25% undivided interest in the Indian Springs processing plant, and a subsidiary of Enterprise Products Partners, L.P. owns the remaining 75% and operates the facility.

In January 2006, we began construction on our Tyler County pipeline, a23-mile,10-inch diameter natural gas pipeline that is the first segment of a natural gas gathering system that crosses Tyler County, Texas. As of June 30, 2006, the Tyler County gathering system had a capacity of 60 MMcf/d, with an average throughput of 20.7 MMcf/d and 29 MMcf/d for the first and second quarters of 2006, respectively. Construction of an extension of the Tyler County gathering system to the Brookeland System is expected to be completed in November 2006 and cost approximately $12.0 million.

The Jasper NGL pipeline is a19-mile,6-inch diameter pipeline that is located in Jasper and Newton Counties, Texas. The pipeline capacity is 18 MBbl/d and delivers NGLs from the Brookeland plant to the Black Lake Pipeline which is jointly owned by Duke Energy Field Services, L.P. and BP America Production Company, for ultimate delivery of the NGLs to a fractionation plant located in Mont Belvieu, Texas.

The Live Oak gathering system is located in Live Oak County, Texas. It gathers gas from Zinergy and redelivers it to the nearby Copano pipeline system for a fixed fee. This system was built and put in service in November 2005. Zinergy had drilled and completed two wells on this system by February 2006. Volumes were averaging 5 MMcf/d as of June 2006.

Natural Gas Supply. As of December 31, 2005, approximately 277 wells and central delivery points were connected to our systems in the southeast Texas and Louisiana regions. Our southeast Texas and Louisiana operations are located in an area experiencing an increase in drilling activity and production. The Texas Railroad Commission has issued 235 drilling permits in Tyler, Polk, Jasper and Newton Counties, Texas and Vernon, Beaureguard and Rapides Parish, Louisiana from January 2004 through the end of 2005. We have secured areas of dedication from Ergon Exploration Inc., Black Stone Minerals Co., Delta Petroleum Corp. “Delta”, B.W.O.C. Inc. (“B.W.O.C.”) and Pogo Producing Company. Each of the entities has at least five additional locations identified as drilling locations on this acreage. The Ergon and

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B.W.O.C. gas was connected to our Tyler County pipeline in March 2006. As of June 30, 2006, the gas on the Tyler County pipeline was producing at a combined rate of approximately 34 MMcf/d.

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 generallypercent-of-proceeds andpercent-of-liquids arrangements. Natural gas is purchased at the wellhead from the producers underpercent-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 and Tennessee Gas Pipeline. Our NGLs are sold to Duke Energy Field Services, L.P. and our condensate production is sold to SemCrude, L.P.

Competition. Our primary competition in this area includes Anadarko Petroleum and Enterprise Products Partners, L.P.

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 communityright-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 east Texas and Louisiana assets have not experienced a lost-time accident since June 2005. Our Texas Panhandle assets have not experienced a lost-time accident since early 2004. Since our inception, we have not experienced a lost-time accident.

Regulation of Operations

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.

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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 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 FERC and/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 non-utility facilities change, they would become subject to rate regulation by the TRRC, which could adversely affect the rates that our facilities are allowed to charge their customers. Texas also administers federal pipeline safety standards under the Pipeline Safety Act of 1968. The “rural gathering exemption” under the Natural Gas Pipeline Safety Act of 1968 presently exempts most of our gathering facilities from jurisdiction under that statute, including those portions located outside of cities, towns or any area designated as residential or commercial, such as a subdivision or shopping center. The “rural gathering exemption,” however, may be restricted in the future. With respect to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation, or DOT, have passed or are considering heightened pipeline safety requirements. We operate our facilities in full compliance with local, state and federal regulations, including DOT 192 and 195.

Twelve miles of our Turkey Creek gathering system is 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 four miles of gathering system that we recently purchased from MGS 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

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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 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.

Environmental Matters

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

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and liabilities as a result of such releases or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this trend will continue in the future.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA.

We also may incur liability under the Resource Conservation and Recovery Act, as amended, also known as “RCRA,” which imposes requirements related to the handling and disposal of solid and hazardous wastes. 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. We intend to conduct environmental investigations at 11 properties, the aggregate cost of which is estimated to range between $160,000 and $398,000 and for which we have accrued reserves in the amount of $300,000 as of December 31, 2005. Depending on the findings made during these investigations, and in anticipation of implementing amended SPCC plans at multiple locations as well as performing selected cavern closures, we estimate that an additional $1.2 million to $2.5 million in costs could be incurred in resolving environmental issues at those properties. Separately, (1) we are entitled to indemnification with respect to certain environmental liabilities retained by prior owners of these properties, and (2) we purchased an environmental pollution liability insurance policy.

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

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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.

Title to Properties andRights-of-Way

Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements,rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to ground leases between us, as lessee, and the fee owner of the lands, as lessors. We, or our predecessors, have leased these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement,right-of-way, permit or license held by us or to our title to any material lease, easement,right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements,rights-of-way, permits and licenses.

Some of the leases, easements,rights-of-way, permits and licenses to be transferred to us require the consent of the grantor of such rights, which in certain instances is a governmental entity. Our general partner expects to obtain, prior to the closing of this offering, sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects as described in this prospectus. With respect to any material consents, permits or authorizations that have not been obtained prior to closing of this offering, the closing of this offering will not occur unless reasonable basis exist that permit our general partner to conclude that such consents, permits or authorizations will be obtained within a reasonable period following the closing, or the failure to obtain such consents, permits or authorizations will have no material adverse effect on the operation of our business.

Employees

To carry out our operations, Eagle Rock Energy G&P, LLC or its affiliates expect to employ approximately 150 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, will make 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 will make all decisions on behalf of our general partner with respect to the conduct of our business and operations. Neither our general partner nor the general partner of our general partner is elected by our unitholders and neither entity will be subject to re-election on a regular basis in the future. Unitholders will not be 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 will unitholders otherwise be 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, will oversee our operations. Upon the closing of this offering, Eagle Rock Energy G&P, LLC will have eight directors, three of whom will be independent as defined under the independence standards established by the Nasdaq Global Market. 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.

At least two members of the board of directors of Eagle Rock Energy G&P, LLC will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. 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, and must meet the independence and experience standards established by the Nasdaq Global Market and the Securities Exchange Act of 1934, as amended, to serve on an audit committee of a board of directors, and certain other requirements. 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.

In addition, Eagle Rock Energy G&P, LLC will have an audit committee of at least three directors 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 will assist 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 will have 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 will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent

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registered public accounting firm will be given unrestricted access to the audit committee. Eagle Rock Energy G&P, LLC will also have a compensation committee, which will, among other things, oversee the compensation plans described below.

Directors and Executive 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

Alex A. Bucher, Jr.		51	Chairman of the Board, President and Chief Executive Officer
Joan A. W. Schnepp		48	Executive Vice President, Secretary and Director
Richard W. FitzGerald		52	Senior Vice President, Chief Financial Officer and Treasurer
Alfredo Garcia		40	Senior Vice President, Corporate Development
William E. Puckett		50	Senior Vice President, Commercial Operations
J. Stacy Horn		44	Vice President, Commercial Development
Stephen O. McNair		43	Vice President, Operations and Technical Services
Kenneth A. Hersh		43	Director
William J. Quinn		35	Director
John A. Weinzierl		38	Director
William K. White		64	Director Nominee
Philip B. Smith		55	Director Nominee

Because of its ownership of a majority interest in Eagle Rock Holdings, L.P., Natural Gas Partners will have the right to elect all of the members of the board of directors of Eagle Rock Energy G&P, LLC at the closing of this offering. 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 all of their time to our business and operations.

Alex A. Bucher, Jr. was elected Chairman of the Board, President and Chief Executive Officer of Eagle Rock Energy G&P, LLC in August 2006 and served as President, Chief Executive Officer, Treasurer and Director of Eagle Rock Energy G&P, LLC from March 2006 until August 2006. Mr. Bucher has been Secretary, Chief Executive Officer and Director of Eagle Rock Pipeline, L.P. since December 2005 and Eagle Rock Energy, Inc. from December 2003 to December 2005. In June 2002, Mr. Bucher co-founded Eagle Rock Energy, Inc. and served as its President and Treasurer from June 2002 until December 2003. From November 1999 to June 2002, Mr. Bucher was Vice President of Operations and Vice President & Director of Business Development for Midcoast, subsequently Enbridge, Inc., an energy transportation and distribution company. Prior to joining MidCoast, Mr. Bucher was Vice President and Regional Manager for Dynegy, Inc., a gas gathering and processing company.

Joan A. W. Schneppwas elected Executive Vice President, Secretary and Director of Eagle Rock Energy G&P, LLC in March 2006. Ms. Schnepp has been Treasurer, President and Director of Eagle Rock Pipeline, L.P. since December 2005 and Eagle Rock Energy, Inc. from December 2003 to December 2005. In June 2002, Ms. Schnepp co-founded Eagle Rock Energy, Inc. and served as its Secretary and Chief Executive Officer from June 2002 until December 2003. From November 1999 to June 2002, Ms. Schnepp was Vice President of Revenue Management for Midcoast, subsequently Enbridge, Inc., an energy transportation and distribution company.

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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. Mr. FitzGerald brings to Eagle Rock Energy 25 years experience in the areas of business financing strategies, financial accounting, risk management, treasury and SEC reporting. His experience has been largely within the energy industry.

Alfredo Garciawas elected Senior Vice President, Corporate Development of Eagle Rock Energy G&P, LLC 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 software start-up company. Prior to this, Mr. Garcia was a Latin American Associate for HM Capital Partners, a private equity firm formerly known as Hicks Muse Tate & Furst. Mr. Garcia has 15 years of experience in corporate finance, mergers and acquisitions, private equity, investor relations, treasury and accounting.

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.

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 and Technical Services 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.

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 Energy Transfer Partners, L.L.C., the indirect general partner of Energy Transfer Partners, L.P., a natural gas gathering and processing and transportation and storage and retail propane company, since February 2004 and has served as a director of LE GP, LLC, the general partner of Energy Transfer Equity, L.P., since October 2002.

William J. Quinnwas elected Director of Eagle Rock Energy G&P, LLC in March 2006. 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.

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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. Whitewill serve as a Director of Eagle Rock Energy G&P, LLC upon completion of this offering, and will serve as Chairman of the audit committee and as a member of the conflicts and compensation committees 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.

Philip B. Smithwill serve as a Director of Eagle Rock Energy G&P, LLC upon completion of this offering, and will serve as a member of the audit committee and as a member of the conflicts and compensation committees 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.

Reimbursement of Expenses of Our General Partner

Neither our general partner nor Eagle Rock Energy G&P, LLC will receive any management fee or other compensation for its management of our partnership. Our general partner and its affiliates, including Eagle Rock Energy G&P, LLC, will, however, be reimbursed for all expenses incurred on our behalf. These expenses include the cost of employee, officer and director compensation and benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of our business and allocable to us. We will recognize and record these expenses in our financial statements on an accrual basis and in the same period as our general partner or its affiliates incur them on our behalf. In addition, our general partner and its affiliates will provide us with the personnel necessary to perform all business services, the supervisors and management personnel necessary to manage the performance of these services, the systems required to support and operate our business and the personnel, compensation, insurance, and all other expenses in order to be in compliance with all applicable laws, ordinances, codes, rules, standards and regulations of our business. The partnership agreement provides that our general partner will determine the expenses that are allocable to us and it is our expectation that those expenses will be reimbursed at actual cost. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed.

Executive Compensation

Our general partner was formed in May 2006 and Eagle Rock Energy G&P, LLC was formed in October 2005. Eagle Rock Energy G&P, LLC has not accrued any obligations with respect to management incentive or retirement benefits for its directors and officers for the 2005 or 2006 fiscal years. It is the current intention that all employees, including executive and other officers, will be employed by Eagle Rock Energy G&P, LLC, as the general partner of our general partner. While the compensation of the executive officers of Eagle Rock Energy G&P, LLC will be set by the compensation committee of Eagle Rock Energy G&P, LLC’s board of directors, it is our intention to compensate executive officers and other key employees with competitive base salaries, annual bonuses based on our performance and individual performance and awards under our Long-Term Incentive Plan. Commencing upon completion of this offering, the officers and employees of Eagle Rock Energy G&P, LLC may participate in employee benefit plans and arrangements sponsored by Eagle Rock Energy G&P, LLC or our partnership, including

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plans and arrangements that may be established in the future. We anticipate that the board of directors will grant awards to our key employees and our outside directors pursuant to the Long-Term Incentive Plan described below following the closing of this offering; however, the board has not yet made any determination as to the number of awards, the type of awards or when the awards would be granted.

Employment and Severance Agreements

At the time of his employment, Richard W. FitzGerald entered into an employment agreement with Eagle Rock Energy G&P, LLC, which provides for an annual base salary of $200,000. The agreement also entitles Mr. FitzGerald to participate in our compensation and benefit plans, and receivecompany-provided disability benefits and life insurance and certain other fringe benefits. Mr. FitzGerald is also eligible to participate in a company-sponsored incentive bonus plan. In addition, the agreement contains a severance provision that provides that if Mr. FitzGerald’s employment is terminated for any reason other than cause, he is entitled to a one-time severance payment in the amount of his annual base salary. As part of his employment agreement, Mr. FitzGerald has also made an investment of $50,000 in Eagle Rock Holdings, L.P. and was granted 150,000 units in Eagle Rock Holdings, L.P.

We have not entered into any other employment agreements with our executive officers.

Compensation of Directors

Officers or employees of Eagle Rock Energy G&P, LLC or its affiliates who also serve as directors will not receive additional compensation for their service as a director of Eagle Rock Energy G&P, LLC. Our general partner anticipates that directors who are not officers or employees of Eagle Rock Energy G&P, LLC or its affiliates will receive compensation for serving on the board of directors and committee meetings. It is expected that such directors will receive (a) $50,000 per year as an annual retainer fee; (b) $5,000 per year for each committee of the board of directors on which such director serves; (c) 5,000 restricted common units upon becoming a director, vesting in one-third increments over a three-year period; (d) 1,000 restricted common units on each anniversary of becoming a director, vesting in one-third increments over a three-year period; (e) reimbursement for out-of-pocket expenses associated with attending meetings of the board of directors or committees; (f) reimbursement for educational costs relevant to the director’s duties; and (g) director and officer liability insurance coverage. Each director will be fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law.

Long-Term Incentive Plan

General. Eagle Rock Energy G&P, LLC intends to adopt a Long-Term Incentive Plan, or the Plan, for employees, consultants and directors of Eagle Rock Energy G&P, LLC and its affiliates who perform services for us. The summary of the Plan contained herein does not purport to be complete and is qualified in its entirety by reference to the Plan. The Plan provides for the grant of restricted units, phantom units, unit options, unit awards and substitute awards and, with respect to phantom units, the grant of distribution equivalent rights, or DERs. Subject to adjustment for certain events, an aggregate of common units may be delivered pursuant to awards under the Plan. Units that are canceled, forfeited or withheld to satisfy Eagle Rock Energy G&P, LLC’s tax withholding obligations are available for delivery pursuant to other awards. The Plan will be administered by the compensation committee of Eagle Rock Energy G&P, LLC’s board of directors. The Plan has been designed to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of our common unitholders.

Restricted Units and Phantom Units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equal to the fair market value of a common unit. The compensation committee may make grants of restricted units and phantom units under the Plan to

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eligible individuals containing such terms, consistent with the Plan, as the compensation committee may determine, including the period over which restricted units and phantom units granted will vest. The compensation committee may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria. In addition, the restricted and phantom units will vest automatically upon a change of control (as defined in the Plan) of us or Eagle Rock Energy G&P, LLC, subject to any contrary provisions in the award agreement.

If a grantee’s employment, consulting or membership on the board terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the award agreement or the compensation committee provides otherwise. Common units to be delivered with respect to these awards may be common units acquired by Eagle Rock Energy G&P, LLC in the open market, common units already owned by Eagle Rock Energy G&P, LLC, common units acquired by Eagle Rock Energy G&P, LLC directly from us or any other person, or any combination of the foregoing. Eagle Rock Energy G&P, LLC will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase.

Distributions made by us with respect to awards of restricted units may, in the compensation committee’s discretion, be subject to the same or different vesting requirements as the restricted units. The compensation committee, in its discretion, may also grant tandem DERs with respect to phantom units on such terms as it deems appropriate. DERs are rights that entitle the grantee to receive, with respect to a phantom unit, cash equal to the cash distributions made by us on a common unit.

We intend for the restricted units and phantom units granted under the Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants will not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner will receive remuneration for the units delivered with respect to these awards.

Unit Options. The Plan also permits the grant of options covering common units. Unit options may be granted to such eligible individuals and with such terms as the compensation committee may determine, consistent with the Plan; however, a unit option must have an exercise price equal to the fair market value of a common unit on the date of grant, unless it is a substitute award described below.

Upon exercise of a unit option, Eagle Rock Energy G&P, LLC will acquire common units in the open market at a price equal to the prevailing price on the principal national securities exchange upon which the common units are then traded, or directly from us or any other person, or use common units already owned by the general partner, or any combination of the foregoing. Eagle Rock Energy G&P, LLC will be entitled to reimbursement by us for the difference between the cost incurred by Eagle Rock Energy G&P, LLC in acquiring the common units and the proceeds received by Eagle Rock Energy G&P, LLC from an optionee at the time of exercise. Thus, we will bear the cost of the unit options. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and Eagle Rock Energy G&P, LLC will remit the proceeds it received from the optionee upon exercise of the unit option to us.

Substitution Awards. The compensation committee, in its discretion, may grant substitute or replacement awards to eligible individuals who, in connection with an acquisition made by us, Eagle Rock Energy G&P, LLC or an affiliate, have forfeited an equity-based award in their former employer. A substitute award that is an option may have an exercise price less than the value of a common unit on the date of grant of the award.

Unit Awards. The compensation committee may grant common units that are not subject to forfeiture restrictions to eligible individuals as additional compensation or in lieu of cash compensation the individual would otherwise receive.

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Termination of Long-Term Incentive Plan. Eagle Rock Energy G&P, LLC’s board of directors, in its discretion, may terminate the Plan at any time with respect to the common units for which a grant has not theretofore been made. The Plan will automatically terminate on the earlier of the 10th anniversary of the date it was initially approved by our unitholders or when common units are no longer available for delivery pursuant to awards under the Plan. Eagle Rock Energy G&P, LLC’s board of directors will also have the right to alter or amend the Plan or any part of it from time to time and the compensation committee may amend any award; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant. Subject to unitholder approval, if required by the rules of the principal national securities exchange upon which the common units are traded, the board of directors of Eagle Rock Energy G&P, LLC may increase the number of common units that may be delivered with respect to awards under the Plan.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our units that will be issued upon the consummation of this offering and the related transactions and 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			Common and
	Common Units		Percentage of			Subordinated		Subordinated			Subordinated
	to be		Common Units to			Units to be		Units to be			Units to be
	Beneficially		be Beneficially			Beneficially		Beneficially			Beneficially
Name of Beneficial Owner(1)	Owned		Owned			Owned		Owned			Owned

Eagle Rock Holdings, L.P.(2)		3,459,236		16.7	%		20,691,495		100.0	%		58.4	%
Alex A. Bucher, Jr.(2)		12,094		*	%		72,338		*	%		*	%
Joan A. W. Schnepp(2)		5,443		*	%		32,559		*	%		*	%
Richard W. FitzGerald(2)		861					5,150
Alfredo Garcia(2)		2,548		*	%		15,241		*	%		*	%
William E. Puckett(2)		1,550		*	%		9,270		*	%		*	%
J. Stacy Horn(2)		1,998		*	%		11,949		*	%		*	%
Stephen O. McNair(2)		1,722		*	%		10,300		*	%		*	%
Kenneth A. Hersh(3)		—		—	%		—		—	%		—	%
William J. Quinn		—		—	%		—		—	%		—	%
John A. Weinzierl		—		—	%		—		—	%		—	%
William K. White		—		—	%		—		—	%		—	%
Philip B. Smith		—		—	%		—		—	%		—	%
All directors and executive officers as a group (12 persons)		26,216		*	%		156,807		*	%		*	%


	*	Less than 1%


(1)	Unless otherwise indicated, the address for all beneficial owners in this table is 14950 Heathrow Forest Parkway, Suite 111 Houston, Texas 77032.


(2)	Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., Alex A. Bucher, Jr., Joan A. W. Schnepp, Richard J. FitzGerald, Alfredo Garcia, William E. Puckett, J. Stacy Horn and Stephen O. McNair have a 38.60%, 59.51%, 0.35%, 0.16%, 0.02%, 0.07%, 0.04%, 0.06% and 0.05% limited partner interest, respectively, in Eagle Rock Holdings, L.P. Eagle Rock GP, L.L.C., which is owned 39.14%, 60.35%, 0.35% and 0.16% by Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., Mr. Bucher and Ms. Schnepp, 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. Bucher, Ms. Schnepp, Mr. Garcia, Mr. Puckett and Mr. Horn in proportion to their beneficial ownership in Eagle Rock Holdings, L.P. and Eagle Rock GP, L.L.C.


(3)	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.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, Eagle Rock Holdings, L.P. will own 3,459,236 common units and 20,691,495 subordinated units representing an aggregate 57.2% limited partner interest in us. In addition, our general partner will own 844,551 general partner units representing a 2% 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 to be 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;



		• 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 this offering to replenish working capital that will be distributed to certain subsidiaries of Eagle Rock Holdings, L.P. and the Private Investors prior to the consummation of this offering;


		• cash payment of approximately $184.8 million from the proceeds of this offering as reimbursement for capital expenditures incurred by Eagle Rock Holdings, L.P. and the Private Investors prior to the closing of this offering related to the assets to be contributed to us upon the closing of this offering;



		• cash payment of approximately $11.0 million from the proceeds of this 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 3,459,236 common units and 20,691,495 subordinated units, and 2% to our general partner, assuming it makes any capital contributions necessary to maintain its 2% interest in us. In addition, if distributions exceed the minimum quarterly

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		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 $35.0 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 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 have entered into or will enter into the various documents and agreements that will effect 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 this offering. These agreements will not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not be 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, will be paid from the proceeds of this offering.

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Omnibus Agreement

Upon the closing of this offering, we will enter into an omnibus agreement with Eagle Rock Energy G&P, LLC, Eagle Rock Holdings, L.P. and our general partner that will address 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;



	•	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. We estimate that for the twelve months ending September 30, 2007, we will reimburse Eagle Rock G&P, LLC and Eagle Rock Holdings, L.P. $30.6 million, $10.1 million and $2.5 million for operating expenses, general and administrative expenses and public company expenses, respectively.

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 this 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. will perform 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 will reimburse 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 will indemnify us for two years after the closing of this 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 this offering. The maximum liability for this indemnification obligation will not exceed $7.5 million, and the indemnifying parties will not have any obligation under this indemnification until our aggregate losses exceed $750,000. The indemnifying parties will have no

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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 this offering.

Additionally, Eagle Rock Holdings, L.P., Eagle Rock Energy G&P, LLC and our general partner will indemnify 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 this offering. The indemnifying parties’ maximum liability for this indemnification obligation will not exceed $5.0 million, and Eagle Rock Holdings, L.P. will 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 will 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 will be 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 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 will be restricted, under either our partnership agreement or the omnibus agreement, from competing with us. Eagle Rock Holdings, L.P. 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 or construct those assets.

Agreements with Affiliates


	*Advisory Services, Reimbursement and Indemnification Agreement*

In December 2003, Eagle Rock Holdings, L.P. entered into an advisory services, reimbursement and indemnification agreement with Natural Gas Partners. Pursuant to this agreement, Eagle Rock Holdings, L.P. retained Natural Gas Partners to act as an advisor and to provide consultation, assistance and advice to it with respect to our operations. In addition, Eagle Rock Holdings, L.P. agreed to reimburse Natural Gas Partners for all reasonable disbursements and expenses incurred by Natural Gas Partners in connection with monitoring its investment in us and in connection with rendering advisory services. Eagle Rock Holdings, L.P. also agreed to indemnify Natural Gas Partners for certain actions, claims or liabilities relating to our operations and providing advisory services to us.

Eagle Rock Holdings, L.P. paid advisory fees in the amount of approximately $0.3 million to Natural Gas Partners in the six months ended June 30, 2006, and $0.1 million for the year ended December 31, 2005.

At the closing of this offering and the related formation transactions, Eagle Rock Holdings, L.P. will pay $6.0 million to Natural Gas Partners as consideration for the termination of the advisory services, reimbursement and indemnification agreement between Natural Gas Partners and Eagle Rock Holdings, L.P.


	*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

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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 this offering, the 1,125,416 common units in Eagle Rock Pipeline will be converted into common units in us on approximately a 1-for-0.719 common unit basis.


	*Registration Rights Agreement*

We intend to enter 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 will agree, 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.”


	*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 amonth-to-month contract for the sale and purchase of natural gas with Odyssey Energy Services, LLC, an affiliate of Natural Gas Partners, under which we have the option to sell to Odyssey a portion of our gas supply from our Texas Panhandle systems. The price of gas being sold to Odyssey is tied to daily and/or monthly industry publication postings 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. As of August 1, 2006, we sold Odyssey approximately 15,000 MMBtu/d of natural gas, which equals approximately one-third of our total natural gas sales.

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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 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.


	*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.

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	*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 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.*


	•	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

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		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.


	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

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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 will be in effect as of the closing of this offering will be 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 following the closing of this offering 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 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 will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

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.

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	*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 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

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		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.

		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).

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		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.”

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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.”

Transfer Agent and Registrar

Duties. American Stock Transfer & Trust Company will serve as registrar and transfer agent for the common units. We will 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 will be no charge to unitholders for disbursements of our cash distributions. We will 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


	•	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 this offering.

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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 included in this prospectus as Appendix A. 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 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.”

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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 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 2% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 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

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		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 incentive distribution rights		Except for transfers to an affiliate or another person as part of our general partner’s merger or consolidation, sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder, the approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to September 30, 2016. Please read “— Transfer of Incentive Distribution Rights.”

Transfer of ownership interests in our general partner		No approval required at any time. Please read “— Transfer of Ownership Interests in the General Partner.”

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

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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.

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 2% general partner interest in us. Our general partner’s 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 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

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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 58.7% of the outstanding common and subordinated units.

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;

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	•	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;

	•	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.

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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 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

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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 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. At the closing of this offering, our general partner and its affiliates will own 58.7% 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

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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

	•	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

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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.

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

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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.

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.

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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.

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.

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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.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby, Eagle Rock Holding L.P. and the Private Investors will hold an aggregate of 8,191,495 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. 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 in the offering 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.”


	•	subject to the restrictions described under “Underwriting — No Sales of Similar Securities,” to file with the SEC, within 90 days after the receipt of a request by Eagle Rock Holdings, L.P., 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, L.P.;

	•	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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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; provided, however, that neither our general partner nor any of its affiliates are entitled to any registration rights under our partnership agreement until the March 2006 Private Investors’ registration rights agreement described below is terminated or the securities covered by such registration rights agreement no longer exist. 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.

We entered into a registration rights agreement with the March 2006 Private Investors. In the registration rights agreement we agreed, upon completion of this offering, to register the common units issuable to the March 2006 Private Investors. Specifically, we agreed:


	•	to file with the SEC, within 90 days after the closing date of this offering, 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 closing of this offering;

	•	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.

Eagle Rock Holdings, L.P., our partnership, our general partner and its affiliates, including the executive officers and directors of Eagle Rock Energy G&P, LLC, the Private Investors and the participants in our directed unit program have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. For a description of theselock-up provisions, please read “Underwriting.”

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MATERIAL TAX CONSEQUENCES

This section is a discussion of the material 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 Vinson & Elkins L.L.P., 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 Vinson & Elkins L.L.P. 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 Vinson & Elkins L.L.P. 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 here 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.

For the reasons described below, Vinson & Elkins L.L.P. 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

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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. We estimate that less than 1% of our current gross income is not 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, Vinson & Elkins L.L.P. 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 Vinson & Elkins L.L.P. 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, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied are:


	(a) Neither we nor the operating company will elect to be treated as a corporation; and

	(b) For each taxable year, more than 90% of our gross income will be income that Vinson & Elkins L.L.P. has opined or 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.

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 Vinson & Elkins L.L.P.’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, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in

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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.

A beneficial owner of common units whose units have been transferred 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, gain, deductions or losses 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 tax consequences of holding common units in Eagle Rock Energy Partners, L.P. The references to “unitholders” in the discussion that follows are to persons who are treated 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 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.

Ratio of Taxable Income to Distributions. We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2009, 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 with respect to that period. We anticipate that after the taxable year ending December 31, 2009, the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are

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subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than our estimation above, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater if:


	•	gross income from operations exceeds the amount required to make the minimum quarterly distribution on all units, yet we only distribute the minimum quarterly distribution on all units; or

	•	we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

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

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traded 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 this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of this 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

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income by some unitholders. Finally, although we do not expect that our operations will result in 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.

Vinson & Elkins L.L.P. 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.

Vinson & Elkins L.L.P. 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 borrowing 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.

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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 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), 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 Regulation Section 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 these Treasury Regulations. Please read “— Uniformity of Units.”

Although Vinson & Elkins L.L.P. 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 as non-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 Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. 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 amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you

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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 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 this offering will be borne by our general partner. 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 we incur 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 incur 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.

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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 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 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 held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months 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.

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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.

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, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between 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). A purchaser of units who purchases units from another unitholder generally is required to notify us in writing of that purchase within 30 days after the purchase. 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 requirement.

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 Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

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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 Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. 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 a Form 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.

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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 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 a Schedule 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 Vinson & Elkins L.L.P. 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;

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	(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

	(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 underpayment 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.”

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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.”

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 will initially own property or do business in the States of Louisiana, Texas, Oklahoma and Arkansas. 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. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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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.

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.

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UNDERWRITING

We are offering our common units described in this prospectus through the underwriters named below. UBS Securities LLC, Lehman Brothers Inc. and Goldman, Sachs & Co. are the representatives of the underwriters and the joint book-running managers of this offering. Subject to the terms and conditions of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters has severally agreed to purchase the number of common units listed next to its name in the following table:


		Number of
Underwriters		Common Units

UBS Securities LLC
Lehman Brothers Inc.
Goldman, Sachs & Co.
A.G. Edwards & Sons, Inc.
Wachovia Capital Markets, LLC
Credit Suisse Securities (USA) LLC
Raymond James & Associates, Inc.
RBC Capital Markets Corporation

	Total		12,500,000

The underwriting agreement provides that the underwriters must buy all of the common units if they buy any of them. However, the underwriters are not required to take or pay for the common units covered by the underwriters’ option to purchase additional common units described below.

Our common units and the common units to be sold upon the exercise of the underwriters’ option to purchase additional common units, if any, are offered subject to a number of conditions, including:


	•	receipt and acceptance of our common units by the underwriters;

	•	the validity of the representations and warranties made to the underwriters;

	•	the absence of any material change in the financial markets;

	•	our delivery of customary closing documents to the underwriters; and

	•	the underwriters’ right to reject orders in whole or in part.

We have been advised by the representatives that the underwriters intend to make a market in our common units, but that they are not obligated to do so and may discontinue making a market at any time without notice.

Option to Purchase Additional Common Units

We have granted the underwriters an option to buy up to an aggregate 1,875,000 additional common units. This option may be exercised if the underwriters sell more than 12,500,000 common units in connection with this offering. The underwriters have 30 days from the date of this prospectus to exercise this option. If the underwriters exercise this option, they will each purchase additional common units approximately in proportion to the amounts specified in the table above. The net proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to redeem an equal number of common units held by Eagle Rock Holdings, L.P. and the Private Investors and to reimburse Eagle Rock Energy Holdings, L.P. and the Private Investors for capital expenditures incurred indirectly by them.

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Commissions and Discounts

Common units sold by the underwriters to the public will initially be offered at the initial offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount of up to $ per common unit from the initial public offering price. Any of these securities dealers may resell any common units purchased from the underwriters to other brokers or dealers at a discount of up to $ per common unit from the initial public offering price. If all the common units are not sold at the initial public offering price, the representatives may change the offering price and the other selling terms. Sales of common units made outside of the United States may be made by affiliates of the underwriters. Upon execution of the underwriting agreement, the underwriters will be obligated to purchase the common units at the prices and upon the terms stated therein, and, as a result, will thereafter bear any risk associated with changing the offering price to the public or other selling terms.

The following table shows the per unit and total underwriting discounts and fees we will pay to the underwriters assuming both no exercise and full exercise of the underwriters’ option to purchase up to an additional 1,875,000 units.


	No Exercise	Full Exercise

Per Unit	$	$
Total	$	$

We estimate that the total expenses of this offering payable by us, not including the underwriting discounts and commissions and fees, will be approximately $3.0 million.

No Sales of Similar Securities

Eagle Rock Holdings, L.P., our partnership, and our general partner and its affiliates, including the executive officers and directors of Eagle Rock Energy G&P, LLC, the Private Investors and the participants in our directed unit program will enter intolock-up agreements with the underwriters. Under these agreements, we and each of these persons may not, without the prior written approval of UBS Securities LLC, Lehman Brothers Inc. and Goldman, Sachs & Co., offer, sell, contract to sell or otherwise dispose of or hedge our common units or securities convertible into or exchangeable for our common units, enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of the common units, make any demand for or exercise any right or file or cause to be filed a registration statement with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities or publicly disclose the intention to do any of the foregoing; provided, that the foregoing restrictions shall not apply with respect to the filing of a shelf registration statement for the March 2006 Private Investors. These restrictions will be in effect for a period of 180 days after the date of this prospectus. Thelock-up period will be extended under certain circumstances where we release, or pre-announce a release of our earnings or announce material news or a material event during the 17 days before or 16 days after the termination of the180-day period in which case the restrictions described above will continue to apply until the expiration of the18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event. At any time and without public notice, UBS Securities LLC, Lehman Brothers Inc. and Goldman, Sachs & Co. may in their discretion, release all or some of the securities from theselock-up agreements. The representatives have no present understanding or intent to release any of the securities from these lock-up agreements.

Indemnification

We, our general partner and certain of its affiliates, have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be

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required to make for these liabilities. If we are unable to provide this indemnification, we will contribute to payments the underwriters may be required to make in respect of those liabilities.

Directed Unit Program

At our request, certain of the underwriters have reserved up to 625,000 common units for sale at the initial public offering price to the officers, directors and employees of our general partner and its sole member and certain other persons associated with us. We do not know if these persons will choose to purchase all or any portion of these reserved units, but any purchases they do make will reduce the number of units available to the general public. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other units offered by this prospectus. These persons must commit to purchase no later than before the open of business on the day following the date of this prospectus, but in any event these persons are not obligated to purchase common units and may not commit to purchase common units prior to the effectiveness of the registration statement relating to this offering.

Nasdaq Global Market

We have applied to list our common units on the Nasdaq Global Market under the trading symbol “EROC.”

Price Stabilization, Short Positions

In connection with this offering, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of our common units including:


	•	stabilizing transactions;

	•	short sales;

	•	purchases to cover positions created by short sales;

	•	imposition of penalty bids; and

	•	syndicate covering transactions.

Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of our common units while this offering is in progress. These transactions may also include making short sales of our common units, which involves the sale by the underwriters of a greater number of common units than they are required to purchase in this offering, and purchasing common units on the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ option to purchase additional common units referred to above, or may be “naked” shorts, which are short positions in excess of that amount.

The underwriters may close out any covered short position by either exercising their option to purchase additional common units, in whole or in part, or by purchasing common units in the open market. In making this determination, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units.

Naked short sales are in excess of the underwriters’ option to purchase additional common units. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be

181

downward pressure on the price of the common units in the open market that could adversely affect investors who purchased in this offering.

The underwriters also may impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased common units sold by or for the account of that underwriter in stabilizing or short covering transactions.

As a result of these activities, the price of our common units may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time. The underwriters may carry out these transactions on the Nasdaq Global Market, in theover-the-counter market or otherwise.

Determination of Offering Price

Prior to this offering, there has been no public market for our common units. The initial public offering price was determined by negotiation by us and the representatives of the underwriters. The principal factors considered in determining the initial public offering price include:


	•	the information set forth in this prospectus and otherwise available to the representatives;

	•	our history and prospects, and the history and prospects of the industry in which we compete;

	•	our past and present financial performance and an assessment of the directors and officers of our general partner;

	•	our prospects for future earnings and cash flow and the present state of our development;

	•	the general condition of the securities markets at the time of this offering; and

	•	the recent market prices of, and demand for, publicly traded common units of generally comparable master limited partnerships.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Discretionary Sales

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of units offered by them.

182

Stamp Taxes

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Affiliations

The underwriters and their affiliates may from time to time in the future engage in transactions with us and perform services for us in the ordinary course of their business. In addition, some of the underwriters have engaged in, and may in the future engage in, transactions with us and our predecessor and perform services for us in the ordinary course of their business. In particular, affiliates of UBS Securities LLC, Lehman Brothers Inc. and Wachovia Capital Markets, LLC are lenders under our amended and restated senior secured credit facility, and an affiliate of Goldman, Sachs & Co. is lead arranger, administrative agent and collateral agent under our amended and restated credit agreement. Additionally, an affiliate of Wachovia Capital Markets, LLC is the counterparty to one of our interest rate swaps and commodity hedging instruments and an affiliate of Goldman Sachs & Co. is a counterparty to several of our commodity hedging instruments.

NASD Conduct Rules

Because the National Association of Securities Dealers, Inc. views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules. In no event will the maximum amount of compensation to be paid to NASD members in connection with this offering exceed ten percent. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on the New York Stock Exchange or a national securities exchange.

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.

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 included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein and have been so included 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 Partners, L.P. as of May 25, 2006 and the balance sheet of Eagle Rock Energy GP, L.P. as of May 25, 2006 included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports appearing herein and have been so included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The consolidated financial statements of Eagle Rock Pipeline, L.P. as of December 31, 2004 and 2005 and for each of the three years in the period ended December 31, 2005 included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in

183

their report appearing herein and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The statement of net assets acquired in the Brookeland and Masters Creek acquisition as of March 31, 2006 included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The Brookeland and Masters Creek statement of revenues and direct operating expenses for the years ended December 31, 2003, 2004 and 2005 included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Securities and Exchange Commission, or the SEC, a registration statement on Form S-l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

184

INDEX TO FINANCIAL STATEMENTS


Eagle Rock Energy Partners, L.P. Unaudited Pro Forma Condensed Financial Statements:
Introduction		F-2
Unaudited Pro Forma Condensed Consolidated Balance Sheet at June 30, 2006		F-3
Unaudited Pro Forma Condensed Combined Statement of Operations for the Year Ended December 31, 2005		F-4
Unaudited Pro Forma Condensed Combined Statement of Operations for the Six Months Ended June 30, 2006		F-5
Notes to Unaudited Pro Forma Condensed Financial Statements		F-6
ONEOK Texas Field Services, L.P.:
Report of Independent Registered Public Accounting Firm		F-9
Balance Sheets as of December 31, 2004 and November 30, 2005		F-10
Statements of Operations for the Years Ended December 31, 2003 and 2004 and for the Eleven-Month Period Ended November 30, 2005		F-11
Statements of Partnership Capital for the Years Ended December 31, 2003 and 2004 and for the Eleven-Month Period Ended November 30, 2005		F-12
Statements of Cash Flows for the Years Ended December 31, 2003 and 2004 and for the Eleven-Month Period Ended November 30, 2005		F-13
Notes to Financial Statements		F-14
Eagle Rock Pipeline, L.P.:
Report of Independent Registered Public Accounting Firm		F-22
Consolidated Balance Sheets as of December 31, 2004 and 2005, and June 30, 2006		F-23
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2004, and 2005 and for the Six-Month Periods Ended June 30, 2005 and 2006		F-24
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2004, and 2005, and for the Six-Month Periods Ended June 30, 2005, and 2006		F-25
Consolidated Statements of Members’ Equity for the Years Ended December 31, 2003, 2004, and 2005 and for the Six-Month Period Ended June 30, 2006		F-26
Notes to Consolidated Financial Statements		F-27
Eagle Rock Energy Partners, L.P.:
Report of Independent Registered Public Accounting Firm		F-47
Balance Sheet as of May 25, 2006		F-48
Note to Balance Sheet		F-49
Eagle Rock Energy GP, L.P.:
Report of Independent Registered Public Accounting Firm		F-50
Balance Sheet as of May 25, 2006		F-51
Note to Balance Sheet		F-52
Eagle Rock Pipeline, L.P.:
Report of Independent Registered Public Accounting Firm		F-53
Statement of Net Assets Acquired as of March 31, 2006		F-54
Notes to Statement of Net Assets Acquired		F-55
Brookeland/Masters Creek:
Report of Independent Registered Public Accounting Firm		F-56
Statements of Revenues and Direct Operating Expenses for the Years Ended December 31, 2003, 2004, and 2005		F-57
Notes to Statements of Revenues and Direct Operating Expenses		F-58

F-1

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS

Introduction

The unaudited pro forma condensed financial statements are presented for Eagle Rock Energy Partners, L.P. which was formed on May 24, 2006, and is the successor to Eagle Rock Pipeline, L.P. As Eagle Rock Energy Partners, L.P. was recently formed, the historical financial statements are the same as Eagle Rock Pipeline, L.P. In connection with this offering and the formation of Eagle Rock Energy Partners, L.P., Eagle Rock Pipeline, L.P. will act as the operating partnership.

The following unaudited pro forma condensed consolidated balance sheet as of June 30, 2006 is presented to illustrate the estimated effects of this offering and the application of the net proceeds as set forth under “Use of Proceeds” as if this offering had occurred on June 30, 2006. No adjustment was required for the acquisition of the Panhandle assets from ONEOK or the acquisition of Duke Energy Field Services’ interest in the Brookeland/ Masters Creek assets or the acquisition of assets from Midstream Gas Services, L.P., which we refer to as the MGS acquisition, on June 2, 2006, because they occurred prior to June 30, 2006 and therefore are already reflected in the historical June 30, 2006 consolidated balance sheet.

The following unaudited pro forma condensed combined statements of operations for the year ended December 31, 2005 are presented to illustrate the estimated effects as if the following events had occurred on January 1, 2005:


	•	The purchase of the Panhandle assets from ONEOK which occurred on December 1, 2005;

	•	The purchase of the Brookeland/ Masters Creek assets from Duke Energy Field Services and Swift Energy Corporation which occurred on March 31, 2006 and April 7, 2006, respectively; and

	•	The estimated effects of this offering and the application of the net proceeds as set forth under “Use of Proceeds,” as well as the MGS Acquisition.

The unaudited pro forma condensed consolidated statement of operations for the six months ended June 30, 2006 is presented to illustrate the estimated effects of this offering and the application of the net proceeds as set forth under “Use of Proceeds.” As operations at MGS commenced in January 2006, there were no results of operations to include for the year ended December 31, 2005. Results of operations for the six months ended June 30, 2006 have been included. There was no adjustment required for the acquisition of the Panhandle assets from ONEOK since the results of this transaction are already included in the historical consolidated financial statements.

The unaudited pro forma condensed financial statements are based on the audited Eagle Rock Predecessor and Eagle Rock Pipeline, L.P. consolidated financial statements, included elsewhere in this prospectus, as adjusted to illustrate the estimated pro forma effects of the transactions described above. The unaudited pro forma condensed financial statements should be read together with “Selected Historical and Selected Pro Forma Financial and Operating Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Eagle Rock Predecessor consolidated financial statements and the notes to those statements and the Eagle Rock Pipeline, L.P. consolidated financial statements and the notes to those statements included elsewhere in this prospectus.

The unaudited pro forma condensed financial statements are based on assumptions that Eagle Rock Energy Partners, L.P. believes are reasonable under the circumstances and are intended for informational purposes only. They are not necessarily indicative of the financial results that would have occurred if the transactions described herein had taken place on the dates indicated, nor are they indicative of the future consolidated results.

F-2

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

June 30, 2006


								Eagle Rock Energy
			Eagle Rock Pipeline, L.P.					Partners, L.P.

					Adjustments			Pro Forma As
			Historical		for Offering			Adjusted

			($ in thousands)
ASSETS
Current Assets:
	Cash and cash equivalents		$	7,103	$	(5,000	)(a)	$	33,838
						250,000	(b)
						(16,250	)(c)
						(195,750	)(d)
						(3,000	)(e)
						(3,265	)(f)
	Accounts receivable			42,536		(30,000	)(a)		12,536
	Assets from risk management activities			7,347		—			7,347
	Other current assets			731		—			731

Total current assets				57,717		(3,265	)		54,452
Property, plant and equipment, net				532,938		—			532,938
Intangible and other assets
	Intangible assets, net of amortization			139,427		—			139,427
	Long-term assets from risk management activities			31,298		—			31,298
	Other, net			7,741		2,200	(f)		9,941

TOTAL ASSETS			$	769,121	$	(1,065	)	$	768,056


LIABILITIES & MEMBERS’ EQUITY
Current Liabilities:
	Accounts payable		$	29,758	$	—		$	29,758
	Accrued liabilities			6,267		—			6,267
	Liabilities from risk management activities			1,694		—			1,694
	Current portion of long term debt			3,220		(3,000	)(f)		220

Total current liabilities				40,939		(3,000	)		37,939
Long-term liabilities from risk management activities				30,514		—			30,514
Long-term debt				395,000		1,935	(f)		396,935
Asset retirement obligations				713		—			713
Deferred tax liability				508		—			508
Partners’ Predecessor Equity				301,447		—			—
						(35,000	)(a)
						250,000	(b)
						(16,250	)(c)
						(195,750	)(d)
						(3,000	)(e)
						(301,447	)(g)
Members’ Equity
	Limited partner interests
		Common units		—		147,709	(g)		147,709
		Subordinated units		—		147,709	(g)		147,709
	General partner interest			—		6,029	(g)		6,029

Total partners’ equity				301,447		—			301,447

TOTAL LIABILITIES AND MEMBERS’ EQUITY			$	769,121	$	(1,065	)	$	768,056

See accompanying notes to unaudited pro forma condensed financial statements.

F-3

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

For the Year Ended December 31, 2005

(in thousands except unit and per unit amounts)


					Eagle Rock
					Pipeline
		Eagle Rock			Year Ended
		Predecessor			December 31,																Eagle Rock
		for the Eleven			2005			Combined													Energy
		Months Ended			(Includes			Historical			Adjustments				Adjustments			Adjustments			Partners, L.P.
		November 30,			December for			December 31,			for ONEOK				for DEFS			for the			Pro Forma as
		2005			ONEOK)			2005(1)			Acquisition(2)				Acquisition(3)			Offering			Adjusted

Operating revenues		$	396,953		$	66,382		$	463,335			—			$	38,261			—		$	501,596
	Un-realized derivative gains/(losses)		—			7,308			7,308			—				—			—			7,308
	Realized derivative gains/(losses)		—			—			—			—				—			—			—

	Total operating revenues		396,953			73,690			470,643			—				38,261			—			508,904

	Purchases of natural gas and NGLs		316,979			55,272			372,251			—				22,082			——			394,333
	Operating and maintenance expense		27,518			2,955			30,473			—				5,787			—			36,260
	General and administrative expense		—			4,765			4,765			—				—			761	(l)		5,526
	Depreciation and amortization expense		8,157			4,088			12,245			24,468	(h)			5,995	(k)		—			42,708

Operating income			44,299			6,610			50,909			(24,468	)			4,397			(761	)		30,077

	Interest expense		—			4,031			4,031			28,094	(i)			—			440	(p)		32,565
	Interest (income)		(859	)		—			(859	)		—				—			—			(859	)
	Other (income)		(17	)		(171	)		(188	)		—				—			—			(188	)

Income before income taxes			45,175			2,750			47,925			(52,562	)			4,397			(1,201	)		(1,441	)

Income tax provision			15,811			—			15,811			(15,811	)(j)			—			—			—

Net income (loss)		$	29,364		$	2,750		$	32,114		$	(36,751	)		$	4,397		$	(1,201	)	$	(1,441	)

General partner’s interest in income from continuing operations																					$	(29	)
Limited partners’ interest in income from continuing operations																					$	(1,412	)
Net income per limited partner unit(m)
	Common units — basic													��							$	(0.07	)
	Subordinated units — basic																				$	—
	Common units — dilutive																				$	(0.07	)
Weighted average limited partner units outstanding
	Common units — basic																					20,691,495
	Subordinated units — basic																					20,691,495
	Common units — dilutive																					41,382,990


(1)	Represents eleven months of historical activity of Eagle Rock Predecessor for the period from January 1, 2005 through November 30, 2005, twelve months of historical activity for Eagle Rock Pipeline, L.P. for the period January 1, 2005 through December 31, 2005 which includes one month of activity for the ONEOK acquisition from the date of acquisition, December 1, 2005 through December 31, 2005 on a combined basis.

(2)	Adjustments in this column relate to the purchase of our Panhandle assets from ONEOK on December 1, 2005. Accordingly, these adjustments reflect the impact of the increase to the fair value of these assets.

(3)	Adjustments in this column relate to the purchase of the Brookeland/ Masters Creek assets from Duke Energy Field Services and Swift Energy Corporation on March 31, 2006 and April 7, 2006. Accordingly, these adjustments reflect twelve months of activity for the twelve months ended December 31, 2005.

F-4

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

For the Six Months Ended June 30, 2006

(in thousands, except unit and per unit amounts)


														Eagle Rock
		Eagle Rock												Energy
		Pipeline,			Adjustment			Adjustment			Adjustments			Partners, L.P.
		L.P.			for DEFS			for MGS			for the			Pro Forma as
		Historical			Acquisition(1)			Acquisition(2)			Offering			Adjusted

Operating revenues			246,445		$	10,680		$	3,249			—		$	260,374
	Un-realized derivative gains/(losses)		(35,811	)		—			—			—			(35,811	)
	Realized derivative gains/(losses)		570			—			—			—			570

	Total operating revenues		211,204			10,680			3,249			—			225,133

	Purchases of natural gas and NGLs		188,236			7,256			2,648			—			198,140
	Operating and maintenance expense		14,798			1,854			481			—			17,133
	General and administrative expense		6,010			—			—			169	(l)		6,179
	Depreciation and amortization expense		20,215			1,499	(k)		672	(n)		—			22,386

Operating loss			(18,055	)		71			(552	)		(169	)		(18,705	)

	Interest expense		5,963			—			178	(o)		219	(p)		6,360
	Other (income)		(40	)		—			—			—			(40	)

Loss before income taxes			(23,978	)		71			(730	)		(388	)		(25,025	)

Income tax provision			508			—			—			—			508

Net loss		$	(24,486	)	$	71		$	(730	)	$	(388	)	$	(25,533	)

General partner’s interest in income from continuing operations														$	(511	)
Limited partners’ interest in income from continuing operations														$	(25,022	)
Net income per limited partner unit(m)
	Common units — basic													$	(1.21	)
	Subordinated units — basic													$	—
	Common units — dilutive													$	(1.21	)
Weighted average limited partner units outstanding
	Common units — basic														20,691,495
	Subordinated units — basic														20,691,495
	Common units — dilutive														41,382,990


(1)	Adjustments in this column relate to the purchase of the Brookeland/ Masters Creek assets from Duke Energy Field Services and Swift Energy Corporation on March 31, 2006 and April 7, 2006. Accordingly, these adjustments reflect three months of activity for the three months ended March 31, 2006.

(2)	Adjustments in this column relate to the purchase of the MGS assets on June 2, 2006. Accordingly, these adjustments reflect five months of activity for the five months ended May 31, 2006.

F-5

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS


1.	Basis of Presentation, Transactions and the Offering

The historical financial information is derived from the audited historical financial statements of Eagle Rock Predecessor and Eagle Rock Pipeline, L.P. For the unaudited pro forma condensed consolidated balance sheet as of June 30, 2006, the pro forma adjustments have been prepared as if this offering and the related transactions had taken place on June 30, 2006. For the unaudited pro forma condensed combined statement of operations for the year ended December 31, 2005 and the unaudited pro forma condensed consolidated statement of operations for the six months ended June 30, 2006, the pro forma adjustments have been prepared as if the offering and the related transactions had taken place on January 1, 2005. A general description of the transactions and adjustments for the offering affecting the unaudited pro forma condensed financial statements follows:


	•	the purchase of the Brookeland/ Masters Creek assets on March 31, 2006 and April 7, 2006 required adjustment to include the twelve months of 2005 and the first three months of 2006 in order to present information on these assets as if their 100% beneficial interest was acquired on January 1, 2005;

	•	the purchase of Midstream Gas Services, L.P. (“MGS”) on June 2, 2006, required an adjustment to include the five months ended May 31, 2006, in order to present information on these assets as if they were acquired on January 1, 2006.


	•	adjustments for the offering include the following: (1) the distribution of cash, cash equivalents and accounts receivable to subsidiaries of Eagle Rock Holdings, L.P. and a group of private investors that received common units in Eagle Rock Pipeline, L.P. (the “Private Investors”) immediately prior to the consummation of the offering, (2) the sale of 12,500,000 common units at a price of $20 per unit, (3) payment of underwriting discounts, fees and offering expenses, (4) the distribution of approximately $184.8 million to Eagle Rock Holdings, L.P. and the Private Investors for reimbursement of capital expenditures, (5) the distribution of approximately $11.0 million to Eagle Rock Holdings, L.P. in respect of arrearages or the existing subordinated and general partner units of Eagle Rock Pipeline, L.P. owned by Eagle Rock Holdings, L.P., (6) the payment of $3.0 million for offering and related formation expenses, (7) the payment of $2.2 million in arrangement fees on our Amended and Restated Credit Facility entered into on August 31, 2006 and (8) the elimination of the remaining members’ interest converted into general and limited partner interests.


2.	Pro Forma Adjustments and Assumptions

(a) Reflects distribution of cash and cash equivalents and accounts receivable to subsidiaries of Eagle Rock Holdings, L.P. and the Private Investors immediately prior to the consummation of this offering in the amounts of $5.0 million and $30.0 million, respectively.

(b) Reflects the sale of 12,500,000 common units at a price of $20.00 per unit resulting in gross proceeds of $250 million. If the underwriters were to exercise their over-allotment option, gross proceeds would equal $287.5 million, however there would be no net effect on the number of units outstanding as these incremental proceeds would be used to redeem existing units held by Eagle Rock Holdings, L.P. and the Private Investors.

(d) Reflects the distribution of approximately $184.8 million to Eagle Rock Holdings, L.P. and the Private Investors for reimbursement of capital expenditures and to fund the $6.0 million payment to NGP for the termination of the advisory services, reimbursement and indemnification agreement and the distribution of approximately $11.0 million to Eagle Rock Holdings, L.P. in arrearages on certain units of

F-6

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS — (Continued)

Eagle Rock Pipeline, L.P. The expense has been excluded from the statement of operations as it is nonrecurring.

(e) Reflects the payment of $3.0 million of expenses associated with the offering and related formation transactions.

(f) Reflects elimination of our $3 million in current portion of long-term debt, a payment of principal in the amount of $3.3 million in August 2006, payment and capitalization of $2.2 million in arrangement fees on our amended and restated credit facility entered into on August 31, 2006 and financed with borrowings from our revolver facility and the elimination of our required principal amortization concurrent with this offering.

(g) Reflects the conversion of $294 million of member interests into general and limited partner interests. The limited partner interests consist of common units representing 49% ownership and subordinated units representing 49% ownership and the general partner interest representing 2% ownership.

(h) In connection with the ONEOK acquisition, assets were recorded at fair value in accordance with purchase accounting with $471.1 million being allocated to property, plant and equipment, including acquisition costs and $58.5 million to intangible assets, with a weighted average useful life of 18.3 years. The adjustment represents the incremental depreciation and amortization expense on the ONEOK assets for the twelve months ended December 31, 2005.

(i) In calculating the interest expense for the twelve months ended December 31, 2005, we used the March 2006 three-month LIBOR plus the appropriate margin from our credit facility in place at that time. Application of the total rate of 7.49% on a pro forma principal balance of $400 million yields a twelve month interest expense of $30.4 million. The adjustment represents the incremental interest expense. Additionally, interest expense includes $1.4 million for the year ended December 31, 2005, of amortization of debt issue costs related to our credit agreement and $0.3 million in revolver and letter of credit fees.

(j) As the Partnership will not record taxes other than Texas entity level taxes, on a pro forma basis, the provisions for income taxes accrued by Eagle Rock Predecessor were reversed.

(k) In connection with their acquisition, the Brookeland/ Masters Creek assets were recorded at fair value in accordance with purchase accounting with $87.9 million being allocated to property, plant and equipment, including acquisition costs and $8.0 million to intangible assets, with a weighted average useful life of 18.8 years. For the year ended December 31, 2005, incremental depreciation and amortization expense totals $6.0 million. For the six month period ended June 30, 2006, the adjustment represents the incremental depreciation and amortization expense of $1.5 million for the Brookeland/ Masters Creek assets.

(l) Represents the elimination of the management fee that will be terminated effective upon the closing of the offering of $0.1 million and $0.3 million for the year ended December 31, 2005 and the six months ended June 30, 2006, respectively. Additionally, this adjustment includes the compensation expenses related to the long-term incentive plan of $0.9 million and $0.4 million for such periods, respectively.

(m) If the underwriters were to exercise their over-allotment option there will be no net effect on number of units outstanding as the proceeds from the over-allotment option would be used to redeem existing units currently held by Eagle Rock Holdings, L.P. and the Private Investors.

(n) In connection with the MGS acquisition, assets were recorded at fair value on June 2, 2006 with $3.3 million being allocated to property, plant and equipment, including acquisition costs and $21.7 million to intangible assets, with a weighted average useful life of 16 years. The adjustment also represents the incremental depreciation and amortization expense for the MGS assets for the five month period ended May 31, 2006.

F-7

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS — (Continued)

(o) In calculating the interest expense for the six months ended June 30, 2006, we used the March 2006 three-month LIBOR plus the appropriate margin from the credit facility in place at that time. Application of a 7.49% rate on a pro forma basis to the $4.7 million drawn from our existing revolver used to pay the cash portion of the purchase price of MGS, yields an interest expense of $0.2 million for the six months ended June 30, 2006.

(p) Represents the amortization of debt issue costs of $2.2 million related to our amended and restated credit facility entered into on August 31, 2006 of $0.4 million for the twelve months ended December 31, 2005 and $0.2 million for the six months ended June 30, 2006.


3.	Pro Forma Net Income (Loss) per Unit

Pro forma net income (loss) per unit is determined by dividing the pro forma net income (loss) that would have been allocated, in accordance with the net income and loss allocation provisions of the limited partnership agreement, to the common and subordinated unitholders under the two-class method, after deducting the general partner’s interest of 2% in the pro forma net income (loss), by the number of common and subordinated units expected to be outstanding at the closing of the offering. For purposes of this calculation, we assumed that (1) the initial quarterly distribution was made to all unitholders for each quarter during the periods presented and (2) the number of units outstanding were 20,691,495 common units and 20,691,495 subordinated units. The common and subordinated unitholders each represent 49% limited partner interests. All units were assumed to have been outstanding since January 1, 2005. Basic and diluted pro forma net income (loss) per unit are equivalent as there are no dilutive units at the date of closing of the initial public offering of the common units of Eagle Rock Energy Partners L.P. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common and subordinated units. The pro forma net income (loss) per unit calculations assume that no incentive distributions were made to the general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the period.

F-8

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ONEOK Texas Field Services, L.P.

We have audited the accompanying balance sheets of ONEOK Texas Field Services, L.P. (the “Company”) as of December 31, 2004 and November 30, 2005, and the related statements of operations, partnership capital, and cash flows for the years ended December 31, 2003 and 2004 and the eleven-month period ended November 30, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2004 and November 30, 2005, and the results of its operations and its cash flows for the years ended December 31, 2003 and 2004 and for the eleven-month period ended November 30, 2005, in conformity with accounting principles generally accepted in the United States of America.

As described in the notes 1 and 9 to the financial statements, on December 1, 2005, Eagle Rock Field Services, L.P. (a subsidiary of Eagle Rock Midstream Resources, L.P.) acquired ONEOK Texas Field Services, L.P.

/s/ DELOITTE & TOUCHE LLP

Tulsa, Oklahoma

April 28, 2006

F-9

ONEOK TEXAS FIELD SERVICES, L.P.

BALANCE SHEETS

As of December 31, 2004 and November 30, 2005


			December 31,			November 30,
			2004			2005

ASSETS
CURRENT ASSETS:
	Trade accounts receivable — net		$	30,923,722		$	57,504,280
	Other current assets			103,583			72,638

		Total current assets		31,027,305			57,576,918

PROPERTY, PLANT, AND EQUIPMENT				277,416,065			283,937,499
	Less accumulated depreciation and amortization			(33,476,890	)		(41,450,158	)

		Property, plant, and equipment — net		243,939,175			242,487,341

GOODWILL				18,739,673			18,739,673

AMOUNT DUE FROM AFFILIATES — Net				10,911,596			57,543,486

INVESTMENTS AND OTHER				13,172			99,845

TOTAL ASSETS			$	304,630,921		$	376,447,263


LIABILITIES AND PARTNERSHIP CAPITAL
CURRENT LIABILITIES:
	Accounts payable		$	28,050,478		$	44,846,894
	Accrued taxes			227,865			8,371,637
	Merger consideration earnest money			—			15,000,000
	Other current liabilities			158,364			966,197

		Total current liabilities		28,436,707			69,184,728
DEFERRED INCOME TAXES				70,226,307			71,785,476
OTHER DEFERRED CREDITS				1,623,828			1,769,464

		Total liabilities		100,286,842			142,739,668
COMMITMENTS AND CONTINGENCIES (Note 6)
PARTNERSHIP CAPITAL				204,344,079			233,707,595

TOTAL LIABILITIES AND PARTNERSHIP CAPITAL			$	304,630,921		$	376,447,263

See notes to financial statements.

F-10

ONEOK TEXAS FIELD SERVICES, L.P.

STATEMENTS OF OPERATIONS

For the Years Ended December 31, 2003 and 2004 and for the

Eleven-Month Period Ended November 30, 2005


			Years Ended December 31,				Period Ended
							November 30,
			2003		2004		2005

REVENUES			$	297,289,534	$	335,518,977	$	396,953,100
COSTS AND EXPENSES:
	Cost of natural gas and natural gas liquids			249,283,649		263,840,261		316,978,910
	Operations and maintenance			22,394,552		25,218,165		25,326,379
	Depreciation and amortization			7,187,244		8,267,893		8,157,159
	Ad valorem taxes			1,509,920		2,208,776		2,192,117

		Total costs and expenses		280,375,365		299,535,095		352,654,565

OPERATING INCOME				16,914,169		35,983,882		44,298,535

OTHER INCOME:
	Other income — net			51,752		23,145		17,312
	Interest income			189,598		645,329		858,793

		Total other income		241,350		668,474		876,105

INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE				17,155,519		36,652,356		45,174,640
INCOME TAX PROVISION				6,071,125		12,730,580		15,811,124

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE				11,084,394		23,921,776		29,363,516
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE — Net of tax				227,083		—		—

NET INCOME			$	10,857,311	$	23,921,776	$	29,363,516

See notes to financial statements.

F-11

ONEOK TEXAS FIELD SERVICES, L.P.

STATEMENTS OF PARTNERSHIP CAPITAL

For the Years Ended December 31, 2003 and 2004 and for the

Eleven-Month Period Ended November 30, 2005


	Years Ended December 31,				Period Ended
					November 30,
	2003		2004		2005

PARTNERSHIP CAPITAL — Beginning of period	$	169,564,992	$	180,422,303	$	204,344,079
NET INCOME		10,857,311		23,921,776		29,363,516

PARTNERSHIP CAPITAL — End of period	$	180,422,303	$	204,344,079	$	233,707,595

See notes to financial statements.

F-12

ONEOK TEXAS FIELD SERVICES, L.P.

STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2003 and 2004 and for the

Eleven-Month Period Ended November 30, 2005


				Years Ended December 31,						Period Ended
										November 30,
				2003			2004			2005

OPERATING ACTIVITIES:
	Net income			$	10,857,311		$	23,921,776		$	29,363,516
Adjustments to reconcile net income to net cash provided by operating activities
	Depreciation and amortization				7,187,244			8,267,893			8,157,159
	Provision for deferred income taxes				10,942,967			7,325,058			1,559,008
	Changes in assets and liabilities:
		Accounts receivable and other current assets			(23,791,047	)		(30,904,634	)		(56,598,772	)
		Accounts payable and accrued liabilities			21,363,098			34,705,323			64,320,201
		Other assets and liabilities			5,659,611			(1,502,400	)		801,622

			Net cash provided by operating activities		32,219,184			41,813,016			47,602,734

INVESTING ACTIVITIES:
	Capital expenditures				(5,203,298	)		(5,567,410	)		(6,705,325	)
	Other investing activities				—			—			(2,281	)

			Net cash used in investing activities		(5,203,298	)		(5,567,410	)		(6,707,606	)

FINANCING ACTIVITIES — Increase in amounts due from parent					(27,015,886	)		(36,245,606	)		(40,895,128	)

CHANGE IN CASH AND CASH EQUIVALENTS					—			—			—
CASH AND CASH EQUIVALENTS — Beginning of period					—			—			—

CASH AND CASH EQUIVALENTS — End of period					—			—			—

See notes to financial statements.

F-13

ONEOK TEXAS FIELD SERVICES, L.P.

NOTES TO FINANCIAL STATEMENTS

For the Years Ended December 31, 2003 and 2004, and for the

Eleven-Month Period Ended November 30, 2005


1.	ORGANIZATION AND DESCRIPTION OF BUSINESS

Through November 30, 2005, ONEOK Texas Field Services, L.P. (the “Company”) was a wholly-owned subsidiary of ONEOK, Inc. (“ONEOK”), and is the predecessor to Eagle Rock Energy Partners, L.P. The Company purchases, gathers and processes natural gas and extracts, sells and markets natural gas liquids (“NGLs”) in the Texas Panhandle area. We own or lease six processing facilities, and approximately 3,900 miles of gathering pipelines. On December 1, 2005, the Company merged with Eagle Rock Field Services L.P., a subsidiary of Eagle Rock Midstream Resources, L.P. Subsequent to the merger, Eagle Rock Midstream Resources, L.P. changed its name to Eagle Rock Field Services, Inc.


2.	SUMMARY OF ACCOUNTING POLICIES

Critical Accounting Policies — The following is a summary of our most critical accounting policies, which are defined as those policies most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective, or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters. The development and selection of our critical accounting policies and estimates are a reflection of the policies discussed with the audit committee of ONEOK’s Board of Directors for ONEOK’s corporate accounting policies.

Derivatives and Risk Management Activities — To minimize the risk of fluctuations in natural gas, NGLs and crude oil prices, ONEOK periodically enters into futures transactions and swaps on behalf of its subsidiary companies in order to hedge anticipated sales and purchases of natural gas and crude oil production, fuel requirements and NGL inventories on a consolidated basis. The Company, therefore, does not account for these derivative transactions on its books.

Examples of long-lived asset impairment indicators include:


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

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

F-14

ONEOK TEXAS FIELD SERVICES, L.P.

NOTES TO FINANCIAL STATEMENTS — (Continued)


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

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

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

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

Pension and Postretirement Employee Benefits — ONEOK has a defined benefit pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees. No bargaining unit employees hired after December 31, 2004, are eligible for ONEOK’s defined benefit pension plan; however, they are covered by a profit sharing plan. ONEOK’s actuarial consultant calculates the expense and liability related to these plans and uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. In determining the projected benefit obligations and the costs, assumptions can change from period to period and result in material changes in the costs and liabilities we recognize. Our statements of operations reflect the estimated annual expenses that ONEOK incurred on our behalf associated with pension and postretirement employee benefits by allocation.

Contingencies — Our accounting for contingencies covers a variety of business activities including contingencies for legal exposures and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with SFAS No. 5,Accounting for Contingencies. We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Actual results may differ from our estimates resulting in an impact, either positive or negative, on earnings.


	*Significant Accounting Policies*

Cash and Cash Equivalents — the Company’s cash management function is performed by ONEOK. As a part of this function, the Company’s cash receipts and disbursements are transferred to ONEOK accounts on a daily basis and remitted to the Company as cash is required.

Property, Plant, and Equipment — Gas processing plants and all other properties are stated at cost. Gas processing plants are depreciated using various rates based on estimated lives of available gas reserves. All other property and equipment are depreciated using the straight-line method over its estimated useful life. The weighted average useful lives are as follows:


Pipeline and equipment			33 years
Gas processing and equipment			25 years
Office furniture and equipment			20 years

The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets are capitalized.

F-15

ONEOK TEXAS FIELD SERVICES, L.P.

NOTES TO FINANCIAL STATEMENTS — (Continued)

Revenue Recognition — We recognize revenue when services are rendered or product is delivered. We receive fees for gathering natural gas production from oil and natural gas wells under three primary contract arrangements.


	•	Keep-Whole — We extract NGLs and return to the producer volumes of merchantable natural gas containing the same amount of BTUs as the raw natural gas that the producer delivered to us. We then sell the natural gas liquids to an affiliate.

	•	Percent of Proceeds — We retain a percentage of the NGLs and/or a percentage of the natural gas as payment for gathering, compressing and processing the producer’s raw natural gas. Both the natural gas and natural gas liquids are sold to affiliates.

	•	Fee — We are paid a fee for the services provided such as BTUs gathered, compressed, treated and/or processed.

Income Taxes — In 2001, the Company filed an election to be treated as a C corporation for federal income tax purposes, and was included in the consolidated federal income tax return of ONEOK. For financial reporting purposes, the Company computes its income taxes as if it filed a separate federal income tax return. Thus, deferred income taxes are recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities.

Asset Retirement Obligations — On January 1, 2003, we adopted SFAS No. 143,Accounting for Asset Retirement Obligations. SFAS No. 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.

SFAS No. 143 requires that we recognize the fair value of a liability for an asset retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement.

All legal obligations for asset retirement obligations were identified and the fair value of these obligations was determined as of January 1, 2003. The obligations primarily relate to retirements of gas processing plants, compressor sites and meter sites associated with the business. As a result of the adoption of SFAS No. 143, we recorded a long-term liability of approximately $1.44 million, an increase to property, plant and equipment, net of accumulated depreciation, of approximately $1.08 million, and a cumulative effect loss of approximately $0.21 million, net of tax, in the first quarter of 2003. The related depreciation and amortization expense is immaterial to our financial statements. Subsequent changes to these amounts have been immaterial to our financial statements.

Use of Estimates — Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. Items which may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provisions for uncollectible accounts receivable, unbilled revenues for gas delivered but for which meters have not been read, gas purchased expense for gas received but for which no invoice has been received, provision for income taxes including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts. Accordingly, the reported amounts of our assets and liabilities, revenues and expenses, and related disclosures are necessarily affected by these estimates.

F-16

ONEOK TEXAS FIELD SERVICES, L.P.

NOTES TO FINANCIAL STATEMENTS — (Continued)

We evaluate these estimates on an ongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.

Allocated Expenses — Our historical income statements reflect all of the expenses that the parent incurred on its behalf. The Company’s financial statements therefore include certain expenses incurred by its parent which may include, but are not necessarily limited to, the following:


	•	Officer and employee salaries

	•	Rent or depreciation

	•	Advertising

	•	Accounting, tax, and legal services

	•	Other selling, general and administrative expenses

	•	Costs for pension, medical, postretirement, and other employee benefits

Environmental Expenditures — Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. No environmental liabilities have been recorded as of November 30, 2005 or December 31, 2004, respectively.


3.	PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following.


		As of			As of
		December 31			November 30,
		2004			2005

Land and buildings		$	101,587		$	101,587
Pipelines and related assets			272,878,005			277,318,829
Office equipment, furniture, and fixtures			1,783			127,044
Constructions in progress			3,418,233			5,404,689
Other			1,016,457			985,350

	Total		277,416,065			283,937,499
Less accumulated depreciation			(33,476,890	)		(41,450,158	)

Net		$	243,939,175		$	242,487,341


4.	RELATED-PARTY TRANSACTIONS

The majority of the Company’s natural gas and natural gas liquids sales were to affiliates. Total sales to affiliates were $285.6 million, $322.9 million and $386.3 million for the years ended December 31, 2003 and 2004 and for the eleven-month period ended November 30, 2005, respectively. Trade receivables due from affiliates were $22.9 million and $56.5 million at December 31, 2004 and November 30, 2005, respectively. Additionally, ONEOK and its subsidiaries (affiliates) provided a variety of services to the Company, including cash management and financing services, employee benefits provided through

F-17

ONEOK TEXAS FIELD SERVICES, L.P.

NOTES TO FINANCIAL STATEMENTS — (Continued)

ONEOK’s benefit plans, administrative services provided by ONEOK employees and management, insurance and office space leased in ONEOK’s headquarters building and other field locations. Where costs are specifically incurred on behalf of an affiliate, the costs are billed directly to the affiliate by ONEOK. In other situations, the costs are allocated to the affiliates through a variety of methods, depending upon the nature of the expense and the activities of the affiliates. For example, a benefit which applies equally to all employees is allocated based upon the number of employees in each affiliate. An expense benefiting the consolidated company but having no direct basis for allocation is allocated by a method using a combination of gross plant and investment, operating income and labor expense. All costs directly charged or allocated to the Company by affiliates are included in the statements of income and all such operating costs have been allocated by ONEOK and its affiliates.

Our cash management function, including cash receipts and disbursements, were performed by ONEOK. These cash receipts and disbursements are included in amount due from affiliate reflected in our balance sheets. The net amount due from/ (to) ONEOK was approximately $10.9 million and $57.5 million at December 31, 2004 and November 30, 2005, respectively. Amounts payable to ONEOK have no stated maturity date or interest rate. As of December 31, 2004 and November 30, 2005, ONEOK represented the balance due from/ (to) parent would not be called within a twelve month period. As a result, the amount classified as due from parent has been classified as a non-current asset in the accompanying balance sheets. In connection with the cash management function, interest is allocated to the Company for funds held by ONEOK. The methodology for allocating interest income is based on affiliate cash activity and interest rates developed from market rates on ONEOK’s cash balances.


5.	FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of cash and cash equivalents, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short term nature of these instruments.


6.	COMMITMENTS AND CONTINGENCIES

Leases — We utilize assets under operating leases in several areas of operation. Combined rental expense, including leases with no continuing commitment, amounted to $1.2 million, $1.7 million and $1.6 million for the years ended December 31, 2003 and 2004, and the period ended November 30, 2005, respectively.

Future minimum lease payments under non-cancelable operating leases as of November 30, 2005 are immaterial.

Environmental — The Company is subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose the Company to fines, penalties and/or interruptions in our operations that could be material to the results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities, in the process of transporting natural gas or NGLs, or at any facility that we own, operate or otherwise use, the Company could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect our results, operations and cash flow. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional

F-18

ONEOK TEXAS FIELD SERVICES, L.P.

NOTES TO FINANCIAL STATEMENTS — (Continued)

operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.

The Company’s expenditures for environmental evaluation and remediation to date have not been significant in relation to the results of operations and there were no material effects upon earnings related to compliance with environmental regulations.

Other — The Company is a party to other litigation matters and claims, which are normal in the course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position, or liquidity.

Regulatory Compliance — In the ordinary course of business, the Company is subject to various laws and regulations. In the opinion of management, compliance with existing laws and regulations will not materially affect the Company’s financial position.


7.	INCOME TAXES

Earnings are subject to federal income taxes. The following table shows the components of the Company’s income tax provision (benefit):


	Years Ended December 31,					Period Ended
						November 30,
	2003			2004		2005

Current income taxes (benefit)	$	(4,871,842	)	$	5,405,522	$	14,252,116
Deferred income taxes		10,942,967			7,325,058		1,559,008

Total provision for income taxes before cumulative effect of change in accounting principle		6,071,125			12,730,580		15,811,124
Tax benefit related to cumulative effect of change in accounting principle		(122,275	)		—		—

Total provision for income taxes	$	5,948,850		$	12,730,580	$	15,811,124

Taxes computed at the corporate federal income tax rate reconcile to the reported income tax provision as follows:


	Years Ended December 31,						Period Ended
							November 30,
	2003			2004			2005

Pretax income	$	17,155,519		$	36,652,356		$	45,174,640
Federal statutory income tax rate		35	%		35	%		35	%

Provision for federal income taxes at statutory rate		6,004,432			12,828,325			15,811,124
Other — net		66,693			(97,745	)		—

Income tax provision before cumulative effect of change in accounting principle	$	6,071,125		$	12,730,580		$	15,811,124

The Company recognizes the amount of taxes payable or refundable for the current year and recognizes deferred tax liabilities and assets for the expected future tax consequences of events and transactions that have been recognized in its financial statements or tax returns. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some or all of its deferred tax assets will not be realized. Realization of the deferred income tax assets is dependent on generating sufficient taxable income in future years.

F-19

ONEOK TEXAS FIELD SERVICES, L.P.

NOTES TO FINANCIAL STATEMENTS — (Continued)

Deferred tax assets and liabilities are recognized for the estimated future tax effects of temporary differences between the tax basis of assets or liabilities and its reported amount in the financial statements. The measurement of deferred tax assets and liabilities is based on enacted tax laws and rules currently in effect in each of the taxing jurisdictions in which the Company has operations. Generally, deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related asset or liability for financial reporting. The estimated deferred tax effect of temporary differences and carryforwards as of December 31, 2004 and November 30, 2005 were as follows:


			December 31,		November 30,
			2004		2005

DEFERRED TAX ASSETS — Other accrued liabilities			$	212,580	$	254,919

Deferred tax liabilities:
	Excess of tax over book depreciation and depletion			70,377,637		71,984,249
	Other			61,250		56,146

		Total deferred tax liabilities		70,438,887		72,040,395

Net deferred tax liabilities			$	70,226,307	$	71,785,476


8.	EMPLOYEE BENEFIT PLANS

Employee Benefit Plans — The Company’s income statements reflect the estimated annual expenses that ONEOK incurred on its behalf associated with pension, medical, postretirement and other employee benefits by allocation. Such allocated amounts were $1.0 million, $1.5 million and $1.7 million for the years ended December 31, 2003 and 2004, and the eleven-month period ended November 30, 2005, respectively. Primary benefit plans offered were as follows:

Retirement Plans — We have defined benefit and defined contribution retirement plans covering substantially all employees. Certain officers and key employees are also eligible to participate in supplemental retirement plans.

Other Postretirement Benefit Plans — We sponsor welfare care plans that provide postretirement medical benefits and life insurance to substantially all employees who retire under the retirement plans with at least five years of service. The postretirement medical plan is contributory, with retiree contributions adjusted periodically, and contains other cost sharing feature such as deductibles and coinsurance. Nonbargaining employees retiring between the ages of 50 and 55 who elect postretirement medical coverage and all nonbargaining employees hired on or after January 1, 1999 who elect postretirement medical coverage, pay 100 percent of the retiree premium for participation in the plan. Additionally, any employee who came to us through various acquisitions may be further limited in their eligibility to participate or receive any contributions from us for postretirement medical benefits.

Thrift Plan — ONEOK has a Thrift Plan covering substantially all employees. Employee contributions are discretionary. Subject to certain limits, we match employee contributions. the Company’s income statements reflect the estimated annual expenses that ONEOK incurred on our behalf associated with the thrift plan by allocation.

Profit Sharing Plan — ONEOK has a profit sharing plan for all nonbargaining unit employees hired after December 31, 2004. Nonbargaining unit employees who were employed prior to January 1, 2005, were given a one-time opportunity to make an irrevocable election to participate in the profit sharing plan and not accrue any additional benefits under the defined benefit pension plan after December 31, 2004. ONEOK made a contribution to the profit sharing plan each quarter equal to one percent of each participant’s compensation during the quarter. Additional discretionary employer contributions may be

F-20

ONEOK TEXAS FIELD SERVICES, L.P.

NOTES TO FINANCIAL STATEMENTS — (Continued)

made at the end of each year. Employee contributions are not allowed under the plan. The Company’s income statements reflect the estimated annual expenses that ONEOK incurred on our behalf associated with the profit sharing plan by allocation.


9.	SUBSEQUENT EVENT

On December 1, 2005 Eagle Rock Field Services, L.P. (a subsidiary of Eagle Rock Midstream Resources, L.P.) acquired ONEOK Texas Field Services, L.P. for $528 million. In association with the purchase, prior to November 30, 2005, the Company received merger consideration earnest money of $15 million from Eagle Rock Pipeline, L.P.

* * * * * *

F-21

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Members of

Eagle Rock Pipeline, L.P.

Houston, Texas

We have audited the consolidated balance sheets of Eagle Rock Pipeline, L.P. (the “Partnership”) as of December 31, 2004 and 2005, and the related consolidated statements of operations, members’ equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2004 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

June 2, 2006

(August 31, 2006 as to Note 6)

F-22

EAGLE ROCK PIPELINE, L.P.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2004 AND 2005, AND JUNE 30, 2006


			December 31,							Pro Forma
							June 30,			June 30,
			2004		2005		2006			2006

							(Unaudited)			(Unaudited)
ASSETS
CURRENT ASSETS:
	Cash and cash equivalents		$	8,235,336	$	19,371,706	$	7,103,177		$	7,103,177
	Accounts receivable			149,893		43,557,479		42,536,221			42,536,221
	Risk management assets			—		21,829,647		7,346,906			7,346,906
	Prepayments and other current assets			53,085		1,277,364		731,126			731,126

		Total current assets		8,438,314		86,036,196		57,717,430			57,717,430
PROPERTY, PLANT AND EQUIPMENT — Net				19,563,742		441,587,868		532,937,696			532,937,696
INTANGIBLE ASSETS — Net				—		115,000,292		139,427,232			139,427,232
RISK MANAGEMENT ASSETS				—		44,023,139		31,298,013			31,298,013
OTHER ASSETS				14,480		14,011,567		7,741,126			7,741,126

TOTAL			$	28,016,536	$	700,659,062	$	769,121,497		$	769,121,497


LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
	Accounts payable		$	350,512	$	43,401,308	$	29,758,535		$	29,758,535
	Distributions payable — affiliate			—		5,000,000		—
	Distributions payable — owners			—		—		—			230,750,000
	Accrued liabilities			10,541		2,324,812		6,267,052			6,267,052
	Risk management liabilities			—		2,259,819		1,693,949			1,693,949
	Current maturities of long-term debt			—		3,866,038		3,219,630			3,219,630

		Total current liabilities		361,053		56,851,977		40,939,166			271,689,166

LONG-TERM DEBT				—		404,600,000		395,000,000			395,000,000
ASSET RETIREMENT OBLIGATIONS				—		678,802		713,301			713,301
DEFERRED TAX LIABILITY				—		—		507,855			507,855
RISK MANAGEMENT LIABILITIES				—		30,432,547		30,514,048			30,514,048
COMMITMENTS AND CONTINGENCIES (Note 11)
MEMBERS’ EQUITY (DEFICIT):
	Eagle Rock Pipeline, L.P. Predecessor Equity			27,655,483		—
	Common Unit Holders			—		208,013,148		117,282,067			80,237,374
	Subordinated Unitholders			—		—		184,569,739			(4,543,643	)
	General Partner			—		82,588		(404,679	)		(4,996,604	)

		Total members’ equity		27,655,483		208,095,736		301,447,127			70,697,127

TOTAL			$	28,016,536	$	700,659,062	$	769,121,497		$	769,121,497

See notes to consolidated financial statements.

F-23

EAGLE ROCK PIPELINE, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2003, 2004, AND 2005 AND

FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 2005 AND 2006


			December 31,									June 30,

			2003			2004			2005			2005			2006

												(Unaudited)
REVENUE:
	Natural gas liquids sales			—		$	8,797,372		$	29,191,132		$	7,781,742		$	111,916,698
	Condensate			—			71,545			4,266,431			170,396			29,068,805
	Gathering, compression, and processing fees			—			798,847			6,247,438			469,264			5,946,157
	Natural gas sales			—			968,405			26,463,101			1,667,906			99,186,036
	(Loss) gain on risk management instruments			—			—			7,308,130			—			(35,240,327	)
	Other			—			—			213,920			204,681			326,912

		Total revenue		—			10,636,169			73,690,152			10,293,989			211,204,281

COSTS AND EXPENSES:
	Cost of natural gas and natural gas liquids			—			8,811,311			55,271,501			8,845,312			188,235,810
	Operations and maintenance			—			34,639			2,954,978			339,552			14,797,795
	General and administrative		$	144,045			2,405,658			4,765,420			926,118			6,010,748
	Depreciation and amortization			—			618,925			4,088,131			519,743			20,214,617

		Total costs and expenses		144,045			11,870,533			67,080,030			10,630,725			229,258,970

OPERATING (LOSS) INCOME				(144,045	)		(1,234,364	)		6,610,122			(336,736	)		(18,054,689	)

OTHER INCOME (EXPENSE):
	Interest and other income			—			24,224			171,043			48,326			39,764
	Interest and other expense			—			—			(4,031,369	)					(5,962,994	)

		Total other (expense) income		—			24,224			(3,860,326	)		48,326			(5,923,230	)

(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES				(144,045	)		(1,210,140	)		2,749,796			(288,410	)		(23,977,919	)
INCOME TAX PROVISION				—			—			—			—			507,855

(LOSS) INCOME FROM CONTINUING OPERATIONS				(144,045	)		(1,210,140	)		2,749,796			(288,410	)		(24,485,774	)
INCOME FROM DISCONTINUED OPERATIONS				532,547			22,192,121			—			—			—

NET INCOME (LOSS)			$	388,502		$	20,981,981		$	2,749,796		$	(288,410	)	$	(24,485,774	)

Pro forma loss
	Per common unit - basic														$	(1.32	)

	Per common unit - dilutive														$	(1.32	)

Pro forma outstanding
	Common units - basic															18,117,966

	Common units - dilutive															18,117,966

See notes to consolidated financial statements.

F-24

EAGLE ROCK PIPELINE, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2003, 2004, AND 2005, AND

FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 2005, AND 2006


					December 31,									June 30,

					2003			2004			2005			2005			2006

														(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income (loss)				$	388,502		$	20,981,981		$	2,749,796		$	(288,410	)	$	(24,485,774	)
	Adjustments to reconcile net income to net cash provided by (used in) operating activities:
		Depreciation and amortization				97,553			1,174,115			4,088,131			519,743			20,214,617
		Amortization of debt issue costs				—			—			76,306						432,171
		Gain on sale of assets				—			(19,464,569	)		—			—			—
		Reclassifying financing derivative settlements				—			—			—			—			(500,416	)
		Other				—			—			5,276			—			34,499
		Changes in assets and liabilities — net of acquisitions:
			Accounts receivable			(837,480	)		687,587			(42,820,525	)		(40,895	)		1,021,258
			Prepayments and other current assets			(45,591	)		213,669			(358,241	)		26,542			546,238
			Risk management activities			—			—			(5,708,908	)		—			26,723,498
			Accounts and distribution payable			183,575			166,937			40,094,106			54,982			(13,713,833	)
			Accrued liabilities			8,227			2,314			102,844			—			4,450,096
			Other assets			—			111,127			104,330			2,774			324,452
			Other current liabilities			(131,915	)		(221,163	)		—			—			—

				Net cash (used in) provided by operating activities		(337,129	)		3,651,998			(1,666,885	)		274,736			15,046,806

CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to property, plant and equipment					(332,372	)		(20,490,928	)		(4,156,580	)		(4,697	)		(12,930,627	)
	Sale of fixed assets					—			37,408,767			—			—			—
	Acquisitions					(17,950,000	)		—			(530,950,943	)		—			(100,524,298	)
	Escrow Cash					—			—			(7,643,000	)		—			7,643,000
	Purchase of intangible assets					—			—			(750,443	)		—			(2,185,405	)

				Net cash (used in) provided by investing activities		(18,282,372	)		16,917,839			(543,500,966	)		(4,697	)		(107,997,330	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from (repayment of) long-term debt					14,000,000			(14,000,000	)		400,000,000			—			(2,646,408	)
	Proceeds from revolver					—			—			7,600,000			—			3,000,000
	Repayment of revolver					—			—			—			—			(10,600,000	)
	Payments of debt issuance cost					—			—			(6,534,723	)		—			(861,968	)
	(Payment for) proceeds from derivative contracts					—			—			(27,451,512	)		—			500,416
	Payment of deferred offering costs					—			—			—			—			(1,267,214	)
	Contributions by members					6,240,000			45,000			192,369,077			—			98,390,002
	Distributions to members and affiliates					—			—			(9,678,621	)		(6,120,060	)		(5,832,833	)

				Net cash provided by (used in) financing activities		20,240,000			(13,955,000	)		556,304,221			(6,120,060	)		80,681,995

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS						1,620,499			6,614,837			11,136,370			(5,850,021	)		(12,268,529	)
CASH AND CASH EQUIVALENTS — Beginning of period						—			1,620,499			8,235,336			8,235,336			19,371,706

CASH AND CASH EQUIVALENTS — End of period					$	1,620,499		$	8,235,336		$	19,371,706		$	2,385,315		$	7,103,177

Interest paid — net of amounts capitalized					$	—		$	317,247		$	—		$	—		$	17,338,563

Investments in property, plant, and equipment not paid					$	337,405		$	—		$	1,190,086		$	—		$	1,283,671

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

Prepayment financed by note payable					$	221,163		$	—		$	866,038		$	—		$	—

Issuance of common units for MGS acquisition					$	—		$	—		$	—		$	—		$	20,279,996

See notes to consolidated financial statements.

F-25

EAGLE ROCK PIPELINE, L.P.

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2003, 2004, AND 2005 AND

FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 2006


															Eagle Rock
					Number of					Number of					Pipeline, L.P.
		General			Common		Common			Subordinated		Subordinated			Predecessor
		Partner			Units		Units			Units		Units			Equity			Total

BALANCE —
	January 1, 2003		—			—		—			—		—			—			—
	Capital contributions		—			—		—			—		—		$	6,240,000		$	6,240,000
	Net income		—			—		—			—		—			388,502			388,502

BALANCE —
	December 31, 2003		—			—		—			—		—			6,628,502			6,628,502
	Capital contributions		—			—		—			—		—			45,000			45,000
	Net income		—			—		—			—		—			20,981,981			20,981,981

BALANCE —
	December 31, 2004		—			—		—			—		—			27,655,483			27,655,483
	Net income	$	82,588			—	$	4,067,540			—		—			(1,400,331	)		2,749,797
	Distributions		—			—		—			—		—			(14,678,621	)		(14,678,621	)
	Capital contributions		—			—		142,687,996			—		—			49,681,081			192,369,077
	Conversion of predecessor equity to common units		—			—		61,257,612			—		—			(61,257,612	)		—

BALANCE —
	December 31, 2005		82,588			—		208,013,148			—		—			—			208,095,736
	Net loss (unaudited)		(487,267	)		—		(15,920,546	)		—	$	(8,077,961	)		—			(24,485,774	)
	Distributions (unaudited)		—			—		—			—		(832,833	)		—			(832,833	)
	Conversion of common units to subordinated units (unaudited)		—			—		(193,480,533	)		33,582,918		193,480,533			—			—
	Issuance of common units (unaudited)		—			5,455,050		98,390,002			—		—			—			98,390,002
	Issuance of common units in MGS acquisition (unaudited)		—			1,125,416		20,279,996			—		—			—			20,279,996

BALANCE —
	June 30, 2006 (unaudited)	$	(404,679	)		6,580,466	$	117,282,067			33,582,918	$	184,569,739		$	—		$	301,447,127

See notes to consolidated financial statements.

F-26

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2004 AND 2005, AND JUNE 30, 2006 (UNAUDITED) AND

FOR THE YEARS ENDED DECEMBER 31, 2003, 2004, AND 2005 AND FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 2005 (UNAUDITED) AND

2006 (UNAUDITED)


1.	ORGANIZATION AND DESCRIPTION OF BUSINESS

Eagle Rock Pipeline, L.P., a Texas limited partnership, is a indirect wholly owned subsidiary of Eagle Rock Holdings L.P. (“Holdings”). Holdings is a portfolio company of Irving, TX based private equity capital firm, Natural Gas Partners. Eagle Rock Pipeline, L.P. was formed on November 14, 2005 for the purpose of owning a limited partnership interest in Eagle Rock Midstream Resources, L.P.

The accompanying financial statements include the results of operations of Eagle Rock Pipeline, L.P. from November 15, 2005 and the results of operations of Eagle Rock Midstream Resources L.P. and its predecessor entities on a stand-alone basis for the periods prior to November 15, 2005. The reorganization of these entities were accounted for as a reorganization of entities under common control. The general partner interests of Eagle Rock Pipeline, L.P. and Eagle Rock Midstream Resources, L.P. are held by Eagle Rock Pipeline GP, L.L.C. a wholly owned subsidiary of Holdings. On March 22, 2006, Eagle Rock Pipeline GP, L.L.C. and Eagle Rock Pipeline, L.P. were converted to Delaware entities. Eagle Rock Pipeline, L.P., Eagle Rock Midstream Resources L.P., Eagle Rock Pipeline GP, L.L.C. and their subsidiaries are collectively referred to as “Eagle Rock Energy” or the “Partnership.”

Eagle Rock Energy, through its wholly owned subsidiaries and partnerships, provides midstream energy services, including gathering, transportation, treating, processing and conditioning services in the Texas panhandle region. The Partnership’s natural gas pipelines collect natural gas from designated points near producing wells and transports these volumes to third-party pipelines, the Partnership’s gas processing plants, utilities and industrial consumers. Natural gas shipped to the Partnership’s gas processing plants, either on the Partnership’s pipelines or third-party pipelines, is treated to remove contaminants, conditioned or processed into mixed natural gas liquids, or NGLs. The Partnership conducts it operation within two geographic areas of Texas. The Partnership’s Texas panhandle assets consist of assets acquired from ONEOK, Inc. on December 1, 2005 (see Note 4), and include gathering and processing assets (the “Panhandle Segment”). The Partnership’s Southeast Texas and Louisiana assets include a non-operated 25% undivided interest in a processing plant as well as a non-operated 20% undivided interest in a connected gathering system. In December 2005, the Partnership began operations of a newly constructed pipeline in east Texas that connects to the non-operated system (collectively, the Texas and Louisiana Segment). This pipeline was completed in March 2006. On March 31, 2006, the Partnership’s Southeast Texas and Louisiana Segment completed the acquisition of 100% interest in the Brookeland and Masters Creek processing plants in east Texas from Duke Energy Field Services. On June 2, 2006, the Partnership’s Panhandle Segment completed the acquisition of 100% of Midstream Gas Services, L.P. (see Note 4)


2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation — The accompanying consolidated financial statements include the assets, liabilities and results of Eagle Rock Energy and its subsidiaries for each of the periods presented and have been prepared in accordance with accounting principle generally accepted in the United States. Eagle Rock Energy is the owner of a non-operating undivided interests in a gas processing plant and a gas gathering system. Eagle Rock Energy owns these interests as tenants in common with the 75% owner-operator of the facility. Accordingly, Eagle Rock Energy includes its pro-rata share of assets, liabilities, revenues and expenses related to these assets in its financial statements. All significant intercompany accounts and transactions are eliminated in the consolidated financial statements. The unaudited consolidated interim financial statements as of and for the six months ended June 30, 2006

F-27

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and 2005 have been prepared on the same basis as the annual financial statements and all normal recurring adjustments have been made and should be read in conjunction with the annual financial statements. The results of operations for an interim period may not give a true indication of results for a full year.

Pro Forma Information — The pro forma balance sheet information as of June 30, 2006 gives effect to the distribution of $35.0 million to the existing owners of the Partnership and the distribution of $195.8 million representing $184.8 million to existing owners of the Partnership for reimbursement of capital expenditures and the distribution of approximately $11.0 million to Holdings for arrearages on certain units of the Partnership at the closing of the initial public offering.

The pro forma loss per common unit for the six month period ended June 30, 2006 gives effect to the distribution of $35.0 million to the existing owners of the Partnership and the distribution of $195.8 million representing $184.8 million to existing owners of the Partnership for reimbursement of capital expenditures and the distribution of approximately $11.0 million to Holdings for arrearages on certain units of the Partnership at the closing of the initial public offering. As the Partnership generated a loss during the six month period ended June 30, 2006, pro forma loss per common units assumes the sale of 1,750,000 common units at an assumed offering price of $20.00, the proceeds of which would be necessary to pay the distribution. Pro forma loss per common unit for the six month period ended June 30, 2006 is calculated as follows:


	June 30, 2006

	(unaudited)
Net loss	$	(24,485,774	)

Pro forma common units outstanding		6,580,466
Pro forma common units assumed sold		11,537,500

Total common units outstanding		18,117,966

Pro forma net loss per common unit — basic	$	(1.32	)

Pro forma net loss per common unit — dilutive	$	(1.32	)

Use of Estimates — The preparation of the financial statements in conformity with accounting policies generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Although management believes the estimates are appropriate, actual results can differ from those estimates.

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

Concentration and Credit Risk — Financial instruments that potentially subject the Partnership to concentrations of credit risk consist principally of cash and cash equivalents and accounts receivable.

The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership’s Southeast Texas and Louisiana Segment derives its revenue from customers primarily in the natural gas and utility industries. During the year ended December 31, 2005, the Partnership’s Panhandle Segment derived approximately 98% of its revenues from ONEOK Hydro Carbons and ONEOK Energy, Inc. under contracts that expire on June 1, 2006. On June 1, 2006, the Partnership began marketing to other customers. These industry concentrations have the potential to impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that the Partnership’s customers could be affected by similar changes in economic, industry or other conditions.

F-28

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

However, the Partnership believes that the credit risk posed by this industry concentration is offset by the creditworthiness of the Partnership’s customer base. The Partnership’s portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.

Certain Other Concentrations — The Partnership’s Panhandle Segment relies on two natural gas producer customers for a significant portion of its natural gas and natural gas liquid supply, with two suppliers accounting for 28.1% of its natural gas supply for the year ended December 31, 2005. While there are numerous natural gas and natural gas liquid producers and some of their producer customers are subject to long-term contracts, the Partnership may be unable to negotiate extensions or replacements of these contracts, on favorable terms, if at all. If the Partnership were to lose all or even a portion of the natural gas volumes supplied by these producers and was unable to acquire comparable volumes, the Partnership’s results of operations and financial position could be materially adversely affected.

Property, Plant, and Equipment — Property, plant, and equipment consist of interstate gas transmission systems, gas gathering systems, gas processing, conditioning and treating facilities and other related facilities, which are carried at cost less accumulated depreciation. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership calculates depreciation on the straight-line method principally over20-year estimated useful lives of the Partnership’s assets. The weighted average useful lives are as follows:


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

The Partnership capitalizes interest on major projects during extended construction time periods. Such interest is allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. The Partnership capitalized interest of $10,300 related to the construction of a pipeline in 2005. During the six-month period ended June 30, 2006, the Partnership capitalized interest of $56,650.

The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets are capitalized.

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


	significant adverse change in legal factors or in the business climate;

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

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

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

F-29

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


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

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

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

Intangible Assets — Intangible assets consist ofright-of-ways and easements and acquired customer contracts, which the Partnership’s amortizes over the term of the agreement or estimated useful life. Amortization expense was approximately $1,212,324 for the year ended December 31, 2005, and $7,459,282 (unaudited) for the six months ended June 30, 2006. There was no amortization expense for any period prior to December 1, 2005. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2006 — $14,585,411; 2007 — $14,585,411; 2008 — $14,585,411; 2009 — $14,585,411 and 2010 — $13,610,435. Intangible assets consisted of the following:


	December 31,		June 30,
	2005		2006

			(Unaudited)
Rights-of-way and easements — at cost	$	57,714,082	$	67,891,344
Contracts		58,498,534		80,207,494
Less: accumulated amortization		1,212,324		8,671,606

Net Intangible assets	$	115,000,292	$	139,427,232

The weighted average amortization period for ourrights-of-way and easements and contracts was 20 years and 5 years, respectively, and 12 years in total as of December 31, 2005.

Transportation and Exchange Imbalances — In the course of transporting natural gas and natural gas liquids for others, the Partnership may receive for redelivery different quantities of natural gas or natural gas liquids than the quantities actually redelivered. These transactions result in transportation and exchange imbalance receivables or payables that are recovered or repaid through the receipt or delivery of natural gas or natural gas liquids in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets andmarked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2005, the Partnership had imbalance receivables totaling $231,822 and imbalance payables totaling $808,708, respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold.

F-30

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


	sales of natural gas, NGLs and condensate;

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

	NGL transportation from which we generate revenues from transportation fees.

Revenues associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenues associated with transportation and processing fees are recognized when the service is provided.

For gathering and processing services, Eagle Rock Energy either receives fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under thepercentage-of-proceeds contract type, Eagle Rock Energy is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the keep-whole contract type, Eagle Rock Energy purchases wellhead natural gas and sells processed natural gas and NGLs to third parties.

Transportation, compression and processing-related revenue are recognized in the period when the service is provided and include the Partnership’s fee-based service revenue for services such as transportation, compression and processing including processing under tolling arrangements.

Environmental Expenditures — Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. The Partnership has recorded environmental liabilities of $300,000 as of December 31, 2005.

Income Taxes — No provision for income taxes related to the operation of Eagle Rock Energy is included in the accompanying consolidated financial statements as such income is taxable directly to the partners holding interests in the Partnership. The State of Texas enacted a margin tax in May 2006 that the Partnership will be required to pay beginning in 2008. The method of calculation for this margin tax is similar to an income tax, requiring the Partnership to recognize currently the impact of this new tax on the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. See Note 15.

Derivatives — SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended, establishes accounting, and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. SFAS No. 133 provides that normal purchases and normal sales contracts are not subject to the statement. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership’s forward natural gas purchase and sales contracts are designated as normal purchases and sales. Substantially all forward contracts fall within a one-month to five-year term; however, the Partnership does have certain contracts which extend through the life of the dedicated production. The Partnership uses financial instruments such as puts, swaps and other derivatives

F-31

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its consolidated balance sheet at the instrument’s fair value with changes in fair value reflected in the statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the statement of cash flows. See Note 10 for a description of the Partnership’s risk management activities.


3.	NEW ACCOUNTING PRONOUNCEMENTS

In February 2006, the Financial Accounting Standards Board issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments,” an amendment of FASB Statements No. 133 and No. 140. SFAS 155 amends SFAS 133, which required that a derivative embedded in a host contract that does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS 155 amends SFAS 133 to narrow the scope exception to strips that represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS 155 amends SFAS 140, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS 155 amends SFAS 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS 155 is effective for all financial instruments acquired or issued (or subject to a remeasurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. The Partnership will adopt SFAS 155 on January 1, 2007 and does not expect this standard to have a material impact, if any, on our combined financial statements.

In May 2005, the FASB issued Statement of Financial Standards No. 154,Accounting Changes and Error Corrections(“SFAS 154”). This statement establishes new standards on the accounting for and reporting of changes in accounting principles and error corrections. SFAS 154 requires retrospective application to the financial statements of prior periods for all such changes, unless it is impracticable to do so. The Partnership adopted this statement beginning January 1, 2006. The adoption of this statement had no impact and is not expected to have a material effect on our financial position or results of operations on future financial statements.

F-32

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


4.	ACQUISITIONS

On December 1, 2005, the Partnership completed its acquisition of ONEOK Field Services Texas (“ONEOK Texas”) for $530,950,943 (the “ONEOK Texas Acquisition”) to expand the Partnership’s asset base and to obtain critical mass. ONEOK Texas provides natural gas midstream services in the Texas Panhandle and its assets primarily consist of gathering pipelines and processing plants. The results of operations have been included in the statement of operations since the date of acquisition. The Partnership financed the ONEOK Texas Acquisition and related transactions and costs with proceeds from the following:


	Borrowings of approximately $393.5 million of the $400 million initially borrowed under the new Credit Facility discussed in Note 6;

	Net proceeds received from Holdings from a $133 million private placement of equity to Natural Gas Partners.

The following is an estimate of the purchase price for the ONEOK Texas Acquisition:


Estimated net working capital adjustments	$	530,189,966
Estimated acquisition costs		760,977

Total purchase price for the ONEOK Texas Acquisition	$	530,950,943

With the assistance of a third party valuation firm, management has prepared a preliminary assessment of the fair value of the property, plant and equipment and intangible assets of the ONEOK Texas Acquisition as of December 1, 2005. The purchase price allocation is preliminary due to ongoing evaluation of certain acquired liabilities and the valuation of certain pipeline linefill. Using the preliminary assessment, the purchase price has been allocated as of December 1, 2005, as presented below.


Accounts receivable	$	587,061
Property, plant, and equipment		419,551,246
Intangibles		115,462,173
Accounts payable		(1,766,605	)
Other current liabilities		(2,211,427	)
Asset retirement obligations		(671,505	)

	$	530,950,943

All liabilities assumed were at their fair values. The fair value of intangibles is estimated to be $115,462,173. There were no identified intangibles which were determined to have indefinite lives.

F-33

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following unaudited table presents selected unaudited pro forma financial information incorporating the historical (pre-acquisition) results of ONEOK Texas as if the ONEOK Texas Acquisition had occurred at the beginning of each of the periods presented as opposed to the actual date that the acquisition occurred. The pro forma information is based upon preliminary data currently available and includes certain estimates and assumptions made by management. As a result, this preliminary information is not necessarily indicative of the Partnership’s financial results had the transactions actually occurred at the beginning of the period presented. Likewise, the following unaudited pro forma financial information is not necessarily indicative of future financial results of the Partnership.


		Year ended
		December 31

		2004			2005

		(Unaudited)
Pro forma earnings data:
	Revenue	$	346,155,146		$	470,643,252
	Costs and expenses		338,585,761			444,093,741

	Operating income		7,569,385			26,549,511
	Other income (expense), net		(31,003,490	)		(32,039,060	)

Loss from continuing operations		$	(23,434,105	)	$	(5,489,549	)

On March 31, 2006, the Partnership’s Southeast Texas and Louisiana Segment completed the acquisition of an 80% interest in the Brookeland gathering and processing facility, a 76.3% interest in the Masters Creek gathering system and 100% of the Jasper NGL line for $75,654,404 to solidify the Partnership’s Southeast Texas and Louisiana operations and to integrate with the segments existing operations. The Partnership commenced recording these results of operations on April 1, 2006. On April 7, 2006, the remaining interests were acquired for $20,154,328 and the results of operations have been recorded effective as of April 1, 2006, as results of operations for the period April 1, 2006 to April 7, 2006 were not material. Included in other assets at December 31, 2005 is $7,643,000 of escrow cash on deposit for the acquisition of these assets. This escrow cash was released on March 31, 2006. The purchase price is expected to be allocated on a preliminary basis to property, plant and equipment and intangibles in the amounts of $69,711,637 and $6,314,027, respectively, based on their respective fair value as determined by management with the assistance of a third party value specialist. In addition to long term assets, the Partnership assumed certain accrued liabilities.

On June 2, 2006, the Partnership purchased Midstream Gas Services, L.P. (“MGS”) for $4.7 million in cash and 1,125,416 in common units to integrate with the Panhandle segments existing operations. The Partnership will issue up to 1,109,878 common units, subject to adjustment, 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 Partnership commenced recording the results of operations on June 2, 2006.

F-34

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following (unaudited) pro forma information for the six month period ended June 30, 2006 assumes the Brookeland gathering and processing facility, the Masters Creek gathering system, the Jasper NGL line and the MGS interests had been acquired on January 1, 2006:


(Unaudited):
Revenue	$	225,133,348
Costs and expenses		(243,669,042	)

Operating loss		(18,535,694	)
Other income (expenses), net		(6,101,690	)
Income tax provision		(507,855	)

Loss from continuing operations	$	(25,145,239	)

In July, 2004, the Partnership acquired a 25% undivided interest in a processing plant as well as a 20% undivided interest in a connected gathering system for $19,969,137. The results of operations have been recorded on a pro-rata consolidation basis and have been included in the statement of operations since the date of acquisition.


5.	FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS

Fixed assets consisted of the following:


	December 31
					June 30
	2004		2005		2006

					(Unaudited)
Land	$	25,426	$	326,818	$	853,872
Plant		254,226		63,718,080		72,530,857
Gathering and pipeline		2,227,927		345,295,404		432,008,571
Equipment and machinery		16,918,581		24,386,247		30,681,087
Vehicles and transportation equipment		101,683		1,970,047		162,551
Office equipment, furniture, and fixtures		25,425		132,659		479,567
Computer equipment		508,443		508,443		1,322,464
Corporate		63,710		126,448		1,983,696
Linefill		—		3,673,639		3,922,624
Construction in progress		—		4,888,085		5,182,300

		20,125,421		445,025,870		549,127,589
Less: accumulated depreciation and amortization		561,679		3,438,002		16,189,393

Net fixed assets	$	19,563,742	$	441,587,868		532,937,696

Depreciation expense for the years ended December 31, 2003, 2004 and 2005 and for the six months ended June 30, 2005 and 2006 were $91,245, $1,113,321, $2,875,807, $519,743 (unaudited) and $12,755,335(unaudited).

Asset Retirement Obligations — On December 31, 2005, we adopted FASB Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143(“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation”, as used in SFAS No. 143,Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within our control. Although uncertainty about the timing and/or method of

F-35

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, we are required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The adoption of FIN 47 had no impact on the Partnership’s financial statements.

A reconciliation of our liability for asset retirement obligations is as follows:


Asset retirement obligations — January 1, 2005		$	—
	Addition to asset retirement obligations		673,526
	Accretion		5,276

Asset retirement obligations — December 31, 2005			678,802
	Addition to asset retirement obligations		—
	Accretion (unaudited)		34,499

Asset retirement obligations — June 30, 2006 (unaudited)		$	713,301

Asset retirement obligations prior to January 1, 2005 were not significant.


6.	LONG-TERM DEBT

Long-term debt consists of:


		December 31,		June 30,
		2005		2006

				(Unaudited)
Revolver		$	7,600,000		—
Term loan			400,000,000		398,000,000
Other			866,038		219,630

	Total Debt		408,466,038		398,219,630
Less: current portion			3,866,038		3,219,630

Total Long-term debt		$	404,600,000	$	395,000,000

On August 31, 2006, the Partnership amended and restated its existing credit agreement (the “Amended and Restated Credit Agreement”). The Amended and Restated Credit Agreement is a $500,000,000 credit agreement with a syndicate of commercial and investment banks and institutional lenders, with Goldman Sachs Credit Partners L.P., as the administrative agent. The Amended and Restated Credit Agreement provides for $300,000,000 aggregate principal amount of Series B Term Loans (the “Term Loan”) and up to $200,000,000 aggregate principal amount of Revolving Commitments (the “Revolver”). The Amended and Restated Credit Agreement includes a sub limit for the issuance of standby letters of credit for the aggregate unused amount of the Revolver. At August 31, 2006, the Partnership had $300,000,000 outstanding under the Term Loan, $97.0 million outstanding under the Revolver and $13.7 million of outstanding letters of credit.

In connection with the Amended and Restated Credit Agreement, the Partnership incurred debt issuance costs of $2.2 million.

The principal amount due under the Term Loan shall be repaid in consecutive quarterly installments on the four quarterly scheduled interest payment dates applicable to the Term Loan, commencing September 30, 2006, in an amount equal to one-quarter percent (0.25%) of the original principal amount outstanding with the remaining outstanding principal amount due on the Term Loan maturity date. Upon consummation of the Partnership’s initial public offering, quarterly installments under the Term Loan will cease with the balance due on the Term Loan maturity date. The Revolver matures on the revolving commitment termination date.

F-36

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In certain instances defined in the Amended and Restated Credit Agreement, the Term Loan is subject to mandatory repayments and the Revolver is subject to a commitment reduction for cumulative asset sales exceeding $15,000,000; insurance/condemnation proceeds; the issuance of equity securities; the issuance of debt; and up until the Partnership completes an initial public offering, when the Partnership has consolidated excess cash flow (as defined). The Amended and Restated Credit Agreement requires that prior to completing an initial public offering, the Partnership shall, no later than forty-five days after the end of any fiscal year resulting in consolidated excess cash flow, prepay the Term Loan and/or reduce the revolving commitments in an aggregate amount equal to (i) 75% of Consolidated Excess Cash Flow minus (ii) voluntary and scheduled repayments of the Term Loan; provided that after $200,000,000 of the Term Loan has been repaid, the Partnership will only be required to make the prepayments and/or reductions in an amount equal to (i) 50% of consolidated excess cash flow minus (ii) voluntary and scheduled repayments of the Term Loan. Upon consummation of the Partnership’s initial public offering, this repayment requirement is eliminated.

The Amended and Restated Credit Agreement contains various covenants that limit the Partnership’s ability to grant certain liens; make certain loans and investments; make certain capital expenditures outside the Partnership’s current lines of business or certain related lines of business; make distributions other than from available cash; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Partnership’s assets. Additionally, the Amended and Restated Credit Agreement limits the Partnership’s ability to incur additional indebtedness with certain exceptions and purchase money indebtedness and indebtedness related to capital or synthetic leases not to exceed $7.5 million.

The Amended and Restated Credit Agreement also contains covenants, which, among other things, requires the Partnership, on a consolidated basis, to maintain specified ratios or conditions as follows:



	EBITDA (as defined) to interest expense of not less than 2.0 to 1.0 through December 31, 2006 and 2.50 to 1.0 thereafter or upon consummation of the Partnership’s initial public offering;



	Total consolidated funded debt to EBITDA (as defined) of not more than 6.0 to 1.0 through December 31, 2006 and 5.0 to 1.0 thereafter or upon consummation of the Partnership’s initial public offering and 5.25 to 1.0 for the three quarters following an acquisition;

Based upon the senior debt to EBITDA ratio calculated as of August 31, 2006 (utilizing trailing four quarters’ EBITDA as defined under the Credit Agreement proforma for the initial public offering), the Partnership has approximately $23.0 million (unaudited) of unused capacity under the Amended and Restated Credit Agreement Revolver.

At the Partnership’s election, the Term Loan and the Revolver bears interest on the unpaid principal amount either at a base rate plus the applicable margin (defined as 1.25% per annum, reducing to 1.00% when consolidated funded debt to EBITDA (as defined) is less than 3.5 to 1); or at the Adjusted Eurodollar Rate plus the applicable margin (defined as 2.25% per annum, reducing to 2.00% when consolidated funded debt to EBITDA (as defined) is less than 3.5 to 1). At August 31, 2006, the Partnership elected the Eurodollar Rate plus the applicable margin (defined as 2.25%) for a cumulative rate of 7.65%. The applicable margin will increase permanently by 0.50% per annum on January 31, 2007 if by such date the loans under this Amended and Restated Credit Agreement have not obtained a rating by both S&P and Moody’s, and each applicable margin set forth shall decrease by 0.25% per annum on the date that the loans under the Amended and Restated Credit Agreement obtain ratings equal to or greater than Ba3 by Moody’s and BB- by S&P, which decrease shall remain in effect so long as such ratings are maintained.

Base rate interest loans are paid the last day of each March, June, September and December. Eurodollar Rate Loans are paid the last day of each interest period, representing one-, two-, three- or six-,

F-37

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

nine- or twelve-months, as selected by the Partnership. Interest on the Term Loans is paid each December 31, March 31, June 30 and September 30 of each year, commencing on September 30, 2006. The Partnership pays a commitment fee equal to (1) the average of the daily difference between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding revolver loans plus the aggregate principal amount of all outstanding swing loans times (2) 0.50% per annum; provided, that the commitment fee percentage shall increase permanently by 0.25% per annum on January 31, 2007 if the loans under the Amended and Restated Credit Agreement have not obtained a rating by both S&P and Moody’s. The Partnership also pays a letter of credit fee equal to (1) the applicable margin for revolving loans that are Eurodollar Rate loans times (2) the average aggregate daily maximum amount available to be drawn under all such Letters of Credit (regardless of whether any conditions for drawing could then be met and determined as of the close of business on any date of determination). Additionally, the Partnership pays a fronting fee equal to 0.125%, per annum, times the average aggregate daily maximum amount available to be drawn under all letters of credit.

The obligations under the Amended and Restated Credit Agreement are secured by first priority liens on substantially all of the Partnership’s assets, including a pledge of all of the capital stock of each of its subsidiaries.

Prior to entering in the Amended and Restated Credit Agreement, the Partnership operated under a $475,000,000 credit agreement (the “Credit Agreement”) with a syndicate of commercial banks, including Goldman Sachs Credit Partners L.P., as the administrative agent. The Credit Agreement was entered into on December 1, 2005. The Credit Agreement provided for $400,000,000 aggregate principal amount of Series A Term Loans (the “Original Term Loan”) and up to $75,000,000($100,000,000 effective June 2, 2006) aggregate principal amount of Revolving Commitments (the “Original Revolver”). The Credit Agreement included a sub limit for the issuance of standby letters of credit for the lesser of $55 million or the aggregate unused amount of the Original Revolver. At December 31, 2005, the Partnership had $400,000,000 outstanding under the Original Term Loan, $7.6 million outstanding under the Original Revolver and $0.1 million of outstanding letters of credit.

Under the initial terms of the Credit Agreement, the Partnership exercised its option on June 2, 2006 to increase the existing Original Revolver commitment to $100,000,000. In connection with the exercise of this option, the Partnership incurred additional debt issuance costs of $430,963.

The principal amount due under the Original Term Loan was required to be repaid in consecutive quarterly installments on the four quarterly scheduled interest payment dates applicable to the Original Term Loan, commencing April 1, 2006 and ending October 1, 2012, in an amount equal to one-quarter percent (0.25%) of the original principal amount outstanding with the remaining outstanding principal amount due December 1, 2012. The Original Revolver was scheduled to mature on December 1, 2012.

In certain instances defined in the Credit Agreement, the Original Term Loans was subject to mandatory repayments and the Original Revolver was subject to a commitment reduction for cumulative asset sales exceeding $10,000,000; insurance/condemnation proceeds; the issuance of equity securities; the issuance of debt; and when the Partnership has consolidated excess cash flow (as defined). The Credit Agreement required that commencing in 2006, the Partnership shall, no later than ninety days after the end of any fiscal year, prepay the Original Term Loan and/or reduce the revolving commitments in an aggregate amount equal to (i) 75% of consolidated excess cash flow minus (ii) voluntary and scheduled repayments of the Term Loan; provided that after $200,000,000 of the Original Term Loan has been repaid, the Partnership will only be required to make the prepayments and/or reductions in an amount equal to (i) 50% of consolidated excess cash flow minus (ii) voluntary and scheduled repayments of the Original Term Loan. On August 18, 2006, the Partnership made a $3.3 million (unaudited) prepayment under this excess cash flow sweep provision of the Credit Agreement.

F-38

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Credit Agreement contained various covenants that limited the Partnership’s ability to grant certain liens; make certain loans and investments; make certain capital expenditures outside the Partnership’s current lines of business or certain related lines of business; make distributions other than from available cash; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Partnership’s assets. Additionally, the Credit Agreement limited the Partnership’s ability to incur additional indebtedness with certain exceptions, purchase money indebtedness and indebtedness related to capital or synthetic leases not to exceed $5.0 million, unsecured indebtedness not to exceed $5.0 million and unsecured indebtedness qualifying as subordinated debt.

The Credit Agreement also contained covenants, which, among other things, required the Partnership, on a consolidated basis, to maintain specified ratios or conditions as follows:


	EBITDA (as defined) to interest expense of not less than 2.0 to 1.0 through December 31, 2006 and 2.50 to 1.0 thereafter;

	Total senior debt to EBITDA (as defined) of not more than 6.0 to 1.0 through December 31, 2006 and 5.0 to 1.0 thereafter;

Based upon the senior debt to EBITDA ratio calculated as of December 31, 2005 (utilizing trailing four quarters’ EBITDA as defined under the Credit Agreement), the Partnership has approximately $67.4 million of unused capacity under the Credit Agreement Original Revolver.

Management believes the Partnership was in compliance with the financial covenants under the Credit Agreement as of December 31, 2005 and June 30, 2006 (unaudited). If an event of default existed under the Credit Agreement, the lenders would be able to accelerate the maturity of the Credit Agreement and exercise other rights and remedies.

At the Partnership’s election, the Original Term Loan and the Original Revolver bears interest on the unpaid principal amount either at a base rate plus the applicable margin (defined as 1.50% per annum); or at the Adjusted Eurodollar Rate plus the applicable margin (defined as 2.50% per annum). At December 31, 2005, the Partnership elected the Eurodollar Rate plus the applicable margin (defined as 2.50%) for a cumulative rate of 6.79%.

Base rate interest loans under the Original Revolver was paid the last day of each March, June, September and December. Eurodollar Rate Loans under the Original Revolver are paid the last day of each interest period, representing one-, two-, three- or six-, nine- or twelve-months, as selected by the Partnership. Interest on the Original Term Loans was paid each January 1, April 1, July 1 and October 1 of each year, commencing on April 1, 2006. The Partnership was required to pay a commitment fee equal to (1) the average of the daily difference between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding revolver loans times (2) 0.50% per annum. The Partnership also was required to pay a letter of credit fee equal to (1) the applicable margin for revolving loans that are Eurodollar Rate loans times (2) the average aggregate daily maximum amount available to be drawn under all such letters of credit. Additionally, the Partnership was required to pay a fronting fee equal to 0.25%, per annum, times the average aggregate daily maximum amount available to be drawn under all letters of credit.

The obligations under the Credit Agreement were secured by first priority liens on substantially all of the assets, including a pledge of all of the capital stock of each of its subsidiaries.

On March 31, 2006, the Credit Agreement was amended to (i) allow the Partnership to make quarterly distributions to certain private investors and (ii) increasing the 2006 capital expenditure limit from $23 million to $28 million. In connection with this amendment to the Credit Agreement, the Partnership, incurred additional debt issuance costs of $431,000.

F-39

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Scheduled maturities of long-term debt as of December 31, 2005, were as follows:


	Principal
	Amount

2006	$	3,866,038
2007		4,000,000
2008		4,000,000
2009		4,000,000
2010		4,000,000
Thereafter		388,600,000

	$	408,466,038


7.	MEMBER’S EQUITY

At December 31, 2005, the Partnership had common units outstanding representing 98.01% of limited partnership interest and 1.99% of general partner interests all of which were controlled by Holdings. On March 27, 2006, the Partnership sold 5,455,050 common units in a private placement for $98,300,002 and converted the 98.01% limited partnership interest into 33,582,918 subordinated units. Additionally, Holdings contributed $90,000 during the six months ended June 30, 2006. At June 30, 2006, there were 6,580,466 common units and 33,582,918 subordinated units outstanding.

Subordinated units represent limited liability interests in the Partnership, and holders of subordinated units exercise the rights and privileges available to unitholders under the limited liability company agreement. Subordinated units, during the subordination period, will generally receive quarterly cash distributions only when the common units have received a minimum quarterly distribution of $0.32 per unit for the quarter ended June 30, 2006 and $0.35 per unit for each quarters thereafter. Subordinated units will convert into common units on a one-for-one basis when the subordination period ends. Pursuant to the Partnership’s agreement of limited partnership, the subordination period will extend until the occurrence of an initial public offering of the Partnership or the earliest date following March 31, 2009 for which there does not exist any cumulative common unit arrearage.

On August 15, 2006, the Partnership declared and paid a distribution of $1,856,469 (unaudited) to its common unit holders. As of June 30, 2006, the Partnership was in arrears on its subordinated units and general partner units in the amount of $10,746,534 (unaudited) and $262,292, respectively.


8.	RELATED PARTY TRANSACTIONS

On December 1, 2005, Holdings modified its management fee arrangement with Natural Gas Partners. Under the agreement, Natural Gas Partners increased the management fee to $500,000 annually; however, the fee increases to $1,000,000 annually upon completion of an initial public offering. These fees have been pushed down to the Partnership by Holdings. During 2004 and 2005, Eagle Rock Energy recorded management fees to Natural Gas Partners totaling $67,500 and $106,042, respectively. For the six months ended June 30, 2005 and 2006, management fees were $33,750 (unaudited) and $265,000 (unaudited), respectively. During 2005, the Partnership declared and accrued a $5,000,000 distribution to Natural Gas Partners. This distribution was included in the balance sheet at December 31, 2005, in distributions payable — affiliate.

As discussed in Note 4, on June 2, 2006, the Partnership acquired Midstream Gas Services, L.P. Midstream Gas Services, L.P. is a portfolio company of Natural Gas Partners.

F-40

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On July 1, 2006, the Partnership entered into a month-to-month contract for the sale and purchase of natural gas with an affiliate of Natural Gas Partners, under which the Partnership’s panhandle segment has the option to sell a portion of its gas supply. The Partnership has received a Letter of Credit related to this agreement.


9.	FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.

The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. As of December 31, 2005, the debt associated with the Credit Agreement bore interest at floating rates. As such, carrying amounts of this debt instruments approximates fair value.


10.	RISK MANAGEMENT ACTIVITIES

The Credit Agreement required the Partnership to enter into interest rate risk management activities. In December 2005, the Partnership entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into this swap is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments for a period of five years from January 1, 2006 to January 1, 2011. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense. The table below summarizes the terms, amounts received or paid and the fair values of the various interest swaps:


								Amounts		Fair Value
			Notional		Fixed			Paid in		December 31,
Effective Date	Expiration Date		Amount		Rate			2005		2005

01/03/2006		01/03/2011	$	100,000,000		4.9500	%	$	—	$	(173,247	)
01/03/2006		01/03/2011		100,000,000		4.9625			—		(666,723	)
01/03/2006		01/03/2011		50,000,000		4.8800			—		(610,724	)
01/03/2006		01/03/2011		50,000,000		4.8800			—		(148,528	)

For the six month period ended June 30, 2006, the Partnership recorded a fair value gain of $9,087,608 (unaudited). As of June 30, 2006, the fair value of these contracts totaled $7,488,386 (unaudited).

The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond the Partnership’s control. In order to manage the risks associated with natural gas and NGLs, the Partnership engages in risk management activities that take the form of commodity derivative instruments. Currently these activities are governed by the Board of Directors, which today typically prohibits speculative transactions and limits the type, maturity and notional amounts of derivative transactions. We intend to implement a Risk Management Policy that will allow management to purchase crude oil and natural gas liquids puts and certain natural gas put or call options in order to reduce our exposure to substantial adverse changes in the prices of these commodities. We intend to monitor and ensure compliance with this Risk Management Policy with senior level executives in our operations, finance and legal departments.

In October and December 2005, the Partnership entered into the following:


	•	Over-the-counter NGL puts, costless collar and swap transactions for the sale of Mt. Belvieu gas liquids with a combined notional amount of 530,000 Bbls per month for a term from January 2006 through December 2010;

F-41

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	•	Condensate puts and costless collar transactions for the sale of West Texas Intermediate crude oil with a combined notional amount of 250,000 Bbls per month for a term from January 2006 through December 2010; and

	•	Natural gas calls for the sale of Henry Hub natural gas with a notional amount of 200,000 MMBtu per month for a term from January 2006 through December 2007.

The counterparties used for these transactions have investment grade ratings. The NGL and condensate derivatives are intended to hedge the risk of weakening NGL and condensate prices with offsetting increases in the value of the puts based on the correlation between NGL prices and crude oil prices. The natural gas derivatives are included to hedge the risk of increasing natural gas prices with the offsetting value of the natural gas calls.

Eagle Rock Energy has not designated these derivative instruments as hedges and as a result is marking these derivative contracts to market with changes in fair values recorded as an adjustment to themark-to-market gains on risk management transactions within revenue. For the year ended December 31, 2005, the Partnership recorded a fair value gain of $7,308,130 related to these contracts. As of December 31, 2005, the fair value of these contracts totaled $34,759,642. For the six month period ended June 30, 2006, the Partnership recorded a fair value loss of $25,980,805 (unaudited) related to these contracts. As of June 30, 2006, the fair value of these contracts totaled $(1,051,464) (unaudited).


11.	COMMITMENTS AND CONTINGENT LIABILITIES

Litigation — The Partnership is subject to several lawsuits, primarily related to the payments of liquids and gas proceeds in accordance with contractual terms. The Partnership has accruals of $1,631,000 as of December 31, 2005, related to these matters. In addition, the Partnership is also subject to other lawsuits related to the payment of liquid and gas proceeds in accordance with contractual terms for which the Partnership has been indemnified up to a certain dollar amount. For the indemnified lawsuits, the Partnership has not established any accruals as the likelihood of these suits being successful against them is considered remote. If there ultimately is a finding against the Partnership in the indemnified cases, the Partnership could make a claim against the indemnification up to limits of the indemnification. These matters are not expected to have a material adverse effect on our financial position, results of operations or cash flows.

Insurance — Eagle Rock Energy carries insurance coverage which includes the assets and operations, that management believes is consistent with companies engaged in similar commercial operations with similar type properties. These insurance coverages includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from Eagle Rock Energy field operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms, and conditions common for companies with similar types of operations.

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

F-42

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Regulatory Compliance — In the ordinary course of business, the Partnership is subject to various laws and regulations. In the opinion of management, compliance with existing laws and regulations will not materially affect the financial position of the Partnership.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership’s combined results of operations, financial position or cash flows. At December 31, 2005 and June 30, 2006, the Partnership had liabilities of $300,000 recorded for environmental matters.

Other Commitments and Contingencies — Eagle Rock Energy utilizes assets under operating leases for its corporate office and in several areas of its operation. Rental expense, including leases with no continuing commitment, amounted to $0, $36,727, $159,626, $24,222 (unaudited), and $844,700 (unaudited) for the years ended December 31, 2003, 2004, and 2005, and the six months ended June 30, 2005 and 2006, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term. At December 31, 2005, commitments under long-term non-cancelable operating leases for the next five years and thereafter are payable as follows: 2006 — $230,657; 2007 — $225,494; 2008 — $226,533; 2009 — $228,012; 2010 — $228,012 and thereafter — $228,012.


12.	SEGMENTS

Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of two geographic segments: (i) gathering, transportation and marketing of natural gas in the Texas Panhandle (“Panhandle Segment”), (ii) natural gas processing and related NGL transportation in the southeast Texas and Louisiana region (“Southeast Texas and Louisiana Segment”), and (iii) risk management and other corporate activities. The Partnership currently reports its operations, both internally and externally, using these segments. The Partnership evaluates segment performance based on segment margin before depreciation and amortization. Through December 31, 2005, all of the Partnership’s revenue was derived from, and all of the Partnership assets and operations were located in Texas. Transactions between reportable segments are conducted on an arm’s length basis. Prior to the December 1, 2005, acquisition of ONEOK Texas, the Partnership had only one segment.

F-43

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Summarized financial information concerning the Partnership’s reportable segments is shown in the following table:


			Southeast
($ in millions)			Texas and
Year Ended December 31, 2003	Panhandle		Louisiana		Corporate		Total

Sales to external customers	$	—	$	—	$	—	$	—
Interest expense and other financing costs		—		—		—		—
Depreciation and amortization		—		—		—		—
Segment profit (loss)(b)		—		—		—		—
Capital expenditures		—		0.3		—		0.3
Segment assets		—		19.3		2.0		21.3


			Southeast
($ in millions)			Texas and
Year Ended December 31, 2004	Panhandle		Louisiana		Corporate		Total

Sales to external customers	$	—	$	10.6	$	—	$	10.6
Interest expense and other financing costs		—		—		—		—
Depreciation and amortization		—		0.6		—		0.6
Segment profit (loss)(b)		—		1.8		—		1.8
Capital expenditures		—		20.5		—		20.5
Segment assets		—		19.7		8.3		28.0


			Southeast
($ in millions)			Texas and
Year Ended December 31, 2005	Panhandle		Louisiana		Corporate			Total

Sales to external customers	$	43.0	$	23.4	$	7.3	(a)	$	73.7
Interest expense and other financing costs		—		—		4.0			4.0
Depreciation and amortization		2.9		1.0		0.1			4.0
Segment profit (loss)(b)		7.8		3.3		7.3			18.4
Capital expenditures		—		4.1		0.1			4.2
Segment assets		525.4		82		93.3			700.7


			Southeast
($ in millions)			Texas and
Six Months Ended June 30, 2005	Panhandle		Louisiana		Corporate		Total

	(Unaudited)
Sales to external customers	$	—	$	10.3	$	—	$	10.3
Interest expense and other financing costs		—		—		—		—
Depreciation and amortization		—		0.5		—		0.5
Segment profit (loss)(b)		—		1.4		—		1.4
Capital expenditures		—		—		—		—
Segment assets		—		18.5		3.1		21.6

F-44

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			Southeast
($ in millions)			Texas and
Six Months Ended June 30, 2006	Panhandle		Louisiana		Corporate			Total

	(Unaudited)
Sales to external customers	$	212.2	$	34.2	$	(35.2	)(a)	$	211.2
Interest expense and other financing costs		—		—		5.9			5.9
Depreciation and amortization		17.5		2.7		—			20.2
Segment profit (loss)(b)		50.1		8.1		(35.2	)		23.0
Capital expenditures		5.4		4.5		3.0			12.9
Segment assets		566.3		121.0		81.8			769.1


(a)	Represents results of our derivatives activity.

(b)	Segment profit (loss) is defined as sales to external customers minus cost of natural gas and natural gas liquids and other cost of sales.

The following table reconciles segment profit (loss) to income from continuing operations ($ in millions):


										Six Months
	Year Ended			Year Ended			Year Ended			Ended June 30,
	December 31,			December 31,			December 31,
	2003			2004			2005			2005			2006

										(Unaudited)
Segment profit	$	—		$	1.8		$	18.4		$	1.4		$	23.0
Operations and maintenance		—			—			(2.9	)		(0.3	)		(14.8	)
General and administrative		(0.1	)		(2.4	)		(4.8	)		(0.9	)		(6.0	)
Depreciation and amortization		—			(0.6	)		(4.1	)		(0.5	)		(20.2	)
Interest expense, net		—			—			(3.9	)		—			(6.0	)
Provision for income taxes		—			—			—			—			(0.5	)

(Loss) income from continuing operations	$	(0.1	)	$	(1.2	)	$	2.7		$	(0.3	)	$	(24.5	)


13.	DISCONTINUED OPERATIONS

On July 1, 2004, the Partnership closed on the sale of its Dry Trail assets for $37,408,767. The Dry Trail assets consisted of a CO₂ tertiary recovery plant near Hough, Oklahoma. The Dry Trail assets had revenues of $851,798 and $5,131,662 in 2003 and 2004, respectively and generated income of $532,548 and $2,727,552 which is net of interest expense allocated to these operations of $46,156 and $270,500 in 2003 and 2004, respectively. All interest incurred during the period the Partnership owned the Dry Trail assets was allocated to discontinued operations as the debt was specifically related to those assets and was paid off with proceeds from the sale. The Partnership realized a gain of $19,464,569 in 2004 on the sale. There were no assets or liabilities related to the Dry Trail assets as of December 31, 2004 and 2005. The Dry Trial assets were acquired in November 2003 for $17,950,000.


14.	EMPLOYEE BENEFIT PLAN

In 2004, the Partnership began providing a defined contribution benefit plan to its employees that have been with the Partnership longer than six months. The plan provides for a dollar for dollar matching contribution by the Partnership of up to 3% of an employee’s contribution and 50% of additional contributions up to 5%. Additionally, the Partnership contributes 6% of a participating employee’s base salary annually. Expenses under the plan for the years ended December 31, 2004 and 2005 and for the six months ended June 30, 2005 and 2006 were $65,261 and $37,300, $11,600 (unaudited) and $91,871 (unaudited), respectively.

F-45

EAGLE ROCK PIPELINE, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

15. INCOME TAXES (UNAUDITED)

In May 2006, the State of Texas enacted a margin tax that will become effective in 2008. This margin tax will require the Partnership to pay a tax of 1.0% on our “margin,” as defined in the law, beginning in 2008 based on our 2007 results. The margin to which the tax rate will be applied generally will be calculated as our revenues for federal income tax purposes less the cost of the products sold for federal income tax purposes, in the State of Texas. Under the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”, the Partnership is required to record the effects on deferred taxes for a change in tax rates or tax law in the period that includes the enactment date.

Under FAS 109, taxes based on income like the Texas margin tax are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at the end of the period. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

Temporary differences related to the Partnership’s property will affect the Texas margin tax, so we have recorded a deferred tax liability in the amount of $507,855 (unaudited).

* * * * * *

F-46

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Eagle Rock Energy Partners, L.P.

Houston, Texas

We have audited the accompanying balance sheet of Eagle Rock Energy Partners, L.P. (the “Partnership”) as of May 25, 2006. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of Eagle Rock Energy Partners, L.P. as of May 25, 2006 in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

June 2, 2006

F-47

EAGLE ROCK ENERGY PARTNERS, L.P.

Balance Sheet

May 25, 2006


ASSETS
Cash		$	1,000

	Total assets	$	1,000


PARTNERS’ EQUITY
Partners’ capital:
	Limited partner	$	980
	General partner		20

	Total partners’ capital	$	1,000

See accompanying note to balance sheet.

F-48

EAGLE ROCK ENERGY PARTNERS, L.P.

Note to Balance Sheet

May 25, 2006

(1) Organization

Eagle Rock Energy Partners, L.P. (the “Partnership”), is a Delaware limited partnership formed on May 25, 2006 to acquire Eagle Rock Pipeline, L.P. The Partnership’s general partner is Eagle Rock Energy GP, L.P. The Partnership has been formed and capitalized; however, there have been no other transactions involving the Partnership.

The Partnership intends to offer common units, representing limited partner interests, pursuant to a public offering. In addition, the Partnership will issue common units and subordinated units in exchange for the outstanding common and subordinated units of Eagle Rock Pipeline, L.P., as well as a 2% general partner interest in the Partnership to Eagle Rock Energy GP, L.P.

F-49

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Eagle Rock Energy GP, L.P.

Houston, Texas

We have audited the accompanying balance sheet of Eagle Rock Energy GP, L.P. (the “Partnership”) as of May 25, 2006. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of Eagle Rock Energy GP, L.P. as of May 25, 2006 in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

June 2, 2006

F-50

EAGLE ROCK ENERGY GP, L.P.

Balance Sheet

May 25, 2006


ASSETS
Cash		$	980
Investment in Eagle Rock Energy Partners, L.P.			20

	Total Assets	$	1,000


PARTNERS’ EQUITY
Partners’ capital:
	Limited Partner	$	1,000
	General Partner		0

	Total partners’ capital	$	1,000

See accompanying note to balance sheet.

F-51

EAGLE ROCK ENERGY GP, L.P.

Note to Balance Sheet

May 31, 2006

(1) Organization

Eagle Rock Energy GP, L.P. (the “General Partner”) is a Delaware limited partnership formed on May 25, 2006, to become the General Partner of Eagle Rock Energy Partners, L.P. The General Partner has invested $20 in Eagle Rock Energy Partners, L.P. (the “Partnership”) for its 2% general partner interest. The General Partner has no transactions other than formation and capitalization.

The Partnership intends to offer common units, representing limited partner interest, pursuant to a public offering. In addition, the Partnership will issue subordinated units.

F-52

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Eagle Rock Pipeline, L.P.

Houston, Texas

We have audited the accompanying statement of net assets acquired (the “Brookeland and Masters Creek Acquired Assets”) as of March 31, 2006. This financial statement is the responsibility of the Brookeland and Masters Creek Acquired Assets’ management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. The Brookeland and Masters Creek Acquired Assets is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Brookeland and Masters Creek Acquired Assets’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such statement of net assets acquired presents fairly, in all material respects, the financial position of the Brookeland and Masters Creek Acquired Assets as of March 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

June 2, 2006

F-53

EAGLE ROCK PIPELINE, L.P.

STATEMENT OF NET ASSETS ACQUIRED

AS OF MARCH 31, 2006


			March 31,
			2006

NET ASSETS ACQUIRED
PROPERTY, PLANT AND EQUIPMENT:
	Land		$	416,713
	Plant			8,161,614
	Gathering and pipeline			56,427,509
	Equipment and machinery			4,428,068
	Office equipment, furniture and fixtures			43,076
	Linefill			234,657

		Total property, plant and equipment		69,711,637

INTANGIBLE ASSETS — Right-of-ways				6,314,027
CURRENT LIABILITIES — accrued liabilities				(371,260	)

NET ASSETS ACQUIRED			$	75,654,404

See notes to statement of net assets acquired.

F-54

EAGLE ROCK PIPELINE, L.P.

NOTES TO STATEMENT OF NET ASSETS ACQUIRED

AS OF MARCH 31, 2006


1.	BASIS OF PRESENTATION

On March 31, 2006, the Eagle Rock Pipeline, L.P. (the “Partnership”) completed the acquisition of an 80% interest in the Brookeland gathering and processing facility, a 76.3% interest in the Masters Creek gathering system and 100% of the Jasper NGL line in east Texas for $75,654,404. The purchase price has been allocated on a preliminary basis to property, plant and equipment and intangibles based on their respective fair values as determined by management with the assistance of a third party valuation specialist. In addition to the long-term assets the Partnership assumed certain accrued liabilities.

On April 7, 2006, the remaining interests were acquired for $20,154,328. The accompany table reflects the net assets acquired assuming both transactions had occurred as of March 31, 2006.


PROPERTY, PLANT, AND EQUIPMENT:
	Land		$	527,447
	Plant			10,330,406
	Gathering and pipeline			71,422,032
	Equipment and machinery			5,604,742
	Office equipment, furniture and fixtures			54,523
	Linefill			248,985

		Total property, plant and equipment		88,188,135

INTANGIBLE ASSETS — Right-of-ways				7,991,857
CURRENT LIABILITIES — accrued liabilities				(371,260	)

TOTAL			$	95,808,732

F-55

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Eagle Rock Operating, L.P.:

We have audited the accompanying Statements of Revenues and Direct Operating Expenses of the Assets, as defined in the purchase and sale agreement (the “Carve-Out Financial Statement for Brookeland and Masters Creek”) between Duke Energy Field Services, L.P. (“DEFS”) and Eagle Rock Operating, L.P. (“Eagle Rock”) dated December 15, 2005 (the “Agreement”), for the years ended December 31, 2003, 2004, and 2005. The Carve-Out Financial Statement for Brookeland and Masters Creek is the responsibility of DEFS’ management. Our responsibility is to express an opinion on the Carve-Out Financial Statement for Brookeland and Masters Creek based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Carve-Out Financial Statement for Brookeland and Masters Creek is free of material misstatement. The Carve-Out Financial Statement for Brookeland and Masters Creek is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the Carve-Out Financial Statement for Brookeland and Masters Creek, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Carve-Out Financial Statement for Brookeland and Masters Creek. We believe that our audit provides a reasonable basis for our opinion.

The accompanying Carve-Out Financial Statement for Brookeland and Masters Creek was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1 to the Carve-Out Financial Statement for Brookeland and Masters Creek and is not intended to be a complete presentation of the Revenues and Direct Operating Expenses of the Assets, as defined in the Agreement.

In our opinion, such Carve-Out Financial Statement for Brookeland and Masters Creek presents fairly, in all material respects, the Revenues and Direct Operating Expenses as described in Note 1 to the Carve-Out Financial Statement for Brookeland and Masters Creek for the years ended December 31, 2003, 2004, and 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

June 2, 2006

F-56

CERTAIN MID-STREAM ASSETS OF DUKE ENERGY FIELD SERVICES, L.P.

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

For the Years Ended December 31, 2003, 2004, and 2005


			2003			2004			2005

REVENUES:
	Sales — natural gas		$	13,369,036		$	9,381,352		$	8,349,343
	Sales — liquids			29,227,913			27,886,202			26,804,666
	Transport			8,425			4,787			2,102
	Other fee revenue			1,519,702			1,420,794			2,384,339
	Jasper pipeline earnings			1,236,061			947,754			720,617

		Total revenues		45,361,137			39,640,889			38,261,067

DIRECT OPERATING EXPENSES:
	Cost of gas			(24,188,465	)		(22,514,945	)		(22,081,605	)
	Operating costs			(7,195,682	)		(5,806,920	)		(5,787,286	)
	Depreciation			(3,454,140	)		(3,186,738	)		(2,886,332	)

		Total direct operating expenses		34,838,287			(31,508,603	)		(30,755,223	)

EXCESS OF REVENUES OVER DIRECT OPERATING EXPENSES			$	10,522,850		$	8,132,286		$	7,505,844

See notes to Carve-Out Financial Statement.

F-57

CERTAIN MID-STREAM ASSETS OF DUKE ENERGY FIELD SERVICES, L.P.

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

For the Years Ended December 31, 2003, 2004, and 2005


1.	BASIS OF PRESENTATION

Basis of Presentation — In December 2005, Eagle Rock Operating, L.P. (“Eagle Rock”) signed an agreement to acquire from Duke Energy Field Services, L.P. (“DEFS”) certain mid-stream assets (the “assets”), as defined in the Purchase and Sale Agreement between DEFS and Eagle Rock dated December 15, 2005 (“the Agreement”), for approximately $75.7 million. The acquired assets include an 80% interest and a 76.3% interest in processing plants in east Texas. The acquisition closed on March 31, 2006. On April 7, 2006, Eagle Rock acquired the remaining 20% interest and 23.7% interest of the processing plants from Swift Energy Corporation (“Swift”) for approximately $20.2 million. As a result of the purchase of the remaining interests in these assets, Eagle Rock has chosen to present 100% of the operations of these assets within the statement of revenues and direct operative expenses.

The Statement of Revenues and Direct Operating Expenses associated with the assets was derived from DEFS accounting records. Certain expense items not directly associated with the assets, such as interest, income taxes, corporate overhead, and hedging activities, were not recorded in the accounting records of the assets. Any allocation of such costs would be arbitrary and would not be indicative of what such costs actually would have been had the asset been operated as a stand-alone entity.


2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates — Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the Statement of Revenues and Direct Operating Expenses. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates.

Revenue Recognition — Revenues are recognized on sales of natural gas and petroleum products in the period of delivery and transportation revenues in the period the services are provided. For gas processing services, cash or commodities are received as payment depending on the type of contract, at the time the processing occurs. Under“percentage-of-proceeds” contracts, fees are paid in the form of a percentage of the recovered natural gas liquids, which are sold into the market. Under “processing fee” contracts, processing fees are paid in the form of cash.

Depreciation — Depreciation is computed using the straight-line method over the estimated useful life of the individual assets.

Gas Imbalance Accounting — Quantities of natural gas over-delivered or under-delivered related to imbalance agreements with producers or pipelines are recorded monthly using then current index prices or the weighted-average prices of natural gas at the plant or system. These balances are settled with cash or deliveries of natural gas.

Impairment of Long-Lived Assets — The recoverability of long-lived assets is reviewed when circumstances indicate that the carrying amount of the asset may not be recoverable, in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets. The carrying value of a long-lived asset is considered impaired when the anticipated undiscounted cash flow from use of such asset is separately identifiable and is less than its carrying value. In that event, a loss is recognized based on the amount by which the carrying value exceeds the fair value of the long-lived asset. Fair value is determined primarily using the anticipated cash flows discounted at a rate commensurate with the risk involved. No impairment charges were recorded for the years ended December 31, 2003, 2004 and 2005.

F-58

CERTAIN MID-STREAM ASSETS OF DUKE ENERGY FIELD SERVICES, L.P.

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

New Accounting Pronouncement — In June 2005, the Financial Accounting Standards Board (“FASB”) issued SFAS 154, a replacement of APB Opinion No. 20,“Accounting Changes”and FASB Statement No. 3,“Reporting Accounting Changes in Interim Financial Statements.”Among other changes, SFAS 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to do so. SFAS 154 also provides that (1) a change in method of depreciating or amortizing a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) correction of errors in previously issued financial statements should be termed a “restatement.” The new standard is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 depends on the nature and extent of any changes in accounting principles after the effective date, but we do not currently expect SFAS 154 to have a material impact on our consolidated results of operations, cash flows or financial position.

In September 2005, the Emerging Issues Task Force (“EITF”) of the FASB reached consensus in the issue of accounting for buy/sell arrangements as part of its EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (Issue 04-13). Currently, the Company records purchases and sales within the gas processing plant on a gross basis. As part of Issue 04-13, the EITF is requiring that all buy/sell arrangements be reflected on a net basis, such that the purchase and sale are netted and shown as either a net purchase or a net sale in the income statement. This requirement is effective for new arrangements entered into after March 31, 2006. We do not expect that the adoption of Issue 04-13 will have a material effect on our results of operations.


3.	RELATED-PARTY TRANSACTIONS

Revenues for fiscal years 2005, 2004 and 2003 include sales, primarily natural gas and natural gas liquids to affiliates of DEFS and Swift, totaling approximately $30.5 million, $34.0 million and $39.4 million, respectively. These sales were made to the following affiliates of DEFS and Swift:


	2003		2004		2005

Duke Energy NGL Services, Inc.	$	27,570,213	$	26,326,540	$	24,914,590
Duke Energy Trading and Marketing		3,392,725		—		—
ConocoPhilips		5,704,324		5,771,847		4,728,488
Swift Energy Corporation		—		—		203,547
TEPPCO		2,764,187		2,068,687		633,458

Total Related Party Revenue	$	39,431,449	$	34,167,074	$	30,480,083

Duke Energy NGL Services, Inc. is a subsidiary of DEFS. Duke Energy Trading and Marketing is a subsidiary of Duke Energy. Duke Energy owned 70% of DEFS and ConocoPhilips owned 30% of DEFS up until June 2005 when ConocoPhilips increased its ownership to 50%. DEFS was the 100% owner of the General Partner of TEPPCO until it sold its interest in February 2005.

Cost of gas for fiscal years 2003, 2004 and 2005 include purchases totaling approximately $8.0 million, $9.0 million and $8.1 million from Swift. In addition, fiscal years 2003 and 2004 included expenditures related to imbalances to Swift of $4,465 and $171,594, respectively.

* * * * * *

F-59

APPENDIX A

FIRST AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

EAGLE ROCK ENERGY PARTNERS, L.P.

A-1

TABLE OF CONTENTS


ARTICLE I DEFINITIONS
SECTION 1.1	Definitions	A-6
SECTION 1.2	Construction	A-21

ARTICLE II ORGANIZATION
SECTION 2.1	Formation	A-21
SECTION 2.2	Name	A-21
SECTION 2.3	Registered Office; Registered Agent; Principal Office; Other Offices	A-21
SECTION 2.4	Purpose and Business	A-22
SECTION 2.5	Powers	A-22
SECTION 2.6	Power of Attorney	A-22
SECTION 2.7	Term	A-23
SECTION 2.8	Title to Partnership Assets	A-23

ARTICLE III RIGHTS OF LIMITED PARTNERS
SECTION 3.1	Limitation of Liability	A-24
SECTION 3.2	Management of Business	A-24
SECTION 3.3	Outside Activities of the Limited Partners	A-24
SECTION 3.4	Rights of Limited Partners	A-24

ARTICLE IV CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS
SECTION 4.1	Certificates	A-25
SECTION 4.2	Mutilated, Destroyed, Lost or Stolen Certificates	A-25
SECTION 4.3	Record Holders	A-26
SECTION 4.4	Transfer Generally	A-26
SECTION 4.5	Registration and Transfer of Limited Partner Interests	A-26
SECTION 4.6	Transfer of the General Partner’s General Partner Interest	A-27
SECTION 4.7	Transfer of Incentive Distribution Rights	A-27
SECTION 4.8	Restrictions on Transfers	A-28
SECTION 4.9	Citizenship Certificates; Non-citizen Assignees	A-29
SECTION 4.10	Redemption of Partnership Interests of Non-citizen Assignees	A-29

ARTICLE V CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS
SECTION 5.1	Organizational Contributions	A-30
SECTION 5.2	Contributions by the General Partner and Other Parties	A-31
SECTION 5.3	Contributions by Underwriters	A-31
SECTION 5.4	Interest and Withdrawal	A-31
SECTION 5.5	Capital Accounts	A-32
SECTION 5.6	Issuances of Additional Partnership Securities	A-34
SECTION 5.7	Conversion of Subordinated Units	A-35
SECTION 5.8	Limited Preemptive Right	A-36
SECTION 5.9	Splits and Combinations	A-36
SECTION 5.10	Fully Paid and Non-Assessable Nature of Limited Partner Interests	A-36

A-2



ARTICLE VI ALLOCATIONS AND DISTRIBUTIONS
SECTION 6.1	Allocations for Capital Account Purposes	A-36
SECTION 6.2	Allocations for Tax Purposes	A-42
SECTION 6.3	Requirement and Characterization of Distributions; Distributions to Record Holders	A-44
SECTION 6.4	Distributions of Available Cash from Operating Surplus	A-45
SECTION 6.5	Distributions of Available Cash from Capital Surplus	A-46
SECTION 6.6	Adjustment of Minimum Quarterly Distribution and Target Distribution Levels	A-46
SECTION 6.7	Special Provisions Relating to the Holders of Subordinated Units	A-47
SECTION 6.8	Special Provisions Relating to the Holders of Incentive Distribution Rights	A-47
SECTION 6.9	Entity-Level Taxation	A-47

ARTICLE VII MANAGEMENT AND OPERATION OF BUSINESS
SECTION 7.1	Management	A-48
SECTION 7.2	Certificate of Limited Partnership	A-49
SECTION 7.3	Restrictions on the General Partner’s Authority	A-50
SECTION 7.4	Reimbursement of the General Partner	A-50
SECTION 7.5	Outside Activities	A-51
SECTION 7.6	Loans from the General Partner; Loans or Contributions from the Partnership or Group Members	A-52
SECTION 7.7	Indemnification	A-52
SECTION 7.8	Liability of Indemnitees	A-53
SECTION 7.9	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties	A-54
SECTION 7.10	Other Matters Concerning the General Partner	A-55
SECTION 7.11	Purchase or Sale of Partnership Securities	A-56
SECTION 7.12	Registration Rights of the General Partner and its Affiliates	A-56
SECTION 7.13	Reliance by Third Parties	A-59

ARTICLE VIII BOOKS, RECORDS, ACCOUNTING AND REPORTS
SECTION 8.1	Records and Accounting	A-59
SECTION 8.2	Fiscal Year	A-59
SECTION 8.3	Reports	A-59

ARTICLE IX TAX MATTERS
SECTION 9.1	Tax Returns and Information	A-60
SECTION 9.2	Tax Elections	A-60
SECTION 9.3	Tax Controversies	A-60
SECTION 9.4	Withholding	A-60

ARTICLE X ADMISSION OF PARTNERS
SECTION 10.1	Admission of Limited Partners	A-61
SECTION 10.2	Admission of Successor General Partner	A-61
SECTION 10.3	Amendment of Agreement and Certificate of Limited Partnership	A-61

A-3



ARTICLE XI WITHDRAWAL OR REMOVAL OF PARTNERS
SECTION 11.1	Withdrawal of the General Partner	A-62
SECTION 11.2	Removal of the General Partner	A-63
SECTION 11.3	Interest of Departing General Partner and Successor General Partner	A-63
SECTION 11.4	Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages	A-65
SECTION 11.5	Withdrawal of Limited Partners	A-65

ARTICLE XII DISSOLUTION AND LIQUIDATION
SECTION 12.1	Dissolution	A-65
SECTION 12.2	Continuation of the Business of the Partnership After Dissolution	A-65
SECTION 12.3	Liquidator	A-66
SECTION 12.4	Liquidation	A-66
SECTION 12.5	Cancellation of Certificate of Limited Partnership	A-67
SECTION 12.6	Return of Contributions	A-67
SECTION 12.7	Waiver of Partition	A-67
SECTION 12.8	Capital Account Restoration	A-67

ARTICLE XIII AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE
SECTION 13.1	Amendments to be Adopted Solely by the General Partner	A-68
SECTION 13.2	Amendment Procedures	A-69
SECTION 13.3	Amendment Requirements	A-69
SECTION 13.4	Special Meetings	A-70
SECTION 13.5	Notice of a Meeting	A-70
SECTION 13.6	Record Date	A-70
SECTION 13.7	Adjournment	A-70
SECTION 13.8	Waiver of Notice; Approval of Meeting; Approval of Minutes	A-71
SECTION 13.9	Quorum and Voting	A-71
SECTION 13.10	Conduct of a Meeting	A-71
SECTION 13.11	Action Without a Meeting	A-71
SECTION 13.12	Right to Vote and Related Matters	A-72

ARTICLE XIV MERGER, CONSOLIDATION OR CONVERSION
SECTION 14.1	Authority	A-72
SECTION 14.2	Procedure for Merger, Consolidation or Conversion	A-72
SECTION 14.3	Approval by Limited Partners	A-74
SECTION 14.4	Certificate of Merger	A-75
SECTION 14.5	Effect of Merger, Consolidation or Conversion	A-75

ARTICLE XV RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS
SECTION 15.1	Right to Acquire Limited Partner Interests	A-76

A-4



ARTICLE XVI GENERAL PROVISIONS
SECTION 16.1	Addresses and Notices	A-77
SECTION 16.2	Further Action	A-77
SECTION 16.3	Binding Effect	A-78
SECTION 16.4	Integration	A-78
SECTION 16.5	Creditors	A-78
SECTION 16.6	Waiver	A-78
SECTION 16.7	Third-Party Beneficiaries	A-78
SECTION 16.8	Counterparts	A-78
SECTION 16.9	Applicable Law	A-78
SECTION 16.10	Invalidity of Provisions	A-78
SECTION 16.11	Consent of Partners	A-78
SECTION 16.12	Facsimile Signatures	A-78

A-5

FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF EAGLE ROCK ENERGY PARTNERS, L.P.

THIS FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF EAGLE ROCK ENERGY PARTNERS, L.P. dated as of , 2006, is entered into by and between Eagle Rock Energy GP, L.P., a Delaware limited partnership, as the General Partner, and Eagle Rock Holdings, L.P., a Texas limited partnership, as the Organizational Limited Partner, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions.

The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Acquisition” means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing the operating capacity or revenues of the Partnership Group from the operating capacity or revenues of the Partnership Group existing immediately prior to such transaction.

“Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:


	(a) negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

	(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis;provided, that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

“Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the“Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period.

“Adjusted Capital Account” means the Capital Account maintained for each Partner as of the end of each fiscal year of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all losses and deductions that, as of the end of such fiscal year, are reasonably expected to be

A-6

allocated to such Partner in subsequent years under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (ii) the amount of all distributions that, as of the end of such fiscal year, are reasonably expected to be made to such Partner in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of a General Partner Unit, a Common Unit, a Subordinated Unit or an Incentive Distribution Right or any other Partnership Interest shall be the amount that such Adjusted Capital Account would be if such General Partner Unit, Common Unit, Subordinated Unit, Incentive Distribution Right or other Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such General Partner Unit, Common Unit, Subordinated Unit, Incentive Distribution Right or other Partnership Interest was first issued.

“Adjusted Operating Surplus” means, with respect to any period, Operating Surplus generated with respect to such period (a) less any net decrease in cash reserves for Operating Expenditures with respect to such period not relating to an Operating Expenditure made with respect to such period, and (b) plus (i) any net decrease made in subsequent periods in cash reserves for Operating Expenditures initially established with respect to such period and (ii) any net increase in cash reserves for Operating Expenditures with respect to such period required by any debt instrument for the repayment of principal, interest or premium. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) of the definition of Operating Surplus.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d)(i) or 5.5(d)(ii).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution as determined by the General Partner. The General Partner shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

“Agreement” means this First Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P., as it may be amended, supplemented or restated from time to time.

“Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer or partner or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

A-7

“Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:


	(a) the sum of (i) all cash and cash equivalents of the Partnership Group on hand at the end of such Quarter, and (ii) if the General Partner so determines, all or any portion of any additional cash and cash equivalents of the Partnership Group on hand on the date of determination of Available Cash with respect to such Quarter, less

	(b) the amount of any cash reserves established by the General Partner to (i) provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures and for anticipated future credit needs of the Partnership Group) subsequent to such Quarter, (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject or (iii) provide funds for distributions under Section 6.4 or 6.5 in respect of any one or more of the next four Quarters;provided, however, that the General Partner may not establish cash reserves pursuant to (iii) above if the effect of such reserves would be that the Partnership is unable to distribute the Minimum Quarterly Distribution on all Common Units, plus any Cumulative Common Unit Arrearage on all Common Units, with respect to such Quarter; and,provided further, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

Notwithstanding the foregoing,“Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“Board of Directors” means, with respect to the Board of Directors of the General Partner, its board of directors or managers, as applicable, if a corporation or limited liability company, or if a limited partnership, the board of directors or board of managers of the general partner of the General Partner.

“Book Basis Derivative Items” means any item of income, deduction, gain or loss included in the determination of Net Income or Net Loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, depletion, or gain or loss with respect to an Adjusted Property).

“Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

“Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of New York shall not be regarded as a Business Day.

“Capital Account” means the capital account maintained for a Partner pursuant to Section 5.5. The“Capital Account” of a Partner in respect of a General Partner Unit, a Common Unit, a Subordinated Unit, an Incentive Distribution Right or any Partnership Interest shall be the amount that such Capital Account would be if such General Partner Unit, Common Unit, Subordinated Unit, Incentive Distribution Right or other Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such General Partner Unit, Common Unit, Subordinated Unit, Incentive Distribution Right or other Partnership Interest was first issued.

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“Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership.

“Capital Improvement” means any (a) addition or improvement to the capital assets owned by any Group Member, (b) acquisition of existing, or the construction of new, capital assets (including, without limitation, gathering lines, treating facilities, processing plants, fractionation facilities, pipelines, terminals, docks, truck racks, tankage and other storage, distribution or transportation facilities and related or similar midstream assets) or (c) capital contributions by a Group Member to a Person in which a Group Member has an equity interest to fund such Group Member’s pro rata share of the cost of the acquisition of existing, or the construction of new, capital assets (including, without limitation, gathering lines, treating facilities, processing plants, fractionation facilities, pipelines, terminals, docks, truck racks, tankage and other storage, distribution or transportation facilities and related or similar midstream assets) by such Person, in each case if such addition, improvement, acquisition or construction is made to increase the operating capacity or revenues of the Partnership Group, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from the operating capacity or revenues of the Partnership Group or such Person, as the case may be, existing immediately prior to such addition, improvement, acquisition or construction.

“Capital Surplus” has the meaning assigned to such term in Section 6.3(a).

“Carrying Value” means (a) with respect to a Contributed Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, amortization and cost recovery deductions chargedtothe Partners’ Capital Accounts in respect of such Contributed Property, and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Sections 5.5(d)(i) and 5.5(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

“Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

“Certificate” means (a) a certificate (i) substantially in the form of Exhibit A to this Agreement, (ii) issued in global form in accordance with the rules and regulations of the Depositary or (iii) in such other form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Common Units or (b) a certificate, in such form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more other Partnership Securities.

“Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

“Citizenship Certification” means a properly completed certificate in such form as may be specified by the General Partner by which a Limited Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Citizen.

“claim” (as used in Section 7.12(d)) has the meaning assigned to such term in Section 7.12(d).

“Closing Date” means the first date on which Common Units are sold by the Partnership to the Underwriters pursuant to the provisions of the Underwriting Agreement.

“Closing Price” has the meaning assigned to such term in Section 15.1(a).

“Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

“Combined Interest” has the meaning assigned to such term in Section 11.3(a).

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“Commission” means the United States Securities and Exchange Commission.

“Commodity Hedge Contract” means any commodity exchange, swap, forward, cap, floor collar or other similar agreement or arrangement, each of which is for the purpose of hedging the exposure of the Partnership Group to fluctuations in the price of hydrocarbons in their operations and not for speculative purposes.

“Common Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners and Assignees, and having the rights and obligations specified with respect to Common Units in this Agreement. The term “Common Unit” does not include a Subordinated Unit prior to its conversion into a Common Unit pursuant to the terms hereof.

“Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, as to any Quarter within the Subordination Period, the excess, if any, of (a) the Minimum Quarterly Distribution with respect to a Common Unit in respect of such Quarter over (b) the sum of all Available Cash distributed with respect to a Common Unit in respect of such Quarter pursuant to Section 6.4(a)(i).

“Conflicts Committee” means a committee of the Board of Directors of the General Partner composed entirely of two or more directors, each of whom (a) is not a security holder, officer or employee of the General Partner, (b) is not an officer, director or employee of any Affiliate of the General Partner, (c) is not a holder of any ownership interest in the Partnership Group other than Common Units and (d) meets the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Common Units are listed or admitted to trading.

“Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Contribution Agreement” means that certain Contribution and Conveyance Agreement, dated as of the Closing Date, among the General Partner, the Partnership, the Operating Partnership and certain other parties, together with the additional conveyance documents and instruments contemplated or referenced thereunder, as such may be amended, supplemented or restated from time to time.

“Credit Agreement”means the Amended and Restated Credit and Guaranty Agreement, dated as of August 31, 2006, among our Operating Partnership, the Partnership, the subsidiaries of the Partnership, and Goldman Sachs Credit Partners L.P., as administrative agent for the lenders named therein.

“Cumulative Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum resulting from adding together the Common Unit Arrearage as to an Initial Common Unit for each of the Quarters within the Subordination Period ending on or before the last day of such Quarter over (b) the sum of any distributions theretofore made pursuant to Section 6.4(a)(ii) and the second sentence of Section 6.5 with respect to an Initial Common Unit (including any distributions to be made in respect of the last of such Quarters).

“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

“Current Market Price” has the meaning assigned to such term in Section 15.1(a).

“Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Departing General Partner” means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or Section 11.2.

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“Depositary” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

“Eligible Citizen” means a Person qualified to own interests in real property in jurisdictions in which any Group Member does business or proposes to do business from time to time, and whose status as a Limited Partner the General Partner determines does not or would not subject such Group Member to a significant risk of cancellation or forfeiture of any of its properties or any interest therein.

“Estimated Incremental Quarterly Tax Amount” has the meaning assigned to such term in Section 6.9.

“Event of Withdrawal” has the meaning assigned to such term in Section 11.1(a).

“Existing Registration Rights Agreement” means the March 2006 Private Investors’ Registration Rights Agreement.

“Expansion Capital Expenditures” means cash expenditures for Acquisitions or Capital Improvements, and shall not include Maintenance Capital Expenditures.

“Final Subordinated Units” has the meaning assigned to such term in Section 6.1(d)(x).

“First Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(D).

“First Target Distribution” means $0.4169 per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on September 30, 2006, it means the product of $0.4169 multiplied by a fraction of which the numerator is the number of days in such period, and of which the denominator is 92), subject to adjustment in accordance with Sections 6.6 and 6.9.

“Fully Diluted Basis” means, when calculating the number of Outstanding Units for any period, a basis that includes, in addition to the Outstanding Units, all Partnership Securities and options, rights, warrants and appreciation rights relating to an equity interest in the Partnership (a) that are convertible into or exercisable or exchangeable for Units that are senior to or pari passu with the Subordinated Units, (b) whose conversion, exercise or exchange price is less than the Current Market Price on the date of such calculation, (c) that may be converted into or exercised or exchanged for such Units prior to or during the Quarter immediately following the end of the period for which the calculation is being made without the satisfaction of any contingency beyond the control of the holder other than the payment of consideration and the compliance with administrative mechanics applicable to such conversion, exercise or exchange and (d) that were not converted into or exercised or exchanged for such Units during the period for which the calculation is being made;provided, however, that for purposes of determining the number of Outstanding Units on a Fully Diluted Basis when calculating whether the Subordination Period has ended or Subordinated Units are entitled to convert into Common Units pursuant to Section 5.7, such Partnership Securities, options, rights, warrants and appreciation rights shall be deemed to have been Outstanding Units only for the four Quarters that comprise the last four Quarters of the measurement period;provided, further, that if consideration will be paid to any Group Member in connection with such conversion, exercise or exchange, the number of Units to be included in such calculation shall be that number equal to the difference between (i) the number of Units issuable upon such conversion, exercise or exchange and (ii) the number of Units that such consideration would purchase at the Current Market Price.

“General Partner” means Eagle Rock Energy GP, L.P., a Delaware limited partnership, and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).

“General Partner Interest” means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it), which is evidenced by General Partner Units, and includes any and all benefits to which the General Partner is

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entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.

“General Partner Unit” means a fractional part of the General Partner Interest having the rights and obligations specified with respect to the General Partner Interest. A General Partner Unit is not a Unit.

“Group” means a Person that with or through any of its Affiliates or Associates has any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

“Group Member” means a member of the Partnership Group.

“Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

“Holder” as used in Section 7.12, has the meaning assigned to such term in Section 7.12(a).

“Incentive Distribution Right” means a non-voting Limited Partner Interest issued to the General Partner in connection with the transactions contemplated pursuant to the Contribution Agreement, which Limited Partner Interest will confer upon the holder thereof only the rights and obligations specifically provided in this Agreement with respect to Incentive Distribution Rights (and no other rights otherwise available to or other obligations of a holder of a Partnership Interest). Notwithstanding anything in this Agreement to the contrary, the holder of an Incentive Distribution Right shall not be entitled to vote such Incentive Distribution Right on any Partnership matter except as may otherwise be required by law.

“Incentive Distributions” means any amount of cash distributed to the holders of the Incentive Distribution Rights pursuant to Sections 6.4(a)(v), (vi) and (vii) and 6.4(b)(iii), (iv) and (v).

“Indemnified Persons” has the meaning assigned to such term in Section 7.12(d).

“Indemnitee” means (a) the General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was serving at the request of the General Partner or any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as a member, partner, director, officer, fiduciary or trustee of any Group Member, the General Partner or any Departing General Partner or any Affiliate of any Group Member, the General Partner or any Departing General Partner, (e) any Person who is or was serving at the request of the General Partner or any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as an officer, director, member, partner, fiduciary or trustee of another Person;providedthat a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, and (f) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement.

“Initial Common Units” means the Common Units sold in the Initial Offering.

“Initial Limited Partners” means Eagle Rock Holdings, L.P. (with respect to the Common Units and Subordinated Units received by it pursuant to Section 5.2) and the General Partner (with respect to the Incentive Distribution Rights received by it pursuant to Section 5.2), the Persons named on Schedule A to the Contribution Agreement (with respect to the Common Units received by them pursuant to

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Section 5.2) and the Underwriters upon the issuance by the Partnership of Common Units as described in Section 5.3 in connection with the Initial Offering.

“Initial Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement.

“Initial Unit Price” means (a) with respect to the Common Units, the initial public offering price per Common Unit at which the Underwriters offered the Common Units to the public for sale as set forth on the cover page of the prospectus included as part of the Registration Statement and first issued at or after the time the Registration Statement first became effective or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially sold by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of Units.

“Interim Capital Transactions” means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than for items purchased on open account in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) sales of equity interests of any Group Member (including the Common Units sold to the Underwriters pursuant to the exercise of the Over-Allotment Option); (c) sales or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and (ii) sales or other dispositions of assets as part of normal retirements or replacements; (d) the termination of Commodity Hedge Contracts and interest rate swap agreements; (e) capital contributions received; or (f) corporate reorganizations or restructurings.

“Issue Price” means the price at which a Unit is purchased from the Partnership, net of any sales commission or underwriting discount charged to the Partnership.

“March 2006 Private Investors” means the private investors that contributed $98.3 million to our Operating Partnership in March 2006 in exchange for 5,455,050 common units in our Operating Partnership.

“Limited Partner” means, unless the context otherwise requires, the Organizational Limited Partner prior to its withdrawal from the Partnership, each Initial Limited Partner, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person��s capacity as limited partner of the Partnership;provided, however, that when the term “Limited Partner” is used herein in the context of any vote or other approval, including Articles XIII and XIV, such term shall not, solely for such purpose, include any holder of an Incentive Distribution Right (solely with respect to its Incentive Distribution Rights and not with respect to any other Limited Partner Interest held by such Person) except as may otherwise be required by law.

“Limited Partner Interest” means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units, Subordinated Units, Incentive Distribution Rights or other Partnership Securities or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner to comply with the terms and provisions of this Agreement;provided, however, that when the term “Limited Partner Interest” is used herein in the context of any vote or other approval, including Articles XIII and XIV, such term shall not, solely for such purpose, include any Incentive Distribution Right except as may otherwise be required by law.

“Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

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“Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

“Maintenance Capital Expenditures” means cash expenditures (including expenditures for the addition or improvement to the capital assets owned by any Group Member or for the acquisition of existing, or the construction of new, capital assets) if such expenditures are made to maintain, including over the long term, the operating capacity or revenues of the Partnership Group.

“June 2006 Private Investors” means the private investors, including Natural Gas Partners VII, L.P., that received 1,125,416 common units in our Operating Partnership in June 2006 as consideration for our acquisition of Midstream Gas Services, L.P.

“March 2006 Private Investors’ Registration Rights Agreement” means the Registration Rights Agreement, dated March 27, 2006, by and among the Operating Partnership and certain investors named therein.

“Merger Agreement” has the meaning assigned to such term in Section 14.1.

“Minimum Quarterly Distribution” means $0.3625 per Unit per Quarter (or with respect to the period commencing on the Closing Date and ending on September 30, 2006, it means the product of $0.3625 multiplied by a fraction of which the numerator is the number of days in such period and of which the denominator is 92), subject to adjustment in accordance with Sections 6.6 and 6.9.

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act, and any successor to such statute, or the Nasdaq Stock Market or any successor thereto.

“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed, (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii)) at the time such property is distributed, reduced by any indebtedness either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution, in either case, as determined under Section 752 of the Code, and (c) in the case of a contribution of Common Units by the General Partner to the Partnership as a Capital Contribution pursuant to Section 5.2(b), an amount per Common Unit contributed equal to the Current Market Price per Common Unit as of the date of the contribution.

“Net Income” means, for any taxable year, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Income shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d);provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xii) were not in this Agreement.

“Net Loss” means, for any taxable year, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d);provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xii) were not in this Agreement.

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“Net Positive Adjustments” means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

“Net Termination Gain” means, for any taxable year, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.5(b) and shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Net Termination Loss” means, for any taxable year, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.5(b) and shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Non-citizen Assignee” means a Person whom the General Partner has determined does not constitute an Eligible Citizen and as to whose Partnership Interest the General Partner has become the substituted Limited Partner, pursuant to Section 4.9.

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Sections 6.2(b)(i)(A), 6.2(b)(ii)(A) and 6.2(b)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

“Notice of Election to Purchase” has the meaning assigned to such term in Section 15.1(b).

“Omnibus Agreement” means that certain Omnibus Agreement, dated as of the Closing Date, among the General Partner, the Partnership, Eagle Rock Energy GRP, LLC and Eagle Rock Holding, L.P. and certain other parties thereto, as such may be amended, supplemented or restated from time to time.

“Operating Expenditures” means all Partnership Group cash expenditures, including, but not limited to the following: taxes; reimbursements of the General Partner in accordance with this Agreement; interest payments; payments made in the ordinary course of business under Commodity Hedge Contracts (excluding payments made in connection with the termination of any Commodity Hedge Contract prior to the expiration of its terms), provided that with respect to amounts paid in connection with the initial purchase or placing of a Commodity Hedge Contract, such amounts shall be amortized over the life of the applicable Commodity Hedge Contract and upon its termination, if earlier; Maintenance Capital Expenditures and non-Pro Rata repurchases of Units (other than those made with the proceeds of an Interim Capital Transaction), subject to the following:


	(a) payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness shall not constitute Operating Expenditures; and

	(b) Operating Expenditures shall not include (i) Expansion Capital Expenditures, (ii) payment of transaction expenses (including taxes) relating to Interim Capital Transactions or (iii) distributions to Partners. 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 portion consisting of Maintenance Capital Expenditures and the portion consisting of Expansion Capital Expenditures and, with respect to the part of such capital expenditures consisting of Maintenance Capital Expenditures, the period over which the capital expenditures made for other purposes will be deducted as an Operating Expenditure in calculating Operating Surplus.

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“Operating Partnership” means Eagle Rock Pipeline, L.P., a Delaware limited partnership, and any successors thereto.

“Operating Surplus” means, with respect to any period ending prior to the Liquidation Date, on a cumulative basis and without duplication,



	(a) the sum of (i) an amount equal to four times the amount needed for any one Quarter for the Partnership to pay a distribution on all Units, the General Partner Units and the Incentive Distribution Rights at the same per Unit amount as was distributed immediately preceding the date of determination (or with respect to the period commencing on the Closing Date and ending on September 30, 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 Units and General Partner Units Outstanding on the Record Date with respect to such period, and with respect to the Quarter ending December 31, 2006, it means the product of (a) $1.45 and (b) the number of Units and General Partner Units Outstanding on the Record Date with respect to such quarter), and (ii) all cash receipts of the Partnership Group for the period beginning on the Closing Date and ending on the last day of such period, but excluding cash receipts from Interim Capital Transactions (except to the extent specified in Section 6.5), less


	(b) the sum of (i) Operating Expenditures for the period beginning on the Closing Date and ending on the last day of such period (other than Operating Expenditures funded with cash reserves established pursuant to clause (ii) of this paragraph (b)) and (ii) the amount of cash reserves established by the General Partner to provide funds for future Operating Expenditures;provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines.

Notwithstanding the foregoing,“Operating Surplus” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero. In addition, any increase in“Operating Surplus” pursuant to (a)(i) above in respect of an increase in the quarterly distribution rate per Unit, an increase in Outstanding Units 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)(i) above during the term of the Partnership shall not exceed four times the amount needed for any one Quarter to pay a distribution on all Units, the 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.

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.

“Option Closing Date” means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of the Over-Allotment Option.

“Organizational Limited Partner” means Eagle Rock Holdings, L.P. in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

“Outstanding” means, with respect to Partnership Securities, all Partnership Securities that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination;provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of the Outstanding Partnership Securities of any class then Outstanding, all Partnership Securities owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Units so owned shall

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be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Units shall not, however, be treated as a separate class of Partnership Securities for purposes of this Agreement);provided, further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the Outstanding Partnership Securities of any class then Outstanding directly from the General Partner or its Affiliates, (ii) any Person or Group who acquired 20% or more of the Outstanding Partnership Securities of any class then Outstanding directly or indirectly from a Person or Group described in clause (i)providedthat the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Securities issued by the Partnership with the prior approval of the Board of Directors.

“Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

“Partner Nonrecourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

“Partner Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

“Partner Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.

“Partners” means the General Partner and the Limited Partners.

“Partnership” means Eagle Rock Energy Partners, L.P., a Delaware limited partnership.

“Partnership Group” means the Partnership and its Subsidiaries treated as a single consolidated entity.

“Partnership Interest” means an interest in the Partnership, which shall include the General Partner Interest and Limited Partner Interests.

“Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).

“Partnership Security” means any class or series of equity interest in the Partnership (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership), including Common Units, Subordinated Units, General Partner Units and Incentive Distribution Rights.

“Per Unit Capital Amount” means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any Unit held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.

“Percentage Interest” means as of any date of determination (a) as to the General Partner with respect to General Partner Units and as to any Unitholder with respect to Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of General Partner Units held by the General Partner or the number of Units held by such Unitholder, as the case may be, by (B) the total number of Outstanding Units and General Partner Units, and (b) as to the holders of other Partnership Securities issued by the Partnership in accordance with Section 5.6, the percentage established as a part of such issuance. The Percentage Interest with respect to an Incentive Distribution Right shall at all times be zero.

“Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

“Private Investors” means the March 2006 Private Investors and the June 2006 Private Investors, collectively.

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“Pro Rata” means (a) when used with respect to Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests, (b) when used with respect to Partners and Assignees or Record Holders, apportioned among all Partners and Assignees or Record Holders in accordance with their relative Percentage Interests and (c) when used with respect to holders of Incentive Distribution Rights, apportioned equally among all holders of Incentive Distribution Rights in accordance with the relative number or percentage of Incentive Distribution Rights held by each such holder.

“Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

“Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the first fiscal quarter of the Partnership after the Closing Date, the portion of such fiscal quarter after the Closing Date.

“Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

“Record Holder” means the Person in whose name a Common Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or with respect to other Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.

“Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.10.

“Registration Statement” means the Registration Statement on Form S-1 as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering.

“Remaining Net Positive Adjustments” means as of the end of any taxable period, (i) with respect to the Unitholders holding Common Units, or Subordinated Units, the excess of (a) the Net Positive Adjustments of the Unitholders holding Common Units, or Subordinated Units as of the end of such period over (b) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period, (ii) with respect to the General Partner (as holder of the General Partner Units), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the General Partner Units for each prior taxable period, and (iii) with respect to the holders of Incentive Distribution Rights, the excess of (a) the Net Positive Adjustments of the holders of Incentive Distribution Rights as of the end of such period over (b) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Incentive Distribution Rights for each prior taxable period.

“Required Allocations” means (a) any limitation imposed on any allocation of Net Losses or Net Termination Losses under Section 6.1(b) or Section 6.1(c)(ii) and (b) any allocation of an item of income, gain, loss or deduction pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(vii) or Section 6.1(d)(ix).

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“Residual Gain” or “Residual Loss” means any item of gain or loss, as the case may be, of the Partnership recognized for federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss is not allocated pursuant to Section 6.2(b)(i)(A) or Section 6.2(b)(ii)(A), respectively, to eliminate Book-Tax Disparities.

“Retained Converted Subordinated Unit” has the meaning assigned to such term in Section 5.5(c)(ii).

“Second Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(E).

“Second Target Distribution” means $0.4531 per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on September 30, 2006, it means the product of $0.4531 multiplied by a fraction of which the numerator is equal to the number of days in such period and of which the denominator is 92), subject to adjustment in accordance with Sections 6.6 and 6.9.

“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

“Securities Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

“Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders holding Common Units or Subordinated Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time, (ii) with respect to the General Partner (as holder of the General Partner Units), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustment as of that time, and (iii) with respect to the Partners holding Incentive Distribution Rights, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the Partners holding the Incentive Distribution Rights as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

“Special Approval” means approval by a majority of the members of the Conflicts Committee.

“Subordinated Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners and Assignees and having the rights and obligations specified with respect to Subordinated Units in this Agreement. The term “Subordinated Unit” does not include a Common Unit. A Subordinated Unit that is convertible into a Common Unit shall not constitute a Common Unit until such conversion occurs.

“Subordination Period” means the period commencing on the Closing Date and ending on the first to occur of the following dates:


	(a) the first date on which there are no longer outstanding any Subordinated Units due to the conversion of Subordinated Units into Common Units pursuant to Section 5.7 or otherwise; and

	(b) the date on which the General Partner is removed as general partner of the Partnership upon the requisite vote by holders of Outstanding Units under circumstances where Cause does not exist and Units held by the General Partner and its Affiliates are not voted in favor of such removal.

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such

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Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Surviving Business Entity” has the meaning assigned to such term in Section 14.2(b).

“Target Distribution” means, collectively, the First Target Distribution, Second Target Distribution and Third Target Distribution.

“Third Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(F).

“Third Target Distribution” means $0.5438 per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on September 30, 2006, it means the product of $0.5438 multiplied by a fraction of which the numerator is equal to the number of days in such period and of which the denominator is 92), subject to adjustment in accordance with Sections 6.6 and 6.9.

“Trading Day” has the meaning assigned to such term in Section 15.1(a).

“transfer” has the meaning assigned to such term in Section 4.4(a).

“Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as shall be appointed from time to time by the General Partner to act as registrar and transfer agent for the Common Units;provided, that if no Transfer Agent is specifically designated for any other Partnership Securities, the General Partner shall act in such capacity.

“Underwriter” means each Person named as an underwriter in Schedule I to the Underwriting Agreement who purchases Common Units pursuant thereto.

“Underwriting Agreement” means that certain Underwriting Agreement dated as of , 2006 among the Underwriters, the Partnership, the General Partner, the Operating Partnership and other parties thereto, providing for the purchase of Common Units by the Underwriters.

“Unit” means a Partnership Security that is designated as a “Unit” and shall include Common Units and Subordinated Units but shall not include (i) General Partner Units (or the General Partner Interest represented thereby) or (ii) Incentive Distribution Rights.

“Unit Majority” means (i) during the Subordination Period, at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), voting as a class, and at least a majority of the Outstanding Subordinated Units, voting as a class, and (ii) after the end of the Subordination Period, at least a majority of the Outstanding Common Units voting as a class.

“Unitholders” means the holders of Units.

“Unpaid MQD” has the meaning assigned to such term in Section 6.1(c)(i)(B).

“Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).

“Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d)).

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“Unrecovered Initial Unit Price” means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of an Initial Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an Initial Common Unit, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.

“U.S. GAAP” means United States generally accepted accounting principles consistently applied.

“Withdrawal Opinion of Counsel” has the meaning assigned to such term in Section 11.1(b).

Section 1.2 Construction.

Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include”, “includes”, “including” or words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof”, “herein” or “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement.

ARTICLE II

ORGANIZATION

Section 2.1 Formation.

The General Partner and the Organizational Limited Partner have previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act and hereby amend and restate the original Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the owner thereof for all purposes.

Section 2.2 Name.

The name of the Partnership shall be “Eagle Rock Energy Partners, L.P.” The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” “L.P.,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices.

Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 2711 Centerville Road, Suite 400, Wilmington, Delaware 19808-1645, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be Corporation Service Company. The principal office of the Partnership shall be located at 14950 Heathrow Forest Parkway, Suite 111, Houston, Texas 77032, or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner shall determine necessary or appropriate. The address of the General Partner shall be 14950 Heathrow Forest

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Parkway, Suite 111, Houston, Texas 77032, or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

Section 2.4 Purpose and Business.

The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member;provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may decline to propose or approve, the conduct by the Partnership of any business free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

Section 2.5 Powers.

The Partnership shall be empowered to do any and all acts and things necessary or appropriate for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

Section 2.6 Power of Attorney.

(a) Each Limited Partner hereby constitutes and appoints the General Partner and, if a Liquidator shall have been selected pursuant to Section 12.3, the Liquidator (and any successor to the Liquidator by merger, transfer, assignment, election or otherwise) and each of their authorized officers andattorneys-in-fact, as the case may be, with full power of substitution, as his true and lawful agent andattorney-in-fact, with full power and authority in his name, place and stead, to:

(i) execute, swear to, acknowledge, deliver, file and record in the appropriate public offices (A) all certificates, documents and other instruments (including this Agreement and the Certificate of Limited Partnership and all amendments or restatements hereof or thereof) that the General Partner or the Liquidator determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Partnership as a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware and in all other jurisdictions in which the Partnership may conduct business or own property; (B) all certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement; (C) all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the General Partner or the Liquidator determines to be necessary or appropriate to reflect the dissolution and liquidation of the Partnership pursuant to the terms of this Agreement; (D) all certificates, documents and other instruments relating to the admission, withdrawal, removal or substitution of any Partner pursuant to, or other events described in, Article IV, Article X, Article XI or Article XII; (E) all certificates, documents and other instruments relating to the determination of the rights, preferences and privileges of any class or series of Partnership Securities issued pursuant to Section 5.6; and (F) all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger, consolidation or conversion of the Partnership pursuant to Article XIV; and

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(ii) execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to (A) make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Partners hereunder or is consistent with the terms of this Agreement or (B) effectuate the terms or intent of this Agreement;provided, that when required by Section 13.3 or any other provision of this Agreement that establishes a percentage of the Limited Partners or of the Limited Partners of any class or series required to take any action, the General Partner and the Liquidator may exercise the power of attorney made in this Section 2.6(a)(ii) only after the necessary vote, consent or approval of the Limited Partners or of the Limited Partners of such class or series, as applicable.

Nothing contained in this Section 2.6(a) shall be construed as authorizing the General Partner to amend this Agreement except in accordance with Article XIII or as may be otherwise expressly provided for in this Agreement.

(b) The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Limited Partner and the transfer of all or any portion of such Limited Partner’s Partnership Interest and shall extend to such Limited Partner’s heirs, successors, assigns and personal representatives. Each such Limited Partner hereby agrees to be bound by any representation made by the General Partner or the Liquidator acting in good faith pursuant to such power of attorney; and each such Limited Partner, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the General Partner or the Liquidator taken in good faith under such power of attorney. Each Limited Partner shall execute and deliver to the General Partner or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as the General Partner or the Liquidator may request in order to effectuate this Agreement and the purposes of the Partnership.

Section 2.7 Term.

The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.8 Title to Partnership Assets.

Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement;provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership as soon as reasonably practicable;provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

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ARTICLE III

RIGHTS OF LIMITED PARTNERS

Section 3.1 Limitation of Liability.

The Limited Partners and assignees shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2 Management of Business.

No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. Any action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not be deemed to be participation in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners or assignees under this Agreement.

Section 3.3 Outside Activities of the Limited Partners.

Subject to the provisions of Section 7.5, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, any Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

Section 3.4 Rights of Limited Partners.

(a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand, and at such Limited Partner’s own expense:


	(i) to obtain true and full information regarding the status of the business and financial condition of the Partnership;

	(ii) promptly after its becoming available, to obtain a copy of the Partnership’s federal, state and local income tax returns for each year;

	(iii) to obtain a current list of the name and last known business, residence or mailing address of each Partner;

	(iv) to obtain a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed;

	(v) to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Partner and that each Partner has agreed to contribute in the future, and the date on which each Partner became a Partner; and

	(vi) to obtain such other information regarding the affairs of the Partnership as is just and reasonable.

(b) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to

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be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner in good faith believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS;

REDEMPTION OF PARTNERSHIP INTERESTS

Section 4.1 Certificates.

Upon the Partnership’s issuance of Common Units or Subordinated Units to any Person, the Partnership shall issue, upon the request of such Person, one or more Certificates in the name of such Person evidencing the number of such Units being so issued. In addition, (a) upon the General Partner’s request, the Partnership shall issue to it one or more Certificates in the name of the General Partner evidencing its General Partner Units and (b) upon the request of any Person owning Incentive Distribution Rights or any other Partnership Securities other than Common Units or Subordinated Units, the Partnership shall issue to such Person one or more certificates evidencing such Incentive Distribution Rights or other Partnership Securities other than Common Units, or Subordinated Units. Certificates shall be executed on behalf of the Partnership by the President or any Executive Vice President, Senior Vice President or Vice President and the Secretary or any Assistant Secretary of the General Partner. No Common Unit Certificate shall be valid for any purpose until it has been countersigned by the Transfer Agent;provided, however, that if the General Partner elects to issue Common Units in global form, the Common Unit Certificates shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Common Units have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.7(c), the Partners holding Certificates evidencing Subordinated Units may exchange such Certificates for Certificates evidencing Common Units on or after the date on which such Subordinated Units are converted into Common Units pursuant to the terms of Section 5.7.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

(a) If any mutilated Certificate is surrendered to the Transfer Agent (for Common Units) or the General Partner (for Partnership Securities other than Common Units), the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent (for Common Units) or the General Partner (for Partnership Securities other than Common Units) shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Securities as the Certificate so surrendered.

(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent (for Common Units) shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:


	(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

	(ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

	(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

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	(iv) satisfies any other reasonable requirements imposed by the General Partner.

If a Limited Partner fails to notify the General Partner within a reasonable period of time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

(c) As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders.

The Partnership shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be the Record Holder of such Partnership Interest.

Section 4.4 Transfer Generally.

(a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall be deemed to refer to a transaction (i) by which the General Partner assigns its General Partner Units to another Person or by which a holder of Incentive Distribution Rights assigns its Incentive Distribution Rights to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest (other than an Incentive Distribution Right) assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of the General Partner of any or all of the shares of stock, membership interests, partnership interests or other ownership interests in the General Partner.

Section 4.5 Registration and Transfer of Limited Partner Interests.

(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests. The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Common Units and transfers of such Common Units as herein provided. The Partnership shall not recognize transfers of Certificates evidencing Limited Partner Interests unless such transfers are effected in the manner described in this Section 4.5. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions of Section 4.5(b), the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Common Units, the Transfer Agent shall countersign and deliver, in the name of the holder or

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the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(b) Except as otherwise provided in Section 4.9, the General Partner shall not recognize any transfer of Limited Partner Interests until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer;provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto.

(c) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.8, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or an amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partner Interests (other than the Incentive Distribution Rights) shall be freely transferable.

(d) The General Partner and its Affiliates shall have the right at any time to transfer their Subordinated Units and Common Units (whether issued upon conversion of the Subordinated Units or otherwise) to one or more Persons.

Section 4.6 Transfer of the General Partner’s General Partner Interest.

(a) Subject to Section 4.6(c) below, prior to September 30, 2016, the General Partner shall not transfer all or any part of its General Partner Interest (represented by General Partner Units) to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of its General Partner Interest to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into such other Person or the transfer by the General Partner of all or substantially all of its assets to such other Person.

(b) Subject to Section 4.6(c) below, on or after September 30, 2016, the General Partner may transfer all or any of its General Partner Interest without Unitholder approval.

(c) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability of any Limited Partner under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest of the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.3, be admitted to the Partnership as the General Partner immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7 Transfer of Incentive Distribution Rights.

Prior to September 30, 2016, a holder of Incentive Distribution Rights may transfer any or all of the Incentive Distribution Rights held by such holder without any consent of the Unitholders to (a) an Affiliate of such holder (other than an individual) or (b) another Person (other than an individual) in connection with (i) the merger or consolidation of such holder of Incentive Distribution Rights with or into such other Person, (ii) the transfer by such holder of all or substantially all of its assets to such other Person or (iii) the sale of ownership interests in such holder,providedthat, in the case of this clause (iii),

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the initial holder of the Incentive Distribution Rights continues to remain as the General Partner following such sale. Any other transfer of the Incentive Distribution Rights prior to September 30, 2016, shall require the prior approval of holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates). On or after September 30, 2016, the General Partner or any other holder of Incentive Distribution Rights may transfer any or all of its Incentive Distribution Rights without Unitholder approval. Notwithstanding anything herein to the contrary, no transfer of Incentive Distribution Rights to another Person shall be permitted unless the transferee agrees to be bound by the provisions of this Agreement.

Section 4.8 Restrictions on Transfers.

(a) Except as provided in Section 4.8(d) below, but notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if it receives an Opinion of Counsel that such restrictions are necessary to avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes. The General Partner may impose such restrictions by amending this Agreement;provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

(c) The transfer of a Subordinated Unit that has converted into a Common Unit shall be subject to the restrictions imposed by Section 6.7(c).

(d) Nothing contained in this Article IV, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

(e) Each certificate evidencing Partnership Interests shall bear a conspicuous legend in substantially the following form:

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF EAGLE ROCK ENERGY PARTNERS, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF EAGLE ROCK ENERGY PARTNERS, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE EAGLE ROCK ENERGY PARTNERS, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). EAGLE ROCK ENERGY GP L.P., THE GENERAL PARTNER OF EAGLE ROCK ENERGY PARTNERS, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF EAGLE ROCK ENERGY

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	PARTNERS, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

Section 4.9 Citizenship Certificates; Non-citizen Assignees.

(a) If any Group Member is or becomes subject to any federal, state or local law or regulation that the General Partner determines would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Limited Partner, the General Partner may request any Limited Partner to furnish to the General Partner, within 30 days after receipt of such request, an executed Citizenship Certification or such other information concerning his nationality, citizenship or other related status (or, if the Limited Partner is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the General Partner may request. If a Limited Partner fails to furnish to the General Partner within the aforementioned30-day period such Citizenship Certification or other requested information or if upon receipt of such Citizenship Certification or other requested information the General Partner determines that a Limited Partner is not an Eligible Citizen, the Limited Partner Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.10. In addition, the General Partner may require that the status of any such Limited Partner be changed to that of a Non-citizen Assignee and, thereupon, the General Partner shall be substituted for such Non-citizen Assignee as the Limited Partner in respect of the Non-citizen Assignee’s Limited Partner Interests.

(b) The General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Non-citizen Assignees, distribute the votes in the same ratios as the votes of Partners (including the General Partner) in respect of Limited Partner Interests other than those of Non-citizen Assignees are cast, either for, against or abstaining as to the matter.

(c) Upon dissolution of the Partnership, a Non-citizen Assignee shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Non-citizen Assignee’s share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Non-citizen Assignee of his Limited Partner Interest (representing his right to receive his share of such distribution in kind).

(d) At any time after he can and does certify that he has become an Eligible Citizen, a Non-citizen Assignee may, upon application to the General Partner, request that with respect to any Limited Partner Interests of such Non-citizen Assignee not redeemed pursuant to Section 4.10, such Non-citizen Assignee be admitted as a Limited Partner, and upon approval of the General Partner, such Non-citizen Assignee shall be admitted as a Limited Partner and shall no longer constitute a Non-citizen Assignee and the General Partner shall cease to be deemed to be the Limited Partner in respect of the Non-citizen Assignee’s Limited Partner Interests.

Section 4.10 Redemption of Partnership Interests of Non-citizen Assignees.

(a) If at any time a Limited Partner fails to furnish a Citizenship Certification or other information requested within the30-day period specified in Section 4.9(a), or if upon receipt of such Citizenship Certification or other information the General Partner determines, with the advice of counsel, that a Limited Partner is not an Eligible Citizen, the Partnership may, unless the Limited Partner establishes to the satisfaction of the General Partner that such Limited Partner is an Eligible Citizen or has transferred his Partnership Interests to a Person who is an Eligible Citizen and who furnishes a Citizenship

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Certification to the General Partner prior to the date fixed for redemption as provided below, redeem the Limited Partner Interest of such Limited Partner as follows:


	(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner, at his last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon surrender of the Certificate evidencing the Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Limited Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

	(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

	(iii) Upon surrender by or on behalf of the Limited Partner, at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank, the Limited Partner or his duly authorized representative shall be entitled to receive the payment therefor.

	(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

(b) The provisions of this Section 4.10 shall also be applicable to Limited Partner Interests held by a Limited Partner as nominee of a Person determined to be other than an Eligible Citizen.

(c) Nothing in this Section 4.10 shall prevent the recipient of a notice of redemption from transferring his Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption,providedthe transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner that he is an Eligible Citizen. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS

Section 5.1 Organizational Contributions.

In connection with the formation of the Partnership under the Delaware Act, the General Partner made an initial Capital Contribution to the Partnership in the amount of $20.00 for a 2% General Partner Interest in the Partnership and has been admitted as the General Partner of the Partnership, and the Organizational Limited Partner made an initial Capital Contribution to the Partnership in the amount of $980.00 for a 98% Limited Partner Interest in the Partnership and has been admitted as a Limited Partner of the Partnership. As of the Closing Date, the interest of the Organizational Limited Partner shall be redeemed as provided in the Contribution Agreement; and the initial Capital Contribution of the Organizational Limited Partner shall thereupon be refunded. Ninety-eight percent of any interest or other profit that may have resulted from the investment or other use of such initial Capital Contributions shall be allocated and distributed to the Organizational Limited Partner, and the balance thereof shall be allocated and distributed to the General Partner.

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Section 5.2 Contributions by the General Partner and Other Parties.

(a) On the Closing Date and pursuant to the Contribution Agreement: (i) the General Partner shall contribute to the Partnership, as a Capital Contribution, all of its ownership interests in Eagle Rock Pipeline, L.P., a Delaware limited partnership(“Eagle Rock Pipeline”), in exchange for (A) 844,551 General Partner Units representing a continuation of its 2% General Partner Interest, subject to all of the rights, privileges and duties of the General Partner under this Agreement, (B) the Incentive Distribution Rights and (C) the right to receive $ million to reimburse the General Partner for certain capital expenditures; (ii) Eagle Rock Holdings shall contribute to the Partnership, as a Capital Contribution, all of its limited partner interests in Eagle Rock Pipeline and its interest in Eagle Rock Pipeline GP, LLC in exchange for 3,459,236 Common Units, 20,691,495 Subordinated Units and the right to receive $ million in reimbursement for certain capital expenditures, and (iii) the Private Investors shall contribute all of their ownership interests in Eagle Rock Pipeline in exchange for (A) an aggregate of 4,732,259 Common Units as specified onSchedule A to the Contribution Agreement and (B) the right to receive $ million in reimbursement for certain capital expenditures.

(b) Upon the issuance of any additional Limited Partner Interests by the Partnership (other than the Common Units issued in the Initial Offering, the Common Units issued pursuant to the Over-Allotment Option, and the Common Units and Subordinated Units issued pursuant to Section 5.2(a)), the General Partner may, in exchange for a proportionate number of General Partner Units, make additional Capital Contributions in an amount equal to the product obtained by multiplying (i) the quotient determined by dividing (A) the General Partner’s Percentage Interest by (B) 100 less the General Partner’s Percentage Interest times (ii) the amount contributed to the Partnership by the Limited Partners in exchange for such additional Limited Partner Interests. Except as set forth in Article XII, the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.

Section 5.3 Contributions by Underwriters.

(a) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Partnership cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter at the Closing Date. In exchange for such Capital Contributions by the Underwriters, the Partnership shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made in an amount equal to the quotient obtained by dividing (i) the cash contribution to the Partnership by or on behalf of such Underwriter by (ii) the Issue Price per Initial Common Unit.

(b) Upon the exercise of the Over-Allotment Option, each Underwriter shall contribute to the Partnership cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units to be purchased by such Underwriter at the Option Closing Date. In exchange for such Capital Contributions by the Underwriters, the Partnership shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made in an amount equal to the quotient obtained by dividing (i) the cash contributions to the Partnership by or on behalf of such Underwriter by (ii) the Issue Price per Initial Common Unit.

(c) No Limited Partner Interests will be issued or issuable as of or at the Closing Date other than (i) the Common Units issuable pursuant to subparagraph (a) hereof in aggregate number equal to 12,500,000, (ii) the “Additional Units” as such term is used in the Underwriting Agreement in an aggregate number up to 1,875,000 issuable upon exercise of the Over-Allotment Option pursuant to subparagraph (b) hereof, (iii) the 20,691,495 Subordinated Units issuable pursuant to Section 5.2 hereof, (iv) the 8,191,495 Common Units issuable pursuant to Section 5.2 hereof, and (v) the Incentive Distribution Rights.

Section 5.4 Interest and Withdrawal.

No interest shall be paid by the Partnership on Capital Contributions. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon termination of the Partnership may be considered as such by law and

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then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

Section 5.5 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including income and gain exempt from tax) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss or deduction which is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose),provided, that:


	(i) Solely for purposes of this Section 5.5, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement or governing, organizational or similar documents) of all property owned by (x) any other Group Member that is classified as a partnership for federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for federal income tax purposes of which a Group Member is, directly or indirectly, a partner.

	(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

	(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss and deduction shall be made without regard to any election under Section 754 of the Code which may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

	(iv) Any income, gain or loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

	(v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership

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	were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.5(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery or amortization attributable to such property shall be determined as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment.

	(vi) If the Partnership’s adjusted basis in a depreciable or cost recovery property is reduced for federal income tax purposes pursuant to Section 48(q)(1) or 48(q)(3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Partners pursuant to Section 6.1. Any restoration of such basis pursuant to Section 48(q)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Partners to whom such deemed deduction was allocated.

(c) (i) A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(ii) Subject to Section 6.7(c), immediately prior to the transfer of a Subordinated Unit or of a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 by a holder thereof (other than a transfer to an Affiliate unless the General Partner elects to have this subparagraph 5.5(c)(ii) apply), the Capital Account maintained for such Person with respect to its Subordinated Units or converted Subordinated Units will (A) first, be allocated to the Subordinated Units or converted Subordinated Units to be transferred in an amount equal to the product of (x) the number of such Subordinated Units or converted Subordinated Units to be transferred and (y) the Per Unit Capital Amount for a Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any Subordinated Units or converted Subordinated Units(“Retained Converted Subordinated Units”). Following any such allocation, the transferor’s Capital Account, if any, maintained with respect to the retained Subordinated Units or Retained Converted Subordinated Units, if any, will have a balance equal to the amount allocated under clause (B) hereinabove, and the transferee’s Capital Account established with respect to the transferred Subordinated Units or Retained Converted Subordinated Units will have a balance equal to the amount allocated under clause (A) hereinabove.

(d) (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services or the conversion of the General Partner’s Combined Interest to Common Units pursuant to Section 11.3(b), the Capital Account of all Partners and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance and had been allocated to the Partners at such time pursuant to Section 6.1 in the same manner as any item of gain or loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt;provided, however, that the General Partner, in arriving at such valuation, must take fully into account the fair market value of the Partnership Interests of all Partners at such time. The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain

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or Unrealized Loss had been recognized in a sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Partners, at such time, pursuant to Section 6.1 in the same manner as any item of gain or loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

Section 5.6 Issuances of Additional Partnership Securities.

(a) The Partnership may issue additional Partnership Securities and options, rights, warrants and appreciation rights relating to the Partnership Securities for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

(b) Each additional Partnership Security authorized to be issued by the Partnership pursuant to Section 5.6(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Securities), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may redeem the Partnership Security; (v) whether such Partnership Security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Security; and (viii) the right, if any, of each such Partnership Security to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Security.

(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Securities and options, rights, warrants and appreciation rights relating to Partnership Securities pursuant to this Section 5.6, (ii) the conversion of the General Partner Interest (represented by General Partner Units) or any Incentive Distribution Rights into Units pursuant to the terms of this Agreement, (iii) reflecting admission of such additional Limited Partners in the books and records of the Partnership as the Record Holder of such Limited Partner Interest and (iv) all additional issuances of Partnership Securities. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Securities being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Securities or in connection with the conversion of the General Partner Interest or any Incentive Distribution Rights into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Securities are listed or admitted to trading.

(d) No fractional Units shall be issued by the Partnership.

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Section 5.7 Conversion of Subordinated Units.

(a) All of the Outstanding Subordinated Units will convert into Common Units on a one-for-one basis on the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter ending on or after September 30, 2009, in respect of which:


	(i) distributions of Available Cash from Operating Surplus under Section 6.4(a) on each of the Outstanding Common Units, Subordinated Units and General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units with respect to each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Outstanding Common Units, Subordinated Units and General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units during such periods;

	(ii) the Adjusted Operating Surplus for each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and General Partner Units and any other Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during such periods on a Fully Diluted Basis with respect to such periods; and

	(iii) there are no Cumulative Common Unit Arrearages.

(b) Notwithstanding Section 5.7(a), all of the Outstanding Subordinated Units will convert into Common Units on a one-for-one basis on the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter ending on or after September 30, 2007 in respect of which:


	(i) distributions of Available Cash from Operating Surplus under Section 6.4(a) on each of the Outstanding Common Units, Subordinated Units and General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units with respect to each of the four consecutive Quarters immediately preceding such date equaled or exceeded 150% of the sum of the Minimum Quarterly Distribution on all of the Outstanding Common Units, Subordinated Units and General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units during such Quarters;

	(ii) the Adjusted Operating Surplus for each of the four consecutive Quarters immediately preceding such date equaled or exceeded 150% of the sum of the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and General Partner Units and any other Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during such Quarters on a Fully Diluted Basis with respect to such Quarters; and

	(iii) there are no Cumulative Common Unit Arrearages.

(c) Any Subordinated Units that are not converted into Common Units pursuant to Section 5.7(a) or (b) shall convert into Common Units on a one-for-one basis on the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of the final Quarter of the Subordination Period.

(d) Notwithstanding any other provision of this Agreement, all the then Outstanding Subordinated Units will automatically convert into Common Units on a one-for-one basis as set forth in, and pursuant to the terms of, Section 11.4.

(e) A Subordinated Unit that has converted into a Common Unit shall be subject to the provisions of Section 6.7(b) and Section 6.7(c).

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Section 5.8 Limited Preemptive Right.

Except as provided in this Section 5.8 and in Section 5.2, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Security, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Securities from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Securities to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Securities.

Section 5.9 Splits and Combinations.

(a) Subject to Section 5.9(d), Section 6.6 and Section 6.9 (dealing with adjustments of distribution levels), the Partnership may make a Pro Rata distribution of Partnership Securities to all Record Holders or may effect a subdivision or combination of Partnership Securities so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis (including any Common Unit Arrearage or Cumulative Common Unit Arrearage) or stated as a number of Units (including the number of Subordinated Units that may convert prior to the end of the Subordination Period) are proportionately adjusted.

(b) Whenever such a distribution, subdivision or combination of Partnership Securities is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Securities to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates to the Record Holders of Partnership Securities as of the applicable Record Date representing the new number of Partnership Securities held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Securities Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of this Section 5.9(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.10 Fully Paid and Non-Assessable Nature of Limited Partner Interests.

All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Section 17-607 of the Delaware Act.

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes.

For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss and deduction (computed in accordance

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with Section 5.5(b)) shall be allocated among the Partners in each taxable year (or portion thereof) as provided herein below.

(a) Net Income. After giving effect to the special allocations set forth in Section 6.1(d), Net Income for each taxable year and all items of income, gain, loss and deduction taken into account in computing Net Income for such taxable year shall be allocated as follows:


	(i) First, 100% to the General Partner, in an amount equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(iii) for all previous taxable years until the aggregate Net Income allocated to the General Partner pursuant to this Section 6.1(a)(i) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(iii) for all previous taxable years;

	(ii) Second, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests, until the aggregate Net Income allocated to such Partners pursuant to this Section 6.1(a)(ii) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to such Partners pursuant to Section 6.1(b)(ii) for all previous taxable years; and

	(iii) Third, the balance, if any, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests.

(b) Net Losses. After giving effect to the special allocations set forth in Section 6.1(d), Net Losses for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Losses for such taxable period shall be allocated as follows:


	(i) First, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests, until the aggregate Net Losses allocated pursuant to this Section 6.1(b)(i) for the current taxable year and all previous taxable years is equal to the aggregate Net Income allocated to such Partners pursuant to Section 6.1(a)(iii) for all previous taxable years,providedthat the Net Losses shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account);

	(ii) Second, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests;provided, that Net Losses shall not be allocated pursuant to this Section 6.1(b)(ii) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account); and

	(iii) Third, the balance, if any, 100% to the General Partner.

(c) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(d), all items of income, gain, loss and deduction taken into account in computing Net Termination Gain or Net Termination Loss for such taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.4 and Section 6.5 have been made;provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.


	(i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Gain shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be increased by the amount so allocated in each of the

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	following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):


	(A) First, to each Partner having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account;

	(B) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (B), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(i) or Section 6.4(b)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter defined as the “Unpaid MQD”) and (3) any then existing Cumulative Common Unit Arrearage;

	(C) Third, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (C), until the Capital Account in respect of each Subordinated Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price, determined for the taxable year (or portion thereof) to which this allocation of gain relates, and (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(iii) with respect to such Subordinated Unit for such Quarter;

	(D) Fourth, 100% to the General Partner and all Unitholders in accordance with their respective Percentage Interests, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Unpaid MQD, (3) any then existing Cumulative Common Unit Arrearage, and (4) the excess of (aa) the First Target Distribution less the Minimum Quarterly Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(iv) and Section 6.4(b)(ii) (the sum of (1), (2), (3) and (4) is hereinafter defined as the“First Liquidation Target Amount”);

	(E) Fifth, (x) to the General Partner in accordance with its Percentage Interest, (y) 13% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (x) and (y) of this clause (E), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the First Liquidation Target Amount, and (2) the excess of (aa) the Second Target Distribution less the First Target Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(v) and Section 6.4(b)(iii) (the sum of (1) and (2) is hereinafter defined as the“Second Liquidation Target Amount”);

	(F) Sixth, (x) to the General Partner in accordance with its Percentage Interest, (y) 23% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (x) and (y) of this clause (F), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the Second Liquidation Target Amount, and (2) the excess of (aa) the Third Target Distribution less the Second Target Distribution for each

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	Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(vi) and Section 6.4(b)(iv) (the sum of (1) and (2) is hereinafter defined as the“Third Liquidation Target Amount”); and

	(G) Finally, (x) to the General Partner in accordance with its Percentage Interest, (y) 48% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (x) and (y) of this clause (G).


	(ii) If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Loss shall be allocated among the Partners in the following manner:


	(A) First, if such Net Termination Loss is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (A), until the Capital Account in respect of each Subordinated Unit then Outstanding has been reduced to zero;

	(B) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (B) until the Capital Account in respect of each Common Unit then Outstanding has been reduced to zero; and

	(C) Third, the balance, if any, 100% to the General Partner.

(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:


	(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

	(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

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	(iii) Priority Allocations.


	(A) If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) to any Unitholder with respect to its Units for a taxable year is greater (on a per Unit basis) than the amount of cash or the Net Agreed Value of property distributed to the other Unitholders with respect to their Units (on a per Unit basis), then (1) there shall be allocated income and gain to each Unitholder receiving such greater cash or property distribution until the aggregate amount of such items allocated pursuant to this Section 6.1(d)(iii)(A) for the current taxable year and all previous taxable years is equal to the product of (aa) the amount by which the distribution (on a per Unit basis) to such Unitholder exceeds the distribution (on a per Unit basis) to the Unitholders receiving the smallest distribution and (bb) the number of Units owned by the Unitholder receiving the greater distribution; and (2) the General Partner shall be allocated income and gain in an aggregate amount equal to the product obtained by multiplying (aa) the quotient determined by dividing (x) the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs by (y) the sum of 100 less the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs times (bb) the sum of the amounts allocated in clause (1) above.

	(B) After the application of Section 6.1(d)(iii)(A), all or any portion of the remaining items of Partnership income or gain for the taxable period, if any, shall be allocated (1) to the holders of Incentive Distribution Rights, Pro Rata, until the aggregate amount of such items allocated to the holders of Incentive Distribution Rights pursuant to this Section 6.1(d)(iii)(B) for the current taxable year and all previous taxable years is equal to the cumulative amount of all Incentive Distributions made to the holders of Incentive Distribution Rights from the Closing Date to a date 45 days after the end of the current taxable year; and (2) to the General Partner an amount equal to the product of (aa) an amount equal to the quotient determined by dividing (x) the General Partner’s Percentage Interest by (y) the sum of 100 less the General Partner’s Percentage Interest times (bb) the sum of the amounts allocated in clause (1) above.


	(iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4),1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii).

	(v) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any Partnership taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership income and gain in the amount of such excess as quickly as possible;provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(v) were not in this Agreement.

	(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners in accordance with their respective Percentage Interests. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

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	(vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

	(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners in accordance with their respective Percentage Interests.

	(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

	(x) Economic Uniformity. At the election of the General Partner with respect to any taxable period ending upon, or after, the termination of the Subordination Period, all or a portion of the remaining items of Partnership income or gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii), shall be allocated 100% to each Partner holding Subordinated Units that are Outstanding as of the termination of the Subordination Period(“Final Subordinated Units”) in the proportion of the number of Final Subordinated Units held by such Partner to the total number of Final Subordinated Units then Outstanding, until each such Partner has been allocated an amount of income or gain that increases the Capital Account maintained with respect to such Final Subordinated Units to an amount equal to the product of (A) the number of Final Subordinated Units held by such Partner and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Final Subordinated Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such Final Subordinated Units into Common Units. This allocation method for establishing such economic uniformity will be available to the General Partner only if the method for allocating the Capital Account maintained with respect to the Subordinated Units between the transferred and retained Subordinated Units pursuant to Section 5.5(c)(ii) does not otherwise provide such economic uniformity to the Final Subordinated Units.

	(xi) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required

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	Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this Section 6.1(d)(xi)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.

	(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.


	(xii) Corrective Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:


	(A) In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) hereof), the General Partner shall allocate additional items of income and gain away from the holders of Incentive Distribution Rights to the Unitholders and the General Partner, or additional items of deduction and loss away from the Unitholders and the General Partner to the holders of Incentive Distribution Rights, to the extent that the Additional Book Basis Derivative Items allocated to the Unitholders or the General Partner exceed their Share of Additional Book Basis Derivative Items. For this purpose, the Unitholders and the General Partner shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders or the General Partner under the Partnership Agreement (e.g., Additional Book Basis Derivative Items taken into account in computing cost of goods sold would reduce the amount of book income otherwise available for allocation among the Partners). Any allocation made pursuant to this Section 6.1(d)(xii)(A) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

	(B) In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the General Partner, that to the extent possible the aggregate Capital Accounts of the Partners will equal the amount that would have been the Capital Account balance of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

	(C) In making the allocations required under this Section 6.1(d)(xii), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xii).

Section 6.2 Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

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(b) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners as follows:


	(i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Partners in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

	(ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Partners in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.5(d)(i) or Section 5.5(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Partners in a manner consistent with Section 6.2(b)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

	(iii) The General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities, except as otherwise determined by the General Partner with respect to any goodwill contributed to the Partnership upon formation.

(c) For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.2(c) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

(d) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Partnership’s common basis of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

(e) In accordance with Treasury Regulation Section 1.1245-1(e), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest)

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have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(f) All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership;provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(g) Each item of Partnership income, gain, loss and deduction, for federal income tax purposes, shall be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the Nasdaq Global Market on the first Business Day of each month;provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners as of the opening of the Nasdaq Global Market on the first Business Day of the next succeeding month; andprovided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the General Partner, shall be allocated to the Partners as of the opening of the Nasdaq Global Market on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(h) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

Section 6.3 Requirement and Characterization of Distributions; Distributions to Record Holders.

(a) Within 45 days following the end of each Quarter commencing with the Quarter ending on September 30, 2006, an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 17-607 of the Delaware Act, be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner. All amounts of Available Cash distributed by the Partnership on any date from any source shall be deemed to be Operating Surplus until the sum of all amounts of Available Cash theretofore distributed by the Partnership to the Partners pursuant to Section 6.4 equals the Operating Surplus from the Closing Date through the close of the immediately preceding Quarter. Any remaining amounts of Available Cash distributed by the Partnership on such date shall, except as otherwise provided in Section 6.5, be deemed to be “Capital Surplus.” All distributions required to be made under this Agreement shall be made subject to Section 17-607 of the Delaware Act.

(b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Partnership, all receipts received during or after the Quarter in which the Liquidation Date occurs shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.

(d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

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Section 6.4 Distributions of Available Cash from Operating Surplus.

(a) During Subordination Period. Available Cash with respect to any Quarter within the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or 6.5 shall, subject to Section 17-607 of the Delaware Act, be distributed as follows, except as otherwise contemplated by Section 5.6 in respect of other Partnership Securities issued pursuant thereto:


	(i) First, to the General Partner and the Unitholders holding Common Units, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

	(ii) Second, to the General Partner and the Unitholders holding Common Units, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage existing with respect to such Quarter;

	(iii) Third, to the General Partner and the Unitholders holding Subordinated Units, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Subordinated Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

	(iv) Fourth, to the General Partner and all Unitholders, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

	(v) Fifth, (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v) until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

	(vi) Sixth, (A) to the General Partner in accordance with its Percentage Interest, (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this subclause (vi), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and

	(vii) Thereafter, (A) to the General Partner in accordance with its Percentage Interest; (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (vii);

provided, however, if the Minimum Quarterly Distribution, the First Target Distribution, the Second Target Distribution and the Third Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(a)(vii).

(b) After Subordination Period. Available Cash with respect to any Quarter after the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5, subject to Section 17-607 of the Delaware Act, shall be distributed as follows, except as otherwise required by Section 5.6(b) in respect of additional Partnership Securities issued pursuant thereto:


	(i) First, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

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	(ii) Second, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

	(iii) Third, (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (iii), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

	(iv) Fourth, (A) to the General Partner in accordance with its Percentage Interest; (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (A) and (B) of this clause (iv), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and

	(v) Thereafter, (A) to the General Partner in accordance with its Percentage Interest; (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v);

Section 6.5 Distributions of Available Cash from Capital Surplus.

Available Cash that is deemed to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall, subject to Section 17-607 of the Delaware Act, be distributed, unless the provisions of Section 6.3 require otherwise, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until a hypothetical holder of a Common Unit acquired on the Closing Date has received with respect to such Common Unit, during the period since the Closing Date through such date, distributions of Available Cash that are deemed to be Capital Surplus in an aggregate amount equal to the Initial Unit Price. Available Cash that is deemed to be Capital Surplus shall then be distributed to the General Partner and all Unitholders holding Common Units, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage. Thereafter, all Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance with Section 6.4.

Section 6.6 Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.

(a) The Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution, Third Target Distribution, Common Unit Arrearages and Cumulative Common Unit Arrearages shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Partnership Securities in accordance with Section 5.9. In the event of a distribution of Available Cash that is deemed to be from Capital Surplus, the then applicable Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, shall be adjusted proportionately downward to equal the product obtained by multiplying the otherwise applicable Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, as the case may be, by a fraction of which the numerator is the Unrecovered Initial Unit Price of the Common Units immediately after giving effect to such distribution and of which the denominator is the Unrecovered Initial Unit Price of the Common Units immediately prior to giving effect to such distribution.

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(b) The Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, shall also be subject to adjustment pursuant to Section 6.9.

Section 6.7 Special Provisions Relating to the Holders of Subordinated Units.

(a) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holder of a Subordinated Unit shall have all of the rights and obligations of a Unitholder holding Common Units hereunder;provided, however, that immediately upon the conversion of Subordinated Units into Common Units pursuant to Section 5.7, the Unitholder holding a Subordinated Unit shall possess all of the rights and obligations of a Unitholder holding Common Units hereunder, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units;provided, however, that such converted Subordinated Units shall remain subject to the provisions of Sections 5.5(c)(ii), 6.1(d)(x)(A), 6.7(b) and 6.7(c).

(b) A Unitholder shall not be permitted to transfer a Subordinated Unit or a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder’s Capital Account with respect to the retained Subordinated Units or Retained Converted Subordinated Units would be negative after giving effect to the allocation under Section 5.5(c)(ii)(B).

(c) The Unitholder holding a Common Unit that has resulted from the conversion of a Subordinated Unit pursuant to Section 5.7 shall not be issued a Common Unit Certificate pursuant to Section 4.1, and shall not be permitted to transfer such Common Units to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.7(c), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Sections 5.5(c)(ii), 6.1(d)(x) and 6.7(b);provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units represented by Common Unit Certificates.

Section 6.8 Special Provisions Relating to the Holders of Incentive Distribution Rights.

Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Incentive Distribution Rights (a) shall (i) possess the rights and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII and (ii) have a Capital Account as a Partner pursuant to Section 5.5 and all other provisions related thereto and (b) shall not (i) be entitled to vote on any matters requiring the approval or vote of the holders of Outstanding Units, except as provided by law, (ii) be entitled to any distributions other than as provided in Sections 6.4(a)(v), (vi) and (vii), Section 6.4(b)(iii), (iv) and (v), and Section 12.4 or (iii) be allocated items of income, gain, loss or deduction other than as specified in this Article VI.

Section 6.9 Entity-Level Taxation.

If legislation is enacted or the interpretation of existing language is modified by a governmental taxing authority so that a Group Member is treated as an association taxable as a corporation or is otherwise subject to an entity-level tax for federal, state or local income tax purposes, then the General Partner shall estimate for each Quarter the Partnership Group’s aggregate liability (the“Estimated Incremental Quarterly Tax Amount”) for all such income taxes that are payable by reason of any such new legislation or interpretation;providedthat any difference between such estimate and the actual tax liability for such Quarter that is owed by reason of any such new legislation or interpretation shall be taken into account in determining the Estimated Incremental Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, shall be the product

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obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.9 times (b) the quotient obtained by dividing (i) Available Cash with respect to such Quarter by (ii) the sum of Available Cash with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the General Partner. For purposes of the foregoing, Available Cash with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Management.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:


	(i) 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 Partnership Securities, and the incurring of any other obligations;

	(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

	(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article XIV);

	(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

	(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

	(vi) the distribution of Partnership cash;

	(vii) the selection and dismissal of employees (including employees having titles such as “president,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

	(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;

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	(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

	(x) the control of any matters affecting the rights and obligations of the Partnership, 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;

	(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

	(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.8);

	(xiii) the purchase, sale or other acquisition or disposition of Partnership Securities, or the issuance of options, rights, warrants and appreciation rights relating to Partnership Securities;

	(xiv) the undertaking of any action in connection with the Partnership’s participation in any Group Member; and

	(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and the Assignees and each other Person who may acquire an interest in Partnership Securities hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement and the Group Member Agreement of each other Group Member, the Underwriting Agreement, the Omnibus Agreement, the Contribution Agreement, any Group Member Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement; (ii) agrees that the General Partner (on its own or through any officer of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the Assignees or the other Persons who may acquire an interest in Partnership Securities; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty stated or implied by law or equity.

Section 7.2 Certificate of Limited Partnership.

The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to

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maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

Section 7.3 Restrictions on the General Partner’s Authority.

Except as provided in Article XII, Article XIV and Section 4.7, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation, other combination or sale of ownership interests of the Partnership’s Subsidiaries) without the approval of holders of a Unit Majority;provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance. Without the approval of holders of a Unit Majority, the General Partner shall not, on behalf of the Partnership, except as permitted under Section 4.6, 11.1 and Section 11.2, elect or cause the Partnership to elect a successor general partner of the Partnership.

Section 7.4 Reimbursement of the General Partner.

(a) Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.

(b) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person, including Affiliates of the General Partner to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group, which amounts shall also include reimbursement for any Common Units purchased to satisfy obligations of the Partnership under any of its equity compensation plans), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership Group. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

(c) The General Partner and its Affiliates may charge any member of the Partnership Group a management fee to the extent necessary to allow the Partnership Group to reduce the amount of any state franchise or income tax or any tax based upon the revenues or gross margin of any member of the Partnership Group if the tax benefit produced by the payment of such management fee or fees exceeds the amount of such fee or fees.

(d) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership employee benefit plans, employee programs and employee practices (including plans, programs and practices involving the issuance of Partnership Securities or options to purchase or rights, warrants or appreciation rights relating to Partnership Securities), or cause the Partnership to issue Partnership Securities in connection with, or pursuant to, any employee benefit plan, employee program or employee practice maintained or sponsored by the General Partner or any of its Affiliates, in each case for the benefit of employees of the General Partner, any Group Member or any Affiliate or any of them, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Securities that the General Partner or such Affiliates are obligated to provide to any employees pursuant to any such employee benefit plans, employee programs or employee practices. Expenses incurred by the General Partner in connection with any such plans, programs

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and practices (including the net cost to the General Partner or such Affiliates of Partnership Securities purchased by the General Partner or such Affiliates from the Partnership to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b). Any and all obligations of the General Partner under any employee benefit plans, employee programs or employee practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest (represented by General Partner Units) pursuant to Section 4.6.

Section 7.5 Outside Activities.

(a) After the Closing Date, the General Partner, for so long as it is the General Partner of the Partnership (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a limited partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement or (B) the acquiring, owning or disposing of debt or equity securities in any Group Member.

(b) Each Indemnitee (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty expressed or implied by law to any Group Member or any Partner or Assignee. None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Indemnitee.

(c) Notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Indemnitees (other than the General Partner) in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any fiduciary duty or any other obligation of any type whatsoever of any Indemnitee for the Indemnitees (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) the Indemnitees shall have no obligation hereunder or as a result of any duty expressed or implied by law to present business opportunities to the Partnership. Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Indemnitee (including the General Partner). No Indemnitee (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to the Partnership, and such Indemnitee (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person for breach of any fiduciary or other duty by reason of the fact that such Indemnitee (including the General Partner) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership.

(d) The General Partner and each of its Affiliates may acquire Units or other Partnership Securities in addition to those acquired on the Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units or other Partnership Securities acquired by them. The term “Affiliates” when used in this Section 7.5(d) with respect to the General Partner shall not include any Group Member.

(e) Notwithstanding anything to the contrary in this Agreement, to the extent that any provision of this Section 7.5 purports or is interpreted to have the effect of restricting, eliminating or otherwise

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modifying the fiduciary duties that might otherwise, as a result of Delaware or other applicable law, be owed by the General Partner to the Partnership and its Limited Partners, or to constitute a waiver or consent by the Limited Partners to any such fiduciary duty, such provisions in this Section 7.5 shall be deemed to have been approved by the Partners.

Section 7.6 Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.

(a) The General Partner or any of its Affiliates may lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine;provided, however, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm’s-length basis (without reference to the lending party’s financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.6(a) and Section 7.6(b), the term “Group Member” shall include any Affiliate of a Group Member that is controlled by the Group Member.

(b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).

(c) No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty, expressed or implied, of the General Partner or its Affiliates to the Partnership or the Limited Partners by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to (i) enable distributions to the General Partner or its Affiliates (including in their capacities as Limited Partners) to exceed the General Partner’s Percentage Interest of the total amount distributed to all partners or (ii) hasten the expiration of the Subordination Period or the conversion of any Subordinated Units into Common Units.

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee;provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful;provided, further, no indemnification pursuant to this Section 7.7 shall be available to the General Partner or its Affiliates (other than a Group Member) with respect to its or their obligations incurred pursuant to the Underwriting Agreement, the Omnibus Agreement or the Contribution Agreement (other than obligations incurred by the General Partner on behalf of the Partnership). Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

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(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a determination that the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be determined that the Indemnitee is not entitled to be indemnified as authorized in this Section 7.7.

(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees, their heirs, successors, assigns and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8 Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners, or any other Persons who have acquired interests in the Partnership Securities, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted

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in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.

(b) Subject to its obligations and duties as General Partner set forth in Section 7.1(a), the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Group Member or any Partner, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Common Units (excluding Common Units owned by the General Partner and its Affiliates), (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval. If Special Approval is not sought and the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above, then it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement.

(b) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, or such Affiliates causing it to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of this Agreement,

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the Person or Persons making such determination or taking or declining to take such other action must believe that the determination or other action is in the best interests of the Partnership.

(c) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner, and the General Partner, or such Affiliates causing it to do so, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. By way of illustration and not of limitation, whenever the phrase, “at the option of the General Partner,” or some variation of that phrase, is used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be acting in its individual capacity. The General Partner’s organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its members, if the General Partner is a limited liability company, stockholders, if the General Partner is a corporation, or the members or stockholders of the General Partner’s general partner, if the General Partner is a partnership.

(d) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be at its option.

(e) Except as expressly set forth in this Agreement, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner, and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.

(f) The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

Section 7.10 Other Matters Concerning the General Partner.

(a) The General Partner may rely and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b) The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such opinion.

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(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney orattorneys-in-fact or the duly authorized officers of the Partnership.

Section 7.11 Purchase or Sale of Partnership Securities.

The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Securities;providedthat, except as permitted pursuant to Section 4.10, the General Partner may not cause any Group Member to purchase Subordinated Units during the Subordination Period. Such Partnership Securities shall be held by the Partnership as treasury securities unless they are expressly cancelled by action of an appropriate officer of the General Partner. As long as Partnership Securities are held by any Group Member, such Partnership Securities shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Securities for its own account, subject to the provisions of Articles IV and X.

Section 7.12 Registration Rights of the General Partner and its Affiliates.

(a) If (i) the General Partner or any Affiliate of the General Partner (including for purposes of this Section 7.12, any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner) holds Partnership Securities that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Securities (the“Holder”) to dispose of the number of Partnership Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Securities covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Securities specified by the Holder;provided, however, that (i) the Partnership shall not be required to effect more than three registrations pursuant to Section 7.12(a) and Section 7.12(b); (ii) if the Conflicts Committee determines in good faith that the requested registration would be materially detrimental to the Partnership and its Partners because such registration would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to postpone such requested registration for a period of not more than six months after receipt of the Holder’s request, such right pursuant to this Section 7.12(a) or Section 7.12(b) not to be utilized more than once in any twelve-month period and (iii) neither the General Partner nor any of its affiliates shall be entitled to any registration rights pursuant to this Section 7.12 until the earlier to occur of the termination of the Existing Registration Rights Agreement or such time as there ceases to be any Registrable Securities (as defined in the Existing Registration Rights Agreement). Except as provided in the preceding sentence, the Partnership shall be deemed not to have used all commercially reasonable efforts to keep the registration statement effective during the applicable period if it voluntarily takes any action that would result in Holders of Partnership Securities covered thereby not being able to offer and sell such Partnership Securities at any time during such period, unless such action is required by applicable law. In connection with any registration pursuant to the first sentence of this Section 7.12(a), the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request;provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Securities subject to such registration on such

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National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Securities in such states. Except as set forth in Section 7.12(d), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(b) If any Holder holds Partnership Securities that it desires to sell and Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such Holder to dispose of the number of Partnership Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Securities covered by such shelf registration statement have been sold, a “shelf” registration statement covering the Partnership Securities specified by the Holder on an appropriate form under Rule 415 under the Securities Act, or any similar rule that may be adopted by the Commission;provided, however, that the Partnership shall not be required to effect more than three registrations pursuant to Section 7.12(a) and this Section 7.12(b); andprovided further, however, that if the Conflicts Committee determines in good faith that any offering under, or the use of any prospectus forming a part of, the shelf registration statement would be materially detrimental to the Partnership and its Partners because such offering or use would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to suspend such offering or use for a period of not more than six months after receipt of the Holder’s request, such right pursuant to Section 7.12(a) or this Section 7.12(b) not to be utilized more than once in any twelve-month period. Except as provided in the preceding sentence, the Partnership shall be deemed not to have used all reasonable efforts to keep the shelf registration statement effective during the applicable period if it voluntarily takes any action that would result in Holders of Partnership Securities covered thereby not being able to offer and sell such Partnership Securities at any time during such period, unless such action is required by applicable law. In connection with any shelf registration pursuant to this Section 7.12(b), the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such shelf registration under the securities laws of such states as the Holder shall reasonably request;provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such shelf registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Securities subject to such shelf registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Securities in such states. Except as set forth in Section 7.12(d), all costs and expenses of any such shelf registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(c) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of equity securities of the Partnership for cash (other than an offering relating solely to an employee benefit plan), the Partnership shall use all reasonable efforts to include such number or amount of securities held by the Holder in such registration statement as the Holder shall request;provided, that the Partnership is not required to make any effort or take any action to so include the securities of the Holder once the registration statement is declared effective by the Commission or otherwise becomes effective, including any registration statement providing for the offering from time to time of securities pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(c) shall be an underwritten offering, then, in the event that the managing underwriter or

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managing underwriters of such offering advise the Partnership and the Holder in writing that in their opinion the inclusion of all or some of the Holder’s Partnership Securities would adversely and materially affect the success of the offering, the Partnership shall include in such offering only that number or amount, if any, of securities held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(d), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(d) If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Partnership’s obligation under Section 7.7, the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(d) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Securities were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading;provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

(e) The provisions of Section 7.12(a), Section 7.12(b) and Section 7.12(c) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates) after it ceases to be a general partner of the Partnership, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Securities with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed;provided, however, that the Partnership shall not be required to file successive registration statements covering the same Partnership Securities for which registration was demanded during such two-year period. The provisions of Section 7.12(d) shall continue in effect thereafter.

(f) The rights to cause the Partnership to register Partnership Securities pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Partnership Securities, provided (i) the Partnership is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Partnership Securities with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12.

(g) Any request to register Partnership Securities pursuant to this Section 7.12 shall (i) specify the Partnership Securities intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Partnership Securities for distribution, (iii) describe the nature or method of the proposed offer and sale of Partnership Securities, and (iv) contain the undertaking of such

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Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Securities.

Section 7.13 Reliance by Third Parties.

Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Limited Partner hereby waives any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting.

The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders and assignees of Units or other Partnership Securities, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device;provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP.

Section 8.2 Fiscal Year.

The fiscal year of the Partnership shall be a fiscal year ending December 31.

Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership’s website) to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.

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(b) As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership’s website) to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

ARTICLE IX

TAX MATTERS

Section 9.1 Tax Returns and Information.

The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and a taxable year ending on December 31. The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable year shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable year ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(g) without regard to the actual price paid by such transferee.

(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3 Tax Controversies.

Subject to the provisions hereof, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.

Section 9.4 Withholding.

Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner or Assignee (including by reason of Section 1446 of the

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Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.

ARTICLE X

ADMISSION OF PARTNERS

Section 10.1 Admission of Limited Partners.

(a) By acceptance of the transfer of any Limited Partner Interests in accordance with Article IV or the acceptance of any Limited Partner Interests issued pursuant to Article V or pursuant to a merger or consolidation pursuant to Article XIV, and except as provided in Section 4.9, each transferee of, or other such Person acquiring, a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred or issued to such Person when any such transfer, issuance or admission is reflected in the books and records of the Partnership and such Limited Partner becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement, (iv) grants the powers of attorney set forth in this Agreement and (v) makes the consents and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may become a Limited Partner or Record Holder of a Limited Partner Interest without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and until such Person is reflected in the books and records of the Partnership as the Record Holder of such Limited Partner Interest. The rights and obligations of a Person who is a Non-citizen Assignee shall be determined in accordance with Section 4.9 hereof.

(b) The name and mailing address of each Limited Partner shall be listed on the books and records of the Partnership maintained for such purpose by the Partnership or the Transfer Agent. The General Partner shall update the books and records of the Partnership from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate, as provided in Section 4.1 hereof.

(c) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(a).

Section 10.2 Admission of Successor General Partner.

A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest (represented by General Partner Units) pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or 11.2 or the transfer of the General Partner Interest (represented by General Partner Units) pursuant to Section 4.6,provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

Section 10.3 Amendment of Agreement and Certificate of Limited Partnership.

To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if

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required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership, and the General Partner may for this purpose, among others, exercise the power of attorney granted pursuant to Section 2.6.

ARTICLE XI

WITHDRAWAL OR REMOVAL OF PARTNERS

Section 11.1 Withdrawal of the General Partner.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”);


	(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

	(ii) The General Partner transfers all of its rights as General Partner pursuant to Section 4.6;

	(iii) The General Partner is removed pursuant to Section 11.2;

	(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not adebtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

	(v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

	(vi) (A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.

If an Event of Withdrawal specified in Section 11.1(a)(iv), (v) or (vi)(A), (B), (C) or (E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 12:00 midnight, Central Standard Time, on September 30, 2016, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners;provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel(“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability of any Limited Partner or any Group Member or cause any Group

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Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 12:00 midnight, Central Standard Time, on September 30, 2016, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal, a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.

Section 11.2 Removal of the General Partner.

The General Partner may be removed if such removal is approved by the Unitholders holding at least 66²/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of the Outstanding Common Units voting as a single class and a majority of the outstanding Subordinated Units (if any Subordinated Units are then Outstanding) voting as a class (including, in each case, Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.2. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.2, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.2.

Section 11.3 Interest of Departing General Partner and Successor General Partner.

(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner, to require its successor to purchase its General Partner Interest (represented by General Partner Units) and its general partner interest (or equivalent interest), if any, in the other Group Members and all of its Incentive Distribution Rights (collectively, the “Combined Interest”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as

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of the effective date of its departure. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest of the Departing General Partner. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

For purposes of this Section 11.3(a), the fair market value of the Departing General Partner’s Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner’s departure, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such departure, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest of the Departing General Partner. In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner and other factors it may deem relevant.

(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and its Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest of the Departing General Partner to Common Units will be characterized as if the Departing General Partner (or its transferee) contributed its Combined Interest to the Partnership in exchange for the newly issued Common Units.

(c) If a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of the Percentage Interest of the Departing General Partner and the Net Agreed Value of the Partnership’s assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing General Partner was entitled. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner’s admission, the

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successor General Partner’s interest in all Partnership distributions and allocations shall be its Percentage Interest.

Section 11.4 Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages.

Notwithstanding any provision of this Agreement, if the General Partner is removed as general partner of the Partnership under circumstances where Cause does not exist and Units held by the General Partner and its Affiliates are not voted in favor of such removal, (i) the Subordination Period will end and all Outstanding Subordinated Units will immediately and automatically convert into Common Units on a one-for-one basis, (ii) all Cumulative Common Unit Arrearages on the Common Units will be extinguished and (iii) the General Partner will have the right to convert its General Partner Interest (represented by General Partner Units) and its Incentive Distribution Rights into Common Units or to receive cash in exchange therefor in accordance with Section 11.3.

Section 11.5 Withdrawal of Limited Partners.

No Limited Partner shall have any right to withdraw from the Partnership;provided, however, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII

DISSOLUTION AND LIQUIDATION

Section 12.1 Dissolution.

The Partnership shall not be dissolved by the admission of additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1 or Section 11.2, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership. The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:


	(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and an Opinion of Counsel is received as provided in Section 11.1(b) or 11.2 and such successor is admitted to the Partnership pursuant to Section 10.2;

	(b) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

	(c) the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act; or

	(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2 Continuation of the Business of the Partnership After Dissolution.

Upon (a) dissolution of the Partnership following an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or (iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2, then within 90 days thereafter, or (b) dissolution of the Partnership upon an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), (v) or (vi), then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by the holders of a Unit Majority. Unless such an election is made

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within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:


	(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

	(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

	(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement;provided, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability of any Limited Partner and (y) neither the Partnership nor any Group Member 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 such right to continue (to the extent not already so treated or taxed).

Section 12.3 Liquidator.

Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, voting as a single class. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

Section 12.4 Liquidation.

The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in

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	whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

	(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

	(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable year of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 days after said date of such occurrence).

Section 12.5 Cancellation of Certificate of Limited Partnership.

Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6 Return of Contributions.

The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

Section 12.7 Waiver of Partition.

To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8 Capital Account Restoration.

No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable year of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

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ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE

Section 13.1 Amendments to be Adopted Solely by the General Partner.

Each Partner agrees that the General Partner, without the approval of any Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:


	(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

	(b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

	(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership 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 the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

	(d) a change that the General Partner determines, (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (ii) to be necessary or appropriate to (A) 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 (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.9 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

	(e) a change in the fiscal year or taxable year of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

	(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

	(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.6, including any amendment that the General Partner determines is necessary or appropriate in connection with any modifications to the Incentive Distribution Rights made in connection with the issuance of Partnership Securities pursuant to Section 5.6,providedthat the modifications to the Incentive Distribution Rights and the related issuance of Partnership Securities have received Special Approval;

	(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

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	(i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

	(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4;

	(k) a merger, conveyance or conversion pursuant to Section 14.3(d); or

	(l) any other amendments substantially similar to the foregoing.

Section 13.2 Amendment Procedures.

Except as provided in Section 13.1 and Section 13.3, all amendments to this Agreement shall be made in accordance with the following requirements. Amendments to this Agreement may be proposed only by the General Partner;provided, however, that the General Partner shall have no duty or obligation to propose any amendment to this Agreement and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to propose an amendment, to the fullest extent permitted by law shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. A proposed amendment shall be effective upon its approval by the General Partner and the holders of a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments.

Section 13.3 Amendment Requirements.

(a) Notwithstanding the provisions of Section 13.1 and Section 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced.

(b) Notwithstanding the provisions of Section 13.1 and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c), or (ii) 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 to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

(c) Except as provided in Section 14.3, and without limitation of the General Partner’s authority to adopt amendments to this Agreement without the approval of any Partners or Assignees as contemplated in Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the

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limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Units.

Section 13.4 Special Meetings.

All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the mailing of notice of the meeting. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5 Notice of a Meeting.

Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

Section 13.6 Record Date.

For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

Section 13.7 Adjournment.

When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

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Section 13.8 Waiver of Notice; Approval of Meeting; Approval of Minutes.

The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

Section 13.9 Quorum and Voting.

The holders of a majority of the Outstanding Units of the class or classes for which a meeting has been called (including Outstanding Units deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Limited Partners of such class or classes unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Units, in which case the quorum shall be such greater percentage. At any meeting of the Limited Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Limited Partners holding Outstanding Units that in the aggregate represent a majority of the Outstanding Units entitled to vote and be present in person or by proxy at such meeting shall be deemed to constitute the act of all Limited Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Limited Partners holding Outstanding Units that in the aggregate represent at least such greater or different percentage shall be required. The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Limited Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Units specified in this Agreement (including Outstanding Units deemed owned by the General Partner). In the absence of a quorum any meeting of Limited Partners may be adjourned from time to time by the affirmative vote of holders of at least a majority of the Outstanding Units entitled to vote at such meeting (including Outstanding Units deemed owned by the General Partner) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.

Section 13.10 Conduct of a Meeting.

The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.11 Action Without a Meeting.

If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Units (including Units deemed owned by the General Partner) that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which

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the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner, (b) approvals sufficient to take the action proposed are dated as of a date not more than 90 days prior to the date sufficient approvals are deposited with the Partnership and (c) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners.

Section 13.12 Right to Vote and Related Matters.

(a) Only those Record Holders of the Units on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of “Outstanding”) shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

(b) With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

ARTICLE XIV

MERGER, CONSOLIDATION OR CONVERSION

Section 14.1 Authority.

The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written plan of merger or consolidation(“Merger Agreement”) or a written plan of conversion(“Plan of Conversion”), as the case may be, in accordance with this Article XIV.

Section 14.2 Procedure for Merger, Consolidation or Conversion.

(a) Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner,provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger, consolidation or conversion of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to consent to a merger, consolidation or conversion,

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shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:


	(i) name and state of domicile of each of the business entities proposing to merge or consolidate;

	(ii) the name and state of domicile of the business entity that is to survive the proposed merger or consolidation (the“Surviving Business Entity”);

	(iii) the terms and conditions of the proposed merger or consolidation;

	(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such general or limited partner interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (ii) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

	(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, operating agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

	(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of merger and stated therein); and

	(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

(c) If the General Partner shall determine to consent to the conversion, the General Partner shall approve the Plan of Conversion, which shall set forth:


	(i) the name of the converting entity and the converted entity;

	(ii) a statement that the Partnership is continuing its existence in the organizational form of the converted entity;

	(iii) a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;

	(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the converted entity;

	(v) in an attachment or exhibit, the certificate of limited partnership of the Partnership; and

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	(vi) in an attachment or exhibit, the certificate of limited partnership, articles of incorporation, or other organizational documents of the converted entity;

	(vii) the effective time of the conversion, which may be the date of the filing of the articles of conversion or a later date specified in or determinable in accordance with the Plan of Conversion (provided, that if the effective time of the conversion is to be later than the date of the filing of such articles of conversion, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such articles of conversion and stated therein); and

	(viii) such other provisions with respect to the proposed conversion that the General Partner determines to be necessary or appropriate.

Section 14.3 Approval by Limited Partners.

(a) Except as provided in Section 14.3(d) or 14.3(e), the General Partner, upon its approval of the Merger Agreement or the Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of a special meeting or the written consent.

(b) Except as provided in Section 14.3(d) or 14.3(e), the Merger Agreement or Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority.

(c) Except as provided in Section 14.3(d) or 14.3(e), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or articles of conversion pursuant to Section 14.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion, as the case may be.

(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such conversion, merger, or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with the same rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (B) the merger or consolidation would not result in an amendment to the Partnership Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Unit outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Securities to be issued by the Partnership in such merger or consolidation do not exceed 20% of the Partnership Securities Outstanding immediately prior to the effective date of such merger or consolidation.

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(f) Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.5 shall be effective at the effective time or date of the merger or consolidation.

Section 14.4 Certificate of Merger.

Upon the required approval by the General Partner and the Unitholders of a Merger Agreement or the Plan of Conversion, as the case may be, a certificate of merger or articles of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 14.5 Effect of Merger, Consolidation or Conversion.

(a) At the effective time of the certificate of merger:


	(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

	(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

	(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

	(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b) At the effective time of the articles of conversion:


	(i) the Partnership shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;

	(ii) all rights, title, and interests to all real estate and other property owned by the Partnership shall continue to be owned by the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;

	(iii) all liabilities and obligations of the Partnership shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;

	(iv) all rights of creditors or other parties with respect to or against the prior interest holders or other owners of the Partnership in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and may be pursued by such creditors and obligees as if the conversion did not occur;

	(v) a proceeding pending by or against the Partnership or by or against any of Partners in their capacities as such may be continued by or against the converted entity in its new organizational form and by or against the prior partners without any need for substitution of parties; and

	(vi) the Partnership Units that are to be converted into partnership interests, shares, evidences of ownership, or other securities in the converted entity as provided in the Plan of Conversion shall be so converted, and Partners shall be entitled only to the rights provided in the Plan of Conversion.

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ARTICLE XV

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

Section 15.1 Right to Acquire Limited Partner Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable at its option, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the90-day period preceding the date that the notice described in Section 15.1(b) is mailed. As used in this Agreement, (i) “Current Market Price” as of any date of any class of Limited Partner Interests means the average of the daily Closing Prices (as hereinafter defined) per Limited Partner Interest of such class for the 20 consecutive Trading Days (as hereinafter defined) immediately prior to such date; (ii) “Closing Price” for any day means the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, as reported in the principal consolidated transaction reporting system with respect to securities listed on the principal National Securities Exchange (other than the Nasdaq Stock Market) on which such Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests of such class are not listed or admitted to trading on any National Securities Exchange (other than the Nasdaq Stock Market), the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in theover-the-counter market, as reported by the Nasdaq Stock Market or such other system then in use, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner; and (iii) “Trading Day” means a day on which the principal National Securities Exchange on which such Limited Partner Interests of any class are listed or admitted for trading is open for the transaction of business or, if Limited Partner Interests of a class are not listed or admitted for trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the“Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited

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Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Article IV, Article V, Article VI, and Article XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Article IV, Article V, Article VI and Article XII).

(c) At any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.

ARTICLE XVI

GENERAL PROVISIONS

Section 16.1 Addresses and Notices.

Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Securities at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Securities by reason of any assignment or otherwise. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Partnership is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

Section 16.2 Further Action.

The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

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Section 16.3 Binding Effect.

This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 16.4 Integration.

This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 16.5 Creditors.

None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 16.6 Waiver.

No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 16.7 Third-Party Beneficiaries.

Each Partner agrees that any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee.

Section 16.8 Counterparts.

This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Limited Partner Interest, pursuant to Section 10.1(a) without execution hereof.

Section 16.9 Applicable Law.

This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

Section 16.10 Invalidity of Provisions.

If any provision of this Agreement is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby.

Section 16.11 Consent of Partners.

Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

Section 16.12 Facsimile Signatures.

The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on certificates representing Common Units is expressly permitted by this Agreement.

[REMAINDER OF THIS PAGE INTENTIONALLY LEFT BLANK.]

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IN WITNESS WHEREOF,the parties hereto have executed this Agreement as of the date first written above.


	GENERAL PARTNER:

	EAGLE ROCK ENERGY GP, L.P.

	By: EAGLE ROCK ENERGY G&P, LLC


	By:



	Name: Alex A. Bucher


	Title:	President and Chief Executive Officer


	ORGANIZATIONAL LIMITED PARTNER:

	EAGLE ROCK HOLDINGS, L.P.


	By: EAGLE ROCK GP, L.L.C.


	By:



	Name: Alex A. Bucher


	Title:	President and Chief Executive Officer


	LIMITED PARTNERS:

	All Limited Partners now and hereafter
	admitted as Limited Partners of the
	Partnership, pursuant to powers of attorney
	now and hereafter executed in favor of, and
	granted and delivered to the General
	Partner or without execution hereof
	pursuant to Section 10.1(a) hereof.

	EAGLE ROCK HOLDINGS, L.P.


	By: EAGLE ROCK GP, L.L.C.


	By:



	Name: Alex A. Bucher


	Title:	President and Chief Executive Officer

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EXHIBIT A

to the First Amended and Restated

Agreement of Limited Partnership of

Eagle Rock Energy Partners, L.P.

Certificate Evidencing Common Units

Representing Limited Partner Interests in

Eagle Rock Energy Partners, L.P.


No.	Common Units

In accordance with Section 4.1 of the First Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P., as amended, supplemented or restated from time to time (the“Partnership Agreement”), Eagle Rock Energy Partners, L.P., a Delaware limited partnership (the“Partnership”), hereby certifies that (the“Holder”) is the registered owner of Common Units representing limited partner interests in the Partnership (the“Common Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 14950 Heathrow Forest Parkway, Suite 111, Houston, Texas 77032. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (iii) granted the powers of attorney provided for in the Partnership Agreement and (iv) made the waivers and given the consents and approvals contained in the Partnership Agreement.

Exhibit A-1

This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.


Dated:		Eagle Rock Energy Partners, L.P.

		By: Eagle Rock Energy GP, L.P.

Countersigned and Registered by:		By: Eagle Rock Energy G&P, LLC, its General Partner

American Stock Transfer & Trust Company		By:

as Transfer Agent and Registrar		Name:

By:		By:

Authorized Signature		Secretary

[Reverse of Certificate]

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:


TEN COM -	as tenants in common	UNIF GIFT/ TRANSFERS MIN ACT
TEN ENT -	as tenants by the entireties	Custodian
		(Cust) (Minor)
JT TEN -	as joint tenants with right of survivorship and not as tenants in common	under Uniform Gifts/ Transfers to CD Minors Act (State)

Additional abbreviations, though not in the above list, may also be used.

Exhibit A-2

ASSIGNMENT OF COMMON UNITS OF

EAGLE ROCK ENERGY PARTNERS, L.P.

FOR VALUE RECEIVED, hereby assigns, conveys, sells and transfers unto



(Please print or typewrite name and address of assignee)		(Please insert Social Security or other identifying number of assignee)

Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint as itsattorney-in-fact with full power of substitution to transfer the same on the books of Eagle Rock Energy Partners, L.P.


Date: THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17d-15		NOTE:		The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change. (Signature) (Signature)

No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer.

Exhibit A-3

APPENDIX B

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

B-1

other partnership interest will be the amount which that capital account would be if that common unit, subordinated 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.

B-2

MMcf: One million cubic feet of natural gas.

MBbls/d: One thousand barrels per day.

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 same per-unit amount as was distributed in the immediately preceding 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;provided however, that disbursements made (including contributions to Eagle Rock Energy Partners, L.P. or our subsidiaries or disbursements on behalf of Eagle Rock Energy Partners, L.P. or our subsidiaries) or cash reserves established, increased or reduced after the end of that period but on or before the date of determination of available cash for that period shall be deemed to have been made, established, increased or reduced for purposes of determining operating surplus, within that period if our general partner so determines.

residue gas: The pipeline quality natural gas remaining after natural gas is processed.

B-3

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.

B-4

Until , 2006 (the 25th day after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

PART II

INFORMATION REQUIRED IN THE REGISTRATION STATEMENT


Item 13.	*Other Expenses of Issuance and Distribution.*

Set forth below are the expenses (other than underwriting discounts and fees) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee and the NASD filing fee, the amounts set forth below are estimates.


SEC registration fee		$	32,301
NASD filing fee			30,688
Printing and engraving expenses			800,000
Fees and expenses of legal counsel			750,000
Accounting fees and expenses			1,150,000
Transfer agent and registrar fees			5,000
Nasdaq Global Market listing fee			100,000
Miscellaneous			34,511

	Total	$	3,000,000


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 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 will become 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 this offering, the 6,580,466 common units in Eagle Rock Pipeline, L.P. will be converted into common units in Eagle Rock Energy Partners, L.P. on approximately a 1-for-0.719 common unit basis. All of these interests in Eagle Rock Pipeline will be converted into common units in us upon consummation of this offering.

II-1


Item 16.	*Exhibits.*

The following documents are filed as exhibits to this registration statement:


Exhibit
Number				Description

	1	.1	—	Form of Underwriting Agreement
	3	.1**	—	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P.
	3	.2**	—	Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)
	3	.3**	—	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P.
	3	.4**	—	Limited Partnership Agreement of Eagle Rock Energy GP, L.P.
	3	.5**	—	Certificate of Formation of Eagle Rock Energy G&P, LLC
	3	.6	—	Form of Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC
	4	.1**	—	Registration Rights Agreement dated March 27, 2006, among Eagle Rock Pipeline, L.P. and the Purchasers listed thereto
	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.
	4	.3**	—	Form of Registration Rights Agreement between Eagle Rock Energy Partners, L.P. and Eagle Rock Holdings, L.P.
	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)
	5	.1**	—	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered.
	8	.1	—	Opinion of Vinson & Elkins L.L.P. relating to tax matters.
	10	.1	—	Amended and Restated Credit and Guaranty Agreement
	10	.2	—	Form of Omnibus Agreement
	10	.3**	—	Form of Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan
	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.
	10	.5†**	—	Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and ONEOK Texas Field Services, L.P.
	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.)
	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.)
	10	.8†**	—	Minimum Volume Agreement between ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC
	10	.9†**	—	Gas Purchase Agreement between ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC
	10	.10†**	—	Gas Purchase Contract between Warren Petroleum Company (Eagle Rock Field Services, L.P.) and Wallace Oil & Gas, Inc. (Cimarex Energy Co.)
	10	.11	—	Form of Contribution, Conveyance and Assumption Agreement
	10	.12	—	Employment Agreement dated August 2, 2006 between Eagle Rock Energy G&P, LLC and Richard W. FitzGerald
	21	.1**	—	List of Subsidiaries of Eagle Rock Energy Partners, L.P.
	23	.1	—	Consent of Deloitte & Touche LLP
	23	.2**	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
	23	.3	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
	23	.4	—	Consent of Director Nominee
	23	.5	—	Consent of Director Nominee
	24	.1**	—	Powers of Attorney (contained on page II-3)

II-2


*	To be filed by amendment.


**	Previously filed.


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


Item 17.	*Undertakings.*

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

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.

The undersigned registrant hereby undertakes that:


	(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

	(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus 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.

The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with the general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to the general partner or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

II-3

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 September 12, 2006.


	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/Alex A. Bucher



	Name: Alex A. Bucher


	Title:	Chairman of the Board, President and Chief Executive Officer

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/Alex A. Bucher Alex A. Bucher		Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)	September 12, 2006

/s/Joan A.W. Schnepp Joan A.W. Schnepp		Executive Vice President, Secretary and Director	September 12, 2006

/s/Richard W. FitzGerald Richard W. FitzGerald		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) (Principal Accounting Officer)	September 12, 2006

/s/Alfredo Garcia Alfredo Garcia		Senior Vice President, Corporate Development	September 12, 2006

* Kenneth A. Hersh		Director	September 12, 2006

* William J. Quinn		Director	September 12, 2006

* John A. Weinzierl		Director	September 12, 2006

*By:	/s/Joan A.W. Schnepp Joan A.W. Schnepp As Attorney-in-fact

II-4

EXHIBIT INDEX


Exhibit
Number				Description

	1	.1	—	Form of Underwriting Agreement
	3	.1**	—	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P.
	3	.2**	—	Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)
	3	.3**	—	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P.
	3	.4**	—	Limited Partnership Agreement of Eagle Rock Energy GP, L.P.
	3	.5**	—	Certificate of Formation of Eagle Rock Energy G&P, LLC
	3	.6	—	Form of Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC
	4	.1**	—	Registration Rights Agreement dated March 27, 2006, among Eagle Rock Pipeline, L.P. and the Purchasers listed thereto
	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.
	4	.3**	—	Form of Registration Rights Agreement between Eagle Rock Energy Partners, L.P. and Eagle Rock Holdings, L.P.
	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)
	5	.1**	—	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered.
	8	.1	—	Opinion of Vinson & Elkins L.L.P. relating to tax matters.
	10	.1	—	Amended and Restated Credit and Guaranty Agreement
	10	.2	—	Form of Omnibus Agreement
	10	.3**	—	Form of Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan
	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.
	10	.5†**	—	Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and ONEOK Texas Field Services, L.P.
	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.)
	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.)
	10	.8†**	—	Minimum Volume Agreement between ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC
	10	.9†**	—	Gas Purchase Agreement between ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC
	10	.10†**	—	Gas Purchase Contract between Warren Petroleum Company (Eagle Rock Field Services, L.P.) and Wallace Oil & Gas, Inc. (Cimarex Energy Co.)
	10	.11	—	Form of Contribution, Conveyance and Assumption Agreement
	10	.12	—	Employment Agreement dated August 2, 2006 between Eagle Rock Energy G&P, LLC and Richard W. FitzGerald
	21	.1**	—	List of Subsidiaries of Eagle Rock Energy Partners, L.P.
	23	.1	—	Consent of Deloitte & Touche LLP
	23	.2**	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
	23	.3	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
	23	.4	—	Consent of Director Nominee
	23	.5	—	Consent of Director Nominee
	24	.1**	—	Powers of Attorney (contained on page II-3)


*	To be filed by amendment.


**	Previously filed.


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

Eagle Rock Energy Partners L P (EROC) Inactive S-1/AIPO registration (amended)