Resolute Energy Partners S-1 IPO registration

As filed with the Securities and Exchange Commission on September 28, 2007

Registration No. 333-          

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

Resolute Energy Partners, LP

(Exact Name of Registrant as Specified in Its Charter)

Delaware
(State or Other Jurisdiction of
Incorporation or Organization) 1311
(Primary Standard Industrial
Classification Code Number) 26-1086221
(I.R.S. Employer
Identification Number)

1675 Broadway, Suite 1950

Denver, Colorado 80202

(303) 534-4600

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

Nicholas J. Sutton

Chief Executive Officer

1675 Broadway, Suite 1950

Denver, Colorado 80202

(303) 534-4600

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

Copies to:

William N. Finnegan, IV
Alan P. Baden
Vinson & Elkins LLP
First City Tower
1001 Fannin Street, Suite 2500
Houston, Texas 77002
(713) 758-2222 Joshua Davidson
R. Joel Swanson
Baker Botts L.L.P.
One Shell Plaza
910 Louisiana, Suite 3200
Houston, Texas 77002
(713) 229-1234

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

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

CALCULATION OF REGISTRATION FEE

	Proposed Maximum
Title of Each Class of	Aggregate Offering	Amount of
Securities to Be Registered	Price(1)(2)	Registration Fee
Common units representing limited partner interests	$332,062,500	$10,195

(1)	Includes common units issuable upon exercise of the underwriters’ over-allotment option.
(2)	Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(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 prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED SEPTEMBER 28, 2007

PROSPECTUS

13,750,000 Common Units

Representing Limited Partner Interests

Resolute Energy Partners, LP is a Delaware limited partnership recently formed to own, exploit and develop oil and gas properties. This is the initial public offering of our common units. No public market currently exists for our common units. We expect the initial public offering price to be between $      and $      per common unit. We intend to apply to list the common units on the New York Stock Exchange under the symbol “REN.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 20.

These risks include, but are not limited to, the following:

•  We may not have sufficient cash flow from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.

•  Our development operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could adversely affect our ability to replace our production and proved reserves.

•  Because oil and gas properties are a depleting asset, we must successfully develop our properties and make acquisitions in order to maintain our production and sustain our distributions over time.

•  A significant part of our development plan involves the implementation of our CO₂ projects. These projects are subject to numerous uncertainties and may be less successful than planned.

•  We have a single customer, and the loss of that customer for any reason or the failure of that customer to pay for the crude oil that we sell to it could have a material adverse effect on our financial results and ability to make cash distributions to our unitholders.

•  Oil prices are currently at historically high levels and are very volatile. A sustained decline in oil prices will cause a decline in our cash flow from operations, which may force us to reduce our distributions or cease paying distributions altogether.

•  You will have limited voting rights and will not be 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 general partner and its affiliates control us and will have conflicts of interest with us. Our partnership agreement limits the fiduciary duties that our general partner owes to us, which may permit it to favor its own interests to your detriment, and limits the circumstances under which you may make a claim relating to conflicts of interest and the remedies available to you in that event.

•  Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes, then our cash available for distribution to you would be substantially reduced.

•  You will 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(1)	$	$
Proceeds to Resolute Energy Partners, LP (before expenses)	$	$

(1) Excludes a structuring fee of $      payable to Lehman Brothers Inc., UBS Securities LLC and Wachovia Capital Markets, LLC for evaluation, analysis and structuring of our partnership and this offering. Please see “Underwriting” for more information.

We have granted the underwriters a30-day option to purchase up to an additional 2,062,500 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 13,750,000 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.

Lehman Brothers, on behalf of the underwriters, expects to deliver the common units on or about          , 2008.

Lehman Brothers UBS Investment Bank Wachovia Securities

 , 2008

Our Areas of Operation

TABLE OF CONTENTS

	Page
SUMMARY		1
Resolute Energy Partners, LP		1
Planned Operating and Development Activities		2
Hedging Activities		2
Our Management and Natural Gas Partners		3
Our Business Strategies		3
Our Competitive Strengths		4
Risk Factors		4
Management of Resolute Energy Partners, LP		4
Principal Executive Offices and Internet Address		4
Our Partnership Structure and Formation Transactions		5
Summary of Conflicts of Interest and Fiduciary Duties		7
Our General Partner’s Right to Receive Incentive Distributions		7
The Offering		8
Summary Historical and Pro Forma Financial Data		12
Non-GAAP Financial Measures		16
Summary Historical Operating and Reserve Data		18
RISK FACTORS		20
Risks Related to Our Business		20
Risks Inherent in an Investment in Us		33
Tax Risks to Common Unitholders		41
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		45
USE OF PROCEEDS		46
CAPITALIZATION		47
DILUTION		48
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		49
General		49
Our Minimum Quarterly Distribution Rate		51
Unaudited Pro Forma Available Cash for Year Ended December 31, 2006, and Twelve Months Ended June 30, 2007		52
Estimated Cash Available for Distributions for the Year Ending December 31, 2008		55
Assumptions and Considerations		57
Operations and Revenue		58
Capital Expenditures and Expenses		60
Sensitivity Analysis		62
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS		65
Distributions of Available Cash		65
Operating Surplus and Capital Surplus		66
Subordination Period		69
Distributions of Available Cash from Operating Surplus during the Subordination Period		70
Distributions of Available Cash from Operating Surplus after the Subordination Period		71
General Partner Interest and Incentive Distribution Rights		71
Percentage Allocations of Available Cash from Operating Surplus		72

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	Page
Distributions from Capital Surplus		72
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels		73
Distributions of Cash Upon Liquidation		73
SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA		75
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		78
Overview		78
How We Evaluate Our Operations		81
Factors That Significantly Affect Our Results		83
Results of Operations		85
Six Months Ended June 30, 2007, Compared to Six Months Ended June 30, 2006		86
Year Ended December 31, 2006, Compared to the Year Ended December 31, 2005		87
Year Ended December 31, 2005, Compared to the Period from January 22, 2004 (Inception) to December 31, 2004		89
Liquidity and Capital Resources		90
Revolving Credit Facility		93
Contractual Obligations		93
Off-Balance Sheet Obligations		94
Critical Accounting Policies and Estimates		94
Recent Accounting Pronouncements		97
Quantitative and Qualitative Disclosures About Market Risk		97
BUSINESS		99
Greater Aneth Field		100
Our Business Strategies		101
Our Competitive Strengths		103
Oil Recovery Overview		104
Recent Development and Operating Activity		105
Planned Operating and Development Activities		106
Estimated Net Proved Reserves		108
Production and Price History		111
Productive Wells		112
Acreage		112
Drilling Results		112
Relationship with the Navajo Nation		112
Marketing and Customers		114
Aneth Gas Processing Plant		115
Title to Properties		116
Competition		116
Seasonality		116
Environmental and Safety Matters and Regulation		116
Laws and Regulations Pertaining to Oil and Gas Operations on Navajo Nation Lands		120
Other Regulation of the Oil and Gas Industry		123
Legal Proceedings		125
Employees		125
Offices		125

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	Page
MANAGEMENT		126
Management of Resolute Energy Partners, LP		126
Directors and Executive Officers		127
Reimbursement of Expenses of Our General Partner		129
Executive Compensation		129
Compensation of Directors		129
Compensation Discussion and Analysis		129
Long-Term Incentive Plan		130
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		135
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		136
Distributions and Payments to Our General Partner and its Affiliates		136
Agreements Governing the Transactions		137
Administrative Services Agreement		137
Competition		138
Indemnification		138
Other Arrangements with Affiliates		138
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		139
Conflicts of Interest		139
Fiduciary Duties		144
DESCRIPTION OF THE COMMON UNITS		146
The Units		146
Transfer Agent and Registrar		146
Transfer of Common Units		146
THE PARTNERSHIP AGREEMENT		148
Organization and Duration		148
Purpose		148
Power of Attorney		148
Cash Distributions		148
Capital Contributions		148
Voting Rights		149
Limited Liability		150
Issuance of Additional Securities		151
Amendment of the Partnership Agreement		151
Merger, Sale or Other Disposition of Assets		153
Termination and Dissolution		154
Liquidation and Distribution of Proceeds		154
Withdrawal or Removal of the General Partner		155
Transfer of General Partner Interest		156
Transfer of Ownership Interests in the General Partner		156
Transfer of Incentive Distribution Rights		156
Change of Management Provisions		156
Limited Call Right		157
Meetings; Voting		157

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	Page
Status as Limited Partner		158
Non-Eligible Holders; Redemption		158
Indemnification		159
Reimbursement of Expenses		159
Books and Reports		160
Right to Inspect Our Books and Records		160
Registration Rights		160
UNITS ELIGIBLE FOR FUTURE SALE		161
MATERIAL TAX CONSEQUENCES		162
Partnership Status		163
Limited Partner Status		164
Tax Consequences of Common Unit Ownership		164
Tax Treatment of Operations		170
Disposition of Common Units		174
Uniformity of Common Units		176
Tax-Exempt Organizations and Other Investors		176
Administrative Matters		177
State, Local and Other Tax Considerations		179
INVESTMENT IN RESOLUTE ENERGY PARTNERS, LP BY EMPLOYEE BENEFIT PLANS		180
UNDERWRITING		182
Commissions and Expenses		182
Option to Purchase Additional Common Units		182
Lock-Up Agreements		183
Offering Price Determination		184
Indemnification		184
Directed Unit Program		184
Stabilization, Short Positions and Penalty Bids		184
Electronic Distribution		185
New York Stock Exchange		185
Discretionary Sales		185
Stamp Taxes		185
Relationships/NASD Conduct Rules		186
VALIDITY OF THE COMMON UNITS		187
EXPERTS		187
WHERE YOU CAN FIND MORE INFORMATION		188
INDEX TO FINANCIAL STATEMENTS		F-1
APPENDIX A — FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP		A-1
APPENDIX B — GLOSSARY OF TERMS		B-1
APPENDIX C — REPORT OF NETHERLAND, SEWELL & ASSOCIATES, INC., INDEPENDENT PETROLEUM ENGINEERS		C-1
Purchase and Sale Agreement
Asset Sale Agreement
Certificate of Limited Partnership
Certificate of Formation
Cooperative Agreement
First Amendment of Cooperative Agreement
Carbon Dioxide Sale and Purchase Agreement
Product Sale and Purchase Contract
Consent of Ehrhardt Keefe Steiner & Hoffman PC
Consent of Deloitte & Touch LLP
Consent of Sproule Associates Limited
Consent of Netherland, Sewell & Associates, Inc.

iv

You should rely only on the information contained in this prospectus or any free-writing prospectus prepared by or on behalf of us in connection with this offering. 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 only 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          , 2008 (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.

References in this prospectus to “we,” “our,” “us” or like terms, when used in a historical context, refer to Resolute Holdings, LLC and its subsidiaries. When used in the present tense or prospectively, those terms refer to Resolute Energy Partners, LP and its subsidiaries. References to “Resolute Holdings” refer to Resolute Holdings, LLC and its subsidiaries, including Resolute Holdings Sub, LLC and its subsidiaries. References to “Resolute Aneth” refer to Resolute Aneth, LLC, an indirect wholly owned subsidiary of Resolute Holdings.

v

SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. 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 an initial public offering price of $20.00 per common unit and, unless otherwise noted, that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk Factors” beginning on page 20 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. Our proved reserve information as of June 30, 2007, is based on evaluations prepared by Resolute Holdings’ internal reservoir engineers and audited by Netherland, Sewell & Associates, Inc., independent petroleum engineers. A summary of our reserve report as of June 30, 2007, is included in this prospectus as Appendix C.

Resolute Energy Partners, LP

We are an independent oil and gas partnership engaged in the exploitation and development of our properties in the Greater Aneth Field, a mature, long-lived oil producing field located in the Paradox Basin on the Navajo Reservation in southeast Utah. The Greater Aneth Field was discovered in 1956 and was subsequently developed by several large integrated oil companies. It covers approximately 50,000 gross acres and is the largest oil field in the Paradox Basin. We own a majority of the working interests in, and are the operator of, three (out of a total of four) federal production units covering approximately 43,000 gross acres of the Greater Aneth Field. These units are the Aneth Unit, in which we own a 62% working interest, the McElmo Creek Unit, in which we own a 75% working interest, and the Ratherford Unit, in which we own a 59% working interest. We refer to these properties as our “Aneth Field Properties.” As of June 30, 2007, we had interests in and operated 402 gross (265 net) active producing wells and 335 gross (219 net) active water and carbon dioxide, or “CO₂,” injection wells on our Aneth Field Properties. The crude oil produced from our Aneth Field Properties is generally characterized as light, sweet crude oil that is highly desired as a refinery blending feedstock.

As of June 30, 2007, our estimated net proved reserves were approximately 78.1 MMBoe, of which approximately 38% were proved developed producing reserves and approximately 99% were oil. The standardized measure of our estimated net proved reserves as of June 30, 2007, was $1.16 billion. For additional information about the calculation of our standardized measure, please see “— Summary Historical Operating and Reserve Data.” We believe our Aneth Field Properties are well-suited for our partnership because they have relatively predictable production profiles based on a long history of production, a shallow expected annual decline rate of approximately 6% and a high reserves to production ratio. The following table sets forth summary information attributable to our estimated net proved reserves that is derived from our reserve report presented as of June 30, 2007, and audited by Netherland, Sewell & Associates, Inc., independent petroleum engineers. Reserves and production information is as of and for the periods indicated.

															Oil Reserves to
															Oil Production
	Estimated Net Proved Reserves as of June 30, 2007 (MMBoe)														Ratio (in years)
			Proved										Average				Proved
	Proved		Developed										Net Daily				Developed
	Developed		Non-		Proved Undeveloped						Total		Production		Proved		Producing
	Producing		Producing		CO2		Drilling		Total		Proved		(Boe/d)(1)		Reserves(2)		Reserves(3)
Aneth Unit		9.7		0.1		21.7		1.9		23.6		33.4		1,708		59		17
McElmo Creek Unit		13.8		0.1		7.6		0.6		8.2		22.1		2,481		25		15
Ratherford Unit		5.9		4.5		11.6		0.6		12.2		22.6		1,689		42		9
Total		29.4		4.7		40.9		3.1		44.0		78.1		5,878		39		15
Future development costs (in millions)(4)					$	209.1	$	50.4	$	259.5
Future development costs ($/Boe)(5)					$	5.11	$	16.26	$	5.90

(1) For the three months ended June 30, 2007.

1

(2)	Determined by dividing total estimated net proved oil reserves as of June 30, 2007, by oil production volumes for the three months ended June 30, 2007, on an annualized basis. The calculation of this ratio does not give effect to gas reserves or gas production.
(3)	Determined by dividing total estimated net proved developed producing oil reserves as of June 30, 2007, by oil production volumes for the three months ended June 30, 2007, on an annualized basis. The calculation of this ratio does not give effect to gas reserves or gas production.
(4)	Future development costs do not include $55.4 million of net capital expenditures that we had incurred since our acquisition of each of our Aneth Field Properties through June 30, 2007.
(5)	Determined by dividing our estimated total future development costs related to reserves classified as proved undeveloped by total estimated net proved undeveloped reserves as of June 30, 2007.

We acquired our Aneth Field Properties primarily through two significant acquisitions. We completed our first acquisition of properties in November 2004 from Chevron Corporation, which properties we refer to as the “Chevron Properties.” We completed our second acquisition of properties in April 2006 from Exxon Mobil Corporation, which properties we refer to as the “ExxonMobil Properties.” We acquired our Aneth Field Properties in connection with our strategic alliance with Navajo Nation Oil and Gas Company, Inc., or “NNOG,” an oil and gas company owned and operated by the Navajo Nation. NNOG owns a minority interest in each of the Chevron Properties and the ExxonMobil Properties and possesses options to purchase additional minority interests in those properties from us at fair market value if certain financial hurdles are met. See “Business — Relationship with the Navajo Nation” for additional information about our relationship with the Navajo Nation and NNOG’s purchase options.

Planned Operating and Development Activities

We have begun a program to increase production through the initiation, extension and expansion of CO₂ flood projects, the drilling of development wells, upgrades to field infrastructure, workovers of producing wells and recompletion of existing wells into new producing zones. According to our reserve report, at June 30, 2007, approximately 44 MMBoe of our estimated net proved reserves were classified as proved undeveloped, of which approximately 93% were attributable to recoveries associated with the expansions and extensions of the CO₂ flood projects that we have begun to implement. Our CO₂ flood projects involve extensions and expansions of a CO₂ flood project initiated in the McElmo Creek Unit in 1985 and a pilot CO₂ flood project initiated in the Aneth Unit in 1998. Following the initiation of the CO₂ flood program in the McElmo Creek Unit in 1985, oil production from the unit increased significantly over a period of 13 years before the unit returned to a state of naturally declining production in 1998. Because of the similar geological characteristics across our Aneth Field Properties, we expect to achieve similar results with our CO₂ flood projects as were experienced with the McElmo Creek Unit flood program.

We had incurred $28.4 million of capital expenditures through June 30, 2007, and we expect to incur an additional $209.1 million of capital expenditures over the next 20 years (including purchases of CO₂ under existing contracts), in connection with bringing those incremental proved undeveloped reserves attributable to our CO₂ flood projects into production. We have entered into two long-term CO₂ purchase contracts for substantially all of the CO₂ we expect to use in connection with our CO₂ flood projects. In order to further these CO₂ flood projects, we expect to incur approximately $62 million of these future capital expenditures during the second half of 2007 and all of 2008 and approximately $101 million of these future capital expenditures from 2009 through 2012. We expect these CO₂ flood projects to result in an average future development cost of approximately $5.11 per Boe. We currently estimate that these CO₂ flood projects, along with our other planned development activities, can in three years increase our average daily production by more than 50% over our current average daily production, following which we expect our rate of production to remain stable for approximately five years, then ultimately decline by approximately 6% per annum thereafter.

Hedging Activities

We have used, and we expect to continue to use, certain financial transactions, commonly referred to as hedges, to limit the volatility of our realized oil prices. As of June 30, 2007, we had in place oil hedges

2

covering approximately 67.1% of our anticipated oil production from proved developed producing reserves for the six months ending December 31, 2007, at a weighted average price of $71.76, approximately 62.7% of our anticipated oil production from proved developed producing reserves for 2008 at a weighted average price of $70.16 and approximately 51.5% of our anticipated oil production from proved developed producing reserves for 2009 through 2012 at a weighted average price of $63.07. For additional information about the hedges we have entered into, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk and Hedging Arrangements.”

Our Management and Natural Gas Partners

The founding members of our management team have experience in acquiring properties and managing operationally intensive oil and gas fields. Six members of our senior management who formed Resolute Holdings in 2004 previously worked together as part of the senior management team of HS Resources, Inc., an independent oil and gas company that was listed on the New York Stock Exchange and primarily operated in the Denver-Julesburg Basin in northeast Colorado. HS Resources conducted resource development programs, managed and enhanced a gas gathering and processing system and built a hydrocarbon physical marketing and transportation business. Its development activities included drilling new wells, deepening wells and recompleting and refracturing existing wells to add reserves and enhance production. HS Resources also had an active program of acquiring producing properties and properties with development potential. HS Resources was acquired by Kerr-McGee Corporation in 2001.

We are also supported by Natural Gas Partners, with which our senior management has had a relationship for more than 17 years. Natural Gas Partners VII, L.P. owns 70.1% of Resolute Holdings, which in turn will own a 65.0% limited partner interest in us, a 2.0% general partner interest in us and all of our incentive distribution rights. Two members of the board of directors of our general partner are members of the management of Natural Gas Partners. Since 1988, the Natural Gas Partners private equity funds have made investments in more than 110 entities in more than 140 transactions throughout the energy industry. Currently, these funds hold investments in more than 20 private oil and gas exploration and production companies with operations located in major producing basins throughout the United States. We believe that our relationship with Natural Gas Partners, and its experience investing in oil and gas companies, provides us with a number of benefits, including increased exposure to acquisition opportunities and access to a significant group of transactional and financial professionals who have experience in assisting the companies in which it has invested to meet their financial and strategic growth objectives. Although we may have the opportunity to make acquisitions as a result of our relationship with Natural Gas Partners, Natural Gas Partners has no legal obligation to offer any acquisition opportunities to us, may decide not to offer any acquisition opportunities to us and is not restricted from competing with us, and we cannot say which, if any, of such potential acquisition opportunities we would choose to pursue.

Our Business Strategies

Our primary business objective is to generate stable cash flow and pay quarterly cash distributions to our unitholders, with the potential to increase such quarterly cash distributions over time. We intend to accomplish this objective by executing the following business strategies:

•  bring currently proved undeveloped reserves into production;

•  increase production and improve operating efficiencies on our existing properties;

•  reduce commodity price risk through hedging;

•  maintain a disciplined financial policy; and

•  pursue acquisitions of mature properties with low-risk development potential.

3

Our Competitive Strengths

We believe we are well-positioned to execute our primary business objective because of the following competitive strengths:

•  a high quality base of long-lived oil producing properties;

•  properties with significant low-risk and low-cost development opportunities;

•  operating control over our properties;

•  experienced management team with operational, transactional and financial experience in the energy industry; and

•  our relationship with Natural Gas Partners.

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. You should read carefully the risks under the caption “Risk Factors” that begins on page 20 of this prospectus.

Management of Resolute Energy Partners, LP

Resolute Energy GP, LLC, our general partner, has direct responsibility for conducting our business and managing our operations, and the board of directors and officers of our general partner will make decisions on our behalf. The senior executives who currently manage our business will continue to manage us. Our operations will be conducted through, and our operating assets will be owned by, our operating subsidiaries. Upon the completion of this offering, we will own, directly or indirectly, all of the ownership interests in our operating subsidiaries. We, our subsidiaries and our general partner do not have employees.

Neither our general partner nor the board of directors of our general partner will be elected by our unitholders. References herein to the officers or directors of our general partner refer to the officers and directors of Resolute Energy GP, LLC. Please read “Management.”

Principal Executive Offices and Internet Address

Our principal executive offices are located at 1675 Broadway, Suite 1950, Denver, Colorado 80202 and our telephone number is(303) 534-4600. Our website is located at               and will be activated in connection with the completion of this offering. 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.

4

Our Partnership Structure and Formation Transactions

We are a Delaware limited partnership formed on September 13, 2007. The board of directors of our general partner has sole responsibility for conducting our business and managing our operations. Our operations will be conducted through, and our operating assets will be owned by, our operating company and its subsidiaries. At the closing of this offering, we will own, directly or indirectly, all of the ownership interests in our operating company and its sole subsidiary.

In connection with this offering, the following transactions will occur at or prior to closing:

•  Resolute Aneth will distribute $7.5 million of working capital to Resolute Holdings;

•  Resolute Holdings will contribute to Resolute Energy Operating, LLC all of Resolute Holdings’ interests in Resolute Aneth;

•  Resolute Holdings and our general partner will convey Resolute Energy Operating, LLC to us in exchange for 6,651,316 common units and 20,401,316 subordinated units, representing an aggregate 65.0% limited partner interest in us, a 2.0% general partner interest in us and all of our incentive distribution rights;

•  we will issue 13,750,000 common units to the public, representing an aggregate 33.0% limited partner interest in us, and will use the proceeds from this offering to repay all of the outstanding indebtedness under our existing revolving credit facility and a portion of the outstanding indebtedness under our existing term loan facility and to replenish the $7.5 million of working capital previously distributed to Resolute Holdings, as described above;

•  we will enter into a new revolving credit facility and will borrow approximately $152.7 million under that facility to repay all remaining outstanding indebtedness under our existing term loan facility; and

•  we will enter into an administrative services agreement with Resolute Holdings, our general partner and certain of their affiliates, pursuant to which we will agree to indemnify Resolute Holdings for certain liabilities arising after the closing of this offering and one of Resolute Holdings’ subsidiaries, Resolute Natural Resources Company, will operate our properties and perform administrative services for us such as accounting, marketing, corporate development, finance, land, legal and engineering in exchange for reimbursement from us.

If the underwriters exercise their option to purchase additional common units, we will use the net proceeds to repay a portion of the outstanding indebtedness that we intend to borrow under our new revolving credit facility.

5

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

Ownership of Resolute Energy Partners, LP

Publicly held common units	33.0	%
Common units held by Resolute Holdings	16.0	%
Subordinated units held by Resolute Holdings	49.0	%
General partner interest	2.0	%
Total	100.0	%

6

Summary of Conflicts of Interest and Fiduciary Duties

General.  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.” However, because our general partner is owned by Resolute Holdings, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to Resolute Holdings and its owners, including Natural Gas Partners. 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, including Natural Gas Partners, 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 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, 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 our units, which in turn has an effect on whether our general partner receives incentive cash distributions as discussed below. 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.”

Partnership Agreement Modifications to Fiduciary Duties.  Our partnership agreement limits the liability and reduces the fiduciary duties our general partner owes to holders of our common units and subordinated units, which may permit it to favor its own interests to your detriment. 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. Our partnership agreement also provides that Resolute Holdings and its affiliates, including Natural Gas Partners, are not restricted from competing with us. By purchasing a common unit, you agree 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. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties” for a more detailed description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to unitholders.

For a description of our other relationships with our affiliates, please read “— The Offering” and “Certain Relationships and Related Party Transactions.”

Our General Partner’s Right to Receive Incentive Distributions

In addition to its 2% general partner interest, our general partner holds 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 (up to 48%) as higher target distribution levels of cash are distributed to our unitholders. For a more detailed description of the incentive distribution rights, please read “— The Offering” and “Provisions of Our Partnership Agreement Relating to Cash Distributions — Incentive Distribution Rights.”

7

The Offering

Common units offered to the public	13,750,000 common units.
	15,812,500 common units, if the underwriters exercise in full their option to purchase additional common units.
Units outstanding after this offering	20,401,316 common units and 20,401,316 subordinated units, each representing 49% limited partner interests in us.
Use of proceeds	We intend to use the net proceeds of approximately $257.1 million from this offering, after deducting underwriting discounts and a structuring fee but before paying offering expenses, to:
	• pay approximately $3.4 million of expenses associated with the offering and related formation transactions;
	• replenish approximately $7.5 million of working capital previously distributed to Resolute Holdings prior to the closing of this offering;
	• repay all of the outstanding indebtedness under our existing revolving credit facility of approximately $173.9 million; and
	• repay approximately $72.3 million of the outstanding indebtedness under our existing term loan facility.
	Affiliates of UBS Securities LLC and Wachovia Capital Markets, LLC are lenders under our existing revolving credit facility and, accordingly, will receive a portion of the proceeds from this offering. Please read “Underwriting — Relationships/NASD Conduct Rules.”
	We also anticipate that we will borrow approximately $152.7 million of indebtedness under our new revolving credit facility upon the closing of this offering, and we intend to use the net proceeds from such borrowings to repay the remaining balance under our existing term loan facility. Please read “Use of Proceeds.”
	If the underwriters exercise their option to purchase additional common units, we will use the net proceeds to repay a portion of the outstanding indebtedness that we intend to borrow under our new revolving credit facility.
Cash distributions	We intend to make minimum quarterly distributions of $0.35 per unit per quarter ($1.40 per unit on an annualized basis) to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses. Our ability to pay cash distributions at this minimum quarterly 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.

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	We expect to pay a prorated distribution for the first quarter during which we are a publicly traded partnership. Assuming that we become a publicly traded partnership before March 31, 2008, we will pay unitholders a prorated distribution for the period from the first day our common units are publicly traded to and including March 31, 2008. We expect to pay this cash distribution on or before May 15, 2008.
	We will distribute our available cash 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 $0.35 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 $0.35;
	• third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.4025;
	• fourth, 85% to all unitholders, pro rata, and 15% to our general partner, until each unit has received a distribution of $0.4375;
	• fifth, 75% to all unitholders, pro rata, and 25% to our general partner, until each unit has received a distribution of $0.525; and
	• thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.
	The amount of pro forma available cash generated during the year ended December 31, 2006, and the twelve months ended June 30, 2007, would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units and 69.7% and 78.5%, respectively, of the minimum quarterly distribution on our subordinated units during those periods (69.2% and 78.0%, respectively, assuming the underwriters exercise in full their option to purchase additional common units). Please read “Our Cash Distribution Policy and Restrictions on Distributions.”
	We believe that we will have sufficient cash available for distribution to make cash distributions for the four quarters ending December 31, 2008, at the minimum quarterly distribution rate of $0.35 per unit per quarter ($1.40 per unit on an annualized basis) on all common units and subordinated units. Please read “Our Cash Distribution Policy and Restrictions on Distributions — Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2008.”
Subordinated units	Resolute Holdings 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 $0.35 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.

9

	The subordination period generally will end if we have earned and paid from operating surplus at least $1.40 on each outstanding common unit and subordinated unit and the related distributions on our general partner’s 2% general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2012. The subordination period may also end on or after December 31, 2010, if certain financial tests are met as described below, but the subordination period will not end prior to December 31, 2010, under any circumstances, except 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.
Early conversion of subordinated units	If we have earned and paid from operating surplus at least $1.40 on each outstanding common unit and subordinated unit and the related distributions on our general partner’s 2% general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2010, 25% of the subordinated units will convert into common units at the end of such period. In addition, if we have earned and paid from operating surplus at least $1.40 on each outstanding common unit and subordinated unit and the related distributions on our general partner’s 2% general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2011, an additional 25% of the subordinated units will convert into common units at the end of such period. The early conversion of the second 25% of the subordinated units may not occur until at least one year after the early conversion of the first 25% of the subordinated units.
	In addition to the early conversion described above, if we have earned and paid from operating surplus at least $2.10 (150% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the related distributions on our general partner’s 2% general partner interest for any two consecutive, non-overlapping four quarter periods ending on or after December 31, 2010, all of the outstanding subordinated units will convert into common units at the end of such period.
Issuance of additional units	We can issue an unlimited number of units, including units that are senior to the common 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 not have the 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

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	this offering, our general partner and its affiliates will own an aggregate of 66.3% 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. Please read “The Partnership Agreement — Limited Call Right.”
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, 2010, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.40 per unit, we estimate that your average allocable federal taxable income per year will be no more than $      per unit. Please read “Material Tax Consequences — Tax Consequences of Common 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.”
Agreement to be bound by the partnership agreement	By purchasing a common unit, you will become a limited partner and be bound by all of the terms of our partnership agreement.
Proposed exchange listing and trading symbol	We intend to apply to list the common units on the New York Stock Exchange under the symbol “REN.”

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Summary Historical and Pro Forma Financial Data

The following table presents summary historical financial data of the Chevron Properties and summary consolidated and combined historical financial data of Resolute Natural Resources Company, WYNR, LLC, BWNR, LLC and Resolute Aneth, each of which are subsidiaries of Resolute Holdings and are collectively referred to in this prospectus as “Resolute Energy Partners Predecessor,” and summary pro forma financial data of Resolute Energy Partners, LP. In addition, because they are considered a predecessor to Resolute Energy Partners Predecessor, we include statements of revenue and direct operating expenses for the Chevron Properties covering the eleven-month period ended November 30, 2004.

The summary historical financial data have been prepared on the following basis:

•  the historical financial information of the Chevron Properties for the eleven-month period ended November, 30, 2004, the date on which we acquired the Chevron Properties, was derived from audited statements of revenue and direct operating expenses related to the Chevron Properties;

•  the historical consolidated and combined financial information of Resolute Energy Partners Predecessor as of December 31, 2004, and for the period from Inception (January 22, 2004) to December 31, 2004, and as of and for the years ended December 31, 2005 and 2006, have been derived from the audited financial statements of Resolute Energy Partners Predecessor; and

•  the historical financial information of Resolute Energy Partners Predecessor as of and for the six months ended June 30, 2006 and 2007, have been derived from the unaudited historical financial statements of Resolute Energy Partners Predecessor.

The historical financial information covering the Chevron Properties does not include depreciation, depletion and amortization expense, corporate overhead expenses, income taxes and other non-operating expenses incurred by Chevron during the period presented. This information is not available to us. Furthermore, it is our belief that these corporate-level expenses incurred by a major integrated oil company are not comparable to corporate-level expenses that would be incurred by a much smaller company like ours.

The summary pro forma financial data for the year ended December 31, 2006, and as of and for the six months ended June 30, 2007, set forth in the following table are derived from the unaudited pro forma financial statements of Resolute Energy Partners, LP included elsewhere in this prospectus. The historical combined financial statements of Resolute Energy Partners Predecessor include the results of two exploration companies, WYNR, LLC and BWNR, LLC, and one operating company, Resolute Natural Resources Company, that are owned by Resolute Holdings and that we collectively refer to in this prospectus as the “Retained Subsidiaries.” The two exploration companies hold oil and gas leases with no reserves or production attributable to them and have conducted very little activity since their organization. The operating company holds no oil or gas leases. The Retained Subsidiaries will not be contributed to us in connection with the closing of this offering. The pro forma statements of operations for the year ended December 31, 2006, and as of and for the six months ended June 30, 2007, have been prepared to reflect the elimination, as of January 1, 2006, of the Retained Subsidiaries from the combined financial information of Resolute Energy Partners Predecessor. The pro forma balance sheet as of June 30, 2007, has been prepared to reflect this same elimination as though it occurred on June 30, 2007. The unaudited pro forma financial statements of Resolute Energy Partners, LP give pro forma effect to the following significant transactions:

•  our acquisition of the ExxonMobil Properties as though that acquisition had occurred on January 1, 2006, in the case of the statements of operations, or as of June 30, 2007, in the case of the balance sheet;

•  the retention by Resolute Holdings of the Retained Subsidiaries and the distribution by Resolute Aneth of $7.5 million of working capital to Resolute Holdings;

•  the contribution by Resolute Holdings to Resolute Energy Operating, LLC of Resolute Aneth, and the contribution to us of Resolute Energy Operating, LLC by Resolute Holdings and our general partner in exchange for our issuance of 6,651,316 common units and 20,401,316 subordinated units, representing

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a 65% limited partner interest in us, a 2% general partner interest in us and all of our incentive distribution rights;

•  our sale of 13,750,000 common units to the public;

•  the use of the proceeds from this offering to repay all of the outstanding indebtedness under our existing revolving credit facility, which we expect to be approximately $1.7 million more than the outstanding balance as of June 30, 2007, and a portion of the outstanding indebtedness under our existing term loan facility and to replenish the $7.5 million of working capital previously distributed to Resolute Holdings, as described above; and

•  our borrowing of $151.0 million of indebtedness under our new revolving credit facility to repay the remaining balance under our existing term loan facility.

The summary pro forma financial data should not be considered as indicative of the historical results we would have had or the results we will have after this offering. You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical consolidated and combined financial statements of Resolute Energy Partners Predecessor and notes thereto, the unaudited pro forma consolidated financial statements of Resolute Energy Partners, LP and notes thereto and the audited statements of revenues and direct operating expenses of the Chevron Properties and the ExxonMobil Properties included elsewhere in this prospectus. Among other things, the historical and pro forma financial statements include more detailed information regarding the basis of presentation for the following information. In addition, the pro forma financial information does not include the estimated $3.1 million of annual incremental general and administrative expenses that we expect to incur as a result of being a publicly traded partnership.

The following table includes Adjusted EBITDA, which is a financial measure not calculated in accordance with generally accepted accounting principles, or “GAAP.” We explain this measure below and reconcile it to the most directly comparable financial measures calculated and presented in accordance with GAAP. Please read “— Non-GAAP Financial Measures.”

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																		Pro Forma
	Chevron		Resolute Energy Partners Predecessor															Resolute Energy
	Properties		January 22,															Partners, LP
	Eleven Months		2004																		Six Months
	Ended		(Inception) to			Year Ended						Six Months Ended						Year Ended			Ended
	November 30,		December 31,			December 31,						June 30,						December 31,			June 30,
	2004		2004(1)			2005			2006(2)			2006(2)			2007			2006			2007
	(In thousands)
Statements of Operations Data:
Revenues:
Oil	$	27,370	$	2,468		$	39,198		$	102,000		$	40,090		$	57,646		$	120,167		$	57,646
Gas(3)		257		(179	)		681			836			331			242			851			242
Other		—		101			2,094			3,735			1,350			2,371			4,516			2,371
Total revenues		27,627		2,390			41,973			106,571			41,771			60,259			125,534			60,259
Operating expenses:
Lease operating(4)		6,526		658			8,734			24,857			9,405			16,507			27,181			16,507
Workover		—		21			3,860			13,312			4,437			5,700			14,351			5,700
Production taxes		2,972		340			2,772			7,806			3,062			4,536			9,279			4,536
General and administrative(4)		—		2,415			3,281			6,015			2,172			34,617			5,613			32,960
Depletion, depreciation, and amortization		—		407			4,680			11,071			4,140			7,915			12,150			7,641
Accretion of asset retirement obligations		—		20			216			206			95			145			222			145
Total operating expenses		9,498		3,861			23,543			63,267			23,311			69,420			68,796			67,489
Operating income (loss)	$	18,129		(1,471	)		18,430			43,304			18,460			(9,161	)		56,738			(7,230	)
Other income (expense):
Other income				51			147			546			262			266			361			216
Gain (loss) on derivative instruments				3,592			(28,852	)		10,895			(24,569	)		(19,541	)		10,895			(19,541	)
Interest expense				(190	)		(2,545	)		(18,121	)		(6,149	)		(12,545	)		(9,760	)		(4,810	)
Total other income (expense)				3,453			(31,250	)		(6,680	)		(30,456	)		(31,820	)		1,496			(24,135	)
Income (loss) before income taxes				1,982			(12,820	)		36,624			(11,996	)		(40,981	)		58,234			(31,365	)
Income tax provision				(742	)		(3,830	)		—			—			—			—			—
Net income (loss)			$	1,240		$	(16,650	)	$	36,624		$	(11,996	)	$	(40,981	)	$	58,234		$	(31,365	)
Net income per limited partners’ unit																		$	1.40		$	(0.75	)
Other Financial Data (unaudited):
Adjusted EBITDA			$	(784	)	$	17,780		$	52,546		$	20,254		$	33,963		$	67,075		$	34,212
Balance Sheet Data (at period end):
Working capital			$	530		$	(1,862	)	$	(6,939	)	$	(11,910	)	$	(7,477	)				$	(2,762	)
Total assets				97,498			106,563			376,733			357,381			445,559						425,331
Long-term debt				44,000			45,925			267,500			271,350			395,250						150,975
Shareholder’s/Member’s/Partners’ equity (deficit)(5)				44,997			28,698			61,860			15,163			(45,008	)					185,367
Cash Flow Data:
Net cash provided by (used in):
Operating activities			$	(2,225	)	$	11,516		$	31,756		$	(5,296	)	$	16,694
Investing activities				(84,541	)		(14,402	)		(242,388	)		(225,324	)		(45,560	)
Financing activities				87,377			2,275			214,323			220,416			25,175

(1)	Includes the results of operations of the Chevron Properties for the period beginning on the date of acquisition, November 30, 2004.
(2)	Includes the results of operations of the ExxonMobil Properties for the period beginning on the date of acquisition, April 14, 2006.
(3)	We acquired the Chevron Properties on November 30, 2004. In conjunction with the revenue distribution for plant operations during December 2004, our proceeds were adjusted for the recovery of gas imbalances related to differences between our equity gas produced and our gas plant entitlements, which resulted in us recognizing gas revenues of $(179,000) during the period January 22, 2004 (Inception) to December 31, 2004.
(4)	During the six months ended June 30, 2007, general and administrative expense included a non-cash charge to compensation expense of $32.4 million associated with equity-based compensation recognized during the period pursuant to statement of accounting standards No. 123R “Share - Based Payment,” which

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we refer to as “FAS 123R.” This non-cash charge relates to incentive compensation provisions in the operating agreement between Natural Gas Partners and management. In June 2007, Resolute Holdings made a $100.0 million cash distribution to its members that met a financial requirement for a portion of management’s incentive compensation units to vest, triggering this compensation expense. Please read “Note 4 — Shareholder’s/Member’s Equity (Deficit)” to the unaudited condensed combined financial statements of Resolute Energy Partners Predecessor atF-49. An additional $0.3 million non-cash charge was allocated to lease operating expense related to the same equity-based compensation.

(5) In June 2007, Resolute Holdings made a $100.0 million cash distribution to its members. This distribution represented a return on equity and consequently is reflected in our financial statements by a similar reduction to our Shareholder’s/Member’s/Partners’ equity (deficit) as of June 30, 2007.

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Non-GAAP Financial Measures

We include in this prospectus the non-GAAP financial measure Adjusted EBITDA. Below, we explain this non-GAAP financial measure and provide a reconciliation of it to its most directly comparable financial measures as calculated and presented in accordance with GAAP.

We define Adjusted EBITDA as net income plus net interest expense, income taxes, depletion, depreciation and amortization, amortization of deferred financing costs, accretion of asset retirement obligation, change in fair value of derivative instruments and non-cash equity-based compensation expense. This definition is consistent with the definition of EBITDA in our existing credit agreements, and we anticipate that it will be incorporated into our new revolving credit facility.

Adjusted EBITDA is used as a supplemental liquidity measure by our management 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 capital expenditures.

Adjusted EBITDA is also a financial measure that we expect will be reported to our lenders and used as a gauge for compliance with some of our anticipated financial covenants under our new revolving credit facility.

Adjusted EBITDA is also used as a supplemental performance measure by our 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;

•  our operating performance and return on capital as compared to those of other companies in the exploration and production industry, without regard to financing methods or capital structure; and

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

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. Adjusted EBITDA does not include interest expense, income taxes or depreciation, depletion 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 gross margins. Because we use capital assets, depreciation, depletion and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and our liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income, operating income and net cash provided by operating activities and these measures may vary among companies. Our Adjusted EBITDA may not be comparable to Adjusted EBITDA or EBITDA of another company because other entities may not calculate these measures in the same manner.

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

																Pro Forma
	Resolute Energy Partners Predecessor															Resolute Energy
	January 22,															Partners, LP
	2004																		Six Months
	(Inception) to			Year Ended						Six Months Ended						Year Ended			Ended
	December 31,			December 31,						June 30,						December 31,			June 30,
	2004			2005			2006			2006			2007			2006			2007
Net income (loss)	$	1,240		$	(16,650	)	$	36,624		$	(11,996	)	$	(40,981	)	$	58,234		$	(31,365	)
Interest expense		190			2,545			18,121			6,149			12,545			9,760			4,810
Income taxes		742			3,830			—			—			—			—			—
Depreciation, depletion and amortization		407			4,680			11,071			4,140			7,915			12,150			7,641
Accretion of asset retirement obligation		20			216			206			95			145			222			145
Non-cash change in fair value of derivatives		(3,383	)		23,159			(13,291	)		21,930			21,874			(13,291	)		21,882
Non-cash equity-based compensation expense		—			—			—			—			32,663			—			31,099
Other		—			—			(185	)		(64	)		(198	)		—			—
Adjusted EBITDA	$	(784	)	$	17,780		$	52,546		$	20,254		$	33,963		$	67,075		$	34,212
Less:
Cash interest expense		190			2,442			17,644			6,000			12,218
Income taxes		—			4,572			—			—			—
Change in operating assets and liabilities		1,251			(750	)		3,146			8,958			5,051
Net cash provided by (used in) operating activities	$	(2,225	)	$	11,516		$	31,756		$	5,296		$	16,694

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Summary Historical Operating and Reserve Data

The following table shows operating data for the periods indicated. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business — Estimated Net Proved Reserves” and “Business — Production and Price History” in evaluating the data presented below and the data presented in the table on the following page.

														Pro Forma
	Chevron		Resolute Energy Partners Predecessor											Resolute Energy
	Properties		January 22,											Partners, LP
	Eleven Months		2004													Six Months
	Ended		(Inception) to							Six Months Ended				Year Ended		Ended
	November 30,		December 31,			Year Ended December 31,				June 30,				December 31,		June 30,
	2004		2004(1)			2005		2006(2)		2006(2)		2007		2006(3)		2007
Production Sales Data:
Oil (MBbl)		731		60			720		1,588		606		973		1,881		973
Gas (MMcf)(4)		470		(11	)		136		227		81		92		259		92
Natural gas liquids (MBbl)		—		1			56		91		33		58		111		58
Equivalent volumes (MBoe)		810		59			799		1,717		653		1,046		2,035		1,046
Daily equivalent volumes (Boe/d)		2,425		1,922			2,189		4,704		3,608		5,779		5,575		5,779
Average Realized Prices:
Oil ($/Bbl)	$	34.12	$	44.62		$	46.53	$	62.72	$	61.80	$	61.64	$	62.48	$	61.64
Gas ($/Mcf)		5.69		—			5.01		3.68		4.09		2.63		3.29		2.63
Natural gas liquids ($/Bbl)		—		20.00			20.02		33.05		30.36		32.07		32.77		32.07
Other Operating Data:
Lease operating expenses ($/Boe)	$	8.06	$	11.15		$	10.93	$	14.48	$	14.40	$	15.78	$	13.36	$	15.78
Workover expenses ($/Boe)		—		0.36			4.83		7.75		6.79		5.45		7.05		5.45
Production taxes ($/Boe)		3.67		5.76			3.47		4.55		4.69		4.34		4.56		4.34

(1)	Includes the operating data of the Chevron Properties for the period beginning on the date of acquisition, November 30, 2004.
(2)	Includes the operating data of the ExxonMobil Properties for the period beginning on the date of acquisition, April 14, 2006.
(3)	The pro forma operating data for the year ended December 31, 2006, include the operating data of the ExxonMobil Properties as though such acquisition had been completed on January 1, 2006.
(4)	We acquired the Chevron Properties on November 30, 2004. In conjunction with the revenue distribution for plant operations during December 2004, our proceeds were adjusted for the recovery of gas imbalances related to differences between our equity gas produced and our gas plant entitlements, which resulted in us recognizing gas production of (11) MMcf during the period January 22, 2004 (Inception) to December 31, 2004.

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The following table presents our estimated net proved oil and gas reserves and the standardized measure of our estimated net proved reserves as of December 31, 2004, 2005 and 2006, and as of June 30, 2007. The data as of December 31, 2004 and 2005 are based on reports prepared by us and audited by Sproule Associates Inc., independent petroleum engineers. The data as of December 31, 2006, and June 30, 2007, are based on reports prepared by us and audited by Netherland, Sewell & Associates, Inc., independent petroleum engineers. The standardized measure values shown in the table are not intended to represent the current market value of our estimated net proved oil and gas reserves. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC.

										As of
	As of December 31,									June 30,
	2004			2005			2006(1)			2007
Estimated total proved reserves:
Oil (MBbl)		17,827			23,500			78,357			77,792
Gas (MMcf)		2,404			3,750			1,890			1,630
Total (MBoe)		18,228			24,125			78,672			78,064
% Proved developed		67	%		59	%		42	%		44	%
Standardized measure (in millions)(2)(3)	$	199.3		$	325.2		$	978.3		$	1,159.3

(1)	Includes the ExxonMobil Properties acquired on April 14, 2006.
(2)	Standardized measure is the estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of the estimate), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Our standardized measure as of December 31, 2006, and June 30, 2007, does not reflect any future federal income tax expenses because we were not subject to federal income taxes as of those dates. Standardized measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk.”
(3)	In accordance with SEC requirements, our estimated net proved reserves and standardized measure were determined using end of the period prices for oil and gas that were realized as of the date set forth below. The reserves estimates utilized year-end NYMEX posted prices for oil for the dates presented, NYMEX Henry Hub posted prices for gas as of December 31, 2004, 2005 and 2006, and the El Paso San Juan Basin posted price for gas as of June 30, 2007, as shown below, but in each case as adjusted for location differentials as of the effective date of the report, as well as plant fees and Btu content.

							As of
	As of December 31,						June 30,
	2004		2005		2006		2007
Oil ($/Bbl)	$	43.45	$	61.06	$	61.05	$	70.68
Gas ($/MMBtu)		6.15		9.52		5.64		6.12

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RISK FACTORS

The nature of our business activities subjects us to certain hazards and risks. Additionally, limited partner interests are inherently different from the 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.

The risk factors set forth below are not the only risks that may affect our business. Our business could also be affected by additional risks not currently known to us or that we currently deem to be immaterial. 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 flow from operations to enable us to pay the minimum quarterly distribution to our common units following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates.

We may not have sufficient available cash from operations each quarter to enable us to pay our unitholders all or part of the minimum quarterly distribution per common unit. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve that our general partner establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. We intend to reserve a substantial portion of our cash generated from operations to develop our oil and gas properties and to acquire additional oil and gas properties and related assets in order to maintain and grow our level of production and reserves.

The amount of cash we actually generate will depend upon numerous factors related to our business that may be beyond our control, including:

•  the amount of oil we produce;

•  the price at which we sell our oil production;

•  the effectiveness of our commodity price hedging strategy;

•  the development of oil wells and proved undeveloped properties and the success of our enhanced oil recovery activities;

•  the level of our operating and general and administrative costs, including the reimbursement of expenses to our general partner;

•  our ability to replace produced reserves;

•  prevailing economic conditions; and

•  government regulation and taxation.

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 our capital expenditures to implement our development projects and make acquisitions of additional reserves;

•  our ability to borrow under our revolving credit facility to pay distributions;

•  our debt service requirements and restrictions on distributions that will be contained in our revolving credit facility or future debt agreements;

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•  fluctuations in our working capital needs;

•  timing and collectibility of receivables; and

•  the amount of cash reserves, which we expect to be substantial, established by our general partner for the proper conduct of our business.

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.”

On a pro forma basis, we would not have had sufficient cash available for distribution to pay the minimum quarterly distribution on all units for the year ended December 31, 2006 and the twelve months ended June 30, 2007.

The amount of available cash we need to pay the minimum quarterly distribution for four quarters on all of our common units and subordinated units to be outstanding immediately after this offering and the related distributions on our general partner’s 2% general partner interest is approximately $58.3 million (approximately $61.2 million if the underwriters exercise in full their option to purchase additional common units). The amount of our available cash generated during the year ended December 31, 2006 and the twelve months ended June 30, 2007, would have been sufficient to pay all of the minimum quarterly distribution on our common units, but only 69.7% and 78.5%, respectively, of the minimum quarterly distribution on our subordinated units (69.2% and 78.0%, respectively, assuming the underwriters exercise in full their option to purchase additional common units). Further, we may not generate sufficient cash flow to make actual cash distributions. For a calculation of an estimate of our ability to make distributions to unitholders based on our pro forma results for the year ended December 31, 2006, and the twelve months ended June 30, 2007, please read “Cash Distribution Policy and Restrictions on Distributions.”

Our estimate of pro forma cash available for distribution is based on assumptions that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.

Our estimate of the minimum Adjusted EBITDA necessary for us to pay the minimum quarterly distribution on all of our common and subordinated units and the related distributions on our general partner’s 2% general partner interest for each of the four quarters ending December 31, 2008, as set forth in “Our Cash Distribution Policy and Restrictions on Distributions,” is based on our management’s calculations, and we have not received an opinion or report on it from any independent accountants. This estimate is based on assumptions, including production quantities, and in particular the production response to our expanded CO₂ floods, oil and gas prices, hedging activities, expenses, borrowings and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. If any of these assumptions proves to have been inaccurate, our actual results may differ materially from those set forth in our estimates, and we may be unable to pay all or part of the minimum quarterly distribution on our common or subordinated units and the market price of our common units may decline.

We may not make cash distributions during periods in which we record net income.

The amount of cash we have available for distribution depends primarily on our cash flow, including cash from financial reserves and working capital or other borrowings, 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 and may not make cash distributions during periods when we record net income.

We will require substantial capital expenditures to replace our production and reserves, which will reduce our cash available for distribution.

Our exploitation and development program and acquisitions of additional reserves will require us to use cash generated from our operations, additional borrowings or the proceeds from the issuance of additional

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partnership interests, or some combination thereof, which could limit our ability to pay distributions at the then current distribution rate. For example, we expect to spend an additional $209 million of capital expenditures over the next 20 years (including CO₂ purchases) to implement our CO₂ flood projects. In order to further these CO₂ flood projects, we expect to incur approximately $62 million of these future capital expenditures during the second half of 2007 and all of 2008 and approximately $101 million of these future capital expenditures from 2009 through 2012. To the extent our production and reserves decline faster than we anticipate, we will require a greater amount of capital to maintain our production. The use of cash generated from operations to fund development and acquisition activities will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering, the covenants in our new revolving credit facility or future debt agreements, adverse market conditions or other contingencies and uncertainties that are beyond our control. Our failure to obtain the funds necessary for future exploitation, development and acquisition activities could materially affect our business, results of operations, financial condition and ability to pay distributions. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution, thereby increasing the aggregate amount of cash required to maintain the then current distribution rate, which could have a material adverse effect on our ability to pay distributions at the then current distribution rate.

A significant part of our development plan involves the implementation of our CO₂ projects. These projects are subject to numerous uncertainties and may be less successful than planned.

Producing oil and gas reservoirs are depleting assets generally characterized by declining production rates that vary depending upon factors such as reservoir characteristics. A significant part of our business strategy depends on our ability to successfully implement the CO₂ floods and other development projects we have planned for our Aneth Field Properties in order to counter the natural decline in production from the field. As of June 30, 2007, approximately 56% of our estimated net proved reserves were classified as proved undeveloped, meaning we must undertake additional development activities before we can produce those reserves. These development activities involve numerous risks, and their ultimate success depends on our ability to allocate capital resources to these projects, to obtain access to equipment, to successfully implement these projects and on production being at the levels we anticipate. If our development projects are not successful or are significantly delayed, production from our Aneth Field Properties will decrease at a rate that is faster than we currently anticipate, and we may not have sufficient cash available to pay distributions at the minimum quarterly distribution rate or at all. In addition, if our development projects are not successful, we will be required to write-down the value of our reserves, which will limit our borrowing capacity and our access to liquidity and we may be forced to use available cash to pay down debt.

A critical part of our development strategy depends upon our ability to purchase CO₂. If we are not able to purchase CO₂ in the quantities we desire, our development projects and the resulting expected incremental production will be delayed or may not be realized at all. Our ability to purchase CO₂ could be negatively affected for a number of reasons, including because our suppliers of CO₂ are unable to deliver CO₂ or because of temporary or permanent shut-ins of the pipeline that will deliver our CO₂. One of our suppliers has notified us that it may experience constraints on its delivery capacity. If we are not able to obtain CO₂ and undertake our development projects, the expected decline in the rate of production from our Aneth Field Properties will be accelerated, and we will not recover as much production as we currently anticipate.

In addition, the results we obtain from our CO₂ flood projects may not be the same as we expected when preparing our estimate of net proved reserves. Lower than expected production results or delays in when we first realize additional production as a result of our CO₂ flood projects will reduce the value of our reserves, which could reduce our ability to incur indebtedness and require us to use cash to repay indebtedness. Therefore, our future reserves and production and our future cash flow and ability to make cash distributions are highly dependent on our success in efficiently developing and exploiting our current estimated net proved undeveloped reserves.

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We depend on one customer for all of our sales of crude oil production. Furthermore, we operate in a remote location and do not readily have access to markets for our crude oil production other than our current customer. The loss of that customer for any reason or the failure of that customer to pay for the crude oil we have delivered for sale could have a material adverse effect on our financial results and ability to make cash distributions to our unitholders.

We operate in southeastern Utah, and currently we sell all of our crude oil production to a single customer, Giant Industries, Inc. Giant was acquired by and became a subsidiary of Western Refining, Inc. in May 2007. Our crude oil production is transported to a terminal that serves Giant’s two refineries in the region via a crude oil pipeline owned by NNOG. This pipeline currently does not connect with any other interstate crude oil pipelines, and there are no other interstate crude oil pipelines within close proximity of our Aneth Field Properties.

Our production is sold to Giant pursuant to two contracts, each covering about one-half of our production and each with a six-month term that commenced on June 1, 2007. The two contracts contain evergreen provisions that provide for Giant to continue to purchase the production on a month-to-month basis on the same economic terms. After November 30, 2007, Giant has the right to terminate our contracts upon 180 days notice and cease purchasing crude oil from us. If this happens and we are not able to negotiate a new contract with Giant or if Giant ceases to purchase our crude oil production, we will need to find an alternative market for our production.

In addition, if Giant’s refining capacity in the region is temporarily or permanently shut-down for any reason or if our pipeline to Giant’s refineries is temporarily or permanently shut-in for any reason, we will have to find an alternative market for our production. If we are compelled to sell our crude oil to an alternative market, we will incur significantly increased costs associated with the transportation of our production to that market compared to our current costs to sell to Giant through the pipeline we currently use. An increase in these costs could materially and negatively affect our income and cash available for distribution.

We cannot be certain that our commercial relationship with Giant will continue for the indefinite future and we cannot be certain that Giant’s refineries will not suffer material down-time. We also do not know if or how the acquisition of Giant by Western will affect the marketing of our production.

We customarily ship crude oil to Giant daily and receive payment on the twentieth day of the month following the month of production. As a result, at any given time, we have significant amounts of accounts receivable outstanding from Giant. As of June 30, 2007, we recorded $14.1 million of accounts receivable from Giant. If Giant defaults on its obligation to pay us for the crude oil we have delivered, our income and cash available for distribution would be materially and negatively affected. Both Moody’s Investor Services and Standard & Poor’s have assigned Western credit ratings that are below investment grade.

Oil prices are currently at historically high levels and are very volatile. A decline in commodity prices will cause a decline in our cash flow from operations, which may force us to reduce our distributions or cease paying distributions altogether.

The oil markets are highly volatile, and we cannot predict future oil prices. Oil prices have recently been at historically high levels. Prices for oil may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

•  domestic and foreign supply of and demand for oil, including as a result of technological advances affecting energy consumption and supply;

•  weather conditions;

•  overall domestic and global political and economic conditions;

•  actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

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•  domestic and foreign governmental regulations and taxation;

•  the impact of energy conservation efforts;

•  the capacity, cost and availability of oil pipelines and other transportation facilities, and the proximity of these facilities to our wells;

•  the availability of refining and processing capability; and

•  the price and availability of alternative fuels.

In the past, the price of oil has been extremely volatile, and we expect this volatility to continue. For example, during the six months ended June 30, 2007, the NYMEX oil price ranged from a high of $70.68 per Bbl to a low of $50.48 per Bbl. For the five years ended December 31, 2006, the NYMEX oil price ranged from a high of $77.03 per Bbl to a low of $17.97 per Bbl.

A drop in commodity prices can significantly affect our financial results and impede our growth. At the present time we produce very little gas, although at some future time we could acquire gas properties. If that were to occur, we would be susceptible to similar volatility in gas prices. In particular, declines in commodity prices:

•  will reduce the amount of cash flow available to pay distributions to unitholders, to develop our properties, to drill additional wells or to make acquisitions;

•  will reduce the value of our reserves, because declines in oil prices would reduce the amount of oil that we can produce economically and will reduce the expected amount of future cash flow from our properties; and

•  may cause us to reduce our reserves, which could reduce the amount we can borrow under our new revolving credit facility and otherwise limit our ability to borrow money or raise additional capital.

If we raise our distribution levels in response to increased cash flow during periods of relatively high commodity prices, we may not be able to sustain those distribution levels during subsequent periods of lower commodity prices.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities of our proved reserves.

It is not possible to measure underground accumulations of oil or gas in an exact way. Oil and gas reserve engineering requires subjective estimates of underground accumulations of oil and gas and assumptions concerning future oil and gas prices, production levels and operating and development costs. Over time, we may make material changes to reserves estimates to take into account changes in our assumptions and the results of our development activities and actual drilling and production. In estimating our level of oil and gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to an unescalated level of future oil and gas prices and capital, operating and development costs; future production levels; the level of capital expenditures, operating and development costs; the effects of regulation; and the availability of funds.

If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly. In addition, if declines in oil and gas prices result in our having to make substantial downward adjustments to our estimated proved reserves, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to make downward adjustments, as a non-cash impairment charge to earnings, to the carrying value of our oil and gas properties. If we incur impairment charges in the future, it could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our revolving credit facility, which in turn may adversely affect our ability to make cash distributions to our unitholders.

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The standardized measure of future net cash flows from our net proved reserves is based on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserves estimates or underlying assumptions will materially affect the quantities and present value of our proved reserves.

Our standardized measure values are calculated using oil and gas prices that are not adjusted to give effect to our derivative financial instruments and are determined in accordance with the rules and regulations of the SEC. The present value of future net cash flows from our estimated net proved reserves is not necessarily the same as the current market value of our estimated net proved oil and gas reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate. For example, if crude oil prices as of June 30, 2007, were $5.00 per barrel less than they actually were as of that same date, the standardized measure of our estimated net proved reserves as of that same date would have decreased by approximately $120 million.

Actual future net cash flows from our oil and gas properties also will be affected by factors such as the actual prices we receive for oil and gas, our actual operating costs in producing oil and gas, the amount and timing of actual production, the amount and timing of our capital expenditures, supply of and demand for oil and gas and changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with Financial Accounting Standards Board Statement of Financial Accounting Standards No. 69 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

Currently, substantially all of our producing properties are located on the Navajo Reservation, making us vulnerable to risks associated with laws and regulations pertaining to the operation of oil and gas properties on Native American tribal lands.

Substantially all of our estimated net proved reserves as of June 30, 2007, were located on the Navajo Reservation. Operation of oil and gas interests on Indian lands presents certain unique considerations and complexities. These arise from the fact that Indian tribes are “dependent” sovereign nations located within states, but are subject only to tribal laws and treaties with, and the laws and Constitution of, the United States. This creates a potential overlay of three jurisdictional regimes — Indian, federal and state. These considerations and complexities could arise around various aspects of our operations, including real property considerations, employment practices, environmental matters and taxes.

For example, we are subject to the Navajo Preference in Employment Act. This law requires that we give preference in hiring to members of the Navajo Nation, or in some cases other Native American Tribes, if such a person is qualified for the position, rather than hiring the most qualified person. A further regulatory requirement is imposed by the Navajo Nation Business Opportunity Act. This law requires us to give preference to businesses owned by Navajo persons when we are hiring contractors. These regulatory restrictions can negatively affect our ability to recruit and retain the most highly qualified personnel or to utilize the most experienced and economical contractors for our projects.

Furthermore, because tribal property is considered to be held in trust by the federal government, before we can take certain actions, we are required to obtain certain approvals from various federal agencies that are in addition to customary regulatory approvals required of oil and gas producers operating on non-Indian property. These approvals could result in delays in our implementation of, or otherwise prevent us from implementing, our development program. We also are required to obtain approvals from the Resources Committee, which is a standing committee of the Navajo Nation Tribal Council, before we can take certain actions with respect to our Aneth Field Properties. These approvals, even if ultimately obtained, could result in delays in our ability to implement our development program.

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For additional information about the legal complexities and considerations associated with operating on the Navajo Reservation, please see “Business — Laws and Regulations Pertaining to Oil and Gas Operations on Navajo Nation Lands.”

The statutory preferential purchase right held by the Navajo Nation to acquire transferred Navajo Nation oil and gas leases and NNOG’s right of first offer could diminish the value we may be able to receive in a sale of our properties.

Approximately 97% of the gross acres included in our oil and gas properties are located on the Navajo Reservation. The Navajo Nation has a statutory preferential right to purchase at the offered price any Navajo Nation oil and gas lease or working interest in such a lease at the time the lease or interest is proposed to be transferred. The existence of this right can make it more difficult to sell a Navajo Nation oil and gas lease because this right may discourage third parties from purchasing such a lease and, therefore, could reduce the value of our leases if we were to attempt to sell them. For additional information about the preferential purchase right for the benefit of the Navajo Nation, please see “Business — Title to Properties.” In addition, under the terms of our Cooperative Agreement with NNOG, we are obligated to offer to sell any of our Aneth Field Properties to NNOG before we may offer to sell such properties to any other third party. This contractual right could make it more difficult for us to sell our Aneth Field Properties. For additional information about the right of first offer for the benefit of NNOG, please see “Business — Relationship with the Navajo Nation.”

All of our producing properties are located in one field in the Four Corners area of the southwestern United States, making us vulnerable to risks associated with operating in one geographic area.

We rely exclusively on sales of oil and gas that we produce from, and all of our assets are currently located in, the Greater Aneth Field in the southeast Utah portion of the Paradox Basin in the Four Corners area of the southwestern United States. As a result of our lack of diversification in asset type and location, any delays or interruptions of production from these wells caused by such factors as governmental regulation, transportation capacity constraints, curtailment of production or interruption of transportation of oil produced from the wells in this field or shut-downs of the refineries of our sole customer would have a significantly greater impact on our results of operations and cash available for distribution to our unitholders than if we maintained more diverse assets and locations.

We may not be able to redeploy into producing oil and gas properties or other operating assets any cash we may receive upon NNOG’s exercise of its options to purchase a portion of our Aneth Field Properties.

NNOG has a total of six options to purchase for cash, in the aggregate, up to 30.0% of our interest in the Chevron Properties and 30.0% of our interest in the ExxonMobil Properties. These options become exercisable over a period of time if certain financial hurdles are met. If NNOG exercises its purchase options in full, it could acquire from us undivided working interests representing an 18.15% working interest in the Aneth Unit, a 22.5% working interest in the McElmo Creek Unit and a 17.7% working interest in the Ratherford Unit. If NNOG were to exercise any of these options, we might not be able to effectively redeploy the cash received from NNOG in a long-lived producing oil or gas property or other cash generating asset in a timely fashion or at all and our ability to sustain cash distributions could be negatively affected. For additional information about NNOG’s purchase right, please see “Business — Relationship with the Navajo Nation.”

Developing and producing oil and gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

There are numerous risks associated with developing, completing and operating a well, and cost factors can adversely affect the economics of a well. Our development and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

•  high costs, shortages or delivery delays of rigs, equipment, labor or other services;

•  unexpected operational eventsand/or conditions;

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•  reductions in oil prices;

•  increases in severance taxes;

•  limitations on our ability to sell our crude oil production;

•  adverse weather conditions and natural disasters;

•  facility or equipment malfunctions, and equipment failures or accidents;

•  pipe or cement failures and casing collapses;

•  compliance with environmental and other governmental requirements;

•  environmental hazards, such as leaks, oil spills, pipeline ruptures and discharges of toxic gases;

•  lost or damaged oilfield development and service tools;

•  unusual or unexpected geological formations, and pressure or irregularities in formations;

•  fires, blowouts, surface craterings and explosions; and

•  uncontrollable flows of oil, gas or well fluids.

Any of these or other similar occurrences could reduce our cash from operations or result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and impairment of our operations.

We currently possess property, general liability, well control, pollution and other insurance at levels we believe are appropriate; however, insurance against all operational risk is not available to us. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001, have made it more difficult for us to obtain certain types of coverage. We may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and any insurance coverage we do obtain may contain large deductibles or it may not cover certain hazards or potential losses. Losses and liabilities from uninsured and underinsured events and a delay in the payment of insurance proceeds could adversely affect our business, financial condition, results of operations and ability to make distributions to you.

If we do not make acquisitions of reserves on economically acceptable terms, our future growth, ability to maintain production and ability to pay or increase distributions will be limited.

Our ability to grow and to increase distributions to unitholders in the future depends in part on our ability to make acquisitions that result in an increase in available cash per unit, particularly in the event NNOG exercises its options to increase its working interest in the Aneth Field Properties. We may be unable to make such acquisitions because we are:

•  unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with the seller;

•  unable to obtain financing for these acquisitions on economically acceptable terms; or

•  outbid by competitors.

If we are unable to acquire properties containing proved reserves, our total level of proved reserves and associated future production will decline as a result of our ongoing production of our reserves. This could limit our ability to increase or possibly even to maintain our level of cash distributions.

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Any acquisitions we complete are subject to substantial risks that could reduce our ability to make distributions to unitholders.

Even if we do make acquisitions that we believe will maintain or increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:

•  the validity of our assumptions about reserves, future production, the future prices of oil and gas, revenues and costs, including synergies;

•  an inability to integrate successfully the properties and businesses we acquire;

•  a decrease in our liquidity to the extent we use a significant portion of our available cash or borrowing capacity to finance acquisitions;

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

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

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

•  an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;

•  unforeseen difficulties encountered in operating in new geographic areas; and

•  customer or key employee losses at the acquired businesses.

Our decision to acquire a property or business will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential problems. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

If our acquisitions do not generate increases in available cash per unit, our ability to make the minimum quarterly distribution to our unitholders will be adversely affected.

Our future debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

After giving effect to this offering and the related transactions, we estimate that our total debt as of the close of this offering will be approximately $152.7 million. Following this offering, we will have the ability to incur additional debt under our new revolving credit facility, subject to borrowing base limitations in our revolving credit facility. Our significant level of indebtedness could have important consequences to us, including:

•  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;

•  covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

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

•  our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our indebtedness 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. 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 business activities, acquisitions, investmentsand/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

Our new revolving credit facility will have substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.

The operating and financial restrictions and covenants in our new revolving credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions. For example, we anticipate that our new revolving credit facility will restrict, and any future credit facility could restrict, our ability to:

•  incur indebtedness;

•  grant liens;

•  make certain acquisitions and investments;

•  lease equipment;

•  make capital expenditures above specified amounts;

•  redeem or prepay other debt;

•  make distributions to unitholders or repurchase units;

•  enter into transactions with affiliates; and

•  enter into a merger, consolidation or sale of assets.

Furthermore, our new revolving credit facility will contain covenants requiring us to maintain certain financial ratios and tests. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our revolving credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited and our lenders’ commitments to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our revolving credit facility are secured by substantially all of our assets and, if we are unable to repay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets.

We anticipate that our new revolving credit facility will limit the amounts we can borrow to a borrowing base amount determined by the lenders in their sole discretion. The lenders will be able to unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Any increase in the borrowing base will require the consent of all the lenders. If the required lenders do not agree on an increase, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 662/3% of the commitments, not to exceed the then-current borrowing base. Outstanding borrowings in excess

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of the borrowing base will have to be repaid immediately, or we will have to pledge other oil and gas properties as additional collateral.

Shortages of qualified personnel or field equipment and services could affect our ability to execute our plans on a timely basis, reduce our cash flow and our ability to make distributions to our unitholders and adversely affect our results of operations.

The demand for qualified and experienced geologists, geophysicists, engineers, field operations specialists, landmen, financial experts and other personnel in the oil and gas industry can fluctuate significantly, often in correlation with oil and gas prices, causing periodic shortages. From time to time, there also have been shortages of drilling rigs and other field equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors can also result in significant increases in costs for equipment, services and personnel. Higher oil and gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Increased demand resulting from high commodity prices over the past several years resulted in our experiencing some difficulty, and significantly increased costs, in obtaining drilling rigs, experienced crews and related services and we may continue to experience such difficulties in the future. If shortages persist or prices continue to increase, our profit margin, cash flow and operating results could be adversely affected and our ability to conduct our operations in accordance with current plans and budgets could be restricted.

Our hedging activities could reduce our net income and/or cash available for distribution, which could reduce the price at which our units trade and may adversely affect our ability to pay distributions to our unitholders.

To achieve more predictable cash flow and to reduce our exposure to adverse changes in the price of oil, we have entered into, and in the future plan to enter into, derivative arrangements covering a significant portion of our oil production. These derivative arrangements could result in both realized and unrealized hedging losses. Our derivative instruments are subject to mark-to-market accounting treatment, and the change in fair market value of the instrument is reported in our statement of operations each quarter, which has resulted in and will in the future likely result in significant unrealized net losses.

We have direct commodity price exposure on the unhedged portion of our production volumes. As of June 30, 2007, we had in place oil hedges with respect to approximately 55.4% of our estimated oil production from our proved developed producing properties through 2012 using commodity price swap contracts and options. These instruments yield a weighted average price per Bbl of $63.07 for the barrels under contract, including 62.7% of our estimated oil production from our proved developed producing properties for 2008 with a weighted average price per Bbl of $70.16. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Production Levels, Trends and Prices” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk.”

Our actual future production during a period may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have more unhedged production and therefore greater commodity price exposure than we intended. If the actual amount is lower than the nominal 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 cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity and a reduction in our cash available for distribution. As a result of these factors, our derivative 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, our derivative activities are subject to the risk that a counterparty may not perform its obligation under the applicable derivative instrument.

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The effectiveness of hedging transactions to protect us from future oil price declines will be dependent upon oil prices at the time we enter into future hedging transactions as well as our future levels of hedging, and as a result our future net cash flow may be more sensitive to commodity price changes.

As our hedges expire, more of our future production will be sold at market prices unless we enter into additional hedging transactions. We anticipate that our new revolving credit facility will prohibit us from entering into hedging arrangements for more than 80% of our production from projected proved developed producing reserves. Additionally, since the price we pay for CO₂ is tied to the price of crude oil, we further limit the amount we hedge to approximately 75% of our production from proved developed producing reserves. Our commodity price hedging strategy and future hedging transactions will be determined by our general partner, which is not under any obligation to hedge a specific portion of our production, other than to comply with the terms of our revolving credit facility for so long as it may remain in place. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially lower than current prices. Accordingly, our commodity price hedging strategy will not protect us from significant and sustained declines in oil and gas prices received for our future production. Conversely, our commodity price hedging strategy may limit our ability to realize cash flow from commodity price increases. It is also possible that a larger percentage of our future production will not be hedged as compared to the next few years, which would result in our oil revenues becoming more sensitive to commodity price changes.

The nature of our assets exposes us to significant costs and liabilities with respect to environmental and operational safety matters. We are responsible for certain costs associated with the removal and remediation of the decommissioned Aneth Gas Processing Plant.

We may incur significant costs and liabilities as a result of environmental, health and safety requirements applicable to our oil and gas exploitation, production and other activities. These costs and liabilities could arise under a wide range of environmental and safety laws and regulations, including agency interpretations thereof and governmental enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, cleanup and site restoration costs and liens, the denial or revocation of permits or other authorizations and the issuance of injunctions to limit or cease operations. Compliance with these laws and regulations also increases the cost of our operations and may prevent or delay the commencement or continuance of a given operation. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.

As a result of our acquisition of the Chevron Properties and the ExxonMobil Properties, we acquired an interest in the Aneth Gas Processing Plant, which is currently being decommissioned. Under our purchase agreement with Chevron, Chevron is responsible for indemnifying us against the decommissioning costs allocable to the interest we purchased from it. Under our purchase agreement with ExxonMobil, however, we are responsible for the decommissioning cost allocable to the interests we purchased from ExxonMobil, which is 25% of the total cost of the project. We currently estimate that we will be responsible for $2.6 million of the costs associated with decommissioning the Aneth Gas Processing Plant, of which we had paid $0.9 million as of June 30, 2007. Because of certain delays and other circumstances, however, we believe that the costs to decommission the plant could be greater than this estimate. This estimate also does not include any costs for environmental remediation of the subsurface. Please see “Business — Aneth Gas Processing Plant” for additional information about this liability.

Strict or joint and several liability to remediate contamination may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to make distributions to you could be adversely affected. Please read “Business — Environmental and Safety Matters and Regulation” for more information.

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We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue and our ability to pay distributions to our unitholders.

The oil and gas industry is intensely competitive, and we compete with companies that have greater resources. Many of these companies not only explore for and produce oil and gas, but also refine and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and gas properties and exploratory prospects or identify, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration or exploitation activities during periods of low oil and gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Exploitation, development, production and marketing operations in our industry are regulated extensively at the federal, state and local levels. In addition, substantially all of our current leases are regulated by the Navajo Nation. Some of our future leases may be regulated by Native American tribes. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and gas wells and other recovery operations. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations or denial or revocation of permits and subject us to administrative, civil and criminal penalties.

Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statementsand/or plans of development before commencing exploration and production activities. In addition, our activities are subject to regulation, by oil and gas producing states and Native American tribes regarding conservation practices, protection of correlative rights and other concerns. These regulations affect our operations and could limit the quantity of oil and gas we may produce and sell. A risk inherent in our drilling and CO₂ flood projects is the need to obtain permits from state, local and Navajo Nation tribal authorities. Delays or failures in obtaining regulatory approvals or permits or the receipt of an approval or permit with unreasonable conditions or costs could have a material adverse effect on our ability to exploit our properties. Additionally, the oil and gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating staff. See “Business — Environmental and Safety Matters and Regulation” and “Business — Other Regulation of the Oil and Gas Industry” for a description of the laws and regulations that affect us.

We depend on a limited number of key personnel who would be difficult to replace.

We depend substantially on the performance of the executive officers and other key employees of our general partner and its affiliate, Resolute Natural Resources Company. Neither our general partner nor Resolute Natural Resources Company has entered into any employment agreements with any of these employees, and we do not maintain key person life insurance policies on any of these employees. The loss of any member of the senior management team or other key employee of our general partner could negatively affect our ability to execute our strategy.

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Risks Inherent in an Investment in Us

Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with us and have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of our unitholders. Our partnership agreement limits the circumstances under which our unitholders may make a claim relating to conflicts of interest and the remedies available to our unitholders in that event.

Following the offering, Resolute Holdings will own a 65.0% limited partner interest in us and our general partner, which controls us and owns all of our incentive distribution rights. The directors and officers of our general partner have a fiduciary duty to manage us in a manner beneficial to Resolute Holdings. Furthermore, certain directors and officers of Resolute Holdings will be directors or officers of affiliates of our general partner. Conflicts of interest will exist between our general partner and its affiliates, including Resolute Holdings and Natural Gas Partners and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. Please read “— Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.” These potential conflicts include, among others, the following situations:

•  neither our partnership agreement nor any other agreement requires Resolute Holdings or its affiliates (other than our general partner) to pursue a business strategy that favors us. The directors and officers of Resolute Holdings have a fiduciary duty to make these decisions in the best interests of the owners of Resolute Holdings, which may be contrary to our interests;

•  our general partner is allowed to take into account the interests of parties other than us, such as Resolute Holdings and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us and our unitholders;

•  Resolute Holdings and its affiliates, including Natural Gas Partners and its affiliates, are not limited in their ability to compete with us;

•  some officers of Resolute Holdings who provide services to us also will devote significant time to the business of Resolute Holdings, and will be compensated by Resolute Holdings for the services rendered to it;

•  our partnership agreement limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

•  our general partner determines the amount and timing of expenses, asset purchases and sales (including the purchase of assets from Resolute Holdings or its affiliates, including Natural Gas Partners and its affiliates), capital expenditures, borrowings, repayments of indebtedness, issuances of additional partnership securities and cash reserves, each of which can affect the amount of cash that is available for distribution to our unitholders and to our general partner including with respect to its incentive distribution rights;

•  our general partner determines the amount and timing of any capital expenditures and the amount of our estimated 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;

•  subject to the terms of the administrative services agreement and our partnership agreement, our general partner determines which costs incurred by it and its affiliates are reimbursable by us. Please read “Management — Reimbursement of Expenses of Our General Partner”;

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•  our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf and provides for reimbursement to our general partner for such amounts as it deems fair and reasonable to us;

•  our general partner intends to limit its liability regarding our contractual obligations and has an incentive to make any of our debt or other contractual obligations nonrecourse to it and, in some circumstances, is entitled to be indemnified by us;

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

•  our general partner controls the enforcement of obligations owed to us by it 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.”

Resolute Holdings and its affiliates, including Natural Gas Partners and its affiliates, are not limited in their ability to compete with us.

Neither our partnership agreement nor any other agreement between us, Resolute Holdings and our general partner will prohibit Resolute Holdings and its affiliates, including Natural Gas Partners and its affiliates, from owning assets or engaging in businesses that compete directly or indirectly with us. For example, Natural Gas Partners and its affiliates hold investments in more than 20 private oil and gas exploration and production companies with operations located in major producing basins throughout the United States. Natural Gas Partners and its affiliates have in the past and will continue to actively seek investments in companies focused on building oil and gas asset portfolios as well as midstream and oilfield and service opportunities.

In addition, under our partnership agreement, the doctrine of corporate opportunity or any analogous doctrine will not apply to Resolute Holdings and its affiliates, including Natural Gas Partners and its affiliates. As a result, Resolute Holdingsand/or Natural Gas Partners may acquire, develop or dispose of additional oil and gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Because we rely on Resolute Holdings and its affiliates to operate our assets, our personnel resources any be constrained by greater demand on those resources from Resolute Holdings, particularly if Resolute Holdings purchases additional assets in the future. Moreover, because we rely on Resolute Holdings and its affiliates to identify and evaluate potential acquisitions for us, we will not be able to pursue any acquisitions unless Resolute Holdings causes us to do so. As a result, competition from Resolute Holdings and Natural Gas Partners could adversely affect our results of operations and cash available for distribution. Please read “Conflicts of Interest and Fiduciary Duties.”

Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

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 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. Decisions made by our general partner in its individual capacity will be made by a majority of the owners of our general partner, and not by the board of directors of our general partner. Examples include the exercise of its limited call rights, its rights to vote and transfer the units it owns, its registration rights and the determination of whether to

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consent to any merger or consolidation of the partnership or any amendment to the partnership agreement;

•  provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith and in a manner it believed to be in the best interests of the partnership;

•  generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

•  generally provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of conflict is approved by the conflicts committee, although our general partner is not obligated to seek such approval;

•  provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner or the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

•  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.

By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above, and a unitholder will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties” and “Description of the Common Units — Transfer of Common Units.”

Cost reimbursements owed 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.

Pursuant to various agreements we will enter into with Resolute Holdings, our general partner and certain of their affiliates at the closing of this offering, we will reimburse Resolute Holdings for operating expenses related to our operations and for the provision of various general and administrative services for our benefit, which amounts will be determined by our general partner. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. These agreements include the following:

•  Under our partnership agreement, our general partner determines which expenses, including allocated overhead, incurred by it and its affiliates are reimbursable by us. These expenses include a portion of the salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, and other expenses allocated to us by our general partner. Our general partner is entitled to determine, in good faith, the expenses that are allocable to us.

•  We intend to enter into an administrative services agreement with Resolute Holdings and certain of its affiliates pursuant to which Resolute Holdings will operate substantially all of our assets and perform administrative services for us such as accounting, marketing, corporate development, finance, land, legal and engineering. We will reimburse Resolute Holdings for its costs in operating our assets and in performing these services.

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We will deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual maintenance capital expenditures were deducted.

We will deduct estimated, rather than actual, maintenance capital expenditures from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by the board of directors of our general partner. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if we underestimate the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for our previous underestimation. In addition, the ability of our general partner to receive incentive distributions is based on the amount of cash distributed to our unitholders from operating surplus, which in turn is partially dependent upon our determination of estimated maintenance capital expenditures. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing in order to make sufficient expenditures to maintain our production over the long-term, we will be unable to pay the minimum quarterly distribution and could be required to reduce our distributions to unitholders.

The incentive distribution rights owned by our general partner may create a conflict of interest in determining the appropriate level of cash distributions to our unitholders.

Our general partner has incentive distribution rights entitling it to receive up to an additional 48% of our cash distributions above a certain target distribution level. This increased share of our distributions may create a conflict of interest for our general partner in determining whether to distribute cash to our unitholders or reserve it for reinvestment in our business and whether to borrow to pay distributions to our unitholders and itself. Our general partner may have an incentive to distribute more cash than it would if its only economic interest in us were its 2% general partner interest and the common units and subordinated units that its affiliates own. Furthermore, because of the commodity price sensitivity of our business, the general partner may receive incentive distributions solely as a result of increases in commodity prices, as opposed to earning them by growing our asset base through development of our properties or acquisitions.

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 the 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 32.6% 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 66.3% of our aggregate outstanding common units, including all of the subordinated units that it currently owns on a fully converted basis. For additional information about this right, please read “The Partnership Agreement — Limited Call Right.”

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 from transferring all or a portion of their respective ownership interest in our general partner to a third party. The new owners of our general partner

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would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers.

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 our general partner will be chosen by the members of Resolute Holdings as the sole member of such entity. 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 approximately 66.3% 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, other than our general partner and its affiliates, owning 20% or more of our common units, which may limit the ability of significant unitholders to influence the manner or direction of management.

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.

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

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limited partnership have not been clearly established in some of the other states in which we do or may 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. UnderSection 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. 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.

Unitholders may have limited liquidity for their units, a trading market may not develop for our common units, and you may not be able to resell your common units at the initial public offering price.

Prior to this offering, there has been no public market for our common units. After this offering, there will be 13,750,000 publicly traded common units, or 15,812,500 publicly traded common units if the underwriters exercise in full their option to purchase additional common 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 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 units and limit the number of investors who are able to buy the units.

In addition, trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of securities. The market price of our common units could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition.

An increase in interest rates and other factors may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

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The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by affiliates of our general partner.

After this offering, we will have 20,401,316 common units and 20,401,316 subordinated units outstanding, which includes the 13,750,000 common units we are selling in this offering that may be resold in the public market immediately. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. All of our common units that are issued to affiliates of our general partner will be subject to resale restrictions under180-daylock-up agreements with our underwriters. Each of thelock-up arrangements with the underwriters may be waived in the discretion of Lehman Brothers Inc., UBS Securities LLC and Wachovia Capital Markets, LLC. Sales by any of our existing unitholders of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, our general partner has agreed to provide registration rights to these holders, subject to certain limitations. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations. Please read “Units Eligible for Future Sale.”

You will experience immediate and substantial dilution of $15.60 in tangible net book value per common unit.

The assumed initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $4.40 per unit. Based on the assumed initial public offering price of $20.00 per unit, you will incur immediate and substantial dilution of $15.60 per common unit. 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 an unlimited number of additional partnership securities, including partnership securities that are senior to the common units, without unitholder approval, which would dilute our unitholders’ existing ownership interests.

We may issue an unlimited number of partnership securities of any type, including additional common units, without the approval of our unitholders. In addition, we may issue an unlimited number of partnership securities that are senior to the common units in right of distribution, liquidation and voting. We may issue the additional partnership securities to third parties or to our general partner and its affiliates, including Natural Gas Partners and our senior management.

The issuance by us of additional common units or other partnership 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 to 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.

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

We have no history operating as a publicly traded company. As a publicly traded company, 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 New York

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Stock Exchange, have required changes in corporate governance practices of publicly traded companies. Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended.

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 company, 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. Although we produce our financial statements in accordance with GAAP, our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. For example, as we become subject to the requirements of Section 404 of Sarbanes-Oxley for the fiscal year ending December 31, 2008, we or our auditors may identify weaknesses or deficiencies in the operational effectiveness of our internal controls and procedures and may advise us that these weaknesses or deficiencies could collectively constitute a significant deficiency that may rise to the level of a material weakness under Section 404.

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 $3.1 million of estimated incremental costs per year, most of which will be allocated to us by Resolute Holdings, associated with being a publicly traded company 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 company will be higher than we currently estimate.

Before we can pay distributions to our unitholders, we must first pay or reserve cash for our expenses, including acquisition capital and the costs of being a public company and other operating expenses, and we may reserve cash for future distributions during periods of limited cash flows. The amount of cash we have available for distribution to our unitholders will be affected by our level of cash reserves and expenses, including the costs associated with being a public company.

We will not have any employees and will rely on the employees of our general partner and its affiliates.

All of our executive management personnel will be employees of our general partner or its affiliates and they will devote only such time to our business and affairs as they, in their discretion, deem appropriate. We also will utilize a significant number of employees of our general partner and its affiliates to operate our business and provide us with general and administrative services for which we will reimburse our general partner and its affiliates for allocated expenses of personnel who perform services for our benefit, and we will reimburse our general partner and its affiliates for allocated general and administrative expenses generally associated with the services provided. Affiliates of our general partner and Resolute Holdings will also 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 Resolute Holdings and its affiliates.

Unitholders who are not Eligible Holders may not be entitled to receive distributions on or allocations of income or loss on their common units and their common units may become subject to redemption.

In order to comply with U.S. laws with respect to the ownership of interests in oil and gas leases on United States federal lands, our partnership agreement allows us to adopt certain requirements regarding those investors who may own our common units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; (3) a public body, including a municipality; or (4) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any

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state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases on United States federal lands or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof.

At any time, our general partner may require unitholders to certify that they are an Eligible Holder. Our general partner may also determine that unitholders who are not persons or entities who meet the requirements to be an Eligible Holder or who fail to submit a certification when requested to do so may not receive distributions or allocations of income and loss on their units. Such persons may also run the risk of having their units acquired by us at the lower of the purchase price of their units or the then current market price, as determined by our general partner. The redemption price may be paid in cash or by delivery of an unsecured promissory note that shall be subordinated to the extent required by the terms of our other indebtedness, as determined by our general partner. Please read “Description of the Common Units — Transfer of Common Units” and “The Partnership Agreement — Non-Eligible Holders; Redemption.”

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.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, then our cash available for distribution to you would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our 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 IRS on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we will be treated as a corporation, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

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. For example, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

Our 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, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to you.

Changes in current state law may subject us to additional entity-level taxation by individual states. 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. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may 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 affected and the costs 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 result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our common unitholders and our general partner.

You will 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 the 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. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion, intangible drilling costs and depreciation recapture. In addition, because the amount realized includes a common unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material Tax Consequences — Disposition of Common Units — Recognition of Gain or Loss” for a further discussion of the foregoing.

Tax-exempt entities andnon-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), 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 imposed at the highest applicable effective tax rate, andnon-U.S. persons will be required to file United States federal tax returns and pay tax

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on their share of our taxable income. If you are a tax-exempt entity or anon-U.S. person, you should consult your tax advisor before investing in our common units.

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.

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. Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on these issues. 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. Please read “Material Tax Consequences — Tax Consequences of Common Unit Ownership — Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

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

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, Vinson & Elkins L.L.P. is unable to opine as to the validity of this method. If the IRS were to successfully challenge this method or new Treasury Regulations were issued, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees.”

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

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. 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.

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

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and

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the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

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

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 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, which would result in us filing two tax returns (and unitholders receiving twoSchedule K-1s) for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a common 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 twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. 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.

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

In addition to federal income taxes, you may become subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own or acquire property now or in the future, 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 jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially conduct business and own assets in Utah and Colorado. Both of these states impose a personal income tax on individuals. As we make acquisitions or expand our business, we may conduct business or own assets in additional states that impose a personal income tax or that impose entity level taxes to which we could be subject. It is the responsibility of each common unitholder to file all United States federal, foreign, state and local tax returns applicable to you in your particular circumstances. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about:

•  the volatility of oil and gas prices;

•  discovery, estimation, development and replacement of oil and gas reserves;

•  cash flow, liquidity and financial position;

•  business and financial strategy;

•  hedging strategies and plans;

•  amount, nature and timing of capital expenditures, including future development costs;

•  availability and terms of capital;

•  the effectiveness of our CO₂ flood program;

•  timing and amount of future production of oil and gas;

•  availability of drilling and production equipment;

•  operating costs and other expenses;

•  prospect development and property acquisitions;

•  marketing of oil and gas;

•  competition in the oil and gas industry;

•  our relationship with the Navajo Nation and NNOG, as well as the timing of when NNOG’s purchase rights may first become exercisable;

•  the impact of weather and the occurrence of disasters such as fires, floods and other catastrophic events and natural disasters;

•  governmental regulation of the oil and gas industry;

•  developments in oil-producing and gas-producing countries; and

•  strategic plans, expectations and objectives for future operations.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the “Prospectus Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in the “Risk Factors” section and elsewhere in this prospectus or otherwise. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $257.1 million from the sale of 13,750,000 common units offered by this prospectus, after deducting underwriting discounts and a structuring fee but before paying offering expenses. We base this amount on an assumed initial public offering price of $20.00 per common unit (which is the midpoint of the range set forth on the cover of this prospectus) and assume no exercise of the underwriters’ option to purchase additional common units. We intend to use the aggregate net proceeds of this offering to:

•  pay approximately $3.4 million of expenses associated with the offering and related formation transactions;

•  replenish approximately $7.5 million of working capital previously distributed to Resolute Holdings prior to the closing of this offering;

•  repay all of the outstanding indebtedness under our existing revolving credit facility of approximately $173.9 million; and

•  repay approximately $72.3 million of the outstanding indebtedness under our existing term loan facility.

Affiliates of UBS Securities LLC and Wachovia Capital Markets, LLC are lenders under our existing revolving credit facility and, accordingly, will receive a portion of the proceeds from this offering. Please read “Underwriting — Relationships/NASD Conduct Rules.”

We also anticipate that we will borrow approximately $152.7 million of indebtedness under our new revolving credit facility upon the closing of this offering, and we intend to use the net proceeds from such borrowings to repay the remaining balance under our existing term loan facility.

If the underwriters exercise their option to purchase additional common units, we will use the net proceeds to repay a portion of the outstanding indebtedness that we intend to borrow under our new revolving credit facility.

As of June 30, 2007, borrowings under our revolving credit facility and our term loan facility bore interest at rates of 7.08% and 9.86%, respectively, per annum and mature on April 13, 2011, and June 26, 2013, respectively. The indebtedness we incurred under these facilities was used to purchase the Chevron Properties and the ExxonMobil Properties, to make a distribution to Resolute Holdings and for general corporate purposes.

A $1.00 increase or decrease in the assumed initial offering price of $20.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts and a structuring fee but before paying offering expenses, to increase or decrease by approximately $12.9 million. Any such increase or decrease in our net proceeds will increase or decrease, as the case may be, the amount of outstanding indebtedness under our existing term loan facility that is repaid with proceeds from this offering and the amount that we will need to borrow under our new revolving credit facility to repay the remaining balance under our existing term loan facility.

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CAPITALIZATION

The following table shows:

•  the cash and cash equivalents and the capitalization of Resolute Energy Partners Predecessor as of June 30, 2007; and

•  our pro forma cash and cash equivalents and capitalization as of June 30, 2007, adjusted to reflect this offering, the other formation transactions described under “Summary — Our Partnership Structure and Formation Transactions” 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, 2007
	Historical			Pro Forma(1)
	(Unaudited)
	(In thousands)
Cash and cash equivalents	$	—		$	7,500
Total long-term debt:
Existing revolving credit facility(2)		170,250			—
Existing term loan facility		225,000			—
New revolving credit facility(2)		—			150,975
Total		395,250			150,975
Net parent investment/partners’ capital:
Net parent investment		(45,008	)		—
Common unitholders — public		—			61,171
Common unitholders — sponsor		—			29,659
Subordinated units		—			90,830
General partner interest		—			3,707
Total partners’ equity (deficit)		(45,008	)		185,367
Total capitalization	$	350,242		$	336,342

(1)

Assumes an initial public offering price of our common units of $20.00 per common unit and reflects total partners’ equity from the net proceeds of this offering, after deducting the underwriting discount and net offering expenses payable by us and the application of the proceeds as described in “Use of Proceeds.” A $1.00 increase or decrease in the assumed public offering price per common unit would increase or decrease our pro forma total partners’ equity by $12.9 million, assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the underwriting discounts and estimated net offering expenses payable by us. The pro forma information discussed above is illustrative only and following the completion of this offering will be adjusted based on the actual public offering price and other terms of this offering determined at pricing.

(2)

Does not include approximately $1.7 million of additional net indebtedness expected to be outstanding under our existing revolving credit facility as of the closing of this offering We intend to use the net proceeds from this offering to repay all of the outstanding indebtedness under our existing revolving credit facility and a portion of the indebtedness under our existing term loan facility. We will need to borrow an additional approximately $1.7 million under our new revolving credit facility to repay the remaining balance under our existing term loan facility. See “Use of Proceeds.”

The table does not reflect the issuance of up to an additional 2,062,500 common units that may be sold to the underwriters upon exercise of their option to purchase additional common units.

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per common unit after the offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial public offering price of $20.00 per common unit, on a pro forma basis as of June 30, 2007, 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 $183.4 million, or $4.40 per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for accounting purposes, as illustrated in the following table:

Assumed initial public offering price per common unit				$	20.00
Net tangible book value per unit before the offering(1)	$	(2.45	)
Increase in net tangible book value per unit attributable to purchasers in the offering		6.85
Less: Pro forma net tangible book value per unit after the offering(2)					4.40
Immediate dilution in tangible net book value per common unit to new investors(3)				$	15.60

(1)	Determined by dividing the number of units (6,651,316 common units, 20,401,316 subordinated units and the 2% general partner interest, which has a dilutive effect equivalent to 832,707 units, referred to in this prospectus as “general partner equivalent units”) to be issued to a subsidiary of Resolute Holdings for its contribution of assets and liabilities to Resolute Energy Partners, LP 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 (20,401,316 common units, 20,401,316 subordinated units and 832,707 general partner equivalent 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 unit would equal $16.24 or $14.86, respectively.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates in respect of their units 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 except unit data)
General partner and affiliates(1)(2)		27,885,339		67.0	%	$	(68,408	)		(36.9	)%
New investors		13,750,000		33.0	%		253,775			136.9	%
Total		41,635,339		100.0	%	$	185,367			100.0	%

(1)	Upon the consummation of the transactions contemplated by this prospectus, our general partner and its affiliates will own 6,651,316 common units and 20,401,316 subordinated units, representing an aggregate 65% limited partner interest in us, and a 2% general partner interest in us, which has a dilutive effect equivalent to 832,707 general partner equivalent units.
(2)	The assets contributed by affiliates of the general partner were recorded at historical cost in accordance with GAAP. Total consideration provided by affiliates of the general partner is equal to the net tangible book value of such assets as of June 30, 2007.

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with 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 “— Assumptions and Considerations” below. In addition, you should read “Cautionary Note Regarding 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 the historical financial statements of Resolute Energy Partners Predecessor for the eleven months from Inception (January 22, 2004) to December 31, 2004, for the years ended December 31, 2005 and 2006, and for the six months ended June 30, 2006 and 2007, and our pro forma financial statements for the year ended December 31, 2006, and the six months ended June 30, 2007, included elsewhere in this prospectus.

General

Our Cash Distribution Policy.  Our partnership agreement requires us to distribute all of our available cash quarterly. Since we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax. The amount of available cash that we have will be determined by the board of directors of our general partner for each calendar quarter after the closing of this offering and will be based upon recommendations from our management. It is the board’s current policy that we will pay a minimum quarterly distribution of $0.35 per unit for each complete quarter, and that we should increase our level of quarterly cash distributions per unit only when, in the board’s judgment, it believes that (1) we have sufficient reserves and liquidity for the conduct of our business, including to fund the level of maintenance capital expenditures required to maintain our production and (2) we can maintain that increased distribution level over the long-term. We intend initially to fund maintenance capital expenditures with cash flow from operations and to fund expansion capital expenditures with cash flow from operations, borrowings or issuances of additional equity and debt securities.

Definition of Available Cash.  We define available cash in our partnership agreement, and it means, for each fiscal quarter, the sum of all cash and cash equivalents on hand at the end of the quarter:

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

•  provide for the proper conduct of our business, including amounts for maintenance and expansion capital expenditures and debt reduction;

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

•  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 additional cash and cash equivalents on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months.

Restrictions and Limitations on Cash Distributions.  There is no guarantee that unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay distributions at the minimum quarterly distribution rate, except as provided in our partnership agreement. Our distribution policy is subject to certain restrictions and may be changed at any time, including as a result of the following factors:

•  We may borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available

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cash from operations to be insufficient to pay the distribution at the current level. For example, because we intend to have in place derivative financial instruments covering a significant portion of our production, we may be required to pay derivative counterparties the difference between the fixed price and market price before we receive the proceeds from the sale of the hedged production. Our partnership agreement will not restrict our ability to borrow to pay distributions, but we expect to be subject to restrictions on distributions under our new revolving credit facility.

•  We expect our new revolving credit facility to contain certain material financial tests, such as a leverage ratio, a current ratio and an interest coverage ratio, and covenants that we must satisfy. Should we be unable to satisfy these restrictions under our new revolving credit facility, or if we otherwise default under our new revolving credit facility, we would be prohibited from making a distribution to you notwithstanding our stated cash distribution policy. 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 — Revolving Credit Facility.”

•  Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, including future acquisitions and other capital expenditures and anticipated future credit needs, as well as for future cash distributions to our unitholders, and the establishment of those cash reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on the unitholders. 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.

•  We intend to reserve and reinvest between 8% and 12% of our cash generated from operations to develop our existing properties and to acquire additional oil and gas properties in order to maintain our production over the long-term. Over a longer period of time, if we do not make sufficient cash expenditures to maintain our production, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions. In addition, decreases in commodity prices from current levels will adversely affect our ability to pay distributions.

•  While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. During the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of the public common unitholders. After the subordination period has ended, our partnership agreement can be amended with the approval of a majority of the outstanding common units voting as a class (including common units held by Resolute Holdings).

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

•  UnderSection 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders 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 a number of factors, including reduced demand for oil, reduced production from our wells, lower commodity prices for the production we sell, increases in operating or general and administrative expenses, principal and interest payments on any current or future debt, tax expenses, capital expenditures and working capital requirements. Please read “Risk Factors” for a discussion of these factors.

Our Ability to Grow May Depend on Our Ability to Access External Growth Capital. Our partnership agreement requires us to distribute all of our available cash to our unitholders. As a result, to the extent that our cash generated from operations and cash reserves are inadequate to fund capital expenditures after paying distributions to unitholders, then 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 capital

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expenditures. As a result, to the extent we are unable to finance growth through internal and external sources, 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 that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or other 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, which in turn may reduce the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement and we expect no limitations under our new revolving 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 reduce the amount of available cash that we have to distribute to our unitholders.

Our Minimum Quarterly Distribution Rate

Upon completion of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will declare a minimum quarterly distribution of $0.35 per unit per complete quarter, or $1.40 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter. This equates to an aggregate cash distribution of $14.6 million per quarter or $58.3 million per year, in each case based on the number of common units and subordinated units outstanding immediately after completion of this offering. If the underwriters exercise in full their option to purchase additional common units, the ownership interest of the public unitholders will increase to 15,812,500 common units representing an aggregate 36.2% limited partner interest in us and our aggregate cash distribution per quarter would be $15.3 million or $61.2 million per year. Our ability to make cash distributions at the minimum quarterly distribution rate pursuant to this policy will be subject to the factors described above under the caption “— General — Restrictions and Limitations on Cash Distributions.”

The table below sets forth the assumed number of outstanding common units, subordinated units and general partner equivalent 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 minimum quarterly distribution rate of $0.35 per unit per quarter ($1.40 per unit on an annualized basis).

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 2% general partner interest has a dilutive effect equivalent to 832,707 general partner equivalent units. The general partner’s 2% general partner interest in our 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 initial 2% general partner interest. However, if the underwriters exercise their option to purchase additional common units, our general partner will not be required to make an additional capital contribution to us in connection with the issuance of those common units in order to maintain its initial 2% general partner interest.

	No Exercise of the Underwriters’ Option						Full Exercise of the Underwriters’ Option
	to Purchase Additional Common Units						to Purchase Additional Common Units
	Number of		Distributions				Number of		Distributions
	Units		One Quarter		Annualized		Units		One Quarter		Annualized
Publicly held common units		13,750,000	$	4,812,500	$	19,250,000		15,812,500	$	5,534,375	$	22,137,500
Common units held by Resolute Holdings		6,651,316		2,327,961		9,311,842		6,651,316		2,327,961		9,311,842
Subordinated units held by Resolute Holdings		20,401,316		7,140,461		28,561,842		20,401,316		7,140,461		28,561,842
General partner equivalent units		832,707		291,447		1,165,790		874,799		306,180		1,224,718
Total		41,635,339	$	14,572,369	$	58,289,474		43,739,931	$	15,308,977	$	61,235,902

The subordination period generally will end if we have earned and paid at least $1.40 on each outstanding common unit and subordinated unit and the related distributions on our general partner’s 2% general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2012.

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The subordination period may also end on or after December 31, 2010, if certain financial tests are met, but the subordination period will not end prior to December 31, 2010, under any circumstances except 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. 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 quarterly distribution rate, holders of our common units 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 quarterly 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.”

Our cash distribution policy, as expressed in our partnership agreement, 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. During the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of the public common unitholders. After the subordination period has ended, our partnership agreement can be amended with the approval of a majority of the outstanding common units voting as a class (including common units held by Resolute Holdings). Please read “The Partnership Agreement — Voting Rights.”

We will pay our distributions on or about the 15th of each of 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 minimum quarterly distribution for the period from the closing of this offering through the end of the calendar quarter 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 minimum quarterly distribution rate of $0.35 per unit for each quarter in the four quarters ending December 31, 2008. In the following sections, we present two tables, consisting of:

•  “Unaudited Pro Forma Available Cash to Pay Distributions,” in which we present the amount of cash we would have had available for distribution for our fiscal year ended December 31, 2006, and the twelve months ended June 30, 2007, on a pro forma basis after giving effect to the acquisition of the ExxonMobil Properties, the offering and the formation transactions contemplated by this prospectus; and

•  “Estimated Cash Available to Pay Distributions,” in which we present our estimate of the minimum amount of Adjusted EBITDA necessary for us to pay distributions at the minimum quarterly distribution rate on all units for the year ending December 31, 2008.

Unaudited Pro Forma Available Cash for Year Ended December 31, 2006, and Twelve Months Ended June 30, 2007

If we had completed the transactions contemplated in this prospectus, as well as the acquisition of the ExxonMobil Properties, on January 1, 2006, pro forma available cash generated during the year ended December 31, 2006, would have been approximately $49.5 million. This amount would have been sufficient to make cash distributions for 2006 at the minimum quarterly distribution rate of $0.35 per unit per quarter (or $1.40 per unit on an annualized basis) on all of the common units and cash distributions of $0.24 per unit per quarter ($0.96 per unit on an annualized basis) or 69.7% of the minimum quarterly distribution on all of the subordinated units. Assuming the underwriters exercise in full their option to purchase additional common units, this amount would have been sufficient to make the full minimum quarterly distribution on all of the

52

common units and a cash distribution of $0.24 per unit per quarter ($0.96 per unit on an annualized basis) or 69.2% of the minimum quarterly distribution on all of the subordinated units.

If we had completed the transactions contemplated in this prospectus on January 1, 2006, and the other pro forma adjustments described above had also occurred as of such date, our pro forma available cash for the twelve months ended June 30, 2007, would have been approximately $52.0 million. This amount would have been sufficient to make cash distributions for the twelve months ended June 30, 2007, at the minimum quarterly distribution rate of $0.35 per unit per quarter (or $1.40 per unit on an annualized basis) on all of the common units and cash distributions of $0.27 per unit per quarter ($1.08 per unit on an annualized basis) or 78.5% of the minimum quarterly distribution on all of the subordinated units. Assuming the underwriters exercise in full their option to purchase additional common units, this amount would have been sufficient to make the full minimum quarterly distribution on all of the common units and a cash distribution of $0.27 per unit per quarter ($1.08 per unit on an annualized basis) or 78.0% of the minimum quarterly distribution on all of the subordinated units.

Unaudited pro forma available cash from operating surplus for the two historical periods described above includes the benefit of our commodity price hedges that were in effect during the periods presented. It also 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 certain additional personnel, costs associated with reports to unitholders, tax return andSchedule K-1 preparation and distribution, fees paid to independent auditors, lawyers, independent petroleum engineers and other professional advisors, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. We expect this incremental general and administrative expense initially to total approximately $3.1 million per year, most of which will be allocated to us by our general partner and its affiliates.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2006, and for the twelve months ended June 30, 2007, the amount of available cash that would have been available for distribution to our unitholders, assuming the transactions contemplated in this prospectus and other pro forma adjustments described above had occurred as of January 1, 2006. 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.

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Resolute Energy Partners, LP
Unaudited Pro Forma Available Cash to Pay Distributions

				Pro Forma
	Pro Forma			for the
	for the			Twelve Months
	Year Ended			Ended
	December 31,			June 30,
	2006			2007
	(In thousands)
Net Income (Loss)(1)	$	58,234		$	27,284
Interest expense(2)		9,760			9,760
Depreciation, depletion and amortization		12,150			14,846
Accretion of asset retirement obligation		222			255
Non-cash component of change in fair value of derivative instruments		(13,291	)		(13,340	)
Equity-based compensation expense		—			31,099
Adjusted EBITDA		67,075			69,904
Less:
Interest expense		9,760			9,760
Maintenance capital expenditures(3)		7,408			7,680
Incremental general and administrative expenses associated with being a public company(4)		3,075			3,075
General and administrative expenses allocated to Resolute Holdings(4)		(2,636	)		(2,636	)
Pro Forma Available Cash	$	49,468		$	52,025
Annualized minimum quarterly distribution per unit	$	1.40		$	1.40
Pro Forma Cash Distributions:(5)
Distributions to public unitholders	$	19,250		$	19,250
Distributions to our general partner and its affiliates		39,039			39,039
Total distributions		58,289			58,289
Excess (Shortfall)	$	(8,821	)	$	(6,264	)

(1)	Net income has been adjusted to reflect the effect of our having completed the transactions contemplated in this prospectus, as well as the acquisition of the ExxonMobil Properties, as if such transactions occurred on January 1, 2006.
(2)	Represents interest expense on average debt outstanding of $151.0 million after taking into account the application of the proceeds of this offering to repay outstanding indebtedness. Interest is calculated at an assumed London Interbank Offered Rate, or “LIBOR,” of 4.53% plus a borrowing spread of 1.5%, for a total borrowing rate of 6.03%.
(3)	Based on our estimated production levels and natural decline rates, this amount represents an estimate of our annual maintenance capital expenditures required to maintain our production over the long-term. Because our maintenance capital expenditures can be very irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period.
(4)	Reflects incremental general and administrative expenses which we expect to incur to operate as a publicly traded partnership (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Operating Expenses and General and Administrative Expenses”) offset by those expenses that we believe will not be allocated by Resolute Holdings and our general partner to us.

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(5) Assumes the underwriters do not exercise their option to purchase additional common units. In the event the underwriters do exercise in full their option to purchase additional common units, all proceeds would be used to reduce debt. In such case, total distributions would increase to $61.2 million, interest expense would decrease to $7.0 million and the shortfall would increase to $8.5 million and $6.0 million for the year ended December 31, 2006, and the twelve months ended June 30, 2007, respectively.

Estimated Cash Available for Distributions for the Year Ending December 31, 2008

In order for us to pay the minimum quarterly distribution of $0.35 per unit on each of our outstanding common units and subordinated units and the related distributions on our general partner’s 2% general partner interest for each quarter in the year ending December 31, 2008, we estimate that during that period, we must generate at least $77.9 million in Adjusted EBITDA, which we refer to as “Minimum Estimated Adjusted EBITDA.” We believe that we will be able to generate the full amount of our Minimum Estimated Adjusted EBITDA for the year ending December 31, 2008. In “— Assumptions and Considerations” below, we discuss the major assumptions underlying this belief. The Minimum Estimated Adjusted EBITDA should not be viewed as management’s projection of the actual Adjusted EBITDA that we will generate during the year ending December 31, 2008. We can give you no assurance that our assumptions will be realized or that we will generate the Minimum Estimated Adjusted EBITDA, in which event we will not be able to pay quarterly distributions on our common and subordinated units and the related distributions on our general partner’s 2% general partner interest at the minimum quarterly distribution rate.

When considering our ability to generate the Minimum Estimated Adjusted EBITDA of $77.9 million and how we calculate estimated cash available for distribution, please keep in mind all the risk factors and other cautionary statements under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” which discuss factors that could cause our results of operations and cash available for distribution to vary significantly from our estimates.

We do not, as a matter of course, make public projections as to future sales, earnings or other results. However, we have prepared the prospective financial information set forth below in the table entitled “Estimated Cash Available to Pay Distributions” to illustrate our belief that we can generate the Minimum Estimated Adjusted EBITDA necessary for us to have sufficient cash available to allow us to distribute the minimum quarterly distribution on all of our common units and subordinated units and the related distributions on our general partner’s 2% general partner interest. 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 our view, 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, our expected course of action and our expected future financial performance. However, this information is not factual 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 this prospective financial information.

Neither our independent registered public accounting firm nor any other independent registered public accounting firm 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.

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. In light of the above, the statement that we believe that we will have sufficient cash available for distribution to allow us to pay the minimum quarterly distribution on all of our outstanding common units and subordinated units and the related distributions on our general partner’s 2% general partner interest for the year ending December 31, 2008, should not be regarded as a representation by us or the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

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The following table shows how we calculate Minimum Estimated Adjusted EBITDA for the year ending December 31, 2008. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in “— Assumptions and Considerations.”

Resolute Energy Partners, LP
Estimated Cash Available to Pay Distributions

	Forecast for the
	Year Ending
	December 31, 2008
	(In thousands,
	except per unit
	amounts)
Oil and gas revenue	$	150,615
Hedging gains(1)		2,405
Total revenue		153,020
Operating expenses:
Lease operating and workover expense		45,838
Production taxes		11,415
General and administrative		6,281
Depreciation, depletion and amortization		17,711
Total operating expenses		81,245
Operating income		71,775
Interest expense(2)		11,966
Net income		59,809
Adjustments to reconcile net income to cash available for distribution:
Depreciation, depletion and amortization		17,711
Interest expense(2)		11,966
Adjusted EBITDA		89,486
Interest expense(2)(4)		11,966
Maintenance capital expenditures(3)		7,617
Cash available for distribution before expansion capital expenditures	$	69,903
Distributions per unit	$	1.40
Distributions to public common unitholders	$	19,250
Distributions to our general partner and its affiliates		39,039
Total distributions(4)	$	58,289
Excess of cash available to pay distributions before expansion capital expenditures	$	11,614
Expansion capital expenditures(3)	$	48,063
Borrowings to finance expansion capital expenditures(3)		36,449
Excess cash	$	—
Calculation of Minimum Estimated Adjusted EBITDA necessary to pay cash distributions at the minimum quarterly distribution rate:
Adjusted EBITDA	$	89,486
Excess of cash available for distributions before expansion capital expenditures		11,614
Minimum Estimated Adjusted EBITDA necessary to pay cash distributions at the minimum quarterly distribution rate	$	77,872

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(1)	Based on outstanding swap arrangements as of September 1, 2007, with respect to 1.3 MMBbl of crude oil at a weighted average NYMEX price of $70.41.
(2)	Represents interest expense on average debt outstanding of $171.0 million after taking into account the application of the proceeds of this offering to repay outstanding indebtedness and incremental borrowings to fund expansion capital. Interest is calculated at an assumed LIBOR of 5.5% plus a borrowing spread of 1.5% for a borrowing rate of 7.0%.
(3)	Based on our estimated production levels and natural decline rates, this amount represents an estimate of our annual maintenance capital expenditures required to maintain our production over the long-term. Because our maintenance capital expenditures can be very irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period. Our total forecast capital expenditures for the year ending December 31, 2008, are $55.7 million, with $48.1 million of these expenditures being classified as expansion capital expenditures. For purposes of this table, we are assuming that we will fund all of our maintenance capital expenditures for the year ending December 31, 2008, with cash from operations and we will fund our expansion capital expenditures partially with cash from operations and partially with borrowings under our revolving credit facility. The interest expense associated with these incremental borrowings is included in forecast interest expense.
(4)	Assumes the underwriters do not exercise their option to purchase additional common units. In the event the underwriters do exercise in full their option to purchase additional common units, all proceeds would be used to reduce debt. In such case, total distributions would increase to $61.2 million, interest expense would decrease to $9.3 million and the Minimum Estimated Adjusted EBITDA necessary to pay cash distributions at the minimum quarterly distribution rate would increase to $78.1 million.

Assumptions and Considerations

Based upon the specific assumptions outlined below with respect to the year ending December 31, 2008, we expect to generate Adjusted EBITDA in an amount sufficient to allow us to pay the minimum quarterly distribution on all of our outstanding common units and subordinated units and the related distributions on our general partner’s 2% general partner interest for the year ending December 31, 2008, and to establish adequate cash reserves to fund our anticipated maintenance capital expenditures and to partially fund our anticipated expansion capital expenditures.

While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to allow us to pay the minimum quarterly distribution (absent borrowings under our new revolving credit facility), or any amount, on all of our outstanding common units and subordinated units and the related distributions on our general partner’s 2% general partner interest, in which event the market price of our common units may decline substantially. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient cash expenditures to maintain our oil and gas production, we will be unable to pay the minimum quarterly distribution from cash generated from operations and would therefore expect to reduce our distributions. In addition, decreases in commodity prices from current levels will adversely affect our ability to pay distributions. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

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Operations and Revenue

Production.  The following table sets forth information regarding net production of oil, gas and natural gas liquids on a pro forma basis for the twelve months ended June 30, 2007, and on a forecast basis for the year ending December 31, 2008.

	Pro Forma
	for the		Forecast
	Twelve Months		for the
	Ended		Year Ending
	June 30,		December 31,
	2007		2008
Annual production:
Oil (MBbl)		1,955		2,239
Gas (MMcf)		238		323
Natural gas liquids (MBbl)		116		—
Total (MBoe)		2,111		2,293
Average daily production:
Oil (Bbl/d)		5,355		6,134
Gas (Mcf/d)		651		884
Natural gas liquids (Bbl/d)		317		—
Total (Boe/d)		5,781		6,281

The forecast production for the year ending December 31, 2008, is based on our reserve report dated June 30, 2007, as adjusted to take account of potential timing differences in various production categories. We do not forecast natural gas liquids specifically in our reserve report, but rather attempt to reflect this value in the gas forecast. Revenues from gas and natural gas liquids accounted for approximately 3.7% of our total revenue for the twelve months ended June 30, 2007; therefore, we do not believe our method of forecasting gas and natural gas liquids volumes and revenue injects any material error in the forecast. We estimate that our oil and gas production for the year ending December 31, 2008, will be 2.3 MMBoe as compared to 2.1 MMBoe on a pro forma basis for the twelve months ended June 30, 2007. This represents an increase in production of approximately 9%. The net increase of 182.9 MBoe is the result of additional incremental production of approximately 417.7 MBoe in 2008, resulting from our various development activities, partially offset by a decline in forecast production from our current proved producing reserves of 234.8 MBoe.

The forecast utilizes an assumed NYMEX crude oil price of $68.50 per Bbl for the forecast period which, as of the date the forecast was prepared, represented the lowest futures price quoted on the NYMEX website for all months through December 2012. The forecast utilizes an assumed NYMEX gas price of $7.73 per MMbtu for the forecast period which, as of the date the forecast was prepared, represented the average price quoted on NYMEX for the calendar year 2008.

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Prices.  The table below illustrates the relationship between average oil and gas realized prices and the average NYMEX prices on a pro forma basis for the twelve months ended June 30, 2007, and our forecast for the year ending December 31, 2008.

	Pro Forma
	for the			Forecast
	Twelve Months			for the
	Ended			Year Ending
	June 30,			December 31,
	2007			2008
Average oil sales prices (dollars per Bbl):
NYMEX oil price	$	63.84		$	68.50
Realized oil sales price (excluding cash settlements of derivatives)		61.43			66.09
Differential to NYMEX		(2.41	)		(2.41	)
Realized oil sales price (including cash settlements of derivatives)	$	60.50		$	67.17
Average gas sales prices (dollars per unit of measure):
NYMEX gas price per MMBtu	$	6.70		$	7.73
Differential to NYMEX gas		3.94			0.43
Realized gas sales price per Mcf	$	10.64		$	8.16

The basis differential we anticipate realizing on our crude oil production is based on our existing contracts with the purchaser of our crude oil. We assume for purposes of this forecast that these contracts will remain in place over the forecast period. The positive differential anticipated to be realized on our gas production when calculated in dollars per Mcf is a function of the high Btu content of gas produced in the Greater Aneth Field, partially offset by location differential and plant fees.

Use of Derivative Financial Instruments.  As of September 1, 2007, we had in place swap agreements covering 1.3 MMBbl of crude oil, or approximately 56.2% of our estimated total production of 2.2 MMBbl (1.9 MMBbl of which was classified as proved developed producing as of June 30, 2007) of crude oil for the year ending December 31, 2008. We have not historically entered into derivative agreements with respect to our gas production. The table below shows the volumes and prices of our swap agreements for 2008:

	Swaps
				Weighted
	MBbl			Average Price
January 2008 — December 2008		1,259		$	70.41
Percentage of estimated crude oil production		56.2	%

At the closing of this offering, we will also have in place certain derivative financial instruments covering varying amounts of our anticipated crude oil production for the years ending December 31, 2009, through December 31, 2012. For more information about our risk management arrangements, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk and Hedging Arrangements.”

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Operating Revenues.  The following table illustrates the primary components of operating revenues on a pro forma basis for the twelve months ended June 30, 2007, and on a forecast basis for the year ending December 31, 2008 (in thousands):

	Pro Forma
	for the		Forecast
	Twelve Months		for the
	Ended		Year Ending
	June 30,		December 31,
	2007		2008
Oil:
Oil revenues	$	119,557	$	147,983
Oil derivative financial instrument gain		15,923		2,405
Total	$	135,480	$	150,388
Gas and natural gas liquids:
Gas and natural gas liquids revenues	$	5,503	$	2,632
Gas derivative financial instruments gain/(loss)		—		—
Total		5,503		2,632
Total operating revenue	$	140,983	$	153,020

Capital Expenditures and Expenses.

Capital Expenditures.  Our total forecast of capital expenditures for the year ending December 31, 2008, is $55.7 million. These expenditures include $7.6 million of maintenance capital expenditures and $48.1 million of expansion capital expenditures.

We anticipate offsetting declining production and growing production through various development activities on our Aneth Field Properties, including expansion of existing CO₂ floods, workovers of existing producing and injecting wells and the drilling of horizontal laterals from existing vertical wells. Our total forecast of capital expenditures for the year ending December 31, 2008, includes $50.6 million of capital expenditures included in our reserve report dated July 1, 2007. These expenditures include $46.1 million for the CO₂ program, $2.9 million for various projects related to our proved developed non-producing reserves, including capitalized well workovers and $1.6 million for the acquisition of incremental CO₂ in support of our proved developed producing reserves. We do not anticipate incurring any capital expenditures for drilling new wells during the year ending December 31, 2008. In addition to the $50.6 million of capital included in our reserve report we have budgeted approximately $5.1 million for other capital expenditures, which include a $1.5 million contribution to the ExxonMobil escrow account for future plugging and abandonment liabilities, $1.0 million for the ongoing decommissioning of the Aneth Gas Plant and $1.8 million for capitalized general and administrative expenses and capitalized lease operating costs. While it is possible we may acquire additional oil and gas properties during the year ending December 31, 2008, our forecast does not reflect any acquisitions as we cannot assure you that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase agreements.

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Oil and Gas Production Costs.  The following table summarizes oil and gas production expenses on a pro forma basis for the twelve months ended June 30, 2007, and on a forecast basis for the year ending December 31, 2008 (in thousands, except per Boe amounts):

	Pro Forma
	for the		Forecast
	Twelve Months		for the
	Ended		Year Ending
	June 30,		December 31,
	2007		2008
Production expenses:
Lease operating expense	$	25,486	$	26,535
Workover expense		14,575		11,689
Possessory interest and ad valorem taxes		6,473		7,614
Total production expenses	$	46,534	$	45,838
Production expenses (per Boe)	$	22.16	$	19.99

We estimate that our oil and gas production expenses for the year ending December 31, 2008, will be approximately $45.8 million. On a pro forma basis, for the twelve months ended June 30, 2007, production expenses were $46.5 million. This represents a $696,000 decrease in forecast oil and gas production costs. This decrease is mainly a result of a $2.9 million decrease in forecast workover expenses resulting from progress made on reworking wells acquired from ExxonMobil in 2006 and the resulting lower failure rate for these wells. This reduction is partially offset by higher lease operating expenses resulting from increased production volumes and the ongoing CO₂ flood expansion and higher possessory interest and ad valorem taxes resulting from higher assessed valuations. Ad valorem taxes are generally tied to the valuation of the oil and gas properties, and higher valuations result in higher levels of taxation. Ad valorem taxes are levied by the county in which the property is located. Possessory interest taxes are essentially ad valorem taxes charged by the Navajo Nation.

Production Taxes.  The following table summarizes production (severance) taxes before the effects of our derivative financial instruments on a pro forma basis for the twelve months ended June 30, 2007, and on a forecast basis for the year ending December 31, 2008 (dollars in thousands):

	Pro Forma
	for the			Forecast
	Twelve Months			for the
	Ended			Year Ending
	June 30,			December 31,
	2007			2008
Oil and gas revenue, excluding the effect of our derivative financial instruments	$	125,060		$	150,615
Weighted average production tax rate		7.42	%		7.58	%
Production taxes	$	9,280		$	11,415

Our production taxes are calculated as a percentage of our oil and gas revenues, excluding the effects of our derivative financial instruments. In general, as prices and volumes increase, our production taxes increase, and as prices and volumes decrease, our production taxes decrease.

General and Administrative Expenses.  We estimate that our general and administrative expenses for the year ending December 31, 2008, will be approximately $3.2 million, net of overhead reimbursements and capitalized general and administrative expenses, plus an additional $3.1 million of incremental general and administrative expenses that we expect to incur as a result of being a publicly traded partnership. We expect our incremental general and administrative expenses will include compensation and benefit expenses of certain additional personnel, costs associated with reports to unitholders, tax return andSchedule K-1 preparation and distribution, fees paid to independent auditors, lawyers, independent petroleum engineers and other professional advisors, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. We intend to enter into an administrative services

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agreement with Resolute Holdings and its affiliates, including our general partner, pursuant to which Resolute Holdings and its affiliates will manage our assets and perform other administrative services for us such as accounting, marketing, corporate development, finance, land, legal and engineering. We will reimburse Resolute Holdings and its affiliates for their direct expenses and an allocated portion of their general and administrative expenses for their services. Future employee bonuses and unit-based compensation may adversely affect our cash available for distribution, however, we have made no assumptions with respect to these items in the forecast. On a pro forma basis, for the twelve months ended June 30, 2007, general and administrative expenses were approximately $33.4 million with respect to our properties. See “Management — Reimbursement of Expenses of Our General Partner,” “— Executive Compensation” and “— Long-Term Incentive Plan.”

Interest Expense.  At the closing of this offering, assuming that the underwriters do not exercise their option to purchase additional common units, we anticipate we will have $152.7 million of indebtedness outstanding under our new revolving credit facility, which we anticipate will have a borrowing base of $225.0 million. In order to fully fund our anticipated expansion capital expenditures, we anticipate we will need to borrow an additional $36.4 million during 2008 under our new revolving credit facility. Based on these assumptions, we anticipate average indebtedness outstanding during 2008 to be $171.0 million.

Interest expense is calculated on the basis of an anticipated borrowing rate of 7.0%, which consists of a LIBOR of 5.5% and an anticipated borrowing spread under our new revolving credit agreement of 1.5%. This borrowing rate is applied against the average balance expected to be outstanding under our new revolving credit facility.

If the underwriters do exercise in full their option to purchase additional common units, then indebtedness outstanding at the closing of this offering would decrease to $114.2 million and interest expense would decrease to $9.3 million.

Regulatory, Industry and Economic Factors.  Our forecast for the year ending December 31, 2008, is based on the following significant assumptions related to regulatory, industry and economic factors:

•  there will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business;

•  there will not be any major adverse change in commodity prices or the energy industry in general; and

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

Forecast Distributions.  We expect that aggregate quarterly distributions on our common units and subordinated units and our general partner’s 2% general partner interest for the year ending December 31, 2008, will be approximately $58.3 million, assuming the underwriters do not exercise their option to purchase additional common units. If the underwriters do exercise in full their option to purchase additional common units, our anticipated aggregate quarterly distributions would increase to $61.2 million. Quarterly distributions will be paid within 45 days after the close of each calendar quarter.

Sensitivity Analysis

Our ability to generate sufficient cash from operations to pay distributions to our unitholders is a function of two primary variables: (1) production volumes and (2) commodity prices, principally oil prices. In the paragraphs below, we discuss the effect that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the minimum quarterly distribution on all of our outstanding common units and subordinated units and the related distributions on our general partner’s 2% general partner interest for the year ending December 31, 2008.

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Production Volume Changes.  The following table shows estimated distributable cash flow under various assumed production levels for the year ending December 31, 2008. The estimated distributable cash flow amounts shown below are based on the assumptions used in our forecast (in thousands, except per unit amounts).

	Percentage of forecast net production
	90%			100%		110%
Oil and gas revenue (including effect of hedging)	$	137,959		$	153,020	$	168,082
Operating expenses:
Production expense		45,770			45,838		45,906
Production taxes		10,274			11,415		12,557
General and administrative		6,281			6,281		6,281
Depreciation, depletion and amortization		15,940			17,711		19,482
Total operating expenses		78,265			81,245		84,226
Operating income		59,694			71,775		83,857
Interest expense		12,441			11,966		11,492
Net income	$	47,253		$	59,809	$	72,365
Adjustments to reconcile net income to cash available for distributions:
Depreciation, depletion and amortization	$	15,940		$	17,711	$	19,482
Interest expense		12,441			11,966		11,492
Adjusted EBITDA		75,634			89,486		103,339
Interest expense		12,441			11,966		11,492
Maintenance capital expenditures		7,617			7,617		7,617
Cash available for distribution before expansion capital expenditures		55,576			69,903		84,230
Distributions per unit		1.40			1.40		1.40
Distributions to public common unitholders		19,250			19,250		19,250
Distributions to Resolute Holdings		39,039			39,039		39,039
Total distributions		58,289			58,289		58,289
Excess of cash available to pay distributions before expansion capital expenditures		(2,713	)		11,614		25,941
Expansion capital expenditures		48,063			48,063		48,063
Borrowings to finance expansion capital expenditures		48,063			36,449		22,122
Excess cash (shortfall)	$	(2,713	)	$	—	$	—

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Commodity Price Changes.  The following table shows estimated Adjusted EBITDA under various assumed NYMEX oil and gas prices for the year ending December 31, 2008. The estimated Adjusted EBITDA amounts shown below are based on forecast realized commodity prices that take into account our average NYMEX commodity price differential assumptions and derivative financial instruments discussed above. We have assumed no changes in our production based on changes in prices (in thousands, except per unit amounts).

NYMEX oil ($/Bbl)	$	55.00		$	60.00	$	68.50	$	70.00	$	75.00
NYMEX gas ($/MMBtu)	$	6.00		$	6.50	$	7.73	$	8.00	$	8.50
Oil and gas revenue(including effect of hedging)	$	139,004		$	144,131	$	153,020	$	154,612	$	159,739
Operating expenses:
Lease operating expense and workover expense		45,838			45,838		45,838		45,838		45,838
Production taxes		9,064			9,930		11,415		11,679		12,545
General and administrative		6,281			6,281		6,281		6,281		6,281
Depreciation, depletion and amortization		17,711			17,711		17,711		17,711		17,711
Total operating expenses		78,894			79,760		81,245		81,509		82,375
Operating income		60,110			64,371		71,775		73,103		77,364
Interest expense		12,333			12,199		11,966		11,925		11,791
Net income	$	47,777		$	52,172	$	59,809	$	61,178	$	65,573
Adjustments to reconcile net income to cash available for distributions:
Depreciation, depletion and amortization	$	17,711		$	17,711	$	17,711	$	17,711	$	17,711
Interest expense		12,333			12,199		11,966		11,925		11,791
Adjusted EBITDA		77,821			82,082		89,486		90,814		95,075
Interest expense		12,333			12,199		11,966		11,925		11,791
Maintenance capital expenditures		7,617			7,617		7,617		7,617		7,617
Cash available for distribution before expansion capital expenditures	$	57,871		$	62,266	$	69,903	$	71,272	$	75,667
Distributions per unit		1.40			1.40		1.40		1.40		1.40
Distributions to public common unitholders		19,250			19,250		19,250		19,250		19,250
Distributions to Resolute Holdings		39,039			39,039		39,039		39,039		39,039
Total distributions	$	58,289		$	58,289	$	58,289	$	58,289	$	58,289
Excess of cash available to pay distributions before expansion capital expenditures	$	(418	)	$	3,977	$	11,614	$	12,983	$	17,378
Expansion capital expenditures		45,773			46,621		48,063		48,317		49,165
Borrowings to finance expansion capital expenditures		45,773			42,644		36,449		35,334		31,787
Excess cash/(shortfall)	$	(418	)	$	—	$	—	$	—	$	—

As NYMEX oil and gas prices decline, our estimated Adjusted EBITDA does not decline proportionately due to the effects of our derivative financial instruments and due to production taxes, which are calculated as a percentage of our oil and gas revenues, excluding the effects of our derivative financial instruments, and decrease as commodity prices decline. Our forecast capital expenditures include the costs of acquired CO₂. The price we pay for CO₂ is related to the price of oil. As such, our capital expenditures demonstrate some correlation with commodity prices. We have assumed no changes in production or oil and gas operating costs during the year ending December 31, 2008. However, over the long-term, a sustained decline in oil and gas prices would likely lead to a decline in production and oil and gas operating costs as well as a reduction in our realized oil and gas prices. Similarly, over the long-term, a sustained increase in oil and gas prices would likely lead to an increase in production and oil and gas operating costs, as well as an increase in our realized oil and gas prices. Therefore, the foregoing table is not illustrative of the potential effects of changes in commodity prices for periods subsequent to December 31, 2008.

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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 March 31, 2008, we distribute all of our available cash to unitholders of record on the applicable record date.

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

•  lessthe amount of cash reserves established by the board of directors of our general partner to:

•  provide for the proper conduct of our business, including amounts for maintenance and expansion capital expenditures and debt reduction;

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

•  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 additional cash and cash equivalents on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

We define working capital borrowings as borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than additional working capital borrowings.

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 $0.35 per unit, or $1.40 per unit on an annualized basis, 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 will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under our revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Revolving Credit Facility” for a discussion of the restrictions to be included in our revolving credit facility that may restrict our ability to make distributions.

General Partner Interest.  Initially, our general partner will own a 2% general partner interest and will be entitled to 2% of all quarterly 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 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.

Incentive Distribution Rights.  Our general partner also currently owns all of our incentive distribution rights. The incentive distribution rights are limited partner interests in us that entitle our general partner to receive increasing percentages, up to a maximum of 48% (in addition to its 2% general partner interest), of the cash we distribute from operating surplus (as defined below) in excess of $0.4025 per unit per quarter. The maximum distribution of 50% includes distributions paid to our general partner on its 2% general partner

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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 that we distribute 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 $25 million;plus

•  all of our cash receipts after the closing of this offering, excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of our equity and debt securities, (3) sales or other dispositions of assets for cash, other than sales of oil and gas production, dispositions of assets made in connection with plugging and abandoning wells and site reclamation, sales of inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets, (4) the termination of commodity hedge contracts and interest rate swap agreements prior to their respective termination, (5) capital contributions and (6) corporate reorganizations or restructurings;plus

•  working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter;plus

•  cash distributions paid on equity issued to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset is placed into service or the date that it is abandoned or disposed of;less

•  our operating expenditures after the closing of this offering;less

•  the amount of cash reserves established by our general partner to provide funds for future operating and capital expenditures;less

•  all working capital borrowings not repaid within twelve months after having been incurred.

Working capital borrowings are short-term borrowings that we make in order to finance our operations or pay distributions to our partners. Working capital borrowings increase operating surplus and repayment of these borrowings decreases operating surplus.

If a working capital borrowing is not repaid during the twelve-month period following the borrowing other than from additional working capital borrowings, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

Because of fluctuations in our working capital, we may make short-term working capital borrowings in order to level out our distributions from quarter to quarter.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $25 million of cash we receive in the future from non-operating sources such as certain types of asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity securities in operating surplus would be to increase operating surplus by the amount of any such cash

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distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash distributions we receive from non-operating sources.

Part of our business strategy is to limit our exposure to volatility in commodity prices by entering into derivative financial instrument agreements. In general, all of the payments we make or receive under derivative financial instrument agreements, including periodic settlement payments, the purchase price of put contracts and payments made or received in connection with the termination of derivative financial instrument agreements, will be added or deducted in the determination of operating surplus on the date the payment is received or made. Our partnership agreement allows our general partner, with the approval of the conflicts committee of the board of directors of our managing general partner, to allocate payments made or received under derivative financial instrument agreements over multiple periods, or to exclude such payments or receipts from the calculation of operating surplus if it determines such treatment to be appropriate.

Operating Expenditures.  We define operating expenditures in the glossary, and it generally means all of our expenditures, including lease and well operating expenses, taxes, reimbursements of expenses to our general partner, payments made in the ordinary course of business under interest rate and commodity derivative financial instruments, estimated maintenance capital expenditures, repayment of working capital borrowings and debt service payments. Operating expenditures will not include:

•  actual repayment of working capital borrowings deducted from operating surplus that were deemed to have been repaid at the end of the twelve-month period following the borrowing;

•  payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings;

•  actual maintenance capital expenditures;

•  expansion capital expenditures;

•  payment of transaction expenses relating to transactions that do not generate operating surplus; or

•  distributions to partners.

Maintenance Capital Expenditures.  For purposes of determining operating surplus, maintenance capital expenditures are those capital expenditures required to maintain over the long-term our production. Examples of maintenance capital expenditures include capital expenditures to replace oil and gas production, whether through the development, exploitation and production of an existing oil or gas property or the acquisition or development of a new oil or gas property, as well as capital expenditures to maintain and replace equipment used in our oil and gas operations. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of a replacement asset during the period from such financing until the earlier to occur of the date any such replacement asset is placed into service or the date that it is abandoned or disposed of. Plugging and abandonment costs will also constitute maintenance capital expenditures.

Estimated Maintenance Capital Expenditures.  Because our maintenance capital expenditures can be very large and irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus as they were incurred. As a result, to eliminate the effect on operating surplus of these fluctuations, we will estimate the average quarterly maintenance capital expenditures (including estimated plugging and abandonment costs) necessary to maintain our production over the long-term, which amount will be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner, with the concurrence of our conflicts committee. The estimate will be made on a regular basis and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward

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estimated maintenance capital expenditures, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

•  it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units and the related distribution on our general partner’s 2% general partner interest for that quarter and subsequent quarters;

•  it will increase our ability to distribute as operating surplus cash we receive from non-operating sources; and

•  it will be more difficult for us to raise our distribution above the initial quarterly distribution rate and pay incentive distributions to our general partner.

Expansion Capital Expenditures.  Expansion capital expenditures are those capital expenditures that we expect will increase our production over the long-term. Examples of expansion capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interests, or the development, exploitation and production of an existing leasehold interest, to the extent such expenditures are incurred to increase our production. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of such capital improvement during the period from such financing until the earlier to occur of the date any such capital improvement is placed into service or the date that it is abandoned or disposed of.

As described above, none of actual maintenance capital expenditures or expansion capital expenditures are subtracted from operating surplus. Because actual maintenance capital expenditures and expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance all of the portion of the construction, replacement or improvement of a capital asset (such as reserves or equipment) during the period from such financing until the earlier to occur of the date any such capital asset is placed into service or the date that it is abandoned or disposed of, such interest payments and equity distributions are also not subtracted from operating surplus (except, in the case of maintenance capital expenditures, to the extent such interest payments and distributions are included in estimated maintenance capital expenditures).

Capital Surplus.  We also define capital surplus in the partnership agreement and in “— Characterization of Cash Distributions” below, and it will generally be generated only by the following, which we call “interim capital transactions”:

•  borrowings that are not working capital borrowings;

•  sales of our equity and debt securities;

•  sales or other dispositions of assets for cash, other than sales of oil and gas production, dispositions of assets made in connection with plugging and abandoning wells and site reclamation, sales of inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets;

•  the termination of interest rate hedge contracts or commodity hedge contracts prior to the termination date specified therein;

•  capital contributions received; and

•  corporate reorganizations or restructurings.

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,

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regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Subordination Period

General.  Our partnership agreement provides that, during the subordination period (which will commence upon the closing of this offering and will end as described below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.35 per common unit, which 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 to the common units.

Subordination Period.  The subordination period will extend until the first business day of any quarter beginning after December 31, 2012, that each of the following tests are met:

•  distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $1.40 (the annualized 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 $1.40 (the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units and the related distributions on our general partner’s 2% general partner interest during those periods on a fully diluted basis; and

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

Expiration of the Subordination Period.  When the subordination period expires, each outstanding subordinated unit will convert into an equal number of one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not 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

•  the general partner will have the right to convert its 2% general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Early Conversion of Subordinated Units.  If the tests for ending the subordination period are satisfied for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2010, 25% of the subordinated units will convert into an equal number of common units and if the tests for ending the subordination period are satisfied for any three consecutive, non-overlapping four quarter periods ending after December 31, 2011, an additional 25% of the subordinated units will convert into an equal number of common units. The second early conversion of subordinated units may not occur, however, until at least one year following the end of the period for the first early conversion of subordinated units.

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In addition to the early conversion of subordinated units described above, all of the subordinated units will convert into an equal number of common units if the following tests are met:

•  distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $2.10 (150% of the annualized minimum quarterly distribution) for each of the two consecutive, non-overlapping four-quarter periods ending on or after December 31, 2010; and

•  the adjusted operating surplus generated during each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of a distribution of $2.10 per unit (150% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units and the related distributions on our general partner’s 2% general partner interest during those periods on a fully diluted basis.

Adjusted Operating Surplus.  We define adjusted operating surplus in the partnership agreement, and for any period, it generally means:

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

•  any net reduction 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 decrease in working capital borrowings with respect to that period;plus

•  any net reduction 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.

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes cash on hand at the closing of this offering, the operating surplus “basket,” net increases in working capital borrowings, and net drawdowns of reserves of cash generated in prior periods.

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.

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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 below 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. Except in connection with the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, our general partner’s 2% general partner 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 our partnership agreement.

The following discussion assumes that the general partner maintains its 2% general partner interest and 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 $0.4025 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 $0.4375 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 $0.525 per unit for that quarter (the “third target distribution”); and

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

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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 required to maintain its 2% general partner interest and has not transferred any of the incentive distribution rights.

		Marginal Percentage
	Total Quarterly Distribution Per Unit	Interest in Distributions
	Target Amount	Unitholders			General Partner
Minimum Quarterly Distribution	$0.35		98	%		2	%
First Target Distribution	above $0.35 up to $0.4025		98	%		2	%
Second Target Distribution	above $0.4025 up to $0.4375		85	%		15	%
Third Target Distribution	above $0.4375 up to $0.525		75	%		25	%
Thereafter	above $0.525		50	%		50	%

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 any of the incentive distribution rights.

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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;

•  the target distribution levels;

•  the unrecovered initial unit price; 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 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 court of competent jurisdiction or a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to a material amount of entity-level taxation 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 (after deducting our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation) 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 our 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;

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•  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 any of 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 that results, to the extent possible, in the general partner’s capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table presents selected historical financial data of the Chevron Properties and the selected consolidated and combined historical financial data of the Retained Subsidiaries and Resolute Aneth, each of which are subsidiaries of Resolute Holdings and are collectively referred in this prospectus as “Resolute Energy Partners Predecessor,” and selected pro forma financial data of Resolute Energy Partners, LP. In addition, because they are considered a predecessor to Resolute Energy Partners Predecessor, we include statements of revenue and direct operating expenses for the Chevron Properties covering the year ended December 31, 2003, and the eleven-month period ended November 30, 2004.

The selected historical financial data have been prepared on the following basis:

•  the historical financial information of the Chevron Properties for the year ended December 31, 2003, and eleven-month period ended November, 30, 2004, the date on which we acquired the Chevron Properties, was derived from audited statements of revenue and direct operating expenses related to the Chevron Properties;

•  the historical consolidated and combined financial information of Resolute Energy Partners Predecessor as of December 31, 2004, and for the period of Inception (January 22, 2004) to December 31, 2004, and as of and for the years ended December 31, 2005 and 2006, have been derived from the audited financial statements of Resolute Energy Partners Predecessor; and

•  the historical financial information of Resolute Energy Partners Predecessor as of and for the six months ended June 30, 2006 and 2007, have been derived from the unaudited historical financial statements of Resolute Energy Partners Predecessor.

The historical financial information covering the Chevron Properties does not include depreciation, depletion and amortization expense, corporate overhead expenses, income taxes and other non-operating expenses incurred by Chevron during the period presented. This information, as well as the historical financial information covering the Chevron Properties for the year ended December 31, 2002, are not available to us. Furthermore, it is our belief that these corporate-level expenses incurred by a major integrated oil company are not comparable to corporate-level expenses that would be incurred by a much smaller company like ours.

The selected pro forma financial data for the year ended December 31, 2006, and as of and for the six months ended June 30, 2007, set forth in the following table are derived from the unaudited pro forma financial statements of Resolute Energy Partners, LP included elsewhere in this prospectus. The historical combined financial statements of Resolute Energy Partners Predecessor include the results of the Retained Subsidiaries. The Retained Subsidiaries will not be contributed to us in connection with the closing of this offering. The pro forma statements of operations for the year ended December 31, 2006, and as of and for the six months ended June 30, 2007, have been prepared to reflect the elimination, as of January 1, 2006, of the Retained Subsidiaries from the combined financial information of Resolute Energy Partners Predecessor. The pro forma balance sheet as of June 30, 2007, has been prepared to reflect this same elimination as though it occurred on June 30, 2007. The unaudited pro forma financial statements of Resolute Energy Partners, LP give pro forma effect to the following significant transactions:

•  our acquisition of the ExxonMobil Properties as though that acquisition had occurred on January 1, 2006, in the case of the statements of operations, or as of June 30, 2007, in the case of the balance sheet;

•  the retention by Resolute Holdings of the Retained Subsidiaries and the distribution by Resolute Aneth of $7.5 million of working capital to Resolute Holdings;

•  the contribution by Resolute Holdings to Resolute Energy Operating, LLC of Resolute Aneth, and the contribution to us of Resolute Energy Operating, LLC by Resolute Holdings and our general partner in exchange for our issuance of 6,651,316 common units and 20,401,316 subordinated units, representing a 65% limited partner interest in us, a 2% general partner interest in us and all of our incentive distribution rights;

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•  our sale of 13,750,000 common units to the public;

•  the use of the proceeds from this offering to repay all of the outstanding indebtedness under our existing revolving credit facility, which we expect to be approximately $1.7 million more than the outstanding balance as of June 30, 2007, and a portion of the outstanding indebtedness under our existing term loan facility and to replenish the $7.5 million of working capital previously distributed to Resolute Holdings, as described above; and

•  our borrowing of $151.0 million of indebtedness under our new revolving credit facility to repay the remaining balance under our existing term loan facility.

The selected pro forma financial data should not be considered as indicative of the historical results we would have had or the results we will have after this offering. You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical consolidated and combined financial statements of Resolute Energy Partners Predecessor and notes thereto, the unaudited pro forma consolidated financial statements of Resolute Energy Partners, LP and notes thereto and the audited statements of revenues and direct operating expenses of the Chevron Properties and the ExxonMobil Properties included elsewhere in this prospectus. Among other things, the historical and pro forma financial statements include more detailed information regarding the basis of presentation for the following information. In addition, the pro forma financial information does not include the estimated $3.1 million of annual incremental general and administrative expenses that we expect to incur as a result of being a publicly traded partnership.

The following table includes Adjusted EBITDA, which is a financial measure not calculated in accordance with GAAP. We explain this measure below and reconcile it to the most directly comparable financial measures calculated and presented in accordance with GAAP. Please read “Summary — Non-GAAP Financial Measures.”

																				Pro Forma
																				Resolute Energy
					Resolute Energy Partners Predecessor															Partners, LP
	Chevron Properties				January 22,
			Eleven Months		2004																		Six Months
	Year Ended		Ended		(Inception) to			Year Ended						Six Months Ended						Year Ended			Ended
	December 31,		November 30,		December 31,			December 31,						June 30,						December 31,			June 30,
	2003		2004		2004(1)			2005			2006(2)			2006(2)			2007			2006			2007
	(In thousands)
Statements of Operations Data:
Revenues:
Oil	$	24,878	$	27,370	$	2,468		$	39,198		$	102,000		$	40,090		$	57,646		$	120,167		$	57,646
Gas(3)		389		257		(179	)		681			836			331			242			851			242
Other				—		101			2,094			3,735			1,350			2,371			4,516			2,371
Total revenues		25,267		27,627		2,390			41,973			106,571			41,771			60,259			125,534			60,259
Operating expenses:
Lease operating(4)		7,570		6,526		658			8,734			24,857			9,405			16,507			27,181			16,507
Workover		—		—		21			3,860			13,312			4,437			5,700			14,351			5,700
Production taxes		2,813		2,972		340			2,772			7,806			3,062			4,536			9,279			4,536
General and administrative(4)		—		—		2,415			3,281			6,015			2,172			34,617			5,613			32,960
Depletion, depreciation, and amortization		—		—		407			4,680			11,071			4,140			7,915			12,150			7,641
Accretion of asset retirement obligations		—		—		20			216			206			95			145			222			145
Total operating expenses		10,383		9,498		3,861			23,543			63,267			23,311			69,420			68,796			67,489
Operating income (loss)	$	14,884	$	18,129		(1,471	)		18,430			43,304			18,460			(9,161	)		56,738			(7,230	)
Other income (expense):
Other income						51			147			546			262			266			361			216
Gain (loss) on derivative instruments						3,592			(28,852	)		10,895			(24,569	)		(19,541	)		10,895			(19,541	)
Interest expense						(190	)		(2,545	)		(18,121	)		(6,149	)		(12,545	)		(9,760	)		(4,810	)
Total other income (expense)						3,453			(31,250	)		(6,680	)		(30,456	)		(31,820	)		1,496			(24,135	)

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																		Pro Forma
																		Resolute Energy
			Resolute Energy Partners Predecessor															Partners, LP
	Chevron Properties		January 22,
		Eleven Months	2004																	Six Months
	Year Ended	Ended	(Inception) to			Year Ended						Six Months Ended						Year Ended		Ended
	December 31,	November 30,	December 31,			December 31,						June 30,						December 31,		June 30,
	2003	2004	2004(1)			2005			2006(2)			2006(2)			2007			2006		2007
	(In thousands)
Income (loss) before income taxes				1,982			(12,820	)		36,624			(11,996	)		(40,981	)		58,234		(31,365	)
Income tax provision				(742	)		(3,830	)		—			—			—			—		—
Net income (loss)			$	1,240		$	(16,650	)	$	36,624		$	(11,996	)	$	(40,981	)	$	58,234	$	(31,365	)
Net income per limited partner unit																		$	1.40	$	(0.75	)
Other Financial Data (unaudited):
Adjusted EBITDA			$	(784	)	$	17,780		$	52,546		$	20,254		$	33,963		$	67,075	$	34,212
Balance Sheet Data (at period end):
Working capital			$	530		$	(1,862	)	$	(6,939	)	$	(11,910	)	$	(7,477	)			$	(2,762	)
Total assets				97,498			106,563			376,733			357,381			445,559					425,331
Long-term debt				44,000			45,925			267,500			271,350			395,250					150,975
Shareholder’s/member’s/partners’ equity (deficit)(5)				44,997			28,698			61,860			15,163			(45,008	)				185,367
Cash Flow Data:
Net cash provided by (used in):
Operating activities			$	(2,225	)	$	11,516		$	31,756		$	(5,296	)	$	16,694
Investing activities				(84,541	)		(14,402	)		(242,388	)		(225,324	)		(45,560	)
Financing activities				87,377			2,275			214,323			220,416			25,175

(1)	Includes the results of operations of the Chevron Properties for the period beginning on the date of acquisition, November 30, 2004.
(2)	Includes the results of operations of the ExxonMobil Properties for the period beginning on the date of acquisition, April 14, 2006.
(3)	We acquired the Chevron Properties on November 30, 2004. In conjunction with the revenue distribution for plant operations during December 2004, our proceeds were adjusted for the recovery of gas imbalances related to differences between our equity gas produced and our gas plant entitlements, which resulted in us recognizing gas revenues of $(179,000) during the period January 22, 2004 (Inception) to December 31, 2004.
(4)	During the six months ended June 30, 2007, general and administrative expense included a non-cash charge to compensation expense of $32.4 million associated with equity-based compensation recognized during the period pursuant to FAS 123R. This non-cash charge relates to incentive compensation provisions in the operating agreement between Natural Gas Partners and management. In June 2007, Resolute Holdings made a $100.0 million cash distribution to its members that met a financial requirement for a portion of management’s incentive compensation units to vest, triggering this compensation expense. Please read “Note 4 — Shareholder’s/Member’s Equity (Deficit)” to the unaudited condensed combined financial statements of Resolute Energy Partners Predecessor atF-49. An additional $0.3 million non-cash charge was allocated to lease operating expense related to the same equity-based compensation.
(5)	In June 2007, Resolute Holdings made a $100.0 million cash distribution to its members. This distribution represented a return on equity and consequently is reflected in our financial statements by a similar reduction to our Shareholder’s/Member’s/Partner’s equity (deficit) as of June 30, 2007.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The historical financial statements included in this prospectus beginning onpage F-1 reflect the assets, liabilities and operations of Resolute Energy Partners Predecessor. Not all of the assets and operations of Resolute Energy Partners Predecessor will be contributed to us in connection with this offering. You should read the following discussion of the financial condition and results of operations in conjunction with the historical consolidated and combined financial statements and notes and the pro forma financial statements included elsewhere in this prospectus.

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties, many of which are outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and gas, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

General.  We are an independent oil and gas partnership engaged in the exploitation and development of our properties in the Greater Aneth Field, a mature, long-lived oil producing field located in the Paradox Basin on the Navajo Reservation in southeast Utah. We own a majority of the working interests in, and are the operator of, three (out of a total of four) federal production units covering approximately 43,000 gross acres of the Greater Aneth Field. These units are the Aneth Unit, in which we own a 62% working interest, the McElmo Creek Unit, in which we own a 75% working interest, and the Ratherford Unit, in which we own a 59% working interest. As of June 30, 2007, we had interests in, and operated, 402 gross (265 net) active producing wells and 335 gross (219 net) active water and CO₂ injection wells on our Aneth Field Properties. The crude oil produced from our Aneth Field Properties is generally characterized as light, sweet crude oil that is highly desired as a refinery blending feedstock. Substantially all of our revenues are generated from the sale of oil production.

As of June 30, 2007, our estimated net proved reserves were approximately 78.1 MMBoe, of which approximately 44% were proved developed reserves and approximately 99% were oil. The standardized measure of our estimated net proved reserves as of June 30, 2007, was $1.16 billion. For additional information about the calculation of our standardized measure, please see “Business — Estimated Net Proved Reserves.” We believe our Aneth Field Properties are well-suited for our partnership because they have relatively predictable production profiles based on a long history of production, a shallow expected annual decline rate of approximately 6% and a high reserves to production ratio.

We believe that significantly more oil can be recovered from our Aneth Field Properties through industry standard secondary and tertiary recovery techniques. We have evaluated a number of ongoing exploitation activities that we expect will expand our proved developed reserve base. These activities employ technologies that have been used successfully in the Greater Aneth Field and elsewhere. We believe that none of the previous operators of our Aneth Field Properties had committed the capital or attention necessary to fully undertake these activities.

We have identified a nine-year program of work that includes CO₂ flood, waterflood expansions, field infrastructure enhancements, recompletions, workovers of producing and injection wells, infill drilling and other activities. Our activities to date have succeeded in increasing our estimated proved reserves from 54.6 MMBoe (including a small acquisition in addition to the acquisition of the Chevron Properties and ExxonMobil Properties), based on evaluations made at the time of the acquisitions, to 78.1 MMBoe based on our June 30, 2007, reserve report, which represents a 43% increase.

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We focus our efforts on increasing reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flow from operations are dependent on our ability to manage our overall cost structure to a level that allows for profitable production.

Our Acquisitions.  We acquired our Aneth Field Properties primarily through two significant acquisitions. We completed our acquisition of the Chevron Properties in November 2004 and our acquisition of the ExxonMobil Properties in April 2006. We acquired our Aneth Field Properties in connection with our strategic alliance with NNOG. NNOG owns a minority interest in each of the Chevron Properties and the ExxonMobil Properties and possesses options to purchase additional minority interests in those properties from us if certain financial hurdles are met. See “Business — Relationship with the Navajo Nation” for additional information about our relationship with the Navajo Nation and NNOG’s purchase options.

Chevron Properties.  On November 30, 2004, we acquired 75% of Chevron’s interests in the Greater Aneth Field. The purchase price for our interests was approximately $86.2 million, including transaction costs and post-closing adjustments. Our acquisition was financed with a combination of the equity invested in Resolute Holdings by management and by Natural Gas Partners and borrowings under our revolving credit facility. As a result of the acquisition, we acquired a 53% operated interest in the Aneth Unit as well as a 15% non-operated interest in the McElmo Creek Unit and a 3% non-operated interest in the Ratherford Unit. The interests we acquired represented total proved reserves, as evaluated at the time of acquisition, of 18.8 MMBoe with gross production during the fourth quarter of 2004 of approximately 9,580 Bbl/d. The reserves attributable to these interests consisted of approximately 98% oil and 2% gas.

ExxonMobil Properties.  On April 14, 2006, we acquired 75% of ExxonMobil’s interests in the Greater Aneth Field. Our properties included a 7.5% non-operated working interest in the Aneth Unit, a 60% operated working interest in the McElmo Creek Unit and a 56% operated working interest in the Ratherford Unit along with various other related assets, including ExxonMobil’s interest in the Aneth Gas Plant, its interest in a CO₂ pipeline that serves the field, and office facilities in Cortez, Colorado. In connection with the acquisition, ExxonMobil reserved an overriding royalty interest in certain deep, undeveloped portions of the field. The acquisition price for our interests was approximately $214.5 million, including the amount paid at closing and post-closing adjustments. Our acquisition was financed with borrowings under our existing revolving credit facility and a term loan facility. In addition to the cash purchase price, we are obligated to make certain contingent payments to ExxonMobil based on the posted price of West Texas Sour, or “WTS,” crude oil. The maximum amount payable by us to ExxonMobil under these contingent payments in any month is $666,667, and this obligation expires at the end of 2007. Through June 30, 2007, we had made payments to ExxonMobil totaling $8.4 million. Our maximum remaining exposure for contingent payments through December 31, 2007 is $4.0 million. Please see “— Off-Balance Sheet Obligations” for information about this contingency. As of June 30, 2007, our total purchase price, including post-closing adjustments, contingent payments and certain capitalized expenses associated with the acquisition, was $218.2 million.

Our Financial Statements.  Our financial information included in this prospectus presents audited historical consolidated financial statements for Resolute Energy Partners Predecessor as of and for the period from its inception on January 22, 2004, through December 31, 2004, audited historical combined and consolidated financials statements for Resolute Energy Partners Predecessor as of and for each of the two years ended December 31, 2005 and 2006, and unaudited historical combined financial statements for Resolute Energy Partners Predecessor as of and for the six-month periods ended June 30, 2006 and 2007.

We have also included certain financial information for the Chevron Properties and the ExxonMobil Properties. For the Chevron Properties, that information consists of audited statements of revenues and direct operating expenses for the year ended December 31, 2003, and the eleven months ended November 30, 2004. For the ExxonMobil Properties, that information consists of audited statements of revenues and direct operating expenses as of and for the years ended December 31, 2003, 2004 and 2005, and an unaudited statement of revenues and direct operating expenses for the three-month periods ended March 31, 2005 and 2006. None of those financial statements include depreciation, depletion and amortization expenses, corporate overhead expenses, income taxes or any other non-operating expenses during the periods presented. This information is not available to us. It is our belief that these corporate-level expenses as incurred by a major

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integrated oil company are not comparable to corporate-level expenses that would be incurred by a much smaller company like ours.

You should be aware that the historical statements of revenues and direct operating expenses for the Chevron Properties and the ExxonMobil Properties are not indicative of the financial condition or results of operations of those assets following the respective dates of our acquisitions of such assets because of the omission of all corporate-level expenses from those financial statements and because of our significantly higher level of exploitation of the properties compared to that of either Chevron or ExxonMobil during the periods covered by the financial presentations. Accordingly, we have not included a discussion of those historical statements of revenues and direct operating expenses in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

In evaluating historical financial information, you should keep in mind that the business of our predecessor entities had three distinct phases. From inception in January 2004 until our acquisition of the Chevron Properties in November 2004, we had no producing assets. Our financial results reflected mainlystart-up operating expenses. From our acquisition of the Chevron Properties in November 2004 until the acquisition of the ExxonMobil Properties in April 2006, our financial results reflect our ownership and operation of the Chevron Properties and the financial arrangements that we made to acquire them. Subsequent to the acquisition of the ExxonMobil Properties, our financial results reflect our increased level of ownership and operations of our Aneth Field Properties, and the increased indebtedness we incurred to finance the acquisition of the ExxonMobil Properties.

Our Customer.  All of our current crude oil production is sold to Giant Industries, Inc., which was acquired by and became a subsidiary of Western Refining, Inc., in May 2007. Giant has two refineries in the Four Corners area, the 16,600 Bbl/d Bloomfield refinery in Farmington, New Mexico, and the 26,000 Bbl/d Ciniza refinery in Gallup, New Mexico. Giant refines our crude oil in its refineries. Our crude oil production is transported to a terminal that serves these two refineries via an oil pipeline owned by NNOG.

Our crude oil production is sold to Giant pursuant to two contracts, one covering crude oil production from the Chevron Properties and one covering crude oil production from the ExxonMobil Properties. The contracts provide for a price equal to the NYMEX price for crude oil less a fixed differential of $2.55 per Bbl under the contract covering production from the ExxonMobil Properties and $2.20 per Bbl under the contract covering production from the Chevron Properties. The weighted average differential under these two contracts is approximately $2.40 per Bbl based on production at June 30, 2007. The two contracts, each covering about one-half of our production and each with a six-month term that commenced on June 1, 2007, contain evergreen provisions that provide for Giant to continue to purchase the production on a month-to-month basis on the same economic terms. After November 30, 2007, Giant has the right to terminate our contracts upon 180 days notice and cease purchasing crude oil from us. We currently are negotiating a series of longer term agreements with Giant that we expect will provide for crude oil sales from our Aneth Field Properties based on NYMEX crude oil prices less a specified differential.

Our gas production is minimally processed in the field and then sent via pipeline to the San Juan River Gas Plant for further processing. We sell our gas at daily market prices to numerous purchasers at the tailgate of the plant, and we receive a contractually specified percentage of the proceeds from the sale of gas plant products.

For additional information about the marketing and sale of our crude oil and gas production and related risks, please see “Business — Marketing and Customers” and “Risk Factors — We depend on one customer for all of our sales of crude oil production. Furthermore, we operate in a remote location and do not readily have access to markets for our crude oil production other than our current customer. The loss of that customer for any reason or the failure of that customer to pay for the crude oil we have delivered for sale could have a material adverse effect on our financial results and ability to make cash distributions to our unitholders.”

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How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include the following: (1) production levels, trends and prices, (2) reserve volumes and trends, (3) operating expenses and general and administrative expenses, (4) operating cash flow and (5) Adjusted EBITDA.

Production Levels, Trends and Prices.  Oil and gas revenue is the product of our production multiplied by the price that we receive for that production. Because the price that we receive is highly dependent on many factors outside of our control, except to the extent that we have entered into hedging arrangements that can influence our net price either positively or negatively, production is the primary revenue driver over which we have some influence. Although we cannot greatly alter reservoir performance, we can aggressively implement exploitation activities that can increase production or diminish production declines relative to what would have been the case without our intervention. Examples of activities that can positively influence production include minimizing production downtime due to equipment malfunction, well workovers and cleanouts, recompletions of existing wells in new parts of the reservoir, drilling of new wells, and expanded secondary and tertiary recovery programs.

The average sales prices we received for crude oil rose in 2006 compared to 2005. Before the effects of hedging contracts, the average price we received for crude oil in 2006 was $64.23 per Bbl compared to $54.44 per Bbl in 2005. The price that we received for our crude oil production declined during the first quarter of 2007, as the average price we received was $55.75 per Bbl, although prices rebounded in the second quarter to an average price of $62.57 per Bbl.

In the past, the price of crude oil has been extremely volatile, and we expect this volatility to continue. For example, during the six months ended June 30, 2007, the NYMEX West Texas Intermediate crude oil price ranged from a high of $70.68 per barrel to a low of $50.48 per barrel. For the five years ended December 31, 2006, the NYMEX crude oil price ranged from a high of $77.03 per barrel to a low of $17.97 per barrel. Given the inherent volatility of crude oil prices, which are influenced by many factors beyond our control, we plan our activities and budget based on sales price assumptions that we believe are reasonable.

We use hedging arrangements to manage price fluctuations and achieve a more predictable cash flow. These instruments limit our exposure to declines in prices, but also limit our expected benefits if prices increase. When prices for crude oil are volatile, a significant portion of the effect of our proved producing management activities consists of non-cash income or expenses due to changes in the fair value of hedging arrangements. Recognized gains or losses only arise from payments made or received on monthly settlements of contracts or if a contract is terminated prior to its expiration. We currently plan to enter into hedging arrangements that will cover at least 75% of our estimated future crude oil production from proved developed producing reserves for the next five years. Please read “— Quantitative and Qualitative Disclosure About Market Risk — Commodity Price Risk and Hedging Arrangements.”

Reserve Volumes and Trends.  Our reserve volumes have grown significantly over the last several years and consist of high quality, long-lived oil producing properties. We acquired the Chevron Properties on November 30, 2004, purchasing 18.8 MMBoe at an acquisition cost of $4.59 per Boe of estimated net proved reserves. Since then, our reserves have increased to 78.1 MMBoe as of June 30, 2007, an increase of more than 300%. The largest component of this growth was the purchase of the ExxonMobil Properties on April 14, 2006, consisting of 35.3 MMBoe at an acquisition cost of $6.18 per Boe of estimated net proved reserves. The balance, 24.0 MMBoe, resulted from our work in identifying projects to extract additional reserves from the reservoir. The major portion of this increase is directly related to the extensions and expansions of our CO₂ flood projects. We currently estimate that these CO₂ projects will have a future development cost of $5.11 per Boe. We will continue our geologic and engineering studies to further develop and produce the oil resource and maximize the economic development of the original oil in place. Our immediate focus will remain that of continuing to convert the undeveloped portion of our reserves to producing status.

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Operating Expenses and General and Administrative Expenses.

•  Operating Expenses.  Operating expenses are costs associated with the operation of oil and gas properties. Direct labor, severance, ad valorem and similar taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. We assess our operating expenses in part by monitoring the expenses in relation to the amount of production and the number of wells operated. Some of these expenses are relatively independent of the volume of hydrocarbons we produce, but may fluctuate slightly depending on the activities performed during a specific period. Other expenses, such as certain taxes and utility costs, are more directly related to the volumes that we produce. Severance taxes, for example, are charged based on production revenues and therefore are based on the product of the volumes that we produce and the price that we receive for our production. Ad valorem taxes are based on the value of our reserves. Because we operate on the Navajo Reservation, we also pay a possessory interest tax, which is effectively an ad valorem tax assessed by the Navajo Nation. Our largest utility expense is for electricity that is used primarily to power the pumps in producing wells and the compression behind the injection wells. The more fluid that we move, the greater the amount of electricity that we consume. Recent higher oil prices have led to higher demand for drilling rigs, operating personnel and field supplies and services, which in turn have caused increases in the costs of those goods and services.

•  General and Administrative Expenses.  In addition, we also review our general and administrative expenses, a substantial amount of which is incurred through Resolute Holdings and allocated to us. For the year ended December 31, 2006, and the six months ended June 30, 2007, our general and administrative expense was $6.0 million and $34.6 million, respectively. Our general and administrative expenses for the six months ended June 30, 2007, included a non-cash charge to compensation expense of $32.4 million associated with equity-based compensation recognized during the period pursuant to FAS 123R. An additional $0.3 million non-cash charge was allocated to lease operating expense related to the same equity-based compensation. Pursuant to the administrative services agreement we will enter into with our general partner and affiliates of Resolute Holdings in connection with the completion of this offering, we will reimburse the affiliates of Resolute Holdings for expenses incurred on our behalf, including operating, general and administrative and insurance expenses related to our businesses and properties as well as insurance expenses related to director and officer liability coverage.

We anticipate initially incurring approximately $3.1 million of additional general and administrative expenses per year, most of which will be allocated to us by Resolute Holdings, associated with our being a publicly traded limited partnership. These public limited partnership expenses include compensation and benefit expenses of certain additional personnel, costs associated with reports to unitholders, tax return andSchedule K-1 preparation and distribution, fees paid to independent auditors, lawyers, independent petroleum engineers and other professional advisors, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation.

Operating Cash Flow.  Operating cash flow is the cash directly derived from our oil and gas properties, before considering such things as administrative expenses and interest costs. Operating cash flow on a per unit of production basis is a measure of field efficiency, and can be compared to results obtained by operators of oil and gas properties with characteristics similar to ours to evaluate our relative performance. Aggregate operating cash flow is a measure of our ability to sustain our overhead expenses and our costs related to our capital structure, including interest expenses and our distributions to our partners.

Adjusted EBITDA.  We define Adjusted EBITDA as net income plus net interest expense, income taxes, depletion, depreciation and amortization, amortization of deferred financing costs, accretion of asset retirement obligation, change in fair value of derivative instruments and non-cash equity-based compensation expense. This definition is consistent with the definition of EBITDA in our existing credit agreements, and we anticipate that it will be incorporated into our new revolving credit facility.

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Adjusted EBITDA is used as a supplemental liquidity measure by our management 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 capital expenditures.

Adjusted EBITDA is also a financial measure that we expect will be reported to our lenders and used as a gauge for compliance with some of our anticipated financial covenants under our new revolving credit facility.

Adjusted EBITDA is also used as a supplemental performance measure by our 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;

•  our operating performance and return on capital as compared to those of other companies in the exploration and production industry, without regard to financing methods or capital structure; and

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

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. Adjusted EBITDA does not include interest expense, income taxes or depreciation, depletion 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 gross margins. Because we use capital assets, depreciation, depletion and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and our liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income, operating income and net cash provided by operating activities and these measures may vary among companies. Our Adjusted EBITDA may not be comparable to Adjusted EBITDA or EBITDA of another company because other entities may not calculate these measures in the same manner.

Factors That Significantly Affect Our Results

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Crude oil prices have historically been volatile and may fluctuate widely in the future. Sustained periods of low prices for crude oil could materially and adversely affect our financial position, our results of operations, the quantities of oil and gas that we can economically produce, our ability to access capital and our ability to make cash distributions to you.

Like all businesses engaged in the exploration for and production of oil and gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and gas production from a given well decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or gas it produces. We attempt to overcome this natural decline by implementing secondary and tertiary recovery techniques and by acquiring more reserves than we produce. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus on costs necessary to produce our reserves as well as the

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costs necessary to add reserves through production enhancement, drilling and acquisitions. Our ability to make capital expenditures to increase production from our existing reserves and to acquire more reserves is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost-effective manner and to timely obtain permits and regulatory approvals.

You should read this “Management’s Discussion and Analysis of our Financial Condition and Results of Operations” in conjunction with our historical and pro forma financial statements included elsewhere in this prospectus. Below are the period-to-period comparisons of the historical results and the analysis of the financial condition of the Resolute Energy Partners Predecessor. In addition to the impact of the matters discussed in “Risk Factors,” our historical results have differed materially from period to period and our future results could differ materially from Resolute Energy Partners Predecessor’s historical results due to a variety of factors, including the following:

•  We made two significant acquisitions during the periods covered by our historical financial statements. We acquired the Chevron Properties on November 30, 2004, and the ExxonMobil Properties on April 14, 2006, and, accordingly, our financial results for those periods do not reflect the financial results of those assets for the periods prior to acquisition.

•  We incurred approximately $217.1 million of new indebtedness to fund the acquisition of the ExxonMobil Properties on April 14, 2006, including our initial contribution to the related abandonment liability escrow account and other payments related to the transaction.

•  As of June 30, 2007, we had in place oil hedges covering approximately 67.1% of our anticipated oil production from proved developed producing reserves for the remainder of 2007 at a weighted average price of $71.76, approximately 62.7% of our anticipated oil production from proved developed producing reserves for 2008 at a weighted average price of $70.16 and approximately 51.5% of our anticipated oil production from proved developed producing reserves for 2009 through 2012 at a weighted average price of $63.07.

•  According to our reserve report, at June 30, 2007, approximately 44 MMBoe of our estimated net proved reserves were classified as proved undeveloped, of which approximately 93% were attributable to recoveries associated with expansions and extensions of the CO₂ flood projects that we have begun to implement. We have spent approximately $28.4 million on CO₂ flood projects through June 30, 2007, in connection with bringing incremental proved undeveloped reserves into production, and we expect to spend an additional $209.1 million on CO₂ flood projects over the next 20 years (including purchases of CO₂ under existing contracts), approximately $62 million of which we expect to spend during the second half of 2007 and all of 2008 and approximately $101 million of which we expect to spend from 2009 through 2012. We expect these CO₂ flood projects to result in an average future development cost per unit of approximately $5.11 per Boe. A portion of the capital expenditures associated with our CO₂ flood projects are reflected in our historical financial statements.

•  During the six months ended June 30, 2007, general and administrative expense included a non-cash charge to compensation expense of $32.4 million associated with equity-based compensation recognized during the period pursuant to FAS 123R. This non-cash charge relates to incentive compensation provisions in the operating agreement between Natural Gas Partners and management. In June 2007, Resolute Holdings made a $100.0 million cash distribution to its members that met a financial requirement for a portion of management’s incentive compensation units to vest, triggering this compensation expense. Please read “Note 4 — Shareholder’s/Member’s Equity (Deficit)” to the unaudited condensed combined financial statements of Resolute Energy Partners Predecessor at F-49. An additional $0.3 million non-cash charge was allocated to lease operating expense related to the same equity-based compensation.

•  On June 27, 2007, we incurred $102.5 million of new indebtedness to finance a $100 million distribution to the members of Resolute Holdings. The interest costs associated with that debt were only reflected in our statement of operations for the six months ended June 30, 2007, for three days.

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•  The historical financial results of Resolute Energy Partners Predecessor include the results of the Retained Subsidiaries, which will not be contributed to us in connection with the closing of the offering and the other formation transactions described in this prospectus.

•  We anticipate initially incurring approximately $3.1 million of additional general and administrative expenses per year, most of which will be allocated to us by Resolute Holdings, associated with our being a publicly traded limited partnership. These public limited partnership expenses include compensation and benefit expenses of certain additional personnel, costs associated with reports to unitholders, tax return andSchedule K-1 preparation and distribution, fees paid to independent auditors, lawyers, independent petroleum engineers and other professional advisors, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation.

Results of Operations

Set forth in the table below is our financial and operating data for the periods indicated. The historical financial and operating data set forth in the table and related discussion are derived from the historical financial statements of Resolute Energy Partners Predecessor.

	Resolute Energy Partners Predecessor
	January 22,
	2004
	(Inception) to			Year Ended						Six Months Ended
	December 31,			December 31,						June 30,
	2004(1)			2005			2006(2)			2006(2)			2007
	(In thousands)
Statements of Operations Data:
Revenues:
Oil	$	2,468		$	39,198		$	102,000		$	40,090		$	57,646
Gas		(179	)		681			836			331			242
Natural gas liquids		20			1,121			3,008			1,002			1,860
Other		81			973			727			348			511
Total revenues		2,390			41,973			106,571			41,771			60,259
Operating expenses:
Production:
Lease operating		658			8,734			24,857			9,405			16,507
Workover		21			3,860			13,312			4,437			5,700
Production taxes		340			2,772			7,806			3,062			4,536
General and administrative		2,415			3,281			6,015			2,172			34,617
Depletion, depreciation, and amortization		407			4,680			11,071			4,140			7,915
Accretion of asset retirement obligations		20			216			206			95			145
Total operating expenses		3,861			23,543			63,267			23,311			69,420
Operating income (loss)		(1,471	)		18,430			43,304			18,460			(9,161	)
Other income (expense):
Other income		51			147			546			262			266
Gain (loss) on derivative instruments		3,592			(28,852	)		10,895			(24,569	)		(19,541	)
Interest expense		(190	)		(2,545	)		(18,121	)		(6,149	)		(12,545	)
Total other income (expense)		3,453			(31,250	)		(6,680	)		(30,456	)		(31,820	)
Income (loss) before income taxes		1,982			(12,820	)		36,624			(11,996	)		(40,981	)
Income tax provision		(742	)		(3,830	)		—			—			—
Net income (loss)	$	1,240		$	(16,650	)	$	36,624		$	(11,996	)	$	(40,981	)

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	Resolute Energy Partners Predecessor
	January 22,
	2004
	(Inception) to			Year Ended				Six Months Ended
	December 31,			December 31,				June 30,
	2004(1)			2005		2006(2)		2006(2)		2007
Production Sales Data:
Oil (MBbl)		60			720		1,588		606		973
Gas (MMcf)		(11	)		136		227		81		92
Natural gas liquids (MBbl)		1			56		91		33		58
Combined volumes (MBoe)		59			799		1,717		653		1,046
Daily combined volumes (Boe/d)		1,922			2,189		4,704		3,608		5,779
Average Realized Prices (including hedges):
Oil ($/Bbl)	$	44.62		$	46.53	$	62.72	$	61.80	$	61.64
Gas ($/Mcf)		—			5.01		3.68		4.09		2.63
Average Costs ($/Boe):
Lease operating expense	$	11.15		$	10.93	$	14.48	$	14.40	$	15.78
Production tax expense		5.76			3.47		4.55		4.69		4.34
Depreciation, depletion and amortization		6.90			5.86		6.45		6.34		7.57
General and administrative		40.93			4.11		3.50		3.33		33.09

(1)	Includes the results of operations of the Chevron Properties for the period beginning on the date of acquisition, November 30, 2004.
(2)	Includes the results of operations of the ExxonMobil Properties for the period beginning on the date of acquisition, April 14, 2006.

Six Months Ended June 30, 2007, Compared to Six Months Ended June 30, 2006

The financial information discussed below with respect to the six months ended June 30, 2007 and 2006, is unaudited. In the opinion of management, this information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for such periods. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Revenue.  Oil, gas and natural gas liquids revenues increased to approximately $59.7 million during the six months ended June 30, 2007 from $41.4 million during the six months ended June 30, 2006. Total revenue, including gas plant revenue, increased to approximately $60.3 million from $41.8 million during the six months ended June 30, 2007, as compared to the six months ended June 30, 2006. The key revenue measurements were as follows:

					Percentage
	Six Months Ended June 30,				Increase
	2006		2007		(Decrease)
Net Sales:
Total sales (Boe)		652,240		1,045,865		60	%
Average daily sales (Boe/d)		3,608		5,779		60	%
Average Sales Prices ($/Boe):
Average sales price (including hedges)	$	59.93	$	59.84		0	%
Average sales price (excluding hedges)	$	64.04	$	57.62		(10	%)

The increase in revenue from oil, gas and natural gas liquids sales resulted from the increase in production to 1,046 MBoe during the six months ended June 30, 2007, from 652 MBoe during the six months ended June 30, 2006, due primarily to the acquisition of the ExxonMobil Properties but also due in part to our ongoing efforts to enhance day-to-day production.

Operating Expenses.  Production expenses consist of lease operating expenses, including labor, field office rent, vehicle expenses, supervision, transportation, minor maintenance, tools and supplies, workover

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expenses, ad valorem, severance and other taxes and other customary charges. We assess our production expenses in part by monitoring the expenses in relation to the amount of production and the number of wells operated. Production expenses increased to $26.7 million for the six months ended June 30, 2007, from $16.9 million for the six months ended June 30, 2006. The primary reason for the increase is that we acquired the ExxonMobil Properties shortly after the end of the first quarter in 2006. Production expenses per Boe were essentially flat for the comparative periods.

					Percentage
	Six Months Ended June 30,				Increase
	2006		2007		(Decrease)
Production expenses per Boe	$	25.89	$	25.57		(1.2	%)

General and administrative expenses include the costs of our employees and executive officers, related benefits, office leases, professional fees and other costs not directly associated with field operations. We monitor general and administrative expenses in relation to the amount of production and the number of wells operated. General and administrative expenses increased to $34.6 million from $2.2 million during the six months ended June 30, 2007, as compared to the six months ended June 30, 2006. The increase in the absolute level of general and administrative expenses in the six months ended June 30, 2007 versus 2006 resulted from recognition of a non-cash charge to compensation expenses pursuant to FAS 123R of $32.4 million associated with equity-based compensation recognized during the six months ended June 30, 2007, as well as other general and administrative expenses of $2.2 million.

					Percentage
	Six Months Ended June 30,				Increase
	2006		2007		(Decrease)
General and administrative expenses per Boe	$	3.33	$	33.09		894	%

Depreciation, depletion and amortization expenses increased to $7.9 million for the six months ended June 30, 2007, from $4.1 million for the six months ended June 30, 2006, due to the increase in production and a $1.23 per Boe increase in the depreciation, depletion and amortization rate attributable to an increase in our estimated future development costs on our Aneth Field Properties.

Other Income (Expense).  All of our oil hedging agreements are accounted for under mark-to-market accounting rules, which provide for the fair value of the contracts to be reflected as either an asset or a liability on our balance sheet. The change in the fair value during an accounting period is reflected in the income statement for that period. During the six months ended June 30, 2007, the fair value of our oil hedges decreased by $19.5 million. This amount included approximately $1.2 million of realized gains on our oil hedges and a $20.7 million decline in the future value of these hedges. During the six months ended June 30, 2007, we had oil swaps equal to approximately 66% of our oil production during the same period. During the six months ended June 30, 2006, the fair value of our oil hedges decreased by $24.6 million. This amount included approximately $2.6 million of realized losses on our oil hedges and a $22.0 million decline in the future value of these hedges. During the six months ended June 30, 2006, we had oil swaps equal to approximately 64% of our oil production during the same period. A significant portion of our estimated future production from our proved developed reserves is hedged through 2012. See “— Liquidity and Capital Resources.”

Interest expense was $12.5 million for the six months ended June 30, 2007, compared to $6.1 million for the six months ended June 30, 2006. The increase in interest expense was primarily because of additional indebtedness we incurred to finance the acquisition of the ExxonMobil Properties in April 2006.

Year Ended December 31, 2006, Compared to the Year Ended December 31, 2005

Revenue.  Oil, gas and natural gas liquids revenues increased to approximately $105.8 million during the year ended December 31, 2006 from $41.0 million during the year ended December 31, 2005. Total revenue, including gas plant revenue, increased to approximately $106.6 million during the year ended December 31,

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2006, from $42.0 million for the year ended December 31, 2005. The key revenue measurements were as follows:

					Percentage
	Year Ended December 31,				Increase
	2005		2006		(Decrease)
Net Sales:
Total sales (Boe)		798,558		1,716,307		115	%
Average daily sales (Boe/d)		2,189		4,704		115	%
Average Sales Prices ($/Boe):
Average sales price (including hedges)	$	45.41	$	60.67		34	%
Average sales price (excluding hedges)	$	52.56	$	62.09		18	%

The increase in revenue from oil, gas and natural gas liquids sales was due to both an increase in production and sales and an increase in the price that we received for our product. Production increased from 799 MBoe in 2005 to 1.72 MBoe during 2006. That increase is primarily attributable to our purchase of the ExxonMobil Properties in April 2006, but it also is due in part to our ongoing efforts to enhance day-to-day production. The average product price, including hedge effects, increased to $60.67 per Boe during the year ended December 31, 2006, as compared to $45.41 per Boe during the year ended December 31, 2005.

Operating Expenses.  Production expenses increased to $46.0 million for the year ended December 31, 2006, from $15.4 million for the year ended December 31, 2005. The increase of $30.6 million in production expense was due to several factors associated with our acquisition of the ExxonMobil Properties in April 2006. First, $9.5 million of the increase was for workover expenses related to wells in need of substantial operational maintenance. If 2006 workover expenses remained at the same level per Boe as 2005, per unit production expenses would have increased by $4.62, or about 24%. Second, as a result of the acquisition of the ExxonMobil Properties, we became the operator of approximately 200 additional producing wells during the year ended December 31, 2006, compared to the year ended December 31, 2005, substantially increasing our production. On a unit of production basis, lease operating expenses increased from $10.93 per Boe in 2005 to $14.48 per Boe in 2006, a 33% increase. Our production taxes also increased, from $3.47 per Boe to $4.55 per Boe. A portion of the production taxes are directly related to production revenues, and from 2005 to 2006 our weighted average actual sales price increased from $52.53 per Boe to $62.07 per Boe, a 18% increase.

					Percentage
	Year Ended December 31,				Increase
	2005		2006		(Decrease)
Production expenses per Boe	$	19.23	$	26.78		39	%

General and administrative expenses increased to $6.0 million from $3.3 million during the year ended December 31, 2006, as compared to the year ended December 31, 2005. General and administrative expenses per Boe of production were as follows:

					Percentage
	Year Ended December 31,				Increase
	2005		2006		(Decrease)
General and administrative expenses per Boe	$	4.11	$	3.50		(15	%)

The increase in general and administrative expenses was due to our rapidly growing operations and increasing our staffing level to manage the ExxonMobil Properties we acquired in April 2006. However, on a unit of production basis, our general and administrative expenses declined because our increase in production more than offset the increase in general and administrative expenses.

Depreciation, depletion and amortization increased to $11.1 million for the year ended December 31, 2006, from $4.7 million for the year ended December 31, 2005. The increase in depreciation, depletion and amortization was because we had more money invested in properties subject to depletion and more production to which depletion attached following our acquisition of the ExxonMobil Properties in April 2006.

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Other Income (Expense).  During the year ended December 31, 2006, the fair value of our oil hedges increased by $10.9 million. This amount included approximately $2.4 million of realized losses on these hedges and a $13.3 million increase in the future value of these contracts. During the year ended December 31, 2006, we had oil swaps equal to approximately 69% of our oil production during the same period. During the year ended December 31, 2005, the fair value of our oil hedges decreased by $28.9 million. This amount included approximately $5.7 million of realized losses on these hedges and a $23.2 million decline in the future value of these contracts. During the year ended December 31, 2005, we had oil swaps equal to approximately 76% of our oil production during the same period.

Interest expense was $18.1 million for the year ended December 31, 2006, compared to $2.5 million for the year ended December 31, 2005. The increase in interest expense was primarily because of additional indebtedness we incurred to finance the acquisition of the ExxonMobil Properties in April 2006.

Year Ended December 31, 2005, Compared to the Period from January 22, 2004 (Inception) to December 31, 2004

Revenue.  Oil, gas and natural gas liquids revenues increased to approximately $41.0 million during the year ended December 31, 2005 from $2.3 million during the year ended December 31, 2004. Total revenue, including gas plant revenue, increased to approximately $42.0 million during the year ended December 31, 2005, from $2.4 million for the period from January 22, 2004 (Inception) to December 31, 2004. The key revenue measurements were as follows:

	January 22, 2004
	(Inception) to		Year Ended		Percentage
	December 31,		December 31,		Increase
	2004		2005		(Decrease)
Net Sales:
Total sales (Boe)(1)		59,577		798,558		1,240	%
Average daily sales (Boe/d)(1)		1,922		2,189		15	%
Average Sales Prices ($/Boe):
Average sales price (including hedges)	$	44.07	$	45.41		3	%
Average sales price (excluding hedges)	$	40.12	$	52.53		30	%

(1) Average daily sales during the period January 22, 2004 (Inception) to December 31, 2004, represents 31 days of production from the acquisition date of the Chevron Properties (November 30, 2004) through December 31, 2004.

The increase in revenue from oil, gas and natural gas liquids sales was due to both an increase in production and sales and an increase in the price that we received for our product. Production increased from approximately 60,000 Boe in 2004 to almost 800,000 Boe in 2005 because we owned the Chevron Properties for all twelve months of 2005 as compared to only one month of 2004. The average realized product price, after giving effect to hedges, increased to $45.41 per Boe during the year ended December 31, 2005, as compared to $44.07 per Boe during the period of January 22, 2004 (Inception) to December 31, 2004.

Operating Expenses.  Production expenses increased to $15.4 million for the year ended December 31, 2005, from $1.0 million for the year ended December 31, 2004. On a unit of production basis, lease operating expenses increased from $11.15 per Boe in 2004 to $10.93 per Boe in 2005, a 2% decrease, and workover expense increased from $0.36 per Boe in 2004 to $4.83 per Boe in 2005, a 1,242% increase. The vast majority of the aggregate increase resulted from the fact that we owned the Chevron Properties for twelve months of 2005 as compared to only one month of 2004. The increases inper-unit costs resulted from our becoming operator of the Aneth Unit in December 2004, at which time we began an extensive program of maintenance and repair throughout the unit. On aper-unit basis, our production taxes decreased by 40%, from $5.76 in 2004 to $3.47 in 2005, largely as a result of our taking advantage of certain tax credits that had been unused previously. This was despite the fact that a portion of the production taxes are directly related to production revenues, and from 2004 to 2005 our weighted average actual sales price increased from $40.12 per Boe to $52.53 per Boe, or 30%.

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	January 22, 2004
	(Inception) to		Year Ended		Percentage
	December 31,		December 31,		Increase
	2004		2005		(Decrease)
Production expenses per Boe	$	17.27	$	19.23		11.4	%

General and administrative expenses increased to $3.3 million from $2.4 million during the year ended December 31, 2005, as compared to the period from January 22, 2004 (Inception) to December 31, 2004. General and administrative expenses per Boe of production were as follows:

	January 22, 2004
	(Inception) to		Year Ended		Percentage
	December 31,		December 31,		Increase
	2004		2005		(Decrease)
General and administrative expenses per Boe	$	40.93	$	4.11		(90	%)

The increase in general and administrative expenses was due to the increase in our staffing level required to manage the Chevron Properties. However, on a unit of production basis, our general and administrative expenses declined because our increase in production resulting from twelve months of revenues from the Chevron Properties in 2005 compared to one month of revenues during 2004 more than offset the increase in aggregate general and administrative expenses.

Depreciation, depletion and amortization increased to $4.7 million for the year ended December 31, 2005, from $0.4 million for the period from January 22, 2004 (Inception) to December 31, 2004. The increase in depreciation, depletion and amortization resulted primarily from the fact that we owned the Chevron Properties for twelve months of 2005 as compared to only one month of 2004, and as a result we incurred higher depreciation, depletion and amortization because of the increase in production.

Other Income (Expense).  During the year ended December 31, 2005, the fair value of our oil hedges decreased by $28.9 million. This amount included approximately $5.7 million of realized losses on these hedges and a $23.2 million decrease in the future value of these contracts. During the year ended December 31, 2005 we had oil hedges equal to approximately 76% of our oil production during the same period. During the year ended December 31, 2004, the fair value of our oil hedges increased by $3.6 million. This amount included approximately $0.2 million of realized gains on these hedges and a $3.4 million increase in the future value of these contracts.

Interest expense was $2.5 million for the year ended December 31, 2005, compared to $0.2 million for the period from January 22, 2004 (Inception) to December 31, 2004. The increase in interest expense was primarily because of additional indebtedness we incurred to finance the acquisition of the Chevron Properties in November 2004.

Liquidity and Capital Resources

Our primary sources of liquidity are expected to be cash generated from our operations, amounts available under our credit facility and funds from future private and public equity and debt offerings.

Our partnership agreement requires that we distribute our available cash each quarter. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement will permit our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows us to use working capital borrowings to make distributions.

We may borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. In addition, we plan to hedge a significant portion of our production. We settle our hedging arrangements within three days of the end of the month. As is typical in the oil and gas industry, however, we do not generally receive the proceeds from the sale of our production until the 20th day of the month following the month of production. As a result, when commodity prices increase above the fixed price in the derivative contacts, we will be required to pay the

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derivative counterparty the difference between the fixed price in the derivative contract and the market price before we receive the proceeds from the sale of the hedged production. If this occurs, we may make working capital borrowings to fund our distributions.

We plan to reinvest a sufficient amount of our cash flow in our development operations in order to maintain our production over the long-term, and we plan to use external financing sources as well as cash flow from operations and cash reserves to increase our production. In estimating the minimum amount of Adjusted EBITDA that we must generate to pay our minimum quarterly distribution to each of our unitholders for each quarter for the twelve months ended December 31, 2008, we have assumed that we will incur capital expenditures of $7.6 million for our development projects in order to allow us to maintain production at a rate that is substantially similar to our projected 2008 production. This estimate is based on our experience with such projects in the Aneth Unit; however, our actual costs for these projects could be higher or lower. We plan to fund these capital expenditures with cash flow from operations.

If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures, reduce distributions to unitholders,and/or fund a portion of our capital expenditures using borrowings under our credit facility, issuances of debt and equity securities or from other sources, such as asset sales or reduced distributions. We cannot assure you that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our credit facility. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.

Cash Flows.  The following table presents our sources and uses of cash for the periods indicated

	Resolute Energy Partners Predecessor
	January 22, 2004
	(Inception) to			Year Ended						Six Months Ended
	December 31,			December 31,						June 30,
	2004			2005			2006			2006			2007
	(In thousands)
Net cash provided by (used in):
Operating activities	$	(2,225	)	$	11,516		$	31,756		$	5,296		$	16,694
Investing activities		(84,541	)		(14,402	)		(242,388	)		(225,324	)		(45,560	)
Financing activities		87,377			2,275			214,323			220,416			25,175

Operating Activities.  Net cash provided by operating activities was $16.7 million and $5.3 million for the six months ended June 30, 2007 and 2006, respectively. The increase in net cash provided by operating activities was due substantially to the increased production realized from the acquisition of the ExxonMobil Properties in April 2006.

Net cash provided by (used in) operating activities was $31.8 million during the year ended December 31, 2006, compared to $11.5 million during the year ended December 31, 2005 and $(2.2) million during the year ended December 31, 2004. The increase in net cash provided by operating activities in 2006 was substantially due to increased revenues, partially offset by increased expenses, both primarily attributable to the acquisition of the ExxonMobil Properties in April 2006. The increase in net cash provided by operating activities in 2005 was substantially due to increased revenues, partially offset by increased expenses, both primarily attributable to the acquisition of the Chevron Properties in November 2004.

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil prices. Oil prices are determined primarily by prevailing market conditions that are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on our ability to maintain and increase production through our secondary and tertiary recovery projects (primarily our CO₂ floods), drilling programs and acquisitions, as well as the prices of oil and gas.

We enter into arrangements to reduce the impact of oil price volatility on our operations. Currently, we use fixed price swaps and puts to hedge oil prices. Please see “— Quantitative and Qualitative Disclosure About Market Risk.”

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Investing Activities.  Our capital expenditures were $219.1 million and $49.2 million for the six months ended June 30, 2006 and 2007, respectively. Capital expenditures for the six months ended June 30, 2007, included $17.6 million for additions to our CO₂ project in the Aneth Unit, $11.6 million for well recompletions, $3.0 million for acquisition of 3D seismic covering the Aneth Unit, $3.9 million in payments to ExxonMobil under the contingent payments agreement and $2.5 million in expenditures related to our exploration programs. Capital expenditures for the six months ended June 30, 2006, primarily reflects the acquisition of the ExxonMobil Properties along with limited expenditures related to the development of the Chevron Properties.

Our capital expenditures were $234.7 million in the year ended December 31, 2006, $12.4 million in the year ended December 31, 2005, and $84.3 million in the year ended December 31, 2004. Approximately 93% of the total capital expenditures in 2006 was for the purchase of the ExxonMobil Properties, with the remaining 7% being expended for other acquisition, exploration and development expenditures, and other property and equipment. Approximately $16.5 million of that amount was expended on our Aneth Field Property projects and approximately $3.1 million was expended on exploration projects that do not relate to our Aneth Field Properties. The total capital expenditures for 2005 consist of an additional payment of $2.4 million to Chevron in connection with the purchase of the Chevron Properties, $4.3 million for activities on the Aneth Field and $5.7 million on certain other exploration projects that do not relate to our Aneth Field Properties. Substantially all of the capital expenditures for 2004 were incurred in connection with the purchase of the Chevron Properties.

We currently anticipate that our development budget, which predominantly consists of workover, drilling, secondary and tertiary recovery projects and equipment, will be $58.5 million for 2007. As of June 30, 2007, we had $35 million available for borrowing under our existing revolving credit facility. Giving effect to this offering and the application of the net proceeds therefrom, our borrowing capacity under our new revolving credit facility is expected to be approximately $72.3 million, assuming our anticipated borrowing base of $225 million. Please see “— Revolving Credit Facility.” The amount and timing of our capital expenditures is largely discretionary and within our control. We routinely monitor and adjust our capital expenditures in response to changes in oil prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and crews. Based upon current oil price expectations for 2007, we anticipate that the proceeds of this offering, our cash flow from operations and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for 2007. However, future cash flows are subject to a number of variables, including the level of oil production and prevailing commodity prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Financing Activities.  As of June 30, 2007, Natural Gas Partners had contributed $39.0 million and our management had contributed $5.0 million. Both Natural Gas Partners and management have been released from the unfunded portion of their commitments.

In connection with our acquisition of the Chevron Properties we entered into a $185 million revolving credit facility with a group of banks. The revolving credit facility was subject to a borrowing base that was re-determined semi-annually by the lenders. Outstanding amounts under the revolving credit facility were secured by a lien on substantially all of our oil and gas properties. At the time of the acquisition of the Chevron Properties, we borrowed approximately $44 million under this revolving credit facility.

In connection with the acquisition of the ExxonMobil Properties, we amended and restated our former revolving credit facility to provide for a new $300 million revolving credit facility. The credit facility is subject to a borrowing base that is re-determined semi-annually by the lenders, is secured by a lien on substantially all of our oil and gas properties and matures on April 13, 2011. Outstanding amounts under this revolving credit facility accrue interest at a rate determined by adding a specified margin to LIBOR. The specified margin ranges between 1.25% and 1.875% based on the outstanding amounts as a percentage of the borrowing base. At the time of the acquisition of the ExxonMobil Properties, we borrowed $147.0 million

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under this revolving credit facility. Approximately $54.9 million of the borrowings was used to repay all outstanding amounts under our previous credit facility and the remainder of the proceeds was used to partially fund the acquisition of the ExxonMobil Properties. Currently the borrowing base that governs availability under this revolving credit facility is set at $205 million and outstandings are approximately $170 million, leaving $35 million of availability.

Also, at the time of the acquisition of the ExxonMobil Properties, we entered into a $125 million second lien term loan facility. The term loan facility matures on April 13, 2012, and accrues interest at LIBOR plus 5%. Borrowings under the term loan facility are secured by a second lien on substantially all of our oil and gas properties. Proceeds from this term loan were used to complete the acquisition of the ExxonMobil Properties including the payment of fees and expenses associated with the transaction.

On June 27, 2007, we entered into an amended and restated $225 million second lien term loan facility to refinance the $125 million second lien term loan facility we entered into in connection with the acquisition of ExxonMobil Properties and to pay a $100 million cash distribution to the members of Resolute Holdings. This term loan facility matures on April 13, 2012, and the borrowings accrue interest at LIBOR plus 4.5%. Borrowings under this term loan facility are secured by a second lien on substantially all of our oil and gas properties.

Revolving Credit Facility

We plan to enter into a $300 million senior secured revolving credit facility in connection with the closing of the offering. We anticipate that the new revolving credit facility will provide us with $225 million of borrowing capacity, of which we expect approximately $72.3 million of borrowing capacity will be available upon completion of this offering following our incurrence of approximately $152.7 in indebtedness in order to repay amounts outstanding under our term loan facility.

We expect that our new revolving credit facility will mature five years from the effective date, unless extended. We will be allowed to prepay all loans under the credit facility in whole or in part from time to time without premium or penalty, subject to certain restrictions in the revolving credit facility. We anticipate that our obligations under our new revolving credit facility will be secured by mortgages on our oil and gas properties as well as a pledge of all ownership interests in our operating subsidiaries. We anticipate that the obligations under the new revolving credit facility will be guaranteed by all of our operating subsidiaries and may be guaranteed by any future subsidiaries.

We expect that our new revolving credit facility will give us the ability to pay distributions to unitholders as long as there has not been a default or event of default. We expect the revolving credit facility will be available for general partnership purposes, including working capital, capital expenditures and distributions. We expect that the indebtedness under the new revolving credit facility will bear interest at the prime rate or LIBOR plus an applicable margin, will contain various representation, warranties, covenants and indemnities customary for its type, including limitations on our ability to incur indebtedness, grant liens and make distributions and requirements that we maintain specified financial ratios. The foregoing description is not complete and is qualified in its entirety by the terms and conditions of the credit agreement evidencing our revolving credit facility.

Contractual Obligations

We intend to enter into an administrative services agreement with Resolute Holdings and certain of its affiliates pursuant to which Resolute Holdings will operate substantially all of our assets and perform administrative services for us such as accounting, marketing, corporate development, finance, land, legal and engineering. Under the administrative services agreement, we will reimburse Resolute Holdings for its costs in providing services to us as well as for all direct and indirect expenses incurred by Resolute Holdings and its affiliates on our behalf.

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We have the following contractual obligations and commitments as of June 30, 2007:

	Payments Due By Year(1) (in $ millions)
	2007		2008		2009		2010		2011		After 2011		Total
ExxonMobil escrow agreement		—		1.4		1.4		1.3		1.2		5.1		10.4
Asset retirement obligations(2)		0.8		0.7		0.1		0.1		0.1		5.9		7.7
CO2 purchases(3)		5.7		15.4		26.1		17.6		13.4		25.7		103.9
Total		6.5		17.5		27.6		19.0		14.7		36.7		122.0

(1)	This table does not include any liability associated with derivatives or any debt we expect to incur or repay in connection with the closing of this offering. We expect to incur approximately $152.7 million of indebtedness under our new revolving credit facility at the closing of this offering to repay the remaining balance under our term loan facility. Because the amount of interest we expect to be required to pay as a result of the incurrence of this indebtedness will be based upon a floating interest rate, the amount of our future interest payments is not determinable. We expect any indebtedness that is outstanding under our new revolving credit facility will mature six years from the closing of this offering.
(2)	Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance.
(3)	Represents the minimum take or pay quantities associated with our existing CO2 purchase contracts. For purposes of calculating the purchase obligation under these contracts, we have assumed the purchase price over the term of the contracts was the price in effect as of June 30, 2007.

Off-Balance Sheet Obligations

In connection with our acquisition of the ExxonMobil Properties, we agreed to make certain contingent payments to ExxonMobil based on the posted price of West Texas Sour crude oil. The payments are determined based on the amount by which prices for West Texas Sour crude oil exceeds $40 in any given month, multiplied by the production from the ExxonMobil Properties during the month. The price of West Texas Sour crude for purposes of the contingent payments is capped at $49 per barrel (thus producing a maximum differential of $9 per barrel) and the contingent payment is payable with respect to a monthly maximum production quantity of 74,074 barrels net to our interest. Therefore, our maximum amount payable to ExxonMobil under this contingent payment in any month is $666,667. Under the terms of the agreement pursuant to which we acquired the ExxonMobil Properties, these contingent payments are made monthly and will terminate in December 2007. As of June 30, 2007, we had made payments in the aggregate of $8.4 million to ExxonMobil as a result of this provision, and for financial reporting purposes they were treated as an adjustment to the purchase price of the ExxonMobil Properties.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based upon the combined and consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. We have provided below an expanded discussion of our more significant accounting policies, estimates and judgments. After our initial public offering, we will discuss the development, selection and disclosure of each of these with our audit committee. We believe these accounting policies reflect our more

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significant estimates and assumptions used in the preparation of our financial statements. Please read “Note 1 — Description of Business and Summary of Significant Accounting Policies” to the unaudited condensed combined financial statements of Resolute Energy Partners Predecessor atF-18 for a discussion of additional accounting policies and estimates made by our management.

Oil and Gas Properties.  We use the full cost method of accounting for oil and gas producing activities. Under this method, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities, are capitalized within a cost center. Internal costs incurred that are directly identified with acquisition, exploration and development activities, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Our oil and gas properties are all located within the United States, which constitutes a single cost center. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of the properties and the gain significantly alters the relationship between capitalized costs and proved reserves of the cost center. Expenditures for maintenance and repairs are charged to lease operating expense in the period incurred.

Depreciation, depletion and amortization of oil and gas properties is computed on the unit-of-production method based on proved reserves. Amortizable costs include estimates of future development costs of proved undeveloped reserves and asset retirement obligations. We may invest in unevaluated oil and gas properties for the purpose of exploration for proved reserves. The costs of such assets, including exploration costs on properties where a determination of whether proved oil and gas reserves will be established is still under evaluation, and any capitalized interest, are included in unproved oil and gas properties at the lower of cost or estimated fair market value and are not subject to amortization. On an annual basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonment of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized. We have not recorded an impairment of unevaluated properties from the period January 22, 2004 (inception) to December 31, 2006. For the six months ended June 30, 2007, we recorded no impairment of unevaluated properties. Salvage value is taken into account in determining depletion rates and is based on our estimate of the value of equipment and supplies at the time the well is abandoned.

Under the full cost method of accounting, capitalized oil and gas property costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, may not exceed a “ceiling” value comprised of the total of the present value of future net revenues from proved reserves, using current costs and prices, including the effects of derivative instruments accounted for as cash flow hedges but excluding the future cash outflow associated with settling asset retirement obligations that have been accrued on the balance sheet, discounted at 10%, plus the lower of cost or market value of unproved properties and unevaluated properties excluded from costs being amortized, net of related income tax effects related to differences in the book and tax basis of oil and gas properties. At June 30, 2007, and December 31, 2006, the full cost ceiling limitation exceeded the carrying amount of our gas properties by approximately $650 million and $680 million, respectively. Therefore, we were not required to record a ceiling write-down as of June 30, 2007. A decline in oil prices or an increase in operating costs subsequent to the measurement date or reductions in the economically recoverable quantities could result in the recognition of a ceiling write-down of our oil and gas properties in a future period.

Oil and Gas Reserve Quantities.  Our estimate of proved reserves as of June 30, 2007, is based on the quantities of oil and gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell & Associates, Inc., independent petroleum engineers, audited a reserve and economic evaluation of all our properties that was prepared by us on awell-by-well basis.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to

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reserves estimates. We prepare our reserves estimates, and the projected cash flows derived from these reserves estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when auditing our reserve reports. The accuracy of our reserves estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

Our proved reserves estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserves estimates may materially vary from the ultimate quantities of oil, gas and natural gas liquids eventually recovered.

Derivative Instruments and Hedging Activities.  We regularly use derivative financial instruments to reduce our exposure to price fluctuations and thus achieve more predictable cash flows from our oil production. These transactions, currently swaps and puts, act as a hedge against price-driven volatility in our cash flows. Additionally, we may use derivative financial instruments to mitigate our interest rate exposure. We account for these activities pursuant to SFAS No. 133 — Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.

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

We have not specifically designated any of our derivative instruments as cash flow hedges under the terms prescribed by SFAS No. 133, even though they insulate us from changes in commodity prices. As a result, on a periodic basis we report the settled payments of derivatives transactions and also the change in mark-to-market valuation of these instruments, and we record such changes through our income statement in our current earnings. The derivatives transactions that are settled in a given period represent actual cash received from or paid to the counterparty to the transaction. The change in mark-to-market valuation, however, represents a non-cash charge to earnings. As a result, notwithstanding the fact that the hedging transactions serve to reduce our actual cash exposure to changes in price, the reporting treatment required under GAAP potentially serves to increase the volatility of earnings as the non-cash mark-to-market valuation of the derivatives contracts is recognized. Had we designated any of such derivative instruments as cash flow hedges, changes in fair market value, to the extent the hedge is effective, would have been recognized in other comprehensive income until the hedged item was recognized in earnings. As we enter into derivatives transactions, we assess whether such transaction should be designated as a cash flow hedge, weighing the benefit associated with the income statement presentation against the administrative burden associated therewith.

A put option requires us to pay the counterparty the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed floor over the floating market price. The costs incurred to enter into the transactions are amortized over the life of the put option, and the change in fair market value of the instrument is reported in the statement of operations each period.

Asset Retirement Obligations.  Our asset retirement obligations, or “ARO,” consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and natural gas properties. SFAS No. 143 requires that the discounted fair value of a liability for an ARO be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates, and future advances in

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technology. In periods subsequent to initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through depletion, depreciation and amortization expense.

Equity-Based Compensation.  We account for stock-based compensation in accordance with FAS 123R, which requires us to measure the grant date fair value of equity awards given to employees in exchange for services, and to recognize that cost, less estimated forfeitures, over the period that such services are performed. Prior to adopting FAS 123R, we accounted for stock-based compensation under Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees. We adopted FAS 123R on January 1, 2006, using the prospective transition method.

Our operating expenses for the six months ended June 30, 2007, included a non-cash charge to compensation expense of $32.7 million associated with equity-based compensation recognized during the period pursuant to FAS 123R. This non-cash charge relates to incentive compensation provisions in the operating agreement between Natural Gas Partners and management. In June 2007, Resolute Holdings made a $100.0 million cash distribution to its members that met a financial requirement for a portion of management’s incentive compensation units to vest, triggering this compensation expense. Please read “Note 4 — Shareholder’s/Member’s Equity (Deficit)” to the unaudited condensed combined financial statements of Resolute Energy Partners Predecessor at F-49. Approximately $32.4 million of the non-cash charge was allocated to general and administrative expense and the remaining $0.3 million was allocated to lease operating expense.

Recent Accounting Pronouncements

In July 2006, the FASB adopted FIN 48,Accounting for Uncertainty in Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition of positions taken or expected to be taken in income tax returns. FIN 48 also provides guidance on de-recognition, classification of interest and penalties, and accounting and disclosures for annual and interim financial statements. We adopted the provisions of FIN 48 on January 1, 2007. Upon adoption, we recognized approximately $0.5 million, including accrued interest and penalties of $0.1 million, as a contingent liability.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”). This statement clarifies the definition of fair value, establishes a framework for measuring fair value, and expands the disclosures on fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. We have not determined the effect, if any, the adoption of this statement will have on our financial position or results of operations.

In February 2007, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). This statement permits entities to choose to measure many financial instruments and certain other items at fair value. This statement expands the use of fair value measurement and applies to entities that elect the fair value option. The fair value option established by this statement permits all entities to choose to measure eligible items at fair value at specified election dates. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We have not determined the effect, if any, the adoption of this statement will have on our financial position or results of operations.

Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

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Commodity Price Risk and Hedging Arrangements.  Our major market risk exposure is in the pricing applicable to our oil production. Realized pricing on our unhedged volumes of production is primarily driven by the spot market prices applicable to our oil production and the prevailing price for gas. Pricing for oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for unhedged production depend on many factors outside of our control.

We have historically entered into hedging and other risk management arrangements with respect to a significant portion of our projected oil production through various transactions that hedge the future prices received. We anticipate that we will continue this policy upon the completion of this offering. These transactions may include price swaps whereby we effectively will receive a fixed price for our production after we settle with our swap contract counterparty. Additionally, we have put options for which we pay the counterparty the fair value at the purchase date. At the settlement date we receive the excess, if any, of the fixed floor over the floating rate. These hedging activities are intended to support oil prices at targeted levels and to manage our exposure to oil price fluctuations. We do not hold or issue derivative instruments for speculative trading purposes. In determining the amount of our production to hedge, we take into account the fact that the price of the CO₂ we purchase under our supply contracts is determined based on the price of crude oil. We anticipate that our new revolving credit facility will allow us to place swap hedges on up to 80% of expected production from our proved developed producing reserves.

By removing the price volatility from a significant portion of our oil production, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flow from operations for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers. To date, all of our hedges have been entered into with banks that are lenders under our existing revolving credit facility.

At June 30, 2007, we had in place oil swap and put contracts covering significant portions of our estimated 2007 through 2012 oil production. For the six months ending December 31, 2007, we have fixed price swaps for a total hedged amount of 653,200 Bbl at an average price of $71.76 per Bbl, which represents approximately 67.1% of our total expected oil production volume from our proved developed producing properties for the second half of 2007. At June 30, 2007, we also had in place contracts that allow us to put 2,000 Bbl per day of our 2007 production at a price of $60 per Bbl.

Based on an oil price of $70.68 per Bbl as of June 30, 2007, the fair value of our risk management positions as of that date was a liability of $19.2 million, which we owe to the counterparties. A 10% increase in the index oil price above the June 30, 2007, price for oil would increase the liability by $29.1 million; conversely, a 10% decrease in the index oil price would result in an asset of $9.8 million, which represents a $29.1 million increase in value.

Interest Rate Risks.  Upon the closing of this offering, we anticipate that we will have approximately $152.7 million of outstanding debt, all of which will be incurred at a floating rate interest pursuant to the expected terms of our new revolving credit facility. A 1% increase in LIBOR would result in an estimated $1.5 million increase in annual interest expense. We do not currently intend to enter into any hedging arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness.

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BUSINESS

We are an independent oil and gas partnership engaged in the exploitation and development of our properties in the Greater Aneth Field, a mature, long-lived oil producing field located in the Paradox Basin on the Navajo Reservation in southeast Utah. We own a majority of the working interests in, and are the operator of, three (out of a total of four) federal production units covering approximately 43,000 gross acres of the Greater Aneth Field. These units are the Aneth Unit, in which we own a 62% working interest, the McElmo Creek Unit, in which we own a 75% working interest, and the Ratherford Unit, in which we own a 59% working interest. As of June 30, 2007, we had interests in and operated 402 gross (265 net) active producing wells and 335 gross (219 net) active water and CO₂ injection wells on our Aneth Field Properties. The crude oil produced from our Aneth Field Properties is generally characterized as light, sweet crude oil that is highly desired as a refinery blending feedstock.

As of June 30, 2007, our estimated net proved reserves were approximately 78.1 MMBoe, of which approximately 38% were proved developed producing reserves and approximately 99% were oil. The standardized measure of our estimated net proved reserves as of June 30, 2007, was $1.16 billion. For additional information about the calculation of our standardized measure, please see “— Estimated Net Proved Reserves.” We believe our Aneth Field Properties are well-suited for our partnership because they have relatively predictable production profiles based on a long history of production, a shallow expected annual decline rate of approximately 6% and a high reserves to production ratio. The following table sets forth summary information attributable to our estimated net proved reserves that is derived from our reserve report presented as of June 30, 2007, and audited by Netherland, Sewell & Associates, Inc., independent petroleum engineers. Reserves and production information is as of and for the periods indicated.

	Estimated Net Proved Reserves
	as of June 30, 2007
	(MMBoe)														Oil Reserves to Oil Production Ratio (in years)
			Proved										Average				Proved
	Proved		Developed										Net Daily				Developed
	Developed		Non-		Proved Undeveloped						Total		Production		Proved		Producing
	Producing		Producing		CO2		Drilling		Total		Proved		(Boe/d)(1)		Reserves(2)		Reserves(3)
Aneth Unit		9.7		0.1		21.7		1.9		23.6		33.4		1,708		59		17
McElmo Creek Unit		13.8		0.1		7.6		0.6		8.2		22.1		2,481		25		15
Ratherford Unit		5.9		4.5		11.6		0.6		12.2		22.6		1,689		42		9
Total		29.4		4.7		40.9		3.1		44.0		78.1		5,878		39		15
Future development costs (in millions)(4)					$	209.1	$	50.4	$	259.5
Future development costs ($/Boe)(5)					$	5.11	$	16.26	$	5.90

(1)	For the three months ended June 30, 2007.
(2)	Determined by dividing total estimated net proved oil reserves as of June 30, 2007, by oil production volumes for the three months ended June 30, 2007, on an annualized basis. The calculation of this ratio does not give effect to gas reserves or gas production.
(3)	Determined by dividing total estimated net proved developed producing oil reserves as of June 30, 2007, by oil production volumes for the three months ended June 30, 2007, on an annualized basis. The calculation of this ratio does not give effect to gas reserves or gas production.
(4)	Future development costs do not include $55.4 million of net capital expenditures that we had incurred since our acquisition of each of our Aneth Field Properties through June 30, 2007.
(5)	Determined by dividing our estimated total future development costs related to reserves classified as proved undeveloped by total estimated net proved undeveloped reserves as of June 30, 2007.

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Greater Aneth Field

The Greater Aneth Field was discovered in 1956 and was subsequently developed by several large integrated oil companies. It covers approximately 50,000 acres in San Juan County located in southeast Utah and is the largest oil field in the Paradox Basin, a basin located in the Four Corners area of the southwestern United States. During the three months ended March 31, 2007, the Greater Aneth Field produced approximately 9,536 Bbl/d, while our Aneth Field Properties produced approximately 9,308 Bbl/d.

The primary producing horizon in the Greater Aneth Field is the Pennsylvanian-age Desert Creek Formation, which is a carbonate algal-mound formation with average depth of 5,600 feet. While there is some reservoir complexity in the Greater Aneth Field, development of the reserves generally has been accomplished with well-tested methodologies, including drilling and infilling of vertical wells, waterflood activities, horizontal drilling and CO₂ flooding. For administrative, organizational and operational reasons, in 1961 the Greater Aneth Field was divided into four separate federal production units to facilitate efficient development of the field and recovery of reserves. The three units that we operate, the Aneth Unit, the McElmo Creek Unit and the Ratherford Unit, possess substantially similar geologic and operating characteristics.

The following map shows the four federal operating units in the Greater Aneth Field:

We acquired our Aneth Field Properties primarily through two significant acquisitions. In the November 2004 acquisition of the Chevron Properties, we acquired a 53% operating working interest in the Aneth Unit, a 15% non-operating working interest in the McElmo Creek Unit and a 3% non-operating working interest in the Ratherford Unit. In the April 2006 acquisition of the ExxonMobil Properties, we acquired an additional 7.5% non-operating working interest in the Aneth Unit, a 60% operating working interest in the McElmo Creek Unit and a 56% operating working interest in the Ratherford Unit.

We acquired our Aneth Field Properties in connection with our strategic alliance with NNOG, an oil and gas company owned and operated by the Navajo Nation. NNOG maintains a minority interest in each of the Chevron Properties and the ExxonMobil Properties and possesses options to purchase additional minority interests in those properties from us if certain financial hurdles are met. See “— Relationship with the Navajo Nation.”

Aneth Unit.  During the three months ended June 30, 2007, the Aneth Unit produced approximately 2,871 Bbl/d from 163 gross (101 net) active producing wells and we operated 154 gross (95 net) active injection wells in the Aneth Unit. Since its discovery, the Aneth Unit has produced a total of approximately 150.8 MMBbl. The Aneth Unit was originally developed with vertical wells drilled on80-acre spacing and was infill drilled to40-acre spacing in the 1970s. Since unitization in 1961, the unit has been under

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waterflood. Between 1994 and 1998, an affiliate of Texaco operated the Aneth Unit and drilled 43 multi-lateral horizontal wells (23 producers and 20 injectors). Most of these horizontal wells were utilized to create a horizontal waterflood pattern on the eastern side of the unit. In 1998, the injectors in two square miles of the Aneth Unit were converted to a water-alternating-gas CO₂ pilot project to assess the possibility of a field-wide CO₂ injection flood program. The multi-lateral horizontal wells and the pilot CO₂ program were successful in increasing production rate and adding reserves. The pilot CO₂ program was never expanded into a unit-wide program. We became operator of the Aneth Unit on December 1, 2004. We have been successful in reducing the decline rate from the Aneth Unit over the past two and one-half years such that average daily gross production from the Aneth Unit during the three months ended June 30, 2007, has remained relatively constant with average daily gross production from the Aneth Unit during the three months ended December 31, 2004.

McElmo Creek Unit.  During the three months ended June 30, 2007, the McElmo Creek Unit produced approximately 4,020 Bbl/d from 138 gross (104 net) active producing wells and we operated 107 gross (80 net) active injection wells on the McElmo Creek Unit. Since its discovery, the McElmo Creek Unit has produced a total of approximately 159.6 MMBbl. The McElmo Creek Unit has been under waterflood since the early 1960s and prior operators commenced infill drilling to40-acre spacing during the 1970s. A stabilized oil production decline trend was established for the waterflood over approximately seven years prior to the initiation of a CO₂ flood program in 1985. Following the initiation of the CO₂ flood program in the McElmo Creek Unit, oil production from the unit increased approximately 30% over a period of 13 years before the field returned to a state of declining production in 1998. There has been no further development in the McElmo Creek Unit since the CO₂ flood program was initiated. Prior to our acquisition of the ExxonMobil Properties, the McElmo Creek Unit was operated by ExxonMobil. We became operator of the McElmo Creek Unit on June 1, 2006, and during the three months ended June 30, 2007, compared to the three months ended June 30, 2006, average daily gross production from the McElmo Creek Unit increased by 12.7%. This increase in production resulted from a number of factors, including our efforts to return wells to operation, improve artificial lift capacity at producing wells, improve compressor run times, reduce freeze problems in the winter months and increase CO₂ injection.

Ratherford Unit.  During the three months ended June 30, 2007, the Ratherford Unit produced approximately 2,900 Bbl/d from 101 gross (60 net) active producing wells and we operated 74 gross (44 net) active injection wells on the Ratherford Unit. Since its discovery, the Ratherford Unit has produced a total of approximately 99.7 MMBbl. The core of the Ratherford Unit has been developed with horizontal wells, while the edges of the unit are produced from vertical wells. We became operator of the Ratherford Unit on June 1, 2006, and during the three months ended June 30, 2007, compared to the three months ended June 30, 2006, average daily gross production from the Ratherford Unit increased by 21.8%. This increase in production resulted from a number of factors, including our efforts to improve artificial lift capacity at producing wells, increase production from new horizontal drillings, return wells to operation and increase water injection resulting from injection well cleanouts.

Our Business Strategies

Our primary business objective is to generate stable cash flow and pay quarterly cash distributions to our unitholders, with the potential to increase such quarterly cash distributions over time. We intend to accomplish this objective by executing the following business strategies:

Bring Currently Proved Undeveloped Reserves into Production.  At June 30, 2007, we had estimated net proved reserves of approximately 44.0 MMBoe that were classified as proved undeveloped. An estimated 40.9 MMBoe of our proved undeveloped reserves are attributable to recoveries associated with expansions and extensions of the tertiary recovery CO₂ floods that are currently in operation on our Aneth Field Properties. We had incurred approximately $28.4 million of capital expenditures through June 30, 2007, and we expect to incur an additional $209.1 million of capital expenditures over the next 20 years (including purchases of CO₂ under existing contracts), in connection with bringing those incremental proved undeveloped reserves attributable to our CO₂ flood projects into production. In order to further these CO₂ flood projects, we expect to incur approximately $62 million of these future capital expenditures during the second half of 2007 and all of 2008 and approximately $101 million of these future capital expenditures from 2009 through 2012. We currently

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estimate that these CO₂ flood projects, along with our other planned development activities, can in three years increase our average daily production by more than 50% over our current average daily production, following which we expect our rate of production to remain stable for approximately five years, then ultimately decline by approximately 6% per annum thereafter.

Increase Production and Improve Efficiency of Operations on our Existing Properties.  Our management team has experience in managing operationally intensive oil and gas properties. As the operator of our Aneth Field Properties, we have the ability to manage our costs and control the timing of our exploitation activities and, as a result, we have instituted several programs to increase production and improve the efficiency of our operations. For example, we recently conducted a proprietary3-D seismic survey of the Aneth Unit, which is the first seismic survey of the Greater Aneth Field. We expect that the data we will obtain from this seismic survey will provide us with information to enable us to more efficiently develop our Aneth Field Properties. In addition, soon after we acquired the Chevron Properties and became the operator of the Aneth Unit, we undertook a program of repair and maintenance of our producing assets in that unit. As a result of these efforts, we have reduced the failure rate of wells within the Aneth Unit. We are pursuing similar repair and maintenance programs in the McElmo Creek and Ratherford Units. Also, because we are the operator of three of the four federal units in the Greater Aneth Field, we have been able to assemble a critical mass of employees and projects and allocate our resources across a broader area in a more efficient manner than was previously the case when each unit had a different operator.

Reduce Commodity Price Risk through Hedging.  We seek to reduce the effect of short-term commodity price fluctuations and achieve less volatile cash flows through the use of various derivative instruments such as swaps, puts, calls and collars. As of June 30, 2007, we had in place oil hedges covering approximately 67.1% of our anticipated oil production from proved developed producing properties for the six months ending December 31, 2007, at a weighted average price of $71.76, approximately 62.7% of our expected oil production from proved developed producing properties for 2008 at a weighted average price of $70.16 and approximately 51.5% of our expected oil production from proved developed producing properties for 2009 through 2012 at a weighted average price of $63.07. We expect to continue to use hedging arrangements to reduce our commodity price risk with respect to our estimated production from our producing properties.

Maintain a Disciplined Financial Policy.  We intend to maintain sufficient liquidity to fund our operations and maintain relatively low levels of indebtedness in relation to our cash flows. We intend to fund our expansion projects and acquisitions through cash flow, funds available under our credit facilities and the issuance of debt and equity securities while remaining committed to maintaining a capital structure that affords us financial flexibility. We believe this approach will enhance our ability to execute our development plan through varying commodity price cycles and preserve our liquidity.

Pursue Acquisitions of Mature Properties with Low-Risk Development Potential.  From our inception through June 30, 2007, we had acquired approximately 54.6 MMBoe of proved reserves, based on our estimate of proved reserves at the time of each acquisition, for total consideration of approximately $305.9 million, resulting in an acquisition cost of approximately $5.60 per Boe, excluding future development costs. Our development and exploitation activities to date have succeeded in increasing our estimated net proved reserves to 78.1 MMBoe based on our June 30, 2007, reserve report. Including our future development costs included in our reserve report as of June 30, 2007, we estimate that our total development cost will be approximately $7.81 per Boe ($7.86 per Boe assuming we pay ExxonMobil an incremental $4.0 million between June 30 and December 31, 2007). We will look to acquire similar mature producing properties that have upside potential through low-risk development drilling and exploitation projects. We believe that our knowledge of various operating areas and our relationship with Natural Gas Partners will allow us to find, capitalize on and integrate strategic acquisition opportunities in our areas of expertise.

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Our Competitive Strengths

We believe we are well positioned to execute our primary business objective because of the following competitive strengths:

A High Quality Base of Long-Lived Oil Producing Properties.  Our Aneth Field Properties have several characteristics that we believe will provide us with a stable and marketable production platform with which to fund our activities and provide quarterly cash distributions to unitholders for the next several years:

•  Our properties are expected to have a long productive life. As of June 30, 2007, our proved developed producing reserves had a reserves to production ratio of approximately 14 years and our total proved reserves had a reserves to production ratio of 39 years.

•  We believe the light, sweet crude oil we produce from our Aneth Field Properties is more attractive to refineries than the heavy or sour crude oil found in many areas, including the Permian Basin. In addition, because of the quality of our crude oil production, we can typically sell our crude oil production to refiners with a lower price differential compared to heavier crude oil.

Properties with Significant Low-Risk and Low-Cost Development Opportunities.  As of June 30, 2007, approximately 56% of our estimated net proved reserves were classified as proved undeveloped. We believe we can increase our rate of production over the next eight years without acquiring additional reserves by undertaking certain development projects on our Aneth Field Properties. We believe these development projects, particularly our planned CO₂ flood projects, are relatively low risk compared to other activities, particularly because of the successful results of the McElmo Creek Unit CO₂ flood program that has been in operation since 1985. Following the initiation of the CO₂ flood program in the McElmo Creek Unit, oil production from the unit increased significantly over a period of 13 years before the field returned to a state of declining production in 1998. Because of the similar geological characteristics across our Aneth Field Properties, we expect to achieve similar results with our CO₂ flood projects as were experienced with the McElmo Creek Unit flood program. In addition, because we can use existing infrastructure in many places and because of our close proximity to a large supply of CO₂, we believe we can implement our CO₂ flood projects with an average future development cost per unit of approximately $5.11 per Boe.

Operating Control Over Our Properties.  Following the acquisition of the Chevron Properties in November 2004, we became the operator of the Aneth Unit. Following our acquisition of the ExxonMobil Properties in April 2006, we became the operator of the McElmo Creek and the Ratherford Units effective June 1, 2006. As a result of having a critical mass of employees and projects and operating control across the three federal units, we now have the ability to utilize employees on a prioritized basis, where previously the staffs of operators of the separate federal units within the Greater Aneth Field focused only on the unit to which they were assigned. Because we are the operator of all our Aneth Field Properties, we believe we also are able to attract contract services, materials and equipment from a broader market and to negotiate more favorable terms than would otherwise be available. We also have the ability to control the timing, scope and costs of development projects undertaken in our Aneth Field Properties.

Experienced Management Team with Operational, Transactional and Financial Experience in the Energy Industry.  With an average industry work experience of more than 25 years, the senior management team of our general partner has considerable experience in acquiring, exploring, exploiting, developing and operating oil and gas properties, particularly in operationally intensive oil and gas fields. Six members of our senior management who formed Resolute Holdings in 2004 previously worked together as part of the senior management team of HS Resources, Inc., an independent oil and gas company that was listed on the New York Stock Exchange and primarily operated in the Denver-Julesburg Basin in northeast Colorado. HS Resources conducted resource development programs, managed and enhanced a gas gathering and processing system and built a hydrocarbon physical marketing and transportation business. Its development activities included drilling new wells, deepening wells and recompleting and refracturing existing wells to add reserves and enhance production. HS Resources also had an active program of acquiring producing properties and properties with development potential. HS Resources was acquired by Kerr-McGee Corporation in 2001.

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Our Relationship with Natural Gas Partners.  We are also supported by Natural Gas Partners, with which our senior management has had a relationship for more than 17 years. Natural Gas Partners VII, L.P. owns 70.1% of Resolute Holdings, which in turn will own a 65.0% limited partner interest in us, a 2.0% general partner interest in us and all of our incentive distribution rights. Two members of the board of directors of our general partner are members of the management of Natural Gas Partners. Since 1988, the Natural Gas Partners private equity funds have made investments in more than 110 entities in more than 140 transactions throughout the energy industry. Currently, these funds hold investments in more than 20 private oil and gas exploration and production companies with operations located in major producing basins throughout the United States. We believe that our relationship with Natural Gas Partners, and its experience investing in oil and gas companies, provides us with a number of benefits, including increased exposure to acquisition opportunities and access to a significant group of transactional and financial professionals who have experience in assisting the companies in which it has invested to meet their financial and strategic growth objectives. Although we may have the opportunity to make acquisitions as a result of our relationship with Natural Gas Partners, Natural Gas Partners has no legal obligation to offer any acquisition opportunities to us, may decide not to offer any acquisition opportunities to us and is not restricted from competing with us, and we cannot say which, if any, of such acquisition opportunities we would choose to pursue.

Oil Recovery Overview

When an oil field is first produced, the oil typically is recovered as a result of natural pressure within the producing formation, often assisted by pumps of various types. The only natural force present to move the crude oil to the wellbore is the pressure differential between the higher pressure in the formation and the lower pressure in the wellbore. At the same time, there are many factors that act to impede the flow of crude oil, depending on the nature of the formation and fluid properties, such as pressure, permeability, viscosity and water saturation. This stage of production, referred to as “primary production,” recovers only a small fraction of the crude oil originally in place in a producing formation.

Many, but not all, oil fields are amenable to assistance from a waterflood, a form of “secondary recovery,” which is used to maintain reservoir pressure and to help sweep oil to the wellbore. In a waterflood, certain wells are used to inject water into the reservoir while other wells are used to produce the fluid. As the waterflood matures, the fluid produced contains increasing amounts of water and decreasing amounts of oil. Surface equipment is used to separate the oil from the water, with the oil going to pipelines or holding tanks for sale and the water being recycled to the injection facilities. Primary recovery followed by secondary recovery usually produces between 15% and 40% of the crude oil originally in place in a producing formation.

A third stage of oil recovery is called “tertiary recovery” or “enhanced oil recovery” (“EOR”). In addition to maintaining reservoir pressure, this type of recovery seeks to alter the properties of the oil in ways that facilitate production. The three major types of tertiary recovery are chemical flooding, thermal recovery (such as a steamflood) and miscible displacement involving CO₂ or hydrocarbon injection.

In a CO₂ flood, CO₂ is liquefied under high pressure and injected into the reservoir. The CO₂ then swells the oil in a way that increases the mobilization of by-passed oil while also reducing the oil’s viscosity. The lighter oil fractions vaporize into the CO₂ while the CO₂ also condenses into the reservoir’s oil. In this manner, the two fluids become miscible, mixing to form a homogeneous fluid that is mobile and has lower viscosity and lower interfacial tension.

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The following diagram demonstrates the equipment and processes associated with a typical CO₂ flood project:

Miscible CO₂ flooding was first commercially successful with Chevron’s 1972 miscible CO₂ flood in the SACROC field in Scurry County, Texas. According to theOil & Gas Journal’s2006 Worldwide EOR Survey, at that time there were 80 miscible CO₂ projects in the United States (with an additional 15 miscible CO₂ projects in the planning stages) that produced an estimated 234,420 Bbl/d during 2006. In addition to our projects in the Greater Aneth Field, CO₂ projects are located in Texas, Oklahoma, New Mexico, Colorado, Wyoming, Michigan and Mississippi. Four companies, Occidental Petroleum, Kinder Morgan, Amerada Hess and Chevron, are responsible for approximately 70% of the estimated daily production from these CO₂ projects.

Recent Development and Operating Activity

After completing the acquisition of both the Chevron Properties and the ExxonMobil Properties, we became operator of three of the four federal production units within the Greater Aneth Field; the Aneth Unit, in which we own a 62% working interest, the McElmo Creek Unit, in which we own a 75% working interest, and the Ratherford Unit, in which we own a 59% working interest. In that capacity, we are able to control and optimize the timing of development of and production from our three units, something that has not been possible since the Greater Aneth Field was first unitized in 1961. We also are better positioned to optimize operating costs, not only by increasing production but also by efficiently consolidating certain operating and development functions across the three units we operate. The technical information learned through scientific or operational activities conducted in one unit can be used at our other units rather than being limited by separate unit ownership and operations.

Soon after we acquired the Chevron Properties and became the operator of the Aneth Unit, we undertook a program of repair and maintenance of our producing assets in that unit. As a result of these efforts, we have

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reduced the failure rate of producing wells within the Aneth Unit. We are pursuing similar repair and maintenance programs in the McElmo Creek and Ratherford Units.

We recently conducted a proprietary3-D seismic survey of the Aneth Unit, which is the first seismic survey in the Greater Aneth Field. The data has been processed and interpretation is underway. This seismic program, which cost approximately $3.5 million net to our interest, will seek to (1) identify untapped resources; (2) help define locations for exploitation of proved undeveloped reserves; and (3) aid in identifying locations for saltwater disposal.

Planned Operating and Development Activities

We have prepared a nine-year development program for our Aneth Field Properties that includes CO₂ flooding, field infrastructure enhancements, recompletions, workovers of producing and injection wells, infill drilling and waterflood enhancement. The application of each of these activities and technologies has been successfully established in various locations within the Greater Aneth Field, and our development plans have been designed to enhance or extend projects that were previously tested or initiated by the previous operators but were never fully completed due to such factors as lack of fieldwide operatorship and lower commodity prices. We believe that our close working relationship with NNOG and the Navajo Nation will permit us to advance development of our Aneth Field Properties in accordance with our plans.

CO₂ Floods.  A major component of our planned activity over the next several years involves extensions and expansions of the CO₂ floods initiated by the major oil companies, first in the McElmo Creek Unit in 1985 and then in the Aneth Unit in 1998. The McElmo Creek Unit CO₂ flood is virtually unit-wide, whereas the Aneth Unit CO₂ flood was limited to a pilot project covering approximately two square miles of land in the northeast corner of that unit.

The Aneth Unit and the McElmo Creek Unit exhibit similar geologic and reservoir characteristics. As a result, we expect our Aneth Unit CO₂ flood to achieve results similar to those achieved in the McElmo Creek CO₂ flood program. Therefore, we have modeled our estimate of increased incremental proved undeveloped reserves based upon the results achieved in the McElmo Creek Unit CO₂ flood. We have also modeled our projection of increased rate of oil production based upon the oil production response of the McElmo Creek Unit to the injection of CO₂. The oil production rate response is directly related to the rate at which CO₂ is injected. The McElmo Creek CO₂ project was initiated in 1985 with a relatively low rate of injected CO₂, and therefore experienced an oil production rate response that was lower than what could have been achieved had CO₂ been injected at a higher rate. Our estimate of the rate of oil production response is materially greater than the McElmo Creek Unit oil production response based upon our plan to inject CO₂ volumes at a significantly greater rate than was done in connection with the McElmo Creek Unit CO₂ flood.

Aneth Unit.  Phases 1, 2 and 3 of the Aneth Unit CO₂ project will cover the western portion of the Aneth Unit, a project that is estimated to cost about $85.6 million net to our interest, of which approximately $27.7 million had been spent as of June 30, 2007. Phase 1 injection of CO₂ began on July 25, 2007, with first production response anticipated in late 2007 or early 2008. Phase 2 construction has begun, with CO₂ injections anticipated to commence in November 2007. We have completed approximately 65% of the construction of Phases 1 and 2 of the Aneth Unit CO₂ project. We currently anticipate that Phase 3 injections of CO₂ will commence in the second quarter of 2008 and Phase 4 injections of CO₂ will commence in the first quarter of 2009. Later, in Phase 4, we plan to expand the CO₂ flood over the rest of the Aneth Unit. Much of the expenditure associated with the construction of Phases 1, 2 and 3 is for infrastructure and equipment that also will be utilized in Phase 4, such that Phase 4 should be relatively less expensive than Phases 1, 2 and 3.

McElmo Creek Unit.  The waterflood of one portion of the Desert Creek reservoir was abandoned prior to reaching the current economic limit of water-cut. We believe that more hydrocarbons can now be economically recovered from this zone by restarting the waterflood, and we plan to do so in the fourth quarter of 2007. At the same time, we plan to expand the existing CO₂ flood into this same Desert Creek zone as well. The incremental production from both the waterflood restart and the expanded CO₂ flood are expected to be realized concurrently. Capital costs are expected to be relatively minor because the new waterflood and

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CO₂ flood projects will use existing wells and pipelines that are in place for the current waterflood and CO₂ flood operations.

Ratherford Unit.  We plan to initiate a CO₂ flood of the Desert Creek reservoir of the Ratherford Unit in the third quarter of 2011. In the meantime, we plan to rework wells in the Ratherford Unit in preparation for the Ratherford Unit CO₂ flood.

The following table sets forth, as of June 30, 2007, our estimates of the future capital expenditures, net to our interest, necessary to be made for construction, well work and other costs and for purchases of CO₂ to implement our CO₂ flood projects in each of the units of our Aneth Field Properties. The following table also sets forth the estimated net proved undeveloped reserves included in our reserve report as of June 30, 2007, as a result of these projects. We had incurred $28.4 million of capital expenditures through June 30, 2007, and we expect to incur an additional $209.1 million of capital expenditures over the next 20 years (including purchases of CO₂ under existing contracts), in connection with bringing those incremental proved undeveloped reserves attributable to our CO₂ flood project into production. In order to further these CO₂ flood projects, we expect to incur approximately $62 million of these future capital expenditures during the second half of 2007 and all of 2008 and approximately $101 million of these future capital expenditures from 2009 through 2012.

					Estimated				Estimated
	Estimated		Estimated		Future		Estimated		Future
	Future Capital		Future		Total Capital		Reserves		Development
	Expenditures		CO2 Purchases		Expenditures		(MMBoe)		Cost ($/Boe)
	(In millions, except as otherwise indicated)
Aneth Unit — Phases 1 and 2	$	18.1	$	21.6	$	39.7		8.0	$	4.96
Aneth Unit — Phase 3		11.9		9.2		21.1		3.4		6.21
Aneth Unit — Phase 4		24.6		31.7		56.3		10.3		5.47
McElmo Creek Unit		8.4		10.4		18.8		7.6		2.47
Ratherford Unit		35.6		37.6		73.2		11.6		6.31
Total	$	98.6	$	110.5	$	209.1		40.9	$	5.11

As we advance our CO₂ projects, the injected CO₂ will displace an increasing portion of the water currently being injected in the operation of the waterflood. We will need to safely dispose of that water, and to that end we have drilled a water disposal well with four horizontal laterals. Our engineering studies indicate that this initial well should be able to handle most of the water production, although we will not be able to test and utilize the well without the necessary injection permit, which we expect to receive in the fourth quarter of 2007. We are presently in the process of securing permits to drill a second water disposal well to handle any excess water disposal.

The success of our CO₂ projects also depends on our acquiring adequate amounts of CO₂ at the time we need it. In order to pursue our CO₂ projects over the next nine years and to continue our existing CO₂ floods, we estimate that, as of June 30, 2007, we will need gross aggregate volumes of CO₂ of approximately 151.7 Bcf, or approximately 95.8 Bcf net to our working interest. As of June 30, 2007, we had gross aggregate volumes of approximately 159 Bcf committed to us under two contracts. One of these contracts is with ExxonMobil Gas & Power Marketing Company. The price per Mcf of CO₂ under this contract is a variable price tied to the price of West Texas Intermediate Crude Oil. The volume we are allowed to take and that ExxonMobil is required to deliver is 20,000 Mcf per day, or approximately 21 Bcf over the three years remaining on the contract from July 1, 2007. We are obligated to take-or-pay for a percentage of this volume, with certain limitedmake-up rights if we make take-or-pay payments. We also have the right to resell any CO₂ we are obligated to take under this contract but that we are not able to use. We have the right to take delivery into either the McElmo Creek Pipeline (which would be for our own use) or into Kinder Morgan’s Cortez Pipeline (which would occur if we were reselling the CO₂). The contract term runs until June 30, 2010. ExxonMobil has notified us that it may experience constraints on its delivery capacity. We cannot determine at this time if, to what extent or for what period or periods of time this might reduce the volumes available from ExxonMobil. As of June 30, 2007, we had no material accrued take or pay liability with ExxonMobil.

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The second contract is with Kinder Morgan CO₂ Company, L.P. This gas is also delivered from the McElmo Dome CO₂ field. The price under this contract for CO₂ is also tied to the price of West Texas Intermediate Crude Oil, and the contract runs through December 31, 2016. This contract has a variable schedule of committed contract quantities that coincides with the expected requirements and timing of Phases 1, 2 and 3 of our Aneth Unit CO₂ project as well as the requirements and timing of our Dessert Creek II expansion project in the McElmo Creek Unit, less the volumes expected to be provided under our ExxonMobil contract. The Kinder Morgan contract maximum daily quantities range from 6,000 Mcf per day in July 2007, to a high of approximately 32,000 Mcf per day in 2008 and then declining to approximately 5,000 Mcf per day during 2016, the last year of the contract. The aggregate total contract quantity over the term of the contract for these projects is approximately 56 Bcf of CO₂.

The Kinder Morgan contract also covers the additional volumes we expect to require for Phase 4 of the Aneth Unit CO₂ project and for the Ratherford CO₂ project. We are required to include these volumes as committed volumes under the contract if we proceed with these projects. We are only required to commit to the volumes that we specify to Kinder Morgan. The maximum amounts expected for these projects and for which Kinder Morgan could be committed to deliver start from approximately 42,000 Mcf per day expected to be needed in 2009 up to a maximum amount of 52,000 Mcf per day in 2011, declining to a low of approximately 10,000 Mcf per day in 2016. The aggregate total contract quantity over the term of the contract for these two projects is approximately 82 Bcf of CO₂.

We are required to take on a monthly basis, or pay for if not taken, a percentage of the total of the maximum daily quantities for each month during the term of the Kinder Morgan contract. There aremake-up provisions allowing any take or pay payments we make to be applied against future purchases for specified periods of time. We have a one time right to reduce committed volumes under the contract by up to approximately 41 Bcf for 25% of the contract price at the time the volumes are released. We do not have the right to resell CO₂ required to be purchased under the Kinder Morgan contract. As of June 30, 2007, we had no accrued take or pay liability under the Kinder Morgan contract.

The CO₂ that we purchase for our use under the Kinder Morgan contract will be delivered to us through the McElmo Creek Pipeline. This pipeline is approximately 25 miles in length and runs directly from the McElmo Dome field to our McElmo Creek Unit. Pipelines within our Aneth Field Properties are used to distribute the CO₂ to the Aneth Unit. We own a 75% interest in, and are the operator of, the McElmo Creek Pipeline. The pipeline is currently capable of transporting 25,000 to 30,000 Mcf per day, but we are adding pump capacity to the line that we believe will make it capable of carrying up to 90,000 Mcf per day.

Other Planned Activities.  In the Aneth Unit, we plan to infill drill those sections of the unit where historical recovery has been below the unit average. These wells will use multilateral horizontal wellbores in an effort to improve well injection and production rates. All of the horizontal wells currently planned will use existing vertical wellbores. This infill plan, an extension of the horizontal program successfully conducted by Texaco in the mid-1990s, provides for drilling 30 wells (13 producers and 17 injectors) over the next seven years. In the McElmo Creek Unit, the waterflood of one portion of the Desert Creek reservoir was abandoned prior to reaching the current economic limit of water-cut. As a result, we believe that more reserves can be recovered from this zone by restarting the waterflood. In the McElmo Creek Unit, we also plan to infill drill those sections of the unit where historical recovery has been below the unit average. As with the plan in the Aneth Unit, we intend to use multilateral horizontal wells in an effort to improve well injection and production rates. We anticipate drilling ten wells (five producers and five injectors) in this unit over the next five years. Additionally, our Ratherford horizontal infill program contemplates six wells (two producers and four injectors) over the next four years. This plan is an extension of the horizontal program conducted in the Ratherford Unit by Mobil.

Estimated Net Proved Reserves

The following table presents our estimated net proved oil and gas reserves and the present value of our estimated net proved reserves as of December 31, 2004, 2005, and 2006, and as of June 30, 2007. The reserve data as of December 31, 2004 and 2005 are based on reports prepared by us and audited by Sproule Associates

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Inc., independent petroleum engineers. The reserve data as of December 31, 2006, and June 30, 2007 were prepared by us and audited by Netherland, Sewell & Associates, Inc., independent petroleum engineers, which we also refer to as “NSAI” in this prospectus. Please see “Risk Factors — Risks Related to Our Business — Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities of our proved reserves” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in evaluating the material presented below.

NSAI follows the general principles set forth in the standards pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers. A reserve audit as defined by the Society of Petroleum Engineers is not the same as a financial audit. The Society of Petroleum Engineers’ definition of a reserve audit includes the following concepts:

•  A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as to whether such reserve information, in the aggregate, is reasonable and has been presented in conformity with generally accepted petroleum engineering and evaluation principles.

•  The estimation of proved reserves is an imprecise science due to the many unknown geologic and reservoir factors that cannot be estimated through sampling techniques. Since reserves are only estimates, they cannot be audited for the purpose of verifying exactness. Instead, reserve information is audited for the purpose of reviewing in sufficient detail the policies, procedures and methods used by a company in estimating its reserves so that the reserve auditors may express an opinion as to whether, in the aggregate, the reserve information furnished by a company is reasonable and has been estimated and presented in conformity with generally accepted petroleum engineering and evaluation principles.

•  The methods and procedures we used, and the reserve information we furnished, must be reviewed in sufficient detail to permit the reserve auditor, in its professional judgment, to express an opinion as to the reasonableness of the reserve information. The auditing procedures require the reserve auditor to prepare its own estimates of reserve information for the audited properties.

To further clarify, in conjunction with the audit of our proved reserves and associated pre-tax present value, we provided to NSAI our external and internal engineering and geoscience technical data and analyses. Following NSAI’s review of that data, it had the option of honoring our interpretation, or making its own interpretation. No data was withheld from NSAI and NSAI accepted without independent verification the accuracy and completeness of the historical information and data furnished by us with respect to ownership interest, oil and gas production, well test data, oil, natural gas liquids and gas prices, operating and development costs and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of its evaluation something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.

In the course of its evaluations, NSAI prepared, for all of the audited properties, its own estimates of our proved reserves and the pre-tax present value of such reserves discounted at 10%. NSAI’s estimates of those proved reserves and the pre-tax present value of such reserves discounted at ten percent did not differ from our estimates by more than ten percent in the aggregate. However, when compared on alease-by-lease,field-by-field orarea-by-area basis, some of our estimates were greater and some were less than the estimates of NSAI. When such differences do not exceed 10% in the aggregate and NSAI is satisfied that the proved reserves and pre-tax present value of such reserves discounted at 10% are reasonable and that its audit objectives have been met, NSAI will issue an unqualified audit opinion. Remaining differences are not resolved due to the limited benefit of continuing such analyses by us and NSAI. At the conclusion of the audit process, it was NSAI’s opinion, as set forth in its audit letters, that our estimates of our proved oil and gas reserves and associated pre-tax future net revenues discounted at 10% are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles.

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The standardized measure shown in the table below is not intended to represent the current market value of our estimated oil and gas reserves. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC.

	As of December 31,									As of June 30,
	2004			2005			2006(1)			2007
Estimated net proved reserves:
Oil (MBbl)		17,827			23,500			78,357			77,792
Gas (MMcf)		2,404			3,750			1,890			1,630
Total (MBoe)		18,228			24,125			78,672			78,064
Proved developed reserves as a percentage of total proved reserves		67	%		59	%		42	%		44	%
Standardized measure ($ in millions)(2)(3)	$	199.3		$	325.2		$	978.3		$	1,159.3

(1)

Includes the ExxonMobil Properties acquired on April 14, 2006.

(2)

In accordance with SEC requirements, our estimated net proved reserves and standardized measure were determined using end of the period prices for oil and gas that were realized as of the date set forth below. The reserves estimates utilized year-end NYMEX posted prices for oil for the dates presented, NYMEX Henry Hub posted prices for gas as of December 31, 2004, 2005 and 2006 and the El Paso San Juan Basin posted price for gas as of June 30, 2007, shown below, for the product but as adjusted for location differentials as of the effective date of the report as well as plant fees and Btu content.

	As of December 31,						As of June 30,
	2004		2005		2006		2007
Oil ($/Bbl)	$	43.45	$	61.06	$	61.05	$	70.68
Gas ($/MMBtu)		6.15		9.52		5.64		6.12

(3) Standardized measure is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of the estimate), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Our standardized measure as of December 31, 2006, and June 30, 2007, do not reflect any future income tax expenses because we were not subject to federal income taxes as of those dates. Standardized measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk.”

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

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

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

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Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Therefore, without reserve additions in excess of production through successful exploitation and development activities or acquisitions, our reserves and production will ultimately decline over time. Please read “Risk Factors” and “Note 10 — Supplemental Oil and Gas Information (unaudited)” to the unaudited condensed combined financial statements of Resolute Energy Partners Predecessor atF-35 for a discussion of the risks inherent in oil and gas estimates and for certain additional information concerning our estimated proved reserves.

Production and Price History

The following table presents historical operating information of the Chevron Properties for the eleven months ended November 30, 2004, our properties for the period from inception to December 31, 2004, and the years ended December 31, 2005 and 2006, and pro forma historical operating information of our properties for the year ended December 31, 2006, and the six months ended June 30, 2007, giving effect to our purchase of the ExxonMobil Properties as if such purchase had occurred on January 1, 2006.

														Pro Forma
														Resolute Energy
			Resolute Energy Partners Predecessor											Partners, LP
	Chevron Properties		January 22,
	Eleven Months		2004													Six Months
	Ended		(Inception) to							Six Months Ended				Year Ended		Ended
	November 30,		December 31,			Year Ended December 31,				June 30,				December 31,		June 30,
	2004		2004(1)			2005		2006(2)		2006(2)		2007		2006(3)		2007
Production Sales Data:
Oil (MBbl)		731		60			720		1,588		606		973		1,881		973
Gas (MMcf)(4)		470		(11	)		136		227		81		92		259		92
Natural gas liquids (MBbl)		—		1			56		91		33		58		111		58
Equivalent volumes (MBoe)		810		59			799		1,717		653		1,046		2,035		1,046
Daily equivalent volumes (Boe/d)		2,425		1,922			2,189		4,704		3,608		5,779		5,575		5,779
Average Realized Prices:
Oil ($/Bbl)	$	34.12	$	44.62		$	46.53	$	62.72	$	61.80	$	61.64	$	62.48	$	61.64
Gas ($/Mcf)		5.69		—			5.01		3.68		4.09		2.63		3.29		2.63
Natural gas liquids ($/Bbl)		—		20.00			20.02		33.05		30.36		32.07		32.77		32.07
Other Operating Data:
Lease operating expenses ($/Boe)	$	8.06	$	11.15		$	10.93	$	14.48	$	14.40	$	15.78	$	13.36	$	15.78
Workover expenses ($/Boe)		—		0.36			4.83		7.75		6.79		5.45		7.05		5.45
Production taxes ($/Boe)		3.67		5.76			3.47		4.55		4.69		4.34		4.56		4.34

(1)	Includes the operating data of the Chevron Properties for the period beginning on the date of acquisition, November 30, 2004.
(2)	Includes the operating data of the ExxonMobil Properties for the period beginning on the date of acquisition, April 14, 2006.
(3)	The pro forma operating data for the year ended December 31, 2006, include the operating data of the ExxonMobil Properties as though such acquisition had been completed on January 1, 2006.
(4)	We acquired the Chevron Properties on November 30, 2004. In conjunction with the revenue distribution for plant operations during December 2004, our proceeds were adjusted for the recovery of gas imbalances related to differences between our equity gas produced and our gas plant entitlements, which resulted in us recognizing gas production of (11) MMcf during the period January 22, 2004 (Inception) to December 31, 2004.

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Productive Wells

The following table sets forth information as of June 30, 2007, relating to the productive wells in which we owned a working interest. Productive wells consist of producing wells and wells capable of producing, including oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells. Although we currently produce small amounts of gas, all of our producing wells are categorized as oil wells under applicable generally accepted engineering standards.

	Wells
Units	Gross		Net
Aneth Unit		163		101
McElmo Creek Unit		138		104
Ratherford Unit		101		60
Total		402		265

Acreage

All of our leasehold acreage is categorized as developed and all is held by production. The following table sets forth information as of June 30, 2007, relating to our leasehold acreage:

	Developed Acreage(1)
					Net Revenue
Units	Gross(2)		Net(3)		Interest(4)
Aneth Unit		14,775		10,342		53.9%
McElmo Creek Unit		13,357		10,018		61.6%
Ratherford Unit		12,910		7,762		51.0%
Total		41,042		28,122

(1)	Developed acres are all acres within a federal operating unit.
(2)	A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.
(3)	A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests that we own in gross acres expressed as whole numbers and fractions thereof.
(4)	The net revenue interest is the percentage of total production to which we are entitled after reducing such percentage by the percentage of burdens on such production such as royalties and overriding royalties.

Drilling Results

The activities we have conducted have primarily involved acquiring our properties in the Greater Aneth Field and conducting exploitation activities thereon. To date, we have not drilled any new vertical production or injection wells. During the year ended December 31, 2006, we drilled and completed six gross (3.7 net) horizontal wells, including twelve laterals. During the six months ended June 30, 2007, we drilled and completed nine gross (5.6 net) horizontal wells, including fifteen laterals. To date we have not drilled any dry holes.

Relationship with the Navajo Nation

The purchase of our Aneth Field Properties was facilitated by our strategic alliance with NNOG and, through NNOG, the Navajo Nation. The Navajo Nation formed NNOG, a wholly-owned corporate entity, under Section 17 of the Indian Reorganization Act. Through our strategic alliance with NNOG, we help the Navajo Nation achieve one of its most important long-term goals, which is the ownership and operation of the oil and

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gas resources on the Navajo Reservation. We supply NNOG with acquisition, operational and financial expertise and NNOG helps us communicate and interact with the Navajo Nation agencies.

Our strategic alliance with NNOG is embodied in a Cooperative Agreement that we entered into with NNOG in 2004 to facilitate our joint acquisition of Chevron’s interests in the Greater Aneth Field. The agreement was amended subsequently to facilitate our joint acquisition of ExxonMobil’s interests in the Greater Aneth Field. Among other things, this agreement provides that:

•  We and NNOG will cooperate on the acquisition and subsequent development of our respective properties in the Greater Aneth Field. This agreement was fundamental to our being able to purchase our Aneth Field Properties. The Navajo Nation has a statutory preferential right to purchase any oil and gas lease or working interest in such lease at the time the lease or interest is transferred. As a consequence of our agreement with NNOG, the Navajo Nation used the practical influence of its preferential purchase right to the advantage of NNOG and us in acquiring both the Chevron Properties and the ExxonMobil Properties.

•  NNOG has three purchase options with respect to the Chevron Properties and three separate but substantially similar purchase options with respect to the ExxonMobil Properties. Each purchase option would allow NNOG to acquire up to 10% of the working interests we acquired from each of Chevron and ExxonMobil. These purchase options are described in greater detail below.

•  NNOG will assist us in dealing with the Navajo Nation and its various agencies, and we will assist NNOG in expanding its financial expertise and its operating capabilities. Since we acquired the Aneth Field Properties, NNOG has helped facilitate interaction between us and the Navajo Nation Minerals Department and other agencies of the Navajo Nation. For example, NNOG served as an intermediary between us and the Navajo Nation Minerals Department and other agencies of the Navajo Nation to help us secure permits and surface owner approval for our3-D seismic shoot in the Aneth Unit. NNOG also played a very active role in negotiating the terms of a renewal of the right-of-way underlying our gas gathering and compression system in the Aneth Unit.

•  NNOG has a right of first negotiation in the event of a proposed sale or change of control of us or a sale of all or substantially all of the Chevron Properties or the ExxonMobil Properties by us. This right is separate from and in addition to the statutory preferential purchase right held by the Navajo Nation. The transactions contemplated by this offering will not constitute a change of control.

In connection with our acquisition of each of the Chevron Properties and the ExxonMobil Properties, pursuant to the terms of the Cooperative Agreement, we granted NNOG three separate but substantially similar purchase options. Each purchase option entitles NNOG to purchase from us up to 10% of the undivided working interests that we acquired from Chevron or ExxonMobil, as applicable, from each unit in the Greater Aneth Field. Each purchase option entitles NNOG to purchase, for a limited period of time, the applicable portion of the undivided working interest we acquired at fair market value, which is determined without giving effect to the existence of the Navajo Nation statutory preferential purchase right or the fact that the properties are located on the Navajo Reservation. Each option becomes exercisable based upon our achieving a certain multiple of payout of the relevant acquisition costs, subsequent capital costs and ongoing operating costs attributable to the applicable working interests. Revenue applicable to the determination of payout includes the effect of our hedging program. The multiples of payout that trigger the exercisability of the purchase options with respect to each of the Chevron Properties and the ExxonMobil Properties are 100%, 150% and 200%. The options are not exercisable prior to four years from the relevant acquisition except in the case of a sale of such assets by, or a change of control of, us. In that case, the first option for 10% would be accelerated and the other options would terminate. Assuming the purchase options are not accelerated due to a change of control of us, we expect that the initial payout associated with the purchase options granted in connection with the acquisition of the Chevron Properties will occur no sooner than 2010, and the initial payout associated with the purchase options granted in connection with the acquisition of the ExxonMobil Properties will occur no sooner than 2013.

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The following table demonstrates the maximum net undivided working interest in each of the Aneth Unit, the McElmo Creek Unit and the Ratherford Unit that NNOG could acquire from us upon exercising each of its purchase options under the Cooperative Agreement. The exercise by NNOG of its purchase options in full would not give it the right to remove us as operator of any of the units included in our Aneth Field Properties.

	Aneth			McElmo Creek			Ratherford
	Unit			Unit			Unit
Chevron Properties:
Option 1 (100% Payout)		5.30	%		1.50	%		0.30	%
Option 2 (150% Payout)		5.30	%		1.50	%		0.30	%
Option 3 (200% Payout)		5.30	%		1.50	%		0.30	%
Total		15.90	%		4.50	%		0.90	%
ExxonMobil Properties:
Option 1 (100% Payout)		0.75	%		6.00	%		5.60	%
Option 2 (150% Payout)		0.75	%		6.00	%		5.60	%
Option 3 (200% Payout)		0.75	%		6.00	%		5.60	%
Total		2.25	%		18.00	%		16.80	%

Marketing and Customers

All of our current crude oil production is sold to Giant Industries, Inc., which was acquired by and became a subsidiary of Western Refining, Inc., in May 2007. Giant and Western both have refined product marketing and transportation operations in New Mexico, Colorado and Arizona. Giant has two refineries in the Four Corners area, the 16,600 barrel per day Bloomfield refinery in Farmington, New Mexico, and the 26,000 barrel per day Ciniza refinery in Gallup, New Mexico. Giant refines our crude oil in its refineries. Our production is transported to a terminal that serves these two refineries via a crude oil pipeline owned by NNOG.

Our crude oil production is sold to Giant under two contracts, one covering the production from the Chevron Properties and one covering the production from the ExxonMobil Properties. The contracts provide for a price equal to the NYMEX price for crude oil less a fixed differential of $2.55 per Bbl under one of the contracts and $2.20 per Bbl under the other. The weighted average differential under these two contracts is approximately $2.40 per Bbl based on production at June 30, 2007. The two contracts, each covering about one-half of our production and each with a six-month term that commenced on June 1, 2007, contain evergreen provisions that provide for Giant to continue to purchase the production on a month-to-month basis on the same economic terms. After November 30, 2007, Giant has the right to terminate our contracts upon 180 days notice and cease purchasing crude oil from us. We are currently negotiating a series of longer term agreements with Giant that we expect will provide for crude oil sales from the Greater Aneth Field based on NYMEX crude oil prices less a specified differential.

It is our understanding that Giant operated these refineries at approximately 66% of capacity during 2006 due to supply constraints. The Ciniza refinery in Gallup, New Mexico would be capable of processing our crude oil production if operations at the Bloomfield refinery were interrupted for any reason. In August 2005, Giant acquired an idle crude oil pipeline system that originates near Jal, New Mexico, a regional hub for crude oil, and connects with a Giant-owned pipeline network that directly supplies crude oil to the Bloomfield and Ciniza refineries. It is our understanding that the pipeline will have sufficient crude oil transportation capacity to allow Giant to again operate both refineries near capacity if supply is available. The pipeline first became operational in July 2007, and if there is adequate supply to bring the refineries to capacity, Giant has publicly stated that it may increase production runs at the refineries.

Despite the long history of working with Giant, and despite the value of our crude oil production to Giant, we cannot be certain that the commercial relationship will continue for the indefinite future, and we cannot be certain that one or both of the refineries will not suffer significant down-time. We do not know if or

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how the acquisition of Giant by Western will affect the marketing of our crude oil production. If for any reason Giant is unable or unwilling to purchase our crude oil production, we believe we have other alternatives for marketing our crude oil production. We will incur higher costs if we are required to utilize one of these alternatives than sales to Giant, which could materially and negatively affect our income and cash available for distribution to our unitholders.

Our gas production is minimally processed in the field and then sent via pipeline to the San Juan River Gas Plant for further processing. We sell our gas at daily market prices to numerous purchasers at the tailgate of the plant, and we receive a contractually specified percentage of the proceeds from the sale of natural gas liquids and plant products.

We enter into hedging transactions from time to time with unaffiliated third parties for portions of our crude oil production to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and gas prices. For more a detailed discussion, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview” and “— Quantitative and Qualitative Disclosures About Market Risk.”

The market for our production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, the price of imports of oil, weather conditions, the price and availability of alternative fuels, the proximity and capacity of transportation facilities and overall economic conditions. The oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Aneth Gas Processing Plant

In connection with our acquisition of the Chevron Properties, we acquired from Chevron its 25% interest in gas gathering and compression facilities located on and near the Greater Aneth Field. These facilities are located adjacent to, and were once an integrated part of, a large gas processing plant known as the Aneth Gas Processing Plant, which extracted gas liquid products from the gas produced from the Greater Aneth Field and nearby fields. The Aneth Gas Processing Plant consists of a non-operational portion of the plant that is in the process of being decommissioned and removed by Chevron and an operational portion dedicated to gas compression. When we acquired the Chevron Properties, Chevron agreed to retain its interest in the non-operational portion of the plant and to indemnify us against any costs incurred in connection with the decommissioning of that portion of the plant and the restoration of the site. When we acquired the ExxonMobil Properties, however, we acquired an additional 25% interest in the entire plant. Although Chevron will pay all of the expenses attributable to the interest we acquired from it for the decommissioning of the Aneth Gas Processing Plant, we are still responsible for the share of expenses attributable to the interest we acquired from ExxonMobil. As a result, we will be responsible for ExxonMobil’s 25% share of the decommissioning, removal and restoration and any other costs related to the processing facilities.

The decommissioning and abandonment work on the Aneth Gas Processing Plant includes the removal of asbestos-containing building materials and insulation and limited volumes of hydrocarbon-contaminated and solvent-contaminated soil, and the removal of equipment and structures. The authorization for expenditure currently approved by us and the other working interest owners for this project is $10.5 million. Our share of these costs is 25%, or approximately $2.6 million, although these costs may be greater than this estimate.

It is estimated that the decommissioning and abandonment work will be completed by the end of the first quarter of 2009. As of June 30, 2007, we had paid $0.9 million of the costs for the decommissioning project. Thus, remaining costs for the decommissioning of the plant would be approximately $1.7 million under the current authorization for expenditure. These costs do not include any costs forclean-up or remediation of the subsurface. The Aneth Gas Processing Plant was previously evaluated by the U.S. Environmental Protection Agency, or “EPA,” for possible listing on the National Priorities List, or “NPL,” of sites contaminated with hazardous substances with the highest priority forclean-up under the Comprehensive Environmental Response, Compensation, and Liability Act, or “CERCLA.” Based on its investigation, the EPA concluded no further investigation was warranted and that the site was not required to be listed on the NPL. The Navajo Environmental Protection Agency now has primary jurisdiction over the Aneth Gas Processing Plant site,

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however, and we cannot predict whether it will require further investigation and possibleclean-up. We have been advised by Chevron that a significant portion of the subsurfaceclean-up or remediation costs, if any, would be covered by an indemnity from the prior owner of the plant, and Chevron has provided us with a copy of the pertinent purchase agreement that appears to support its position. We cannot predict, however, whether any subsurface remediation will be required or what the cost of thisclean-up or remediation could be. Additionally, we cannot be certain whether any of such costs will be reimbursable to us pursuant to the indemnity of the prior owner.

The interests that we acquired from Chevron and ExxonMobil in the Aneth Gas Processing Plant, as well as the cost obligations we assumed from ExxonMobil with respect to the decommissioning, restoration and possibleclean-up and remediation and any other costs of the non-operational processing plant facilities and site, will be contributed to, and assumed by, us as part of the formation transactions to take place in connection with the closing of this offering. Please see also “— Environmental and Safety Matters and Regulations — Waste Handling.”

Title to Properties

In connection with our acquisitions of the Chevron Properties and the ExxonMobil Properties, we obtained attorneys’ title opinions showing good and defensible title in the seller to at least 80% of the proved reserves of the acquired properties as shown in the relevant reserve reports presented by the sellers. We also reviewed land files and public and private records on substantially all of the acquired properties containing proved reserves. We believe we have satisfactory title to all of our material proved properties in accordance with standards generally accepted in the industry. Prior to completing an acquisition of proved hydrocarbon leases in the future, we intend to perform title reviews on the most significant leases, and, depending on the materiality of properties, we may obtain a new title opinion or review previously obtained title opinions. Our properties are subject to a statutory preferential purchase right for the benefit of the Navajo Nation to purchase at the offered price any Navajo Nation oil and gas lease or working interest in such a lease at the time the lease or interest is proposed to be transferred. This could make it more difficult to sell our oil and gas leases and, therefore, could reduce the value of our leases if we were to attempt to sell them. Our properties are also subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Competition

Competition is intense in all areas of our industry. Major and independent oil and gas companies actively bid for desirable properties, as well as for the equipment and labor required to operate and develop such properties. Many of our competitors have financial and personnel resources that are substantially greater than ours and such companies may be able to pay more for productive properties and to define, evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Seasonality

Our operations have not historically been subject to seasonality in any material respect.

Environmental and Safety Matters and Regulation

General.  We are subject to various stringent and complex federal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment. These laws and regulations may, among other things:

•  require the acquisition of various permits before drilling commences or other operations are undertaken;

•  require the installation of expensive pollution control equipment;

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

•  suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas;

•  require remedial measures to mitigate pollution from historical and ongoing operations, such as the closure of pits and plugging of abandoned wells and remediation of releases of crude oil or other substances; and

•  require preparation of an Environmental Assessmentand/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.

Governmental authorities have the power to enforce compliance with environmental laws, regulations and permits, and violations are subject to injunctive action, as well as administrative, civil and even criminal penalties. The effects of these laws and regulations, as well as other laws or regulations that may be adopted in the future, could have a material adverse impact on our business, financial condition and results of operations.

We believe our operations are in substantial compliance with all existing environmental and safety laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. Spills or releases may occur, however, in the course of our operations, and we cannot assure you that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our business, financial condition, results of operations or ability to make distributions to you.

The following is a summary of some of the existing laws, rules, and regulations to which our business operations are generally subject, as well as a discussion of certain matters that specifically affect our operations.

Comprehensive Environmental Response, Compensation, and Liability Act.  CERCLA, also known as the “Superfund law,” and comparable tribal and state laws impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several 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. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Such claims may be filed under CERCLA as well as state common law theories or state laws that are modeled after CERCLA. In the course of our operations, we generate wastes that may fall within the definition of hazardous substances under CERCLA and subject us to liability under CERCLA, state law equivalents to CERCLA or common law. Therefore, governmental agencies or third parties could seek to hold us responsible for all or part of the costs to clean up a site at which such hazardous substances may have been released or deposited or other damages resulting from a release.

Waste Handling.  The Resource Conservation and Recovery Act, or “RCRA,” and comparable tribal and state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or gas are currently exempt from regulation as hazardous wastes and instead are

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regulated under RCRA’s non-hazardous waste provisions. It is possible, however, that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our operating expenses, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of industrial solid wastes, such as paint wastes, waste solvents, and waste oils, that may be regulated as hazardous wastes.

In connection with our acquisition of the Chevron Properties, we acquired from Chevron an interest in the Aneth Gas Processing Plant located in the Aneth Unit. This gas plant consists of a non-operational portion of the plant that is in the process of being decommissioned and removed by Chevron and an operational portion dedicated to gas treatment and compression. We are responsible for a portion of the costs of decommissioning and removal of the plant and any restoration and other costs related to the processing facilities. For additional information related to our obligations related to this plant, please read “— Aneth Gas Processing Plant.”

Air Emissions.  The federal Clean Air Act and comparable tribal and state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. These regulatory programs may require us to install expensive emissions abatement equipment, modify our operational practices and obtain permits for our existing operations and before commencing construction on a new or modified source of air emissions, such laws may require us to reduce emissions at existing facilities. As a result, we may be required to incur increased capital and operating costs. Federal, tribal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated tribal and state laws and regulations.

In June 2005, the EPA and ExxonMobil entered into a consent decree settling alleged violations of the federal Clean Air Act associated with the McElmo Creek Unit. In response, ExxonMobil submitted amended Title V and Prevention of Significant Deterioration permit applications for the McElmo Creek Unit Main Flare and other sources and paid a civil penalty and costs associated with a Supplemental Environmental Project, or “SEP.” Pursuant to the consent decree, upgrades to the Main Flare were completed in May 2006, and all of the material compliance measures of the consent decree have been met. The EPA is processing the permit applications. We remain subject to the consent decree, including stipulated penalties for violations of emissions limits and compliance measures set forth in the consent decree.

Actual air emissions reported from these facilities, however, have been below emission limits contained in the draft permits and the consent decree.

Water Discharges.  The federal Water Pollution Control Act, or the “Clean Water Act,” and analogous tribal and state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances into waters of the United States, including wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous tribal or state agency. Federal, tribal and state regulatory agencies can impose administrative, civil and criminal penalties for unauthorized discharges or non-compliance with discharge permits or other requirements of the Clean Water Act and analogous tribal and state laws and regulations.

In addition, the Oil Pollution Act of 1990, or “OPA,” augments the Clean Water act and imposes strict liability for owners and operators of facilities that are the source of a release of oil into waters of the United States. OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. For example, operators of certain oil and gas facilities must develop, implement, and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance to cover costs that could be incurred in responding to oil spills. In addition, owners and operators of certain oil and gas facilities may be subject to liability for cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

In August 2004, the EPA and ExxonMobil entered into a consent decree settling alleged violations of the federal Clean Water Act related to past spills of produced water and crude oil from the McElmo Creek and

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Ratherford Units and failure to prepare and implement Spill Prevention, Control and Countermeasure Plans. ExxonMobil paid a civil penalty and costs to implement a SEP and made certain improvements to the production and injection systems. We expect the consent decree to be terminated by the end of 2007, following confirmation by the EPA of completion of the SEP. Until the consent decree is terminated by the EPA, we are subject to various monitoring, recordkeeping, and reporting requirements outlined in the consent decree, as well as stipulated penalties for spills of produced water and crude oil at the McElmo Creek and Ratherford Units.

In November 2001, the EPA issued an administrative order to ExxonMobil for removal and remediation of crude oil released as a result of a shallow casing leak at the McElmo CreekP-20 well in January 2001. In response, ExxonMobil performed various site assessment activities and began recovering crude oil from the ground water. We are obligated to complete the ground water monitoring and remedial activities required under the administrative order, which we estimate will cost from $100,000 to $300,000 net to our 75% interest in the well.

Underground Injection Control.  Our underground injection operations are subject to the federal Safe Drinking Water Act, as well as analogous tribal and state laws and regulations. Under Part C of the Safe Drinking Water Act, the EPA established the Underground Injection Control program, which established the minimum program requirements for tribal and state programs regulating underground injection activities. The Underground Injection Control program includes requirements for permitting, testing, monitoring, recordkeeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. Tribal and state regulations require us to obtain a permit from the applicable regulatory agencies to operate our underground injection wells. We believe that we have obtained the necessary permits from these agencies for our underground injection wells and that we are in substantial compliance with permit conditions and tribal and state rules. Nevertheless, these regulatory agencies have the general authority to suspend or modify one or more of these permits if continued operation of one of our underground injection wells is likely to result in pollution of freshwater, substantial violation of permit conditions or applicable rules or leaks to the environment. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties for property damages and personal injuries.

Pipeline Integrity, Safety, and Maintenance.  As a result of our ownership interest in the McElmo Creek Pipeline, we are subject to regulation by the federal Department of Transportation, or the “DOT,” under the Hazardous Liquid Pipeline Safety Act and comparable state statutes, which relate to the design, installation, testing, construction, operation, replacement and management of hazardous liquid pipeline facilities. Any entity that owns or operates such pipeline facilities must comply with such regulations, permit access to and copying of records, and file certain reports and provide required information. The DOT may assess fines and penalties for violations of these and other requirements imposed by its regulations. We believe that we are in material compliance with all regulations imposed by the DOT pursuant to the Hazardous Liquid Pipeline Safety Act. Pursuant to the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, the DOT is required to issue new regulations by December 31, 2007, setting forth specific integrity management program requirements applicable to low stress hazardous liquid pipelines. We believe that these new regulations will not have a material adverse effect on our financial condition or results of operations.

Environmental Impact Assessments.  Significant federal decisions, such as the issuance of federal permits or authorizations for certain oil and gas exploration and production activities are subject to the National Environmental Policy Act, or “NEPA.” NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans on federal

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lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay our development of oil and gas projects.

Other Laws and Regulations.  Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, a number of states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventoriesand/or regional greenhouse gas cap and trade programs. On August 22, 2007, the Western Climate Initiative, which is comprised of a number of Western states and Canadian provinces, including the State of Utah, issued a greenhouse gas reduction goal statement in which it announced a goal to collectively reduce regional greenhouse gas emissions to 15% below 2005 levels by 2020. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007, inMassachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding inMassachusetts that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” also may result in future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the Kyoto Protocol, an international treaty, pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. The passage or adoption of new legislation or regulatory programs that restrict emissions of greenhouse gases in areas where we conduct business could adversely affect our operations.

The Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security, or the “DHS,” to issue regulations establishing risk-based performance standards for the security at chemical and industrial facilities, including oil and gas facilities, that are deemed to present “high levels of security risk.” The DHS is in the process of adopting regulations that will determine whether some of our facilities or operations will be subject to additional DHS-mandated security requirements. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Occupational Safety and Health Act.  We are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes that strictly govern the protection of the health and safety of workers. The Occupational Safety and Health Administration’s hazard communication standard, the Emergency Planning and Community Right-to-Know Act, and similar state statutes require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and the public. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Laws and Regulations Pertaining to Oil and Gas Operations on Navajo Nation Lands

General.  Laws and regulations pertaining to oil and gas operations on Navajo Nation lands derive from both Navajo law and federal law, including federal statutes, regulations and court decisions, generally referred to as federal Indian law.

The Federal Trust Responsibility.  The federal government has a general trust responsibility to Indian tribes regarding lands and resources that are held in trust for such tribes. The trust responsibility may be a consideration in courts’ resolution of disputes regarding Indian trust lands and development of oil and gas resources on Indian reservations. Courts may consider the compliance of the Secretary of the U.S. Department of the Interior, or the “Interior Secretary,” with trust duties in determining whether leases, rights-of-way, or contracts relative to tribal land are valid and enforceable.

Tribal Sovereignty and Dependent Status.  The United States Constitution vests in Congress the power to regulate the affairs of Indian tribes. Indian tribes hold a sovereign status that allows them to manage their

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internal affairs, subject to the ultimate legislative power of Congress. Tribes are therefore often described as domestic dependent nations, retaining all attributes of sovereignty that have not been taken away by Congress. Retained sovereignty includes the authority and power to enact laws and safeguard the health and welfare of the tribe and its members and the ability to regulate commerce on the reservation. In many instances, tribes have the inherent power to levy taxes and have been delegated authority by the United States to administer certain federal health, welfare and environmental programs.

Because of their sovereign status, Indian tribes also enjoy sovereign immunity from suit and may not be sued in their own courts or in any other court absent Congressional abrogation or a valid tribal waiver of such immunity. The United States Supreme Court has ruled that for an Indian tribe to waive its sovereign immunity from suit, such waiver must be clear, explicit and unambiguous.

NNOG is a federally chartered corporation incorporated under Section 17 of the Indian Reorganization Act and is wholly owned by the Navajo Nation. Section 17 corporations generally have broad powers to sue and be sued. Courts will review and construe the charter of a Section 17 corporation to determine whether the tribe has either universally waived the corporation’s sovereign immunity, or has delegated that power to the Section 17 corporation.

The NNOG federal charter of incorporation provides that NNOG shares in the immunities of the Navajo Nation, but empowers NNOG to waive such immunities in accordance with processes identified in the charter. NNOG has contractually waived its sovereign immunity, and certain other immunities and rights it may have regarding disputes with us relating to certain of the Aneth Field Properties, in the manner specified in its charter. Although the NNOG waivers are similar to waivers that courts have upheld, if challenged, only a court of competent jurisdiction may make that determination based on the facts and circumstances of a case in controversy.

Tribal sovereignty also means that in certain instances a tribal court is the only court that has jurisdiction to adjudicate a dispute involving a tribe, tribal lands or resources or business conducted on tribal lands or with tribes. Although language similar to that used in our agreements with NNOG that provide for alternative dispute resolution and federal or state court jurisdiction has been upheld in other cases, there is no guarantee that a court would enforce these dispute resolution provisions in a future case.

Federal Approvals of Certain Transactions Regarding Tribal Lands.  Under current federal law, the Interior Secretary (or the Interior Secretary’s appropriate designee) must approve any contract with an Indian tribe that encumbers, or could encumber, for a period of seven years or more, (1) lands owned in trust by the United States for the benefit of an Indian tribe or (2) tribal lands that are subject to a federal restriction against alienation, or collectively “Tribal Lands.” Failure to obtain such approval, when required, renders the contract void.

Except for our oil and gas leases, rights-of-way and operating agreements with the Navajo Nation, our agreements do not by their terms specifically encumber Tribal Lands, and we believe that no Interior Secretarial approval was required to enter into those agreements. With respect to our oil and gas leases and unit operating agreements, these and all assignments to us have been approved by the Interior Secretary. In the case of rights-of-way and assignments of these to us, some of these have been approved by the Interior Secretary and others are in various stages of applications for renewal and approval. It is common for these approvals to take an extended period of time, but such approvals are routine and we believe that all required approvals will be obtained in due course.

Federal Management and Oversight.  Reflecting the federal trust relationship with tribes, the Bureau of Indian Affairs, or the “BIA,” exercises oversight of certain matters on the Navajo Nation reservation pertaining to health, welfare and trust assets of the Navajo Nation. Of relevance to us, the BIA must approve all leases, rights-of-way, applications for permits to drill, seismic permits, CO₂ pipeline permits and other permits and agreements relating to development of oil and gas resources held in trust for the Navajo Nation. While NNOG has been successful in facilitating timely approvals from the BIA, such timeliness is not guaranteed and obtaining such approvals may cause delays in developing the Aneth Field Properties.

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Resources Committee of the Navajo Nation Council.  The Resources Committee is a standing committee of the Navajo Nation Tribal Council, and has oversight and regulatory authority over all lands and resources of the Navajo Nation. The Resources Committee reviews, negotiates and recommends to the Navajo Nation Tribal Council actions involving the approval of energy development agreements and mineral agreements; gives final approvals of rights of way, surface easements, geophysical permits, geological prospecting permits, and other surface rights for infrastructure; oversees and regulates all activities within the Navajo Nation involving natural resources and surface disturbance; sets policy for natural resource development; and oversees the enforcement of federal and Navajo law in the development and utilization of resources, including issuing cease and desist orders and assessing fines for violation of its regulations and orders. The Resources Committee also has oversight authority over, among other agencies and matters, the Navajo Nation Environmental Protection Agency and Navajo Nation environmental laws, the Navajo Nation Minerals Department and Navajo Nation oil and gas laws and the Navajo Nation Land Department and Navajo Nation land use laws. While NNOG has been successful thus far in facilitating timely approvals from the Resources Committee for our operations, such timeliness is not guaranteed and obtaining future approvals may cause delays in developing the Aneth Field Properties.

Navajo Nation Minerals Department of the Division of Natural Resources.   The day-to-day operation of the Navajo Nation minerals program, including the initial negotiation of agreements, applications for approval of assignments, exercise of tribal preferential rights and most other permits and licenses relating to oil and gas development, is managed by the professional staff of the Navajo Nation Minerals Department, located within the Division of Natural Resources and subject to the oversight of the Resources Committee. The Resources Committee and the Navajo Nation Council typically defer to the Minerals Department in decisions to approve all leases and other agreements relating to oil and gas resources held in trust for the Navajo Nation. While NNOG has been successful thus far in facilitating timely action and favorable recommendations from the Minerals Department for our operations, such timeliness is not guaranteed and obtaining future approvals may cause delays in developing the Aneth Field Properties.

Taxation Within the Navajo Nation.  In certain instances, federal, state and tribal taxes may be applicable to the same event or transaction, such as severance taxes. State taxes are rarely applicable within the Navajo Nation Reservation except as authorized by Congress or when the application of such taxes does not adversely affect the interests of the Navajo Nation. Federal taxes of general application are applicable within the Navajo Nation, unless specifically exempted by federal law. We currently pay the following taxes to the Navajo Nation:

•  Oil and Gas Severance Tax.  We pay severance tax to the Navajo Nation. The severance tax is payable monthly and is 4% of our gross proceeds from the sale of oil and gas. Approximately 77% of the Aneth Unit is subject to the Navajo Nation severance tax. The other 23% of the Aneth Unit is exempt because it is either located off of the reservation or it is incremental enhanced oil recovery production, which is not subject to the severance tax. Presently all of the McElmo Creek and Ratherford Units are subject to the severance tax.

•  Possessory Interest Tax.  We pay a possessory interest tax to the Navajo Nation. The possessory interest tax applies to all property rights under a lease within the Navajo Nation boundaries, including natural resources. In 2006, the tax was $4.5 million and is projected to be $5.4 million in 2007.

•  Sales Tax.  We pay Navajo sales tax in lieu of the Navajo Business Activity Tax. The sales tax rate was raised from 3% to 4% effective July 1, 2007. All goods and services purchased for use on the Navajo Nation reservation are subject to the sales tax. The sale of oil and gas is exempt from the sales tax.

Royalties from Production on Navajo Nation Lands.  Under our agreements and leases with the Navajo Nation, we pay royalties to the Navajo Nation. The Navajo Nation is entitled to take its royalties in kind, which it currently does for its oil royalties but not its gas royalties. The Minerals Management Service of the United States Department of the Interior has the responsibility for managing and overseeing royalty payments to the Navajo Nation as well as the right to audit royalty payments.

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Navajo Preference in Employment Act.  The Navajo Nation has enacted the Navajo Preference in Employment Act, or the “Employment Act,” requiring preferential hiring of Navajos by non-governmental employers operating within the boundaries of the Navajo Nation. The Employment Act requires that any Navajo candidate meeting job description requirements receives a preference in hiring. The Employment Act also provides that Navajo employees can only be terminated, penalized, or disciplined for “just cause,” requires a written affirmative action plan that must be filed with the Navajo Nation, establishes the Navajo Labor Commission as a forum to resolve employment disputes and provides authority for the Navajo Labor Commission to establish wage rates on construction projects. The restrictions imposed by the Employment Act and its recent broad interpretations by the Navajo Supreme Court may limit our pool of qualified candidates for employment.

Navajo Business Opportunity Act.  Navajo Nation law requires companies doing business in the Navajo Nation to provide preference priorities to certified Navajo-owned businesses by giving them a first opportunity and contracting preference for all contracts within the Navajo Nation. While this law does not apply to the granting of mineral leases, subleases, permits, licenses and transactions governed by other applicable Navajo and federal law, we treat this law as applicable to our material non-mineral contracts and procurement relating to our general business activities within the Navajo Nation.

Navajo Environmental Laws.  The Navajo Nation has enacted various environmental laws that may be applicable to our Aneth Field Properties. As a practical matter, these laws are patterned after similar federal laws, and the EPA currently enforces these laws in conjunction with the Navajo EPA. The current practice does not preclude the Navajo Nation from taking a more active role in enforcement or from changing direction in the future. Some of the Navajo Nation environmental laws not only provide for civil, criminal and administrative penalties, but also provide for third-party suits brought by Navajo Nation tribal members directly against an alleged violator, with specified jurisdiction in the Navajo Nation District Court in Window Rock.

Thirty-Two Point Agreement.  An explosion at an ExxonMobil retail gas station in December 1997 in the Greater Aneth Field prompted protests by local Native American tribal members. The protesters asserted concerns about environmental degradation, health problems, employment opportunities and renegotiating leases. The protest was settled among the local residents, ExxonMobil and the Navajo Nation by the Thirty-Two Point Agreement that provided, among other things, for ExxonMobil to pay partial salaries for two Navajo public liaison specialists, follow Navajo hiring practices, and settle further issues addressed in the Thirty-Two Point Agreement in the Navajo Nation’s “peacemaker” courts, which follow a community-level conflict resolution format. After the Thirty-Two Point Agreement was executed, the Greater Aneth Field resumed normal operations. While we did not assume the obligations of ExxonMobil under the Thirty-Two Point Agreement when we acquired the ExxonMobil Properties in 2006, it has been our policy to voluntarily comply with this agreement.

Moratorium on Future Oil and Gas Development Agreements and Exploration.   In February 1994, the Navajo Nation issued a moratorium on future oil and gas development agreements and exploration on lands situated within the Aneth Chapter on the Navajo Reservation. All of the Aneth Unit and a significant portion of the McElmo Creek Unit are located within the Aneth Chapter. The Navajo Nation has recently taken the position that the term of the moratorium is indefinite. Given that our operations within the Aneth Chapter are based on existing agreements and currently do not contemplate new exploration in this mature field, the moratorium has had and is expected to continue to have little impact on us.

Other Regulation of the Oil and Gas Industry

The oil and gas industry is extensively regulated by numerous federal, state and local authorities, including Native American tribes. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state and Native American tribes are authorized by statute to issue rules and regulations binding on the oil and gas industry and individual companies, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost

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of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Drilling and Production.  Our operations are subject to various types of regulation at federal, state, local and Navajo Nation levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities, the Navajo Nation and other Native American tribes also regulate one or more of the following:

•  the location of wells;

•  the method of drilling and casing wells;

•  the rates of production or “allowables”;

•  the surface use and restoration of properties upon which wells are drilled and other third-parties;

•  the plugging and abandoning of wells; and

•  notice to surface owners and other third-parties.

State and, on federal and Indian lands, the Bureau of Land Management laws and regulations regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third-parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas that we can produce from our wells or limit the number of wells or the locations that we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil and gas within its jurisdiction.

Gas Sales and Transportation.  Historically, federal legislation and regulatory controls have affected the price of gas and the manner in which our production is marketed. The Federal Energy Regulatory Commission, or FERC, has jurisdiction over the transportation and sale for resale of gas in interstate commerce by gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic gas sold in “first sales,” which include all of our sales of our own production.

FERC also regulates interstate gas transportation rates and service conditions, which affects the marketing of gas that we produce, as well as the revenues we receive for sales of our gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what affect, if any, future regulatory changes might have on gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on-shore and instate waters. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point-of-sale locations.

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Legal Proceedings

We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any of our pending proceedings will not have a material adverse effect on our financial condition or results of operations.

Employees

As of June 30, 2007, our general partner and its affiliates had 108 full-time employees, including 26 geologists, geophysicists, petroleum engineers and land and regulatory professionals. Approximately 32 of our field level employees are represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union (USW) labor union and are covered by a collective bargaining agreement. We believe that our relationship with our employees is satisfactory.

Offices

Resolute Natural Resources Company currently leases approximately 22,725 square feet of office space in Denver, Colorado at 1675 Broadway, Suite 1950, Denver, Colorado 80202 where our principal offices are located. The lease for our Denver office expires on December 31, 2011. In addition, we own and maintain field offices in Cortez, Colorado, and Montezuma Creek, Utah, and we lease other, less significant, office space in locations where we have staff. We believe that our office facilities are adequate for our current needs and that additional office space can be obtained if necessary.

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MANAGEMENT

Management of Resolute Energy Partners, LP

Our general partner, Resolute Energy GP, LLC, will manage our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Resolute Holdings, as the sole member of our general partner, will be entitled to elect or appoint all of the directors of our general partner. As a result, unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders, although our partnership agreement limits such duties and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it.

The directors of our general partner will oversee our operations. Upon the closing of this offering, our general partner will have five directors. Our general partner will increase the size of its board of directors to seven following the closing of this offering. Resolute Holdings will elect all members to the board of directors of our general partner and we expect that, when the size of our board of directors increases to seven directors, three of the directors will be independent as defined under the independence standards established by the New York Stock Exchange. The New York Stock Exchange 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 nominating and governance committee.

In compliance with the requirements of the New York Stock Exchange, Resolute Holdings, the sole member of our general partner, has appointed        as an independent member to the board. Resolute Holdings will appoint a second independent member within 90 days of the effective date of the registration statement of which this prospectus is a part and a third independent member within 12 months of the effective date of the registration statement. The independent members of the board of directors of our general partner will serve as the initial members of the conflicts and audit committees of the board of directors of our general partner.

Pursuant to the terms of the limited liability company agreement of our general partner, our general partner will not be permitted to cause us, without the prior written approval of Resolute Holdings, to:

•  sell all or substantially all of our assets;

•  merge or consolidate;

•  dissolve or liquidate;

•  make or consent to a general assignment for the benefit of creditors;

•  file or consent to the filing of any bankruptcy, insolvency or reorganization petition for relief under the United States Bankruptcy Code or otherwise such relief from debtor or protection from creditors; or

•  take various actions similar to the foregoing.

At least two members of the board of directors of our general partner 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 New York Stock Exchange and the Securities Exchange Act of 1934 to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee in good faith 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.

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In addition, our general partner will have an audit committee of at least three directors who meet the independence and experience standards established by the New York Stock Exchange and the Securities Exchange Act of 1934. 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 registered public accounting firm will be given unrestricted access to the audit committee. Our general partner will also have a compensation committee, which will, among other things, oversee the compensation plans described below.

We, our subsidiaries and our general partner do not have employees. All of our executive management personnel will be employees of Resolute Holdings or one of its subsidiaries. The officers of our general partner will manage the day-to-day affairs of our business. We will also utilize a significant number of employees of Resolute Natural Resources Company, a subsidiary of Resolute Holdings, to operate our business and provide us with general and administrative services. We will reimburse our general partner and its affiliates for allocated expenses of operational personnel who perform services for our benefit and for allocated general and administrative expenses. Please read “— Reimbursement of Expenses of Our General Partner.” Nicholas J. Sutton, Chief Executive Officer, and James M. Piccone, President and General Counsel, estimate that they will spend more than 60% of their time devoted to our business.

Directors and Executive Officers

The following table shows information regarding the current directors and executive officers of our general partner.

Name	Age		Position with our general partner
Nicholas J. Sutton		62	Chief Executive Officer and Director
James M. Piccone		57	President, General Counsel, Secretary and Director
Richard F. Betz		45	Vice President, Business Development
Dale E. Cantwell		51	Vice President, Operations
Theodore Gazulis		53	Vice President and Chief Financial Officer
James L. Kincaid, Jr.		42	Vice President, Marketing and Trading
Janet W. Pasque		49	Vice President, Land
Kenneth A. Hersh		44	Director
Richard L. Covington		49	Director

Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.

Nicholas J. Suttonwas elected Chief Executive Officer and Director of our general partner in September 2007. Mr. Sutton has served as a member of the Board of Managers of Resolute Holdings since its inception in January 2004. Mr. Sutton was a co-founder and the Chief Executive Officer of HS Resources, Inc. from 1978 until the company’s acquisition by Kerr-McGee Corporation in late 2001. From 2002 until founding Resolute Holdings in 2004, Mr. Sutton was a director of Kerr-McGee. Currently, Mr. Sutton is a director of Tidewater Inc. and a member of the Board of the St. Francis Memorial Hospital Foundation. He also is a member of the Society of Petroleum Engineers and of the American Association of Petroleum Geologists.

James M. Picconewas elected President, General Counsel, Secretary and Director of our general partner in September 2007. Mr. Piccone has served as a member of the Board of Managers of Resolute Holdings, LLC since its inception in January 2004. From January 2002 until January 2004 Mr. Piccone was Senior Vice President and General Counsel for Aspect Energy, LLC, a private oil and gas company. Mr. Piccone also served as a contract attorney for Aspect Energy from October 2001 until January 2002. Mr. Piccone served as

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Vice President — General Counsel and Secretary of HS Resources from May 1995 until the acquisition of HS Resources by Kerr-McGee in August 2001. Mr. Piccone is admitted to the practice of law in Colorado and is a member of local and national bar associations. He is a member of the American Association of Corporate Counsel and is a director of Alliance for Choice in Education.

Richard F. Betzwas elected Vice-President, Business Development of our general partner in September 2007. Mr. Betz has served as a Vice President of Resolute Holdings since its inception in January 2004. From September 2001 to January 2004, Mr. Betz was involved in various financial consulting activities related to the energy industry. Prior to that, Mr. Betz spent seventeen years with Chase Securities and successor companies, where he was involved primarily in oil and gas corporate finance. Mr. Betz was a Managing Director in the oil and gas investment banking coverage group with primary responsibility for mid-cap exploration and production companies as well as leveraged finance and private equity. In that capacity, Mr. Betz worked with the HS Resources management team for approximately twelve years.

Dale E. Cantwellwas elected Vice President, Operations of our general partner in September 2007. Mr. Cantwell has served as a Vice President of Resolute Holdings since its inception in January 2004. From March 2003 to January 2004, Mr. Cantwell was a private investor. After the acquisition of HS Resources by Kerr-McGee in August 2001 until February 2003, Mr. Cantwell was Vice President of Kerr-McGee Rocky Mountain Corporation. Prior to that, Mr. Cantwell was Vice President of Operations for HS Resources D-J Basin District. From 1979 until joining HS Resources in 1993, he worked for Amoco Production Company in various engineering and marketing capacities. Mr. Cantwell is a member of the Society of Petroleum Engineers.

Theodore Gazuliswas elected Vice President and Chief Financial Officer of our general partner in September 2007. Mr. Gazulis has served as Vice President and Chief Financial Officer of Resolute Holdings since its inception in January 2004. Mr. Gazulis served as a Vice President of HS Resources from 1984 until its acquisition by Kerr-McGee in 2001. Subsequent to HS Resources’ acquisition by Kerr-McGee and prior to the formation of Resolute Holdings, Mr. Gazulis undertook several consulting assignments, including serving on the board of directors of one private oil and gas company and as the chief financial officer of another. Prior to joining HS Resources, he worked for Amoco Production Company and Sohio Petroleum Company. He is a member of the American Association of Petroleum Geologists.

James L. Kincaid, Jr. was elected Vice President, Marketing and Trading of our general partner in September 2007. Mr. Kincaid has served as a Vice President of Resolute Holdings since its inception in January 2004. In addition, Mr. Kincaid has concurrently served as Chief Executive Officer of Odyssey Energy Services, LLC (Resolute Holdings’ marketing joint venture with Wachovia Holdings) since April 2005. Mr. Kincaid was President of Tide West Trading and Transport Company, a subsidiary of Tide West Oil Company, from 1992 until the company was acquired by HS Resources in 1996. After this merger, Mr. Kincaid served as HS Resources’ President until HS Resources was acquired by Kerr-McGee Corporation in late 2001. From 2002 until Resolute’s founding in 2004, Mr. Kincaid pursued various personal interests.

Janet W. Pasquewas elected Vice President, Land of our general partner in September 2007. Ms. Pasque has served as a Vice President of Resolute Holdings since its inception in January 2004. Ms Pasque was a Vice President of HS Resources where she had responsibility for the land department and joint responsibility for the company’s exploration activities from 1993 until the company’s acquisition by Kerr-McGee in late 2001. Subsequent to the HS Resources acquisition by Kerr-McGee, Ms. Pasque managed the land functions at Kerr-McGee Rocky Mountain Corp. until early 2003. Ms. Pasque served as a land consultant from 2003 until the founding of Resolute in 2004. Prior to joining HS Resources in l993, Ms. Pasque worked for Texaco Inc. and Champlin Petroleum Company. Ms. Pasque is a member of the American Association of Professional Landmen.

Kenneth A. Hershwas elected Director of our general partner in September 2007. Mr. Hersh has served as a member of the Board of Managers of Resolute Holdings since inception in January 2004. Mr. Hersh is the Chief Executive Officer of NGP Energy Capital Management, L.L.C. and is a managing partner of the Natural Gas Partners private equity funds and has served in those or similar capacities since 1989. Prior to joining Natural Gas Partners, L.P. in 1989, he was a member of the energy group in the investment banking

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division of Morgan Stanley & Co. He currently serves as a director of NGP Capital Resources Company, as a director of the general partners of each of Energy Transfer Partners LP, Energy Transfer Equity LP and Eagle Rock Energy Partners, L.P. and as a director on the boards of numerous private companies.

Richard L. Covingtonwas elected Director of our general partner in September 2007. Mr. Covington has served as a member of the Board of Managers of Resolute Holdings since inception in January 2004. Mr. Covington is a managing director of the Natural Gas Partners private equity funds. Mr. Covington joined Natural Gas Partners in 1997. Prior to joining NGP, Mr. Covington was a senior shareholder at the law firm of Thompson & Knight, LLP, in Dallas, Texas. Mr. Covington serves on the boards of numerous private energy companies.

Reimbursement of Expenses of Our General Partner

Our general partner will not receive any management fee or other compensation for its management of our partnership. Under the terms of the administrative services agreement, however, we will reimburse Resolute Holdings and its subsidiaries, including our general partner, 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 and any other assets that we acquire in the conduct of our business. The administrative services agreement will provide further that we will reimburse Resolute Holdings and its subsidiaries for our allocable portion of the premiums on insurance policies covering our assets and the conduct of our business.

Executive Compensation

Our general partner was formed in September 2007. Accordingly, our general partner has not accrued any obligations with respect to management incentive or retirement benefits for its directors and officers for the 2006 or 2007 fiscal years. It is the current intention that our general partner will initially have seven employees, including the Chief Executive Officer, the President and General Counsel, the Chief Financial Officer and other senior staff. The compensation of these employees will be set by the compensation committee of the board of directors of our general partner. The officers and employees of our general partner may participate in employee benefit plans and arrangements sponsored by Resolute Holdings and its subsidiaries, or our general partner. Our general partner has not entered into any employment agreements with any of its employees. 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.

Compensation of Directors

Officers or employees of our general partner or its affiliates who also serve as directors will not receive additional compensation for their service as a director of our general partner. Our general partner anticipates that directors who are not officers or employees of our general partner or its affiliates will receive an annual retainer plus compensation for attending meetings of the board of directors and committee meetings. The amount of such compensation has not yet been determined. In addition, each non-employee director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. We expect that each director will be covered by a liability insurance policy paid for by us and also will be fully indemnified, to the fullest extent permitted under Delaware law, by us for his or her actions associated with being a director. We also intend to enter into indemnification agreements with each of the directors of our general partner. For more information regarding these indemnification agreements, please read “Certain Relationships and Related Party Transactions — Indemnification Agreements.”

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Compensation Discussion and Analysis

We do not directly employ any of the individuals responsible for managing or operating our business, and we do not have any directors. Our general partner will manage our operations and activities, and its board of directors and executive officers will make decisions on our behalf. Any compensation decisions that are required to be made by our general partner will be made by the compensation committee of its board of directors. All of our executive officers will be employees of our general partner or its affiliates. The amount we will be obligated to reimburse our general partner or its affiliates for the compensation of our general partner’s executive officers will be based on the allocation methodology for general and administrative expenses contained in the administrative services agreement.

We and our general partner were formed in September 2007. Consequently, our general partner did not accrue any obligations with respect to executive compensation for its directors and executive officers for the fiscal year ended December 31, 2006, or for any prior periods. Accordingly, we are not presenting any compensation for historical periods. We expect that the named executive officers will have a majority of their total compensation allocated to us as compensation expense.

Following the closing of this offering, we expect that Messrs. Sutton, Piccone, Betz, Cantwell, Gazulis and Kincaid and Ms. Pasque, referred to herein collectively as the “named executive officers,” will constitute our most highly compensated officers for 2007. Compensation paid or awarded by us in 2007 with respect to our named executive officers will reflect only the portion of compensation paid by our general partner or its affiliates that is allocated to us pursuant to the allocation methodology contained in the administrative services agreement. The compensation committee of our general partner has ultimate decision making authority with respect to the compensation of our named executive officers; however, the allocation of the compensation expense to us is subject to the terms and conditions of the administrative services agreement and ratification by our general partner’s board of directors. Awards under any long-term incentive plan adopted by our general partner will be recommended by the compensation committee of our general partner and approved by its board of directors.

With respect to compensation decisions relating to the named executive officers, our general partner’s compensation program must provide overall compensation levels that are competitive enough to attract and retain talented management, while at the same time maintaining reasonable and responsible levels of expense control, and contain a reasonable portion of performance-based compensation to align our named executive officers’ interests with the long-term interests of our unitholders.

As discussed below, our general partner intends to adopt a long-term incentive plan that will provide for long-term equity based awards intended to compensate key employees of our general partner based on the performance of our common units. The direct cash cost of any such awards will be allocated to us subject to the terms of the administrative services agreement. Non-cash charges for these awards that may or may not equal the direct cash charges may also be recorded as expenses in our financial statements. Any such awards that we make will be intended to align the recipient’s long-term interests with those of our unitholders.

Long-Term Incentive Plan

General.  Our general partner intends to adopt a Long-Term Incentive Plan, or the “Plan,” for employees, consultants and directors of our general partner 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 appreciation rights, unit awards and substitute awards and, with respect to unit options and phantom units and unit appreciation rights, the grant of distribution equivalent rights, or DERs. Subject to adjustment for certain events, an aggregate of 4.1 million common units may be delivered pursuant to awards under the Plan. Units that are withheld to satisfy tax withholding obligations are available for delivery pursuant to other awards. In addition, if an award is forfeited, cancelled or otherwise terminates or expires without the delivery of units, the units subject to the award will again be available for new awards under the Plan. The Plan will be administered by the compensation committee of the board of directors of our general partner.

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Awards

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 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, for example, the grantee’s completion of a period of service or upon the achievement of specified financial objectives. In addition, the restricted and phantom units will vest automatically upon a change of control (as defined in the Plan) of us or our general partner, 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 our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person, issuance of new units or any combination of the foregoing. Our general partner 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 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. Payment of a DER may be subject to the same vesting termsand/or settlement terms as the award to which it relates or different vestingand/or settlement terms in the discretion of the compensation committee.

We intend for the restricted units and phantom units granted under the Plan to serve as a form of incentive compensation intended to attract and retain superior employees and as a means of rewarding superior 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. The compensation committee will determine the method or methods that may be used to pay the exercise price of unit options, which may include, without limitation, cash, check acceptable to the compensation committee, withholding of units from the award, tender of previously-acquired units, a “cashless-broker” exercise through procedures approved by the compensation committee, or any combination of the above methods. If a grantee’s employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee’s unvested unit options will be automatically forfeited unless, and to the extent, the option agreement or the compensation committee provides otherwise.

Regulations specifically addressing the treatment of options on partnership interests such as our common units have not yet been issued under Section 409A of the Internal Revenue Code. However, under present guidance, based on the rules applicable to options to purchase stock of corporations, if our general partner issues unit options to individuals who do not provide their services to us or one of our subsidiaries directly, in order to avoid adverse tax consequences under Section 409A, the options must have specific exercise features including either a fixed exercise date or a limited exercise period following vesting. In addition, the

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compensation committee may, in its discretion, provide that unit options will become exercisable upon a “change of control” within the meaning of Internal Revenue Code Section 409A. The compensation committee may, in its discretion, grant DERs in connection with unit option awards. Payment of the DER may be subject to the same vesting terms as the option or such other conditions or restrictions as the compensation committee determines in its discretion. If our general partner grants unit options, subject to the issuance of more favorable guidance applicable to partnership interests under Section 409A of the Internal Revenue Code, our general partner will grant only unit options with features that comply with Section 409A.

Upon exercise of a unit option, our general partner 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, issue new units or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring the common units and the proceeds received by our general partner from an optionee at the time of exercise, as well as any employer, payroll, social security, medicare or similar taxes. 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 our general partner will remit the proceeds it received from the optionee upon exercise of the unit option to us. Provisions of the Plan have been designed to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of common unitholders.

Unit Appreciation Rights.  The Plan will permit the grant of unit appreciation rights, or “UARs.” A UAR is an award that, upon exercise, entitles the participation to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the UAR. This excess will be paid in cash or, in the discretion of the compensation committee, common units. The compensation committee may make grants of UARs containing such terms as it may determine, consistent with the provisions of the Plan. A UAR must have an exercise price that is not less than the fair market value of the common units on the date of grant. The compensation committee may, in its discretion, grant DERs with respect to awards of unit appreciation rights. Payment of the DER may be subject to the same vesting terms as the UAR or such other conditions or restrictions as the plan administrator determines in its discretion. In general, UARs will become exercisable over a period determined by the compensation committee. In addition, the compensation committee may, in its discretion, provide that UARs will become exercisable upon a “change in control” within the meaning of Internal Revenue Code Section 409A. If a grantee’s employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee’s unvested UARs will be automatically forfeited unless, and to the extent, that the award agreement or compensation committee provides otherwise.

As with unit options and based on the current state of guidance under Section 409A, if our general partner issues UARs to individuals who do not provide their services to us or one of our subsidiaries directly, in order to avoid adverse tax consequences under Section 409A of the Internal Revenue Code, the UARs must have specific exercise features including either a fixed exercise date or a limited exercise period following vesting. If we grant unit appreciation rights, subject to the issuance of more favorable guidance applicable to partnership interests under Section 409A of the Internal Revenue Code, we will grant only unit appreciation rights with a 409A-compliant features.

The availability of UARs is intended to furnish additional compensation to Plan participants and align their economic interests with those of common unit holders.

Unit Awards.  The Plan will permit the grant of common units that are not subject to vesting restrictions. Unit awards may be in lieu of or in addition to other compensation payable to the individual. The availability of unit awards is intended to furnish additional compensation to Plan participants and to align their economic interests with those of common unitholders.

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Other Unit-Based Awards.  The Plan will permit the grant of other unit-based awards, which are awards that are based, in whole or in part, on the value or performance of a common unit or are denominated or payable in common units. The compensation committee will determine the terms and conditions of any other unit-based awards. Upon settlement, the award may be paid in common units, cash or a combination thereof, as provided in the award agreement.

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, our general partner 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.

Additionally, Resolute Holdings has issued certain Equity Appreciation Rights, or “EARs,” pursuant to a long-term incentive plan instituted in November of 2006. The EAR plan gives the board of directors of Resolute Natural Resources Company, the administrator of the EAR plan, the right, which would be exercised in coordination with the compensation committee of our general partner, to cause an exchange of EARs for awards under the Plan.

Other Provisions

Termination and Amendment of the Plan.  The board of directors of our general partner, 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. The board of directors of our general partner 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 our general partner may increase the number of common units that may be delivered with respect to awards under the Plan.

Tax Withholding.  Unless other arrangements are made, the compensation committee is authorized to withhold for any award, from any payment due under any award or from any compensation or other amount owing to a participant the amount (in cash, units, units that would otherwise be issued pursuant to such award, or other property) of any applicable taxes payable with respect to the grant of an award, its settlement, its exercise, the lapse of restrictions applicable to an award or in connection with any payment relating to an award or the transfer of an award and to take such other actions as may be necessary to satisfy the withholding obligations with respect to an award.

Anti-Dilution Adjustments.  If any “equity restructuring” event occurs that could result in an additional compensation expense under FAS 123R if adjustments to awards with respect to such event were discretionary, the compensation committee will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the plan administrator will adjust the number and type of units with respect to which future awards may be granted. With respect to a similar event that would not result in a FAS 123R accounting charge if adjustment to awards were discretionary, the compensation committee will have complete discretion to adjust awards in the manner it deems appropriate.

U.S. Federal Income Tax Consequences of Awards Under the Plan.  Generally, there are no income tax consequences for the participant or us when awards are granted under the Plan, other than unit awards, which are taxable to the participant and deductible by us on the date of grant. Upon the payment to the participant of common unitsand/or cash in respect of the vesting of restricted units or phantom units or the exercise of unit options or unit appreciation rights, the participant will recognize compensation income equal to the fair market

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value of the cashand/or units as of the payment date and our general partner generally will be entitled to a corresponding deduction. Section 409A of the Internal Revenue Code imposes certain restrictions on awards that constitute “nonqualified deferred compensation.” We intend that all grants will be made in such a manner as to be exempt from, or comply with, the requirements of Section 409A of the Internal Revenue Code. As additional guidance is issued under Section 409A, we may modify the provisions of the Plan and the terms of awards granted under the Plan to comply with the requirements of Section 409A and the guidance issued thereunder.

We intend that all grants will be made in such a manner as to be exempt from, or comply with, the requirements of Section 409A of the Internal Revenue Code.

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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 who then will beneficially own 5% or more of the then outstanding units;

•  all of the directors of Resolute Energy GP, LLC;

•  each named executive officer of Resolute Energy GP, LLC; and

•  all directors and officers of Resolute Energy GP, LLC as a group.

Percentage

Percentage of

Percentage

Common

of Common

Subordinated

Subordinated

of Total

Units to be

Units to be

Units to be

Units to be

Units to be

Beneficially

Beneficially

Beneficially

Beneficially

Beneficially

Name of Beneficial Owner(1)

Owned(2)

Owned

Owned

Owned

Owned

Resolute Holdings, LLC(3)

6,651,316

32.6

%

20,401,316

100

%

66.3

%

Nicholas J. Sutton(3)

—

*

—

*

*

James M. Piccone(3)

—

*

—

*

*

Richard F. Betz(3)

—

*

—

*

*

Dale E. Cantwell(3)

—

*

—

*

*

Theodore Gazulis(3)

—

*

—

*

*

James L. Kincaid, Jr.(3)

—

*

—

*

*

Janet W. Pasque(3)

—

*

—

*

*

Kenneth A. Hersh(3)(4)

—

*

—

*

*

Richard L. Covington(3)

—

*

—

*

*

All directors and executive officers as a group (9 persons)

—

*

—

*

*

*	Less than 1%.
(1)	Unless otherwise indicated, the address for the beneficial owner is 1675 Broadway, Suite 1950, Denver, Colorado 80202.
(2)	Does not include common units that may be purchased in the directed unit program.
(3)	Natural Gas Partners VII, L.P. has a 70.1% membership interest in Resolute Holdings. Nicholas J. Sutton, James M. Piccone, Richard F. Betz, Dale E. Cantwell, Theodore Gazulis, James L. Kincaid, Jr., and Janet W. Pasque collectively have a 29.9% membership interest in Resolute Holdings, though none of such persons holds more than a 10% membership interest in Resolute Holdings. In addition, Messrs. Sutton, Piccone, Hersh and Covington serve as four out of the five directors on the board of directors of Resolute Holdings. Because none of Messrs. Sutton, Piccone, Betz, Cantwell, Gazulis, Kincaid, Hersh or Covington, or Ms. Pasque, have the power to vote, or to direct the vote, or to dispose of, or direct the disposition of, the common units and subordinated units held by Resolute Holdings, each of such persons disclaims beneficial ownership of the common units and subordinated units held by Resolute Holdings.
(4)	G.F.W. Energy VII, L.P., which is the sole general partner of Natural Gas Partners VII, L.P. and GFW VII, L.L.C., which is the sole general partner of G.F.W. Energy VII, L.P., may be deemed to beneficially own any common units and subordinated units held by Resolute Holdings that may be attributable to Natural Gas Partners VII, L.P. Kenneth A. Hersh, who is a member of GFW VII, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose of, or to direct the disposition of, the units. Mr. Hersh disclaims any deemed beneficial ownership of the units held by Resolute Holdings by virtue of his relationship with Natural Gas Partners VII, L.P.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, our general partner and its affiliates will own 6,651,316 common units and 20,401,316 subordinated units, representing an aggregate 65% limited partner interest in us. In addition, our general partner will own a 2% general partner interest in us and all of our 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 Resolute Energy Partners, LP. 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 our general partner and its affiliates for the contribution of the assets and liabilities to us	• 6,651,316 common units;
	• 20,401,316 subordinated units;
	• 2% general partner interest; and
	• the incentive distribution rights.

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 our general partner and its affiliates, as the holders of an aggregate 6,651,316 common units and 20,401,316 subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level.
	Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $1.2 million on their 2% general partner interest and $37.8 million on their common and subordinated units.
Payments to our general partner and its affiliates	We will reimburse our general partner and its affiliates for the payment of certain operating expenses and for the provision of various general and administrative services for our benefit. For further information regarding the administrative fee, please read “Certain Relationship and Related Party Transactions — Administrative Services Agreement — Reimbursement of General and Administrative Expense.”
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,

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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 various agreements and arrangements 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.

Administrative Services Agreement

Upon the closing of this offering, we will enter into an administrative services agreement with Resolute Holdings, our general partner and certain of their affiliates that will address the following matters:

•  our obligation to reimburse Resolute Holdings and its subsidiaries for operating, executive, professional and administrative expenses, including salary, incentive compensation, and benefits it incurs on our behalf in connection with our business and operations;

•  our obligation to reimburse Resolute Holdings for insurance coverage expenses it incurs with respect to our business and operations and with respect to director and officer liability coverage; and

•  our obligation to indemnify Resolute Holdings for certain liabilities.

Our general partner and its affiliates will also receive payments from us pursuant to the contractual arrangements described below under the caption “— Reimbursement of General and Administrative Expenses.”

Any or all of the provisions of the administrative services agreement will be terminable by Resolute Holdings at its 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 administrative services agreement will also terminate in the event of a change of control of us or our general partner.

Reimbursement of General and Administrative Expenses.  Under the administrative services agreement we will reimburse Resolute Holdings and its subsidiaries 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 administrative services agreement will further provide that we will reimburse Resolute Holdings and its subsidiaries for our allocable portion of the premiums on insurance policies covering our assets.

Pursuant to these arrangements, Resolute Holdings and its subsidiaries 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, geology, and engineering as well as field operations. We will reimburse Resolute Holdings and its subsidiaries 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, including both

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long – and short – term incentive compensation, and the cost of their employee benefits, including 401(k) and health insurance benefits.

Indemnification.  Under the administrative services agreement, we have agreed to indemnify Resolute Holdings against environmental claims, losses and expenses associated with the operation of our assets and incurred after the closing date of this offering.

Competition

None of Resolute Holdings, Natural Gas Partners or any of their respective affiliates will be restricted, under our partnership agreement or any other agreement, from competing with us. Resolute Holdings, Natural Gas Partners and any of their respective affiliates may acquire or dispose of additional exploration and production or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets.

Indemnification Agreements with Our Executive Officers and Directors

We intend to enter into indemnification agreements with each of the executive officers and directors of our general partner. Each indemnification agreement will require us to indemnify each indemnitee to the fullest extent permitted by our partnership agreement. This means, among other things, that we must indemnify the executive officer or director against expenses (including attorneys’ fees), judgments, penalties, fines and amounts paid in settlement that are actually and reasonably incurred in an action, suit or proceeding by reason of the fact that the person is or was an executive officer or director of our general partner or is or was serving at our general partner’s request as a director, officer, employee or agent of another corporation or other entity if the indemnitee meets the standard of conduct provided in our partnership agreement. Also as permitted under our partnership agreement, the indemnification agreements require us to advance expenses in defending such an action provided that the executive officer or director undertakes to repay the amounts if the person ultimately is determined not to be entitled to indemnification from us. We will also make the indemnitee whole for taxes imposed on the indemnification payments and for costs in any action to establish indemnitee’s right to indemnification, whether or not wholly successful.

Other Arrangements with Affiliates

Odyssey Energy Services, LLC (“Odyssey”) is an oil and gas marketing and trading joint venture 50% owned by Resolute Holdings and 50% by Wachovia Investment Holdings, Inc., with profits and losses allocated 40% to Resolute Holdings and 60% to Wachovia Investment Holdings, Inc. From time to time Odyssey has facilitated our marketing arrangements and may do so in the future. Odyssey also has facilitated the arrangement of our hedges and other risk management contracts and may continue to do so in the future.

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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 Resolute Holdings and Natural Gas Partners) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of Resolute Energy GP, LLC have fiduciary duties to manage Resolute Energy GP, LLC, our general partner, in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our limited partners. The board of directors or the conflicts committee of the board of directors of our general partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts many not always be in our best interests or that of 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 is responsible for identifying any such conflict of interest and our general partner may choose to resolve the conflict of interest by any one of the methods described in the following sentence. Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

•  approved by the conflicts committee, 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.

As required by our partnership agreement, the board of directors of our general partner will maintain a conflicts committee, consisting of at least two independent directors. Our general partner may, but is not required to, seek approval from the conflicts committee of a resolution of a conflict of interest with our general partner or affiliates. If our general partner seeks approval from the conflicts committee, the conflicts committee will determine if the resolution of a conflict of interest with our general partner or its affiliates is fair and reasonable to us. Any matters approved by the conflicts committee in good faith 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. If a matter is submitted to the conflicts committee and the conflicts committee does not approve the matter, we will not proceed with the matter unless and until the matter has been modified in such a manner that the conflicts committee determines is fair and reasonable 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. 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

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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.

Resolute Holdings and its affiliates 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.

Neither our partnership agreement nor any other agreement between us, Resolute Holdings and our general partner will prohibit Resolute Holdings and its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Resolute Holdings and its affiliates may acquire or dispose of additional exploration and production or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from these entities could adversely impact our results of operations and cash available for distribution.

Neither our partnership agreement nor any other agreement requires Resolute Holdings to pursue a business strategy that favors us or utilizes our assets in determining what markets to pursue or grow. The directors and officers of Resolute Holdings have a fiduciary duty to make these decisions in the best interests of the owners of Resolute Holdings, which may be contrary to our interests.

Because certain of the directors and officers of our general partner are also directors, managersand/or officers of Resolute Holdings, such directors, managers and officers have fiduciary duties to the members of Resolute Holdings, which may include such directors, that may cause them to pursue business strategies that disproportionately benefit Resolute Holdings or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us, such as Resolute Holdings, 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 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 the exercise of 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 our general partner and its affiliates.

All of our executive management personnel will be employees of our general partner but they will devote only such time to our business and affairs as they, in their discretion, deem appropriate. We also will utilize a significant number of employees of Resolute Holdings to operate our business and provide us with general and administrative services for which we will reimburse Resolute Holdings for allocated expenses of personnel who perform services for our benefit and we also will reimburse Resolute Holdings for allocated general and administrative expenses generally associated with the services provided. Affiliates of our general partner and Resolute Holdings will also 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 Resolute Holdings and its affiliates.

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

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, and in a manner it believed to be 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 our general partner 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,” our general partner 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 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 our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

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

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

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

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

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

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

•  the distribution of our cash;

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

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

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

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

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

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•  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 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:

•  the amount and timing of operating and development activities;

•  amount and timing of asset purchases and sales;

•  other 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 $25 million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and the general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

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

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

•  hastening the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits 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 Resolute Holdings and its affiliates are reimbursable by us.

We will reimburse Resolute Holdings 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 in good faith the expenses that are allocable to us.

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

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 against 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 or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

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

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

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

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

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or

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the holders of common units, on the other, depending on the nature of the conflict. We are not required to do so and 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 our 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 and its affiliates to engage in transactions with us that could 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 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.
Rights and remedies of unitholders	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

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“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).

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 or grossly 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 and 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.                 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 direct 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

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 or the books and records of our transfer agent. Each transferee:

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

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

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

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

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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 formed on September 13, 2007, 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, including pursuing the business strategies set forth in “Business — Our Business Strategies”; 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 exploration, development, production and acquisition of oil and gas, 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. For a further description of limits on our business, please read “Certain Relationships and Related Party Transactions.”

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 formation, 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 units and other partnership securities, including to our general partner in respect of its general partner interest and the 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. Except in connection with the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, our general partner’s 2% general partner 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 units 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. Please read “— Issuance of Additional Securities.”
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, Sale or Other Disposition of Assets.”
Dissolution of our partnership	Unit majority. Please read “— Termination and Dissolution.”
Continuation of our partnership 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 December 31, 2017 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of the General Partner.”
Removal of the general partner	Not less than 662/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of the General Partner.”
Transfer of the general partner interest	Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets, to such person. The approval of a majority of the common

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	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 December 31, 2017. Thereafter, our general partner may transfer all or a portion of its general partner interest in us without a vote of our unitholders. Please read “— Transfer of General Partner Interest.”
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 December 31, 2017. 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 our 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 our partnership agreement; or

•  to take other action under our 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 our partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

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

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We currently conduct business only in the states of Utah and Colorado, but in the future we or our subsidiaries may conduct business in other states. Maintenance of our limited liability as a limited partner of the operating partnership may require compliance with legal requirements in the jurisdictions in which we and our subsidiaries conduct business, including qualifying 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 of equity securities, which may effectively rank senior to the common units.

Upon the issuance of additional partnership securities (other than 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. Except in connection with the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, 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 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 under “— No Unitholder Approval,” our general partner is required to seek written approval of the holders of the number of units required to approve

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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.  Generally, no amendment may be made that would:

•  have the effect of reducing the voting percentage of outstanding units required to take any action under the provisions of our partnership agreement;

•  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 32.6% of the outstanding common units and all of the outstanding subordinated units (66.3% of the outstanding units as a single class), assuming the underwriters do not exercise their option to purchase additional common 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 any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities;

•  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, joint venture, limited liability company or other entity, as otherwise permitted by our partnership agreement;

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

•  certain mergers or conveyances set forth in our partnership agreement;

•  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 or assignee if our general partner determines, at its option, 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 (including the division of any limited partner interests into different classes to facilitate uniformity of tax consequences within such class 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 or admitted 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 above amendments described above under “— No Unitholder Approval.” 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, Sale or Other Disposition of Assets

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

In addition, our 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,

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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 or consolidation 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 any partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in our 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 our partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under our 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 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 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

•  our partnership, any operating partnership or any other subsidiaries that we might have would not 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 act with all of the powers of our general partner that are necessary or appropriate to liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Cash Upon Liquidation.” Under some circumstances and subject to some limitations, 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.

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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 December 31, 2017, 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 December 31, 2017, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and such 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 Interest” 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 the vote of the holders of a majority of the outstanding 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 66.3% of our aggregate 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 the removal of our general partner under circumstances where cause exists or the withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine

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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 Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest 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 interest to another person prior to December 31, 2017, 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. Thereafter, our general partner may transfer all or any of its general partner interest to another person without the approval of unitholders. As a condition of any 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 their common or subordinated 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, Resolute Holdings and its affiliates may sell or transfer all or part of their membership interest in Resolute Energy GP, LLC, 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. Prior to December 31, 2017, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after December 31, 2017, 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 Resolute Energy GP, LLC 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

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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 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.

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.”

At the closing of this offering, assuming the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates will own 66.3% of the aggregate outstanding common and subordinated units.

Meetings; Voting

Except as described above regarding a person or group owning 20% or more of any class of units then outstanding, unitholders 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. Units that are owned by Non-Eligible Holders will be voted by our general partner and our general partner will distribute the votes on those units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or, if authorized by our general partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Special 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 (including outstanding units deemed owned

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by the general partner) 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 in the future. Please read “— Issuance of Additional Securities” above. 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 except such units may be considered to be outstanding for purposes of the withdrawal of our general partner. 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 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-Eligible Holders; Redemption

We currently own interests in oil and gas leases on United States federal lands and we may acquire additional interests in similar properties in the future. To comply with certain United States federal laws relating to the ownership of interests in oil and gas leases on United States federal lands, if requested by our general partner, transferees will be required to fill out a properly completed certification that the unitholder is an Eligible Holder, and our general partner, acting on our behalf, may at any time require each unitholder to certify or re-certify that the unitholder is an Eligible Holder. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on United States federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; (3) a public body, including a municipality; or (4) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases on United States federal lands or any direct or indirect interest therein may be acquired and held by an individual that is not a citizen of the United States only through stock ownership in a corporation organized under the laws of the United States or of any state thereof. This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

If a transferee or unitholder, as the case may be, fails to furnish the required certification within 30 days after request by the general partner or provides a false certification, then, as the case may be, such transfer will be void or we will have the right, which we may assign to any of our subsidiaries, to acquire at the lower of the purchase price of their units or the then current market price all but not less than all of the units held by such unitholder. Further, the units held by such unitholder will not be entitled to any allocations of income or loss, distributions or voting rights unless or until a valid certification is provided.

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The purchase price will be paid in cash or delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date. Any such promissory note will also be unsecured and shall be subordinated to the extent required by the terms of our other indebtedness.

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; provided that a person will not be an indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodian services; 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 loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance or be insured under policies obtained by the general partner or any affiliate of the general partner 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.

In addition, we intend to enter into indemnification agreements with each of the executive officers and directors of our general partner. Each indemnification agreement will require us to indemnify each indemnitee to the fullest extent permitted by our partnership agreement. This means, among other things, that we must indemnify the executive officer or director against expenses (including attorneys’ fees), judgments, penalties, fines and amounts paid in settlement that are actually and reasonably incurred in an action, suit or proceeding by reason of the fact that the person is or was an executive officer or a director of our general partner or is or was serving at our general partner’s request as a director, officer, employee or agent of another corporation or other entity if the indemnitee meets the standard of conduct provided in our partnership agreement. Also as permitted under our partnership agreement, the indemnification agreements require us to advance expenses in defending such an action provided that the executive officer or director undertakes to repay the amounts if the person ultimately is determined not to be entitled to indemnification from us. We will also make the indemnitee whole for taxes imposed on the indemnification payments and for costs in any action to establish indemnitee’s right to indemnification, whether or not wholly successful.

Reimbursement of Expenses

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

We intend to enter into an administrative services agreement with Resolute Holdings, our general partner and certain of their affiliates, pursuant to which we will agree to indemnify Resolute Holdings for certain

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liabilities arising after the closing of this offering and one of Resolute Holdings’ subsidiaries, Resolute Natural Resources Company, will operate our properties and perform administrative services for us such as accounting, marketing, corporate development, finance, land, legal and engineering in exchange for reimbursement from us. For a description of the fees and expenses that we will pay pursuant to this agreement, please read “Certain Relationships and Related Party Transactions.”

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

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable 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 of record (without the obligation to determine beneficial interests);

•  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 as the general partner determines is just and reasonable; and

•  any other information regarding our affairs as the general partner determines 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 or which the general partner determines is burdensome to provide and not necessary to for a limited partner to evaluate our business or financial condition.

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

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requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Resolute Energy GP, LLC as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and a structuring fee. Please read “Units Eligible for Future Sale.”

UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, and assuming the underwriters do not exercise their option to purchase additional common units, management of our general partner and Resolute Holdings and its affiliates will hold directly and indirectly an aggregate of 6,651,316 common units and 20,401,316 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 held 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.

Our partnership agreement does not restrict our ability to issue any partnership securities at any time. Any issuance of additional common units or other partnership 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.”

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

Our partnership, our general partner and its affiliates and the directors and executive officers of our general partner, 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 consequences 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 us, insofar as it relates to legal conclusions with respect to matters of United States federal income tax law. 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 Resolute Energy Partners, LP and our operating subsidiaries.

This section does not address all federal income tax matters that affect us or the unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective common 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 our common units.

No ruling has been or will be requested from the IRS regarding any matter that affects us or prospective unitholders. Instead, we will rely on opinions and advice 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 in this discussion 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 our common units and the prices at which our 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 thus will be borne directly by our unitholders. 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.

All statements regarding matters of law and legal conclusions set forth below, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us. Statements of fact do not represent opinions of Vinson & Elkins L.L.P.

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:

•  the treatment of a common unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Common Unit Ownership — Treatment of Short Sales”);

•  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”);

•  whether percentage depletion will be available to a common unitholder or the extent of the percentage depletion deduction available to any common unitholder (please read “— Tax Treatment of Operations — Depletion Deductions”);

•  whether the deduction related to U.S. production activities will be available to a common unitholder or the extent of such deduction to any common unitholder (please read “— Tax Treatment of Operations — Deduction for U.S. Production Activities”); and

•  whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Common Unit Ownership — Section 754 Election” and “— Uniformity of Common Units”).

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Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner in 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. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner, unless the amount of cash distributed to the partner is in excess of his adjusted tax 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 in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships 90% or more of the gross income of which for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, transportation and marketing of natural resources, including oil, 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            % 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 a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that more than 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS, and the IRS has made no determination as to our status or the status of our operating subsidiaries 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. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings, court decisions and the representations described below, we will be classified as a partnership, and each of our operating subsidiaries will be disregarded as an entity separate from us for U.S. federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us. The representations made by us upon which Vinson & Elkins L.L.P. has relied include:

(1)	Neither we, nor any of our operating subsidiaries, have elected or will elect to be treated as a corporation;
(2)	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; and
(3)	Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, gas, or products thereof that are held or to be held by us in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.

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, in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts, 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 deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

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If we were treated as an association 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 common unitholder would be treated as 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 common unitholder’s tax basis in his common units, and taxable capital gain after the common 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 common unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the common units.

The remainder of this section 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 become limited partners of Resolute Energy Partners, LP will be treated as partners of Resolute Energy Partners, LP for federal income tax purposes. Also:

•  assignees who are awaiting admission as partners, and

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

will be treated as partners of Resolute Energy Partners, LP for federal income tax purposes. A beneficial owner of common units whose common 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 common units for federal income tax purposes. Please read “— Tax Consequences of Common Unit Ownership — Treatment of Short Sales.”

Items of our income, gain, loss, or deduction would not appear to be reportable by a common unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a common unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These unitholders are urged to consult their own tax advisors with respect to their status as partners in us for federal income tax purposes.

The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Resolute Energy Partners, LP for U.S. federal income tax purposes.

Tax Consequences of Common Unit Ownership

Flow-Through of Taxable Income.  We will not pay any federal income tax. Instead, each common 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 common unitholder even if he has not received a cash distribution. Each common unitholder will be required to include in income his allocable share of our income, gain, loss and deduction for our taxable year or years ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions.  Distributions made by us to a common unitholder generally will not be taxable to him 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. Cash distributions made by us to a common unitholder in an amount in excess of his tax basis in his common units generally will be considered to be gain from the sale or exchange of those common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. To the extent that cash distributions made by us cause a common 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.”

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Any reduction in a common unitholder’s share of our liabilities for which no partner bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash by us to that common unitholder. A decrease in a common 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, which may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a common unitholder, regardless of his tax basis in his common units, if the distribution reduces the common unitholder’s share of our “unrealized receivables,” including recapture of intangible drilling costs, depletion and depreciation recapture,and/or substantially appreciated “inventory items,” both as defined in Section 751(b) of the Internal Revenue Code, and collectively, “Section 751(b) Assets.” If the distribution reduces a common unitholder’s share of Section 751(b) Assets, he will be treated as having received his proportionate share of the Section 751(b) Assets and then 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 common unitholder’s realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the common unitholder’s tax basis (generally zero) for the share of Section 751(b) Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions.  We estimate that a purchaser of our common units in this offering who holds those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2010, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than            % of the cash distributed to the common unitholder with respect to that period. Thereafter, we anticipate that 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 be sufficient 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 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 intend to adopt and with which the IRS could disagree. Accordingly, these estimates may not prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, 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, than our estimate with respect to the period described above if:

•  gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distribution on all units; or

•  we make a future offering of 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 depletion, depreciation or amortization for federal income tax purposes or that is depletable, 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 common 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 tax basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That tax basis generally will be decreased, but not below zero, by distributions to him from us, by his share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the adjusted tax basis of the underlying producing properties, 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 common unitholder’s share of our nonrecourse liabilities will generally be based on his share of our profits. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

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Limitations on Deductibility of Losses.  The deduction by a common unitholder of his share of our losses will be limited to his tax basis in his common units and, in the case of an individual common unitholder, estate, trust or a corporate common unitholder (if the corporation is taxable under Subchapter C and more than 50% of the value of its stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the common unitholder is considered to be “at risk” with respect to our activities, if that amount is less than his tax basis. A common unitholder subject to these limitations 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 common unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his tax basis or at-risk amount, whichever is the limiting factor, is subsequently increased, provided such losses are otherwise allowable. Upon the taxable disposition of a common unit, any gain recognized by a common 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 loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

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

The at-risk limitation applies on anactivity-by-activity basis, and in the case of oil and gas properties, each property is generally treated as a separate activity. Thus, a taxpayer’s interest in each oil or gas property is generally required to be treated separately so that a loss from any one property would be limited to the at-risk amount for that property and not the at-risk amount for all the taxpayer’s oil and gas properties. It is uncertain how this rule is implemented in the case of multiple oil and gas properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or gas properties we own in computing a common unitholder’s at-risk limitation with respect to us. If a common unitholder were required to compute his at-risk amount separately with respect to each oil or gas property we own, he might not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at-risk amount with respect to his common units as a whole.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitation generally provides that individuals, estates, trusts and certain closely held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from passive activities. The passive loss limitation is applied separately with respect to each publicly traded partnership. Consequently, any losses we generate will be available to offset only 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 a common unitholder’s investments in other publicly traded partnerships) or a common unitholder’s salary or active business income. If we dispose of any part of our interest in an oil or gas property, unitholders will be able to offset their suspended passive activity losses from our activities against the gain, if any, on the disposition. Any previously suspended losses in excess of the amount of gain recognized will remain suspended. Passive losses that are not deductible because they exceed a common unitholder’s share of income we generate may be deducted by the common unitholder 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 tax basis limitation.

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A common 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 attributable 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 common unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a common 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 or qualified dividend income. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders for purposes of the investment interest expense deduction limitation. In addition, the common 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 or local income tax on behalf of any common unitholder or any former common 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 common unitholder on whose behalf the payment was made. If the payment is made on behalf of a common unitholder whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of common units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the 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 a common unitholder in which event the common 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 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, the loss will be first allocated to our unitholders according to their percentage interests in us to the extent of their positive capital account balances and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Internal Revenue Code to account for the difference between the tax basis and fair market value of our assets at the time of this offering, which assets are referred to in this discussion as “Contributed Property.” These “Section 704(c) Allocations” are required to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and the “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “book-tax disparity.” The effect of these allocations to a common unitholder who purchases common units in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market value at the time of the offering. In the event we issue additional common units or engage in certain other transactions in the future, “Reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to all persons who are holders of partnership interests immediately prior to such other transaction, including

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purchasers of common units in this offering, to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated to the extent possible to the common unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other 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 an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than a Section 704(c) Allocation or Reverse Section 704(c) Allocation, will generally be given effect for federal income tax purposes in determining a common unitholder’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a common unitholder’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 unitholders in profits and losses;

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

•  the rights of all the unitholders 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 Common Unit Ownership — Section 754 Election,” “— Uniformity of Common Units” 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 common unitholder’s share of an item of income, gain, loss or deduction.

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

•  none of our income, gain, loss or deduction with respect to those common units would be reportable by the common unitholder;

•  any cash distributions received by the common unitholder with respect to those common 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 common unitholder whose common units are loaned to a short seller. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units. The IRS has announced that it is 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 common 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 non-corporate 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 their tax advisors with respect to the impact of an investment in our common units on their liability for the alternative minimum tax.

Tax Rates.  In general, the highest effective federal income tax rate for individuals currently is 35%, and the maximum United States federal income tax rate for net capital gains of an individual where the asset

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disposed of was held for more than twelve months at the time of disposition, is scheduled to remain at 15% for years 2008 through 2010 and then increase to 20% beginning January 1, 2011.

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. That 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. The Section 743(b) adjustment does not apply to a person who purchases common units directly from us, and it belongs only to the purchaser and not to other unitholders. For purposes of this discussion, a common unitholder’s inside basis in our assets has two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that tax basis.

Where the remedial method of allocating items attributable to book-tax disparities is adopted (which we will generally adopt as to all of our properties), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized book-tax disparity. Under TreasuryRegulation 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, we are authorized to take a position to preserve the uniformity of common units even if that position is not consistent with these and any other Treasury Regulations. Please read “— Uniformity of Common Units.”

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect 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 property’s unamortized book-tax disparity, or treat that portion asnon-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with TreasuryRegulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. 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 common units in the same month would receive depreciation or amortization, whether attributable to 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 Common Units.” A common unitholder’s tax basis for his common units is reduced by his share of our allowable deductions (whether or not such deductions were claimed on our or the unitholder’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the common unitholder to understate gain or overstate loss on any sale of such common units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the common units. If such a challenge were sustained, the gain from the sale of common units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his common units is higher than the common 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 depletion and depreciation deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his common units is lower than those common units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the common units may be affected either favorably or unfavorably by the election. A tax basis

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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 tax basis reduction. Generally a built-in loss or a tax 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 we allocated to our tangible assets to goodwill instead. Goodwill, an intangible asset, is generally either nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax 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 common 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 will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each common unitholder will be required to include in his income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a common unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his common 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 his taxable income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Depletion Deductions.  Subject to the limitations on deductibility of losses discussed above (please read “Tax Consequences of Common Unit Ownership — Limitations on Deductibility of Losses”), unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and gas interests. Although the Internal Revenue Code requires each common unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes. Each common unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the underlying property for depletion and other purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the common unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the common unitholder from the property for each taxable year, computed without the depletion allowance. A common unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the common unitholder’s average daily production of domestic crude oil, or the gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and gas production, with 6,000 cubic feet of domestic gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

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In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a common unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the common unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the common unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the common unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a common unitholder as a result of either the disposition by us of some or all of our oil and gas interests or the disposition by the common unitholder of some or all of his common units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each common unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. We encourage each prospective common unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for Intangible Drilling and Development Costs.  We will elect to currently deduct intangible drilling and development costs (IDCs). IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each common unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a60-month period, beginning with the taxable month in which the expenditure is made. If a common unitholder makes the election to amortize the IDCs over a60-month period, no IDC preference amount in respect of those IDCs will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to oil and gas wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in oil or gas properties and also carries on substantial retailing or refining operations. An oil or gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. In order to qualify as an “independent producer” that is not subject to these IDC deduction limits, a common unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of gas) on average for any day during the taxable year or in the retail marketing of oil and gas products exceeding $5 million per year in the aggregate.

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IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a common unitholder of interests in us. Recapture is generally determined at the common unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Deduction for U.S. Production Activities.  Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such common unitholder, but not to exceed 50% of such unitholder’s IRSForm W-2 wages for the taxable year allocable to domestic production gross receipts. The percentages are 6% for qualified production activities income generated in the years 2007, 2008, and 2009; and 9% thereafter.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each common unitholder will aggregate his share of the qualified production activities income allocated to him from us with the common unitholder’s qualified production activities income from other sources. Each common unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the common unitholder’s share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at-risk rules or the passive activity loss rules. Please read “— Tax Consequences of Common Unit Ownership — Limitations on Deductibility of Losses.”

The amount of a common unitholder’s Section 199 deduction for each year is limited to 50% of the IRSForm W-2 wages actually or deemed paid by the common unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each common unitholder is treated as having been allocated IRSForm W-2 wages from us equal to the common unitholder’s allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders, and thus a unitholder’s ability to claim the Section 199 deduction may be limited.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRSForm W-2 wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each common unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the unitholders. Each prospective common unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Lease Acquisition Costs.  The cost of acquiring oil and gas lease or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read “Tax Treatment of Operations — Depletion Deductions.”

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Geophysical Costs.  The cost of geophysical exploration incurred in connection with the exploration and development of oil and gas properties in the United States are deducted ratably over a24-month period beginning on the date that such expense is paid or incurred.

Operating and Administrative Costs.  Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

Qualified Enhanced Oil Recovery Project Credits.  Certain of our projects may qualify for the Qualified Enhanced Oil Recovery Credits under Section 43 of the Code. This credit is equal to 15% of all qualifying costs, including costs of constructing a carbon dioxide pipeline, costs of acquiring and using carbon dioxide injectant, and well development costs (other than costs of developing carbon dioxide source wells). This credit is reduced by 1/6th for every dollar by which the reference price of crude oil for the preceding calendar year exceeds an inflation adjusted amount. As of the date of the offering, the reference price of crude oil for 2006 exceeded the inflation adjusted amount by more than five dollars, resulting in a 100% phaseout of the credit. However, if crude oil prices decline, common unitholders may be entitled to their allocable share of any resulting credit.

Tax Basis, Depreciation and Amortization.  The tax basis of our tangible assets, such as casing, tubing, tanks, pumping units and other similar property, 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 (i) this offering will be borne by our general partner, and (ii) any other offering will be borne by our unitholders as of that time. Please read “— Tax Consequences of Common 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 subject to these allowances are placed in service. If we determine not to adopt the remedial method of allocation with respect to any difference between the tax basis and the fair market value of goodwill immediately prior to this or any future offering, we may not be entitled to any amortization deductions with respect to any goodwill conveyed to us on formation or held by us at the time of any future offering. Please read “— Uniformity of Common Units.” 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 common 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 Common 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 common 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 we may be able to amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions 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 common units will depend in part on our estimates of the relative fair market values and the 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 tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or tax basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders might change, and unitholders

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might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss.  Gain or loss will be recognized on a sale of common units equal to the difference between the common unitholder’s amount realized and the common unitholder’s tax basis for the common units sold. A common unitholder’s amount realized will equal the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a common unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of common 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 common unitholder’s tax basis in that common unit will, in effect, become taxable income to the extent that a common unit is sold at a price greater than the common 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 common unitholder, other than a “dealer” in common units, on the sale or exchange of a common unit held for more than one year will generally be taxable as long-term capital gain or loss. Capital gain recognized by an individual on the sale of common units held more than twelve months is scheduled to be taxed at a maximum rate of 15% through December 31, 2010. However, a portion of this gain or loss, which may be substantial will be separately computed and taxed as ordinary income or loss under Section 751(a) of the Internal Revenue Code to the extent attributable to assets giving rise to “unrealized receivables” or “inventory items” (both being referred to as “Section 751(a) Assets”) that we own. The term “unrealized receivables” includes potential recapture items, including depreciation, depletion, and IDC recapture. Ordinary income attributable to Section 751(a) Assets may exceed net taxable gain realized on the sale of a common unit and may be recognized even if there is a net taxable loss realized on the sale of a common unit. Thus, a common unitholder may recognize both ordinary income and a capital loss upon a sale of common units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may be used to offset only 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 common 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 tax 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 common units transferred. A common 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 common unitholder considering the purchase of additional common 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 those Treasury 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, that is, 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;

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•  an offsetting notional principal contract; or

•  a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer who 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 or loss 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 common units owned by each of them as of the opening of the applicable exchange on the first business day of the month (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 common unitholder transferring common units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, 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 transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or applies to only transfers of less than all of the common 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 among transferor and transferee unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A common unitholder who owns common 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 is generally 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 is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination.  We will be considered to have 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 common 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 twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders receiving twoSchedule K-1s) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. 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.

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Uniformity of Common Units

Because we cannot match transferors and transferees of common units, we must maintain uniformity of the economic and tax characteristics of the common units to a purchaser of these common 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 TreasuryRegulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the common units. Please read “— Tax Consequences of Common Unit Ownership — Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to that property’s unamortized book-tax disparity, 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 TreasuryRegulation 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 Common 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 common 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 methods and lives as if they had purchased a direct interest in our property. If we adopt this position, 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. We will not adopt this position 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 common 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 common units might be affected, and the gain from the sale of common 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 common 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 common unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

A regulated investment company, or “mutual fund,” is required to derive at least 90% of its gross income from certain permitted sources. Income from the ownership of common units in a “qualified publicly traded partnership” is generally treated as income from a permitted source. We expect that we will meet the definition of a qualified publicly traded partnership.

Non-resident aliens and foreign corporations, trusts or estates that own common units will be considered to be engaged in business in the United States because of the ownership of common 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. Under rules applicable to

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publicly traded partnerships, we will withhold tax, at the highest effective applicable rate, from cash distributions made quarterly to foreign unitholders. Each foreign common unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on aForm W-8 BEN 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 common units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. 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,” that is effectively connected with the conduct of a U.S. 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 common unitholder is a “qualified resident.” In addition, this type of common unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling issued by the IRS, a foreign common unitholder who sells or otherwise disposes of a common unit will be subject to federal income tax on gain realized on the sale or disposition of that common unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign common 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 common unitholder will not be taxed or subject to withholding upon the sale or disposition of a common unit if he has owned less than 5% in value of the common units during the five-year period ending on the date of the disposition and if the common 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 common unitholder, within 90 days after the close of each calendar year, specific tax information, including aSchedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each common unitholder’s share of income, gain, loss and deduction.

We cannot assure you that those positions will 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 common units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each common unitholder to adjust a prior year’s tax liability and possibly may result in an audit of his own return. Any audit of a common 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. The partnership agreement appoints the 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 common unitholder with less than a

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1% profits interest in us to a settlement with the IRS unless that common 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 common 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 common unitholder with an interest in the outcome may participate.

A common 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 common 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:

•  the name, address and taxpayer identification number of the beneficial owner and the nominee;

•  a statement regarding whether the beneficial owner is:

•  a person that is not a U.S. person,

•  a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

•  a tax-exempt entity;

•  the amount and description of common units held, acquired or transferred for the beneficial owner; and

•  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 U.S. persons and specific information on common 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 common 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:

•  for which there is, or was, “substantial authority,” or

•  as to which there is a reasonable basis and the relevant 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 could result in that kind of an “understatement” of income for which no “substantial authority” exists, we would be required to 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 to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

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A substantial valuation misstatement exists if the value of any property, or the adjusted tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted tax basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). If the valuation claimed on a return is 200% 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 for partnerships, individuals, S corporations, and trusts of at least $2.0 million in any single year, or $4.0 million in any combination of tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) is audited by the IRS. Please read “— Information Returns and Audit Procedures” above.

Moreover, if we were to participate in a listed transaction or a reportable transaction (other than a listed transaction) with a significant purpose to avoid or evade tax, you could 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 and Other Tax Considerations

In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property or in which you are a resident. We will initially conduct business and own property in Utah and Colorado. Both of these states impose a personal income tax on individuals. We may also own property or do business in other states in the future that impose personal income taxes or entity level taxes to which we could be subject. Although an analysis of those various taxes is not presented here, each prospective common unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we may do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a common unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular common unitholder’s income tax liability to the state, generally does not relieve a nonresident common unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Common Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.

It is the responsibility of each common unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, or foreign tax consequences of an investment in us. We strongly recommend that each prospective common unitholder consult, and depend on, his own tax counsel or other advisor with regard to those matters. It is the responsibility of each common unitholder to file all tax returns, that may be required of him.

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INVESTMENT IN RESOLUTE ENERGY PARTNERS, LP 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 and provisions under any federal, state, local,non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, “Similar Laws”). 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 individual retirement accounts or annuities (“IRAs”) established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements. Among other things, consideration should be given to:

•  whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

•  whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

•  whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws; 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.

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 unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

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 general partner would also be a fiduciary of such plan and 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 and any other applicable Similar Laws.

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 certain 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

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(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 that are subject to ERISA, IRAs and similar vehicles that are subject to Section 4975 of the Internal Revenue Code.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above and may also satisfy the requirement in (c) above.

Plan fiduciaries contemplating a purchase of our common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Lehman Brothers Inc., UBS Securities LLC and Wachovia Capital Markets, LLC are acting as representatives of the underwriters and joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below.

	Number of
Underwriters	Common Units
Lehman Brothers Inc.
UBS Securities LLC
Wachovia Capital Markets, LLC
Total		13,750,000

The underwriting agreement provides that the underwriters’ obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement, including:

•  the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units as described below), if any of the common units are purchased;

•  the representations and warranties made by us to the underwriters are true;

•  there is no material change in our business or the financial markets; and

•  we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.

	No Exercise	Full Exercise
Per common unit
Total

The representatives of the underwriters have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $      per common unit. After the offering, the representatives may change the offering price and other selling terms.

We will pay Lehman Brothers Inc., UBS Securities LLC and Wachovia Capital Markets LLC a structuring fee of 0.5% of the gross proceeds of this offering (including any exercise of the underwriters’ option to purchase additional common units) for evaluation, analysis and structuring of this offering.

The expenses of the offering that are payable by us are estimated to be $3.35 million (excluding underwriting discounts and commissions and the structuring fee). The underwriters have agreed to reimburse us for a portion of these expenses in an amount of up to 0.25% of the gross proceeds of this offering (including any exercise of the underwriters’ option to purchase additional common units).

Option to Purchase Additional Common Units

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus to purchase, from time to time, in whole or in part, up to an aggregate of 2,062,500 additional common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the

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underwriters sell more than 13,750,000 common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.

Lock-Up Agreements

We, our subsidiaries, our general partner and certain of its affiliates, including the directors and executive officers of our general partner and the participants in our directed unit program, have agreed that, subject to certain exceptions, without the prior written consent of each of Lehman Brothers Inc., UBS Securities LLC and Wachovia Capital Markets, LLC, we and they will not directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, 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 (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.

The180-day restricted period described in the preceding paragraph will be extended if:

•  during the last 17 days of the180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or

•  prior to the expiration of the180-day restricted period, we announce that we will release earnings results during the16-day period beginning on the last day of the180-day period,

in which case the restrictions described in the preceding paragraph 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 occurrence of a material event, unless such extension is waived in writing by Lehman Brothers Inc., UBS Securities LLC and Wachovia Capital Markets, LLC.

Lehman Brothers Inc., UBS Securities LLC and Wachovia Capital Markets, LLC, in their sole discretion, may release the common units and other securities subject to thelock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release common units and other securities fromlock-up agreements, Lehman Brothers Inc., UBS Securities LLC and Wachovia Capital Markets, LLC will consider, among other factors, the holder’s reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time, unless such extension is waived in writing by Lehman Brothers Inc., UBS Securities LLC and Wachovia Capital Markets, LLC.

As described below under “— Directed Unit Program,” any participants in the Directed Unit Program shall be subject to a180-daylock-up with respect to any units sold to them pursuant to that program. Thislock-up will have similar restrictions and an identical extension provision as thelock-up agreement described above. Any units sold in the Directed Unit Program to the directors, officers or employees of our general partner and to certain other persons associated with us shall be subject to thelock-up agreement described above.

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Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated between the representatives and us. In determining the initial public offering price of our common units, the representatives will consider:

•  the history and prospects for the industry in which we compete;

•  our financial information;

•  the ability of our management and our business potential and earning prospects;

•  the prevailing securities markets at the time of this offering; and

•  the recent market prices of, and the demand for, publicly traded common units of generally comparable master limited partnerships.

Indemnification

We, our general partner and certain of our subsidiaries (or their successors) have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933 and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.

Directed Unit Program

At our request, Lehman Brothers Inc. has reserved for sale at the initial public offering price up to           common units offered hereby to the directors, officers and employees of our general partner and its affiliates and certain other persons associated with us. The number of common units available for sale to the general public will be reduced to the extent such persons purchase such reserved common units. Any reserved common units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered hereby. Any participants in this program shall be prohibited from selling, pledging or assigning any units sold to them pursuant to this program for a period of 180 days after the date of this prospectus. This180-daylock-up period shall be extended with respect to our issuance of an earnings release or if material news or a material event relating to us occurs, in the same manner as described above under “—Lock-Up Agreements.”

Stabilization, Short Positions and Penalty Bids

The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Securities Exchange Act of 1934:

•  Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

•  A short position involves a sale by the underwriters of the common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common unitsand/or purchasing common units in the open market. In determining the source of common units to close out the short position, 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

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through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

•  Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.

•  Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on The New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

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 underwritersand/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 common 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 approvedand/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.

New York Stock Exchange

We intend to apply to list our common units for quotation on The New York Stock Exchange under the symbol “REN.” In connection with this listing, the underwriters have undertaken to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet The New York Stock Exchange listing requirements.

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 common units offered by them.

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.

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Relationships/NASD Conduct Rules

The underwriters may in the future perform investment banking and advisory services for us from time to time for which they may in the future receive customary fees and expenses. The underwriters may also, from time to time, engage in other transactions with or perform services for us in the ordinary course of their business. Affiliates of UBS Securities LLC and Wachovia Capital Markets, LLC are lenders under our existing revolving credit facility that will be repaid with a portion of the proceeds from this offering, which will result in these affiliates receiving approximately $8.5 million and $23.2 million, respectively. Although this repayment represents more than 10% of the net proceeds from this offering, because this offering qualifies for an exception under Rule 2710(h)(3) of the NASD Conduct Rules (as discussed below), a Qualified Independent Underwriter is not required.

Because the Financial Industry Regulatory Authority, or “FINRA,” views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules (which are part of the FINRA Rules). 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 a national securities exchange.

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VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Vinson & Elkins LLP, Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The consolidated and combined financial statements of Resolute Energy Partners Predecessor as of December 31, 2004 and 2005, and for the year ended December 31, 2005 and the period January 22, 2004 (Inception) through December 31, 2004, included in this prospectus have been audited by Ehrhardt Keefe Steiner & Hoffman PC, an independent registered public accounting firm, as stated in their report appearing herein and elsewhere in the registration statement and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The financial statements of Resolute Energy Partners Predecessor as of and for the year ended December 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 elsewhere in the registration statement and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The balance sheets of each of Resolute Energy Partners, LP and Resolute Energy GP, LLC, each as of September 26, 2007, 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 elsewhere in the registration statement and are included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The statements of Revenues and Direct Operating Expenses for the properties acquired by Resolute Aneth, LLC from ChevronTexaco (the “Chevron Properties”) for the year ended December 31, 2003 and the eleven months ended November 30, 2004, and for the properties acquired by Resolute Aneth, LLC from Exxon Mobil Corp. (the “ExxonMobil Properties”) for the years ended December 31, 2003, 2004 and 2005 included in this prospectus have been audited by Ehrhardt Keefe Steiner & Hoffman PC, an independent registered public accounting firm, as stated in their reports appearing herein and elsewhere in the registration statement and are included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The information included in this prospectus regarding estimated quantities of proved reserves, the future net revenues from those reserves and their present value is based, in part, on estimates of the proved reserves and present values of proved reserves as of December 31, 2004, 2005 and 2006 and as of June 30, 2007. This information is based on reports prepared by us and audited by independent engineering reserve consultants. The year-end 2004 and 2005 reports were audited by Sproule Associates Inc. The year-end 2006 data and the June 30, 2007 reports were audited by Netherland, Sewell & Associates, Inc.

187

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Securities and Exchange Commission, or the SEC, a registration statement onForm 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 athttp://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.

188

RESOLUTE ENERGY PARTNERS, LP

INDEX TO FINANCIAL STATEMENTS

	Page
RESOLUTE ENERGY PARTNERS, LP
Introduction		F-2
Unaudited Pro Forma Condensed Consolidated Balance Sheet as of June 30, 2007		F-3
Unaudited Pro Forma Condensed Consolidated Statement of Operations for the year ended December 31, 2006		F-5
Unaudited Pro Forma Condensed Consolidated Statement of Operations for the six months ended June 30, 2007		F-6
Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements		F-7
RESOLUTE ENERGY PARTNERS PREDECESSOR
Annual Financial Statements:
Report of Independent Registered Public Accounting Firm		F-11
Report of Independent Registered Public Accounting Firm		F-12
Combined Balance Sheets as of December 31, 2005 and 2006		F-13
Consolidated and Combined Statements of Operations for the period from January 22, 2004 (Inception) to December 31, 2004 and for the years ended December 31, 2005 and 2006		F-14
Consolidated and Combined Statements of Shareholder’s/Member’s Equity for the period from January 22, 2004 (Inception) to December 31, 2004 and for the years ended December 31, 2005 and 2006		F-15
Consolidated and Combined Statements of Cash Flows for the period from January 22, 2004 (Inception) to December 31, 2004 and for the years ended December 31, 2005 and 2006		F-16
Notes to Consolidated and Combined Financial Statements for the period January 22, 2004 (Inception) through December 31, 2004 and the years ended December 31, 2005 and 2006		F-18
Interim Financial Statements:
Condensed Combined Balance Sheets (Unaudited) as of June 30, 2007		F-39
Condensed Combined Statements of Operations (Unaudited) for the six months ended June 30, 2006 and 2007		F-40
Condensed Combined Statements of Shareholder’s/Member’s Equity (Deficit) (Unaudited) for year ended December 31, 2006 and the six months ended June 30, 2007		F-41
Condensed Combined Statements of Cash Flows (Unaudited) for the six months ended June 30, 2006 and 2007		F-42
Notes to the Unaudited Condensed Combined Financial Statements		F-44
RESOLUTE ENERGY PARTNERS, LP
Report of Independent Registered Public Accounting Firm		F-53
Balance Sheet as of September 26, 2007		F-54
Note to Balance Sheet		F-55
RESOLUTE ENERGY GP, LLC
Report of Independent Registered Public Accounting Firm		F-56
Balance Sheet as of September 26, 2007		F-57
Note to Balance Sheet		F-58
CHEVRON PROPERTIES
Report of Independent Registered Public Accounting Firm		F-59
Statements of Revenues and Direct Operating Expenses for the year ended December 31, 2003 and the eleven-month period ended November 30, 2004		F-60
Notes to the Statements of Revenues and Direct Operating Expenses		F-61
EXXONMOBIL PROPERTIES
Report of Independent Registered Public Accounting Firm		F-64
Audited Statements of Revenues and Direct Operating Expenses for the years ended December 31, 2003, 2004 and 2005 and Unaudited Statements of Revenues and Direct Operating Expenses for the three months ended March 31, 2005 and 2006		F-65
Notes to the Statements of Revenues and Direct Operating Expenses		F-66

F-1

Resolute Energy Partners, LP

Unaudited Pro Forma Condensed Consolidated Financial Statements

Introduction

Resolute Energy Partners, LP (the “Partnership”), was formed on September 13, 2007, as a Delaware limited partnership to own, develop and acquire oil and gas properties. Currently, Resolute Holdings, LLC (“Resolute Holdings”), indirectly owns all of the general and limited partner interests in the Partnership. The Partnership plans to pursue an initial public offering (the “Offering”) of common units representing limited partner interests. Immediately prior to the closing of the Offering, Resolute Holdings and its affiliates will contribute Resolute Aneth, LLC (“Resolute Aneth”) to a newly-formed entity, Resolute Energy Operating, LLC. Effective upon the closing of the Offering, Resolute Holdings and its affiliates will contribute to the Partnership all of Holdings’ interest in Resolute Energy Operating, LLC. These transactions will transfer to the Partnership ownership of certain oil and gas properties located in the Greater Aneth Field in the Paradox Basin in the southwestern region of the United States (the “Partnership Properties”). The historical accounting attributes of the Partnership Properties and the Retained Subsidiaries (as defined below) in the hands of Resolute Holdings and its affiliates are referred to herein as “Resolute Energy Partners Predecessor.”

The unaudited pro forma condensed consolidated financial statements are based on the audited and unaudited historical financial statements of Resolute Energy Partners Predecessor included elsewhere in this prospectus. The historical financial statements of Resolute Energy Partners Predecessor include the results of two exploration companies, WYNR, LLC and BWNR, LLC, and one operating company, Resolute Natural Resources Company (collectively, the “Retained Subsidiaries”), all owned by Resolute Holdings. The two exploration companies hold oil and gas leases with no reserves or production attributable to them and have conducted very little activity since their organization. The operating company holds no oil or gas leases. The Retained Subsidiaries will not be contributed to the Partnership in connection with the closing of the Offering. The unaudited pro forma condensed consolidated statements of operations for the year ended December 31, 2006, and for the six months ended June 30, 2007, have been prepared to reflect the elimination as of January 1, 2006, of the Retained Subsidiaries from the combined financial information of Resolute Energy Partners Predecessor. The unaudited pro forma condensed consolidated balance sheet as of June 30, 2007, has been prepared to reflect the same elimination as though it occurred on June 30, 2007.

As further described in Note 1, the unaudited pro forma condensed consolidated financial statements of Resolute Energy Partners, LP give pro forma effect to (i) the acquisition of the ExxonMobil Properties; (ii) the retention by Resolute Holdings of the Retained Subsidiaries and $7.5 million of working capital; (iii) the contribution of Resolute Energy Operating, LLC to the Partnership in exchange for the issuance of common and subordinated units, the 2% general partner interest and the incentive distribution rights; (iv) the sale of 13,750,000 common units to the public; (v) the use of the proceeds from this offering to repay outstanding indebtedness; and (vi) the borrowing of $151.0 million of indebtedness under the Partnership’s new revolving credit facility to repay the Partnership’s remaining outstanding indebtedness.

The Partnership Properties contributed to the Partnership are recorded at historical cost in a manner similar to a reorganization of entities under common control.

The unaudited pro forma condensed consolidated financial statements should be read in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical consolidated and combined financial statements of Resolute Energy Partners Predecessor and notes thereto, the audited statements of revenues and direct operating expenses of the ExxonMobil Properties and the audited statements of revenues and direct operating expenses of the Chevron Properties, each included elsewhere in this prospectus.

The unaudited pro forma condensed consolidated financial statements are based on assumptions that the Partnership 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 results.

F-2

Resolute Energy Partners, LP

Unaudited Pro Forma Condensed Consolidated Balance Sheet

As of June 30, 2007

	Predecessor									Offering and			Resolute Energy
	Historical			Elimination of			Resolute Energy			Financing			Partners, LP
	Financial			Retained			Partners, LP			Pro Forma			Pro Forma,
	Statements			Subsidiaries(a)			Pro Forma			Adjustments			as Adjusted
Assets
Current assets:
Cash and cash equivalents	$			$			$			$	275,000	(b)	$
											(17,875	)(c)
											(3,350	)(d)
											(246,275	)(e)
											150,975	(f)
											(150,975	)(g)		7,500
Accounts receivable:
Trade receivables		32,541			(161	)		32,380			(7,500	)(h)		24,880
Other — Navajo Nation Oil and Gas Company		667						667						667
Derivative instruments		13,580						13,580						13,580
Other current assets		1,008			(949	)		59						59
Total current assets		47,796			(1,110	)		46,686						46,686
Property and equipment, at cost:
Oil and gas properties, full cost method of accounting
Unproved		11,884			(11,884	)
Proved		380,895						380,895						380,895
Accumulated depreciation, depletion and amortization		(23,116	)					(23,116	)					(23,116	)
Net oil and gas properties		369,663			(11,884	)		357,779						357,779
Other property and equipment		3,584			(2,022	)		1,562						1,562
Accumulated depreciation		(959	)		815			(144	)					(144	)
Net other property and equipment		2,625			(1,207	)		1,418						1,418
Net property and equipment		372,288			(13,091	)		359,197						359,197
Other assets:
Restricted cash		9,446						9,446						9,446
Deferred financing costs		5,214						5,214			(5,214	)(i)
											2,000	(g)		2,000
Notes receivable — affiliated entities		2,140			(2,140	)
Deferred offering costs		618						618			(618	)(j)
Derivative instruments		7,659						7,659						7,659
Other assets		398			(55	)		343						343
Total other assets		25,475			(2,195	)		23,280			(3,832	)		19,448
Total assets	$	445,559		$	(16,396	)	$	429,163		$	(3,832	)	$	425,331

See notes to pro forma condensed consolidated financial statements

F-3

Resolute Energy Partners, LP

Unaudited Pro Forma Condensed Consolidated Balance Sheet

As of June 30, 2007

	Predecessor									Offering and			Resolute Energy
	Historical			Elimination of			Resolute Energy			Financing			Partners, LP
	Financial			Retained			Partners, LP			Pro Forma			Pro Forma,
	Statements			Subsidiaries(a)			Pro Forma			Adjustments			as Adjusted
Liabilities and Shareholder’s/Member’s/Partners’ Equity
Current liabilities:
Cash overdraft	$	4,940		$	(4,940	)	$			$			$
Accounts payable and accrued expenses		26,655			(268	)		26,387						26,387
Interest payable		1,467						1,467						1,467
Accrued purchase price payable — ExxonMobil acquisition		1,778						1,778						1,778
Oil and gas sales payable		4,273						4,273						4,273
Asset retirement obligations		1,521						1,521						1,521
Derivative instruments		14,022						14,022						14,022
Accounts payable — Intercompany		617			(617	)		—						—
Total current liabilities		55,273			(5,825	)		49,448			—			49,448
Non-current liabilities:
Long term debt		395,250						395,250			(170,250	)(e)
											(76,025	)(e)
											150,975	(f)
											(148,975	)(g)
														150,975
Asset retirement obligations		6,228						6,228						6,228
Derivative instruments		33,313						33,313						33,313
Contingent tax liability		491			(491	)
Other		12			(12	)
Total long-term liabilities		435,294			(503	)		434,791			(244,275	)		190,516
Total liabilities		490,567			(6,328	)		484,239			(244,275	)		239,964
Shareholder’s/Member’s/Partners’ Equity:
Common stock*		—			—
Additional paid in capital		1,481			(1,481	)
Accumulated deficit		(11,299	)		11,299
Member’s equity (deficit)		(35,190	)		(19,886	)		(55,076	)		275,000	(b)
											(17,875	)(c)
											(3,350	)(d)
											(5,214	)(i)
											(618	)(j)
											(7,500	)(h)
											(185,367	)(k)
General partner’s interest											3,707	(k)		3,707
Limited partners’ interest:
Public — common											61,171	(k)		61,171
Holdings — common											29,659	(k)		29,659
Holdings — subordinated											90,830	(k)		90,830
Total shareholder’s/member’s/partners’ equity		(45,008	)		(10,068	)		(55,076	)		240,443			185,367
Total liabilities and shareholder’s/member’s/partners’ equity	$	445,559		$	(16,396	)	$	429,163		$	(3,832	)	$	425,331

* The par value amount of Resources common stock outstanding is less than $500 and is therefore presented as $0 above due to rounding.

See notes to pro forma condensed consolidated financial statements

F-4

Resolute Energy Partners, LP

Unaudited Pro Forma Condensed Consolidated Statement of Operations

For the year ended December 31, 2006

	Predecessor			Pro Forma Adjustments									Offering and			Resolute Energy
	Historical			Elimination of						Pro Forma			Financing			Partners, LP
	Financial			Retained			ExxonMobil			Resolute Energy			Pro Forma			Pro Forma,
	Statements			Subsidiaries(a)			Properties			Partners, LP			Adjustments			as Adjusted
Revenue:
Oil sales	$	102,000		$			$	18,167		$	120,167					$	120,167
Gas sales		836						15			851						851
Other		3,735						781			4,516						4,516
Total revenue		106,571						18,963			125,534						125,534
Operating expenses:
Lease operating		24,857						2,324			27,181						27,181
Workover		13,312						1,039			14,351						14,351
Production taxes		7,806						1,473			9,279						9,279
General and administrative		6,015			(402	)		—			5,613						5,613
Depreciation, depletion and amortization		11,071			(375	)		1,454	(l)		12,150						12,150
Accretion of asset retirement obligations		206						16	(m)		222						222
Total operating expenses		63,267			(777	)		6,306			68,796						68,796
Income from operations		43,304			777			12,657			56,738						56,738
Other income (expense):
Other income		546			(185	)					361						361
Gain (loss) on derivative instruments		10,895									10,895						10,895
Interest expense		(18,121	)		8			(4,915	)(n)
								(178	)(o)		(23,206	)		13,192	(p)
														654	(q)
														(400	)(r)		(9,760	)
Total other income (expense)		(6,680	)		(177	)		(5,093	)		(11,950	)		13,446			1,496
Net income	$	36,624		$	600		$	7,564		$	44,788		$	13,446		$	58,234
General partner’s interest in net income																$	1,165
Limited partners’ interest in net income:
Common units																$	28,562
Subordinated units																$	28,507
Net income per limited partners’ unit:
Common units																$	1.40
Subordinated units																$	1.40
Weighted average number of limited partner units outstanding:
Common units																	20,401.3
Subordinated units																	20,401.3
Total																	40,802.6

See notes to pro forma condensed consolidated financial statements

F-5

Resolute Energy Partners, LP

Unaudited Pro Forma Condensed Consolidated Statement of Operations

For the six months ended June 30, 2007

	Predecessor									Offering and			Resolute Energy
	Historical			Elimination of			Resolute Energy			Financing			Partners, LP
	Financial			Retained			Partners, LP			Pro Forma			Pro Forma,
	Statements			Subsidiaries(a)			Pro Forma			Adjustments			as Adjusted
Revenue:
Oil sales	$	57,646		$			$	57,646		$			$	57,646
Gas sales		242						242						242
Other		2,371						2,371						2,371
Total revenue		60,259						60,259						60,259
Operating expenses:
Lease operating		16,507						16,507						16,507
Workover		5,700						5,700						5,700
Production taxes		4,536						4,536						4,536
General and administrative		34,617			(1,657	)		32,960						32,960
Depreciation, depletion and amortization		7,915			(274	)		7,641						7,641
Accretion of asset retirement obligations		145						145						145
Total operating expenses		69,420			(1,931	)		67,489						67,489
Income (loss) from operations		(9,161	)		1,931			(7,230	)					(7,230	)
Other income (expense):
Other income		266			(50	)		216						216
Gain (loss) on derivative instruments		(19,541	)					(19,541	)					(19,541	)
Interest expense		(12,545	)		32			(12,513	)		7,903	(p)
											(200	)(r)		(4,810	)
		—
Total other income (expense)		(31,820	)		(18	)		(31,838	)		7,703			(24,135	)
Net income (loss)	$	(40,981	)	$	1,913		$	(39,068	)	$	7,703		$	(31,365	)
General partner’s interest in net loss													$	(627	)
Limited partners’ interest in net loss:
Common units													$	(15,369	)
Subordinated units													$	(15,369	)
Net loss per limited partner unit:
Common units													$	(0.75	)
Subordinated units													$	(0.75	)
Weighted average number of limited partner units outstanding:
Common units														20,401.3
Subordinated units														20,401.3
Total														40,802.6

See notes to pro forma condensed combined financial statements

F-6

RESOLUTE ENERGY PARTNERS, LP

Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements

Note 1 — Basis of Presentation, Transactions and the Offering

Resolute Energy Partners, LP (the “Partnership”), was formed on September 13, 2007 as a Delaware limited partnership to own, develop and acquire oil and gas properties. Currently, Resolute Holdings, LLC (“Resolute Holdings”), indirectly owns all of the general and limited partner interests in the Partnership. The Partnership plans to pursue an initial public offering (the “Offering”) of common units representing limited partner interests. Immediately prior to the closing of the Offering, Resolute Holdings and its affiliates will contribute Resolute Aneth, LLC (“Resolute Aneth”) to a newly-formed entity, Resolute Energy Operating, LLC. Effective upon the closing of the Offering, Resolute Holdings and its affiliates will contribute to the Partnership, all of Holdings’ interests in these transactions will transfer to the Partnership ownership of certain oil and gas properties located in Greater Aneth Field in the Paradox Basin in the southwestern region of the United States (the “Partnership Properties.”) The historical accounting attributes of the Partnership Properties in the hands of Resolute Holdings and its affiliates are referred to herein as “Resolute Energy Partners Predecessor.” Note that the pro forma financial statements do not include an estimated incremental $3.1 million of general and administrative expense that the Partnership expects to incur as a publicly-traded partnership.

The following unaudited pro forma condensed consolidated financial statements for the year ended December 31, 2006, and as of and for the six months ended June 30, 2007, are presented to illustrate the effects of the Offering, the application of net proceeds as set forth under “Use of Proceeds” and related transactions. The unaudited pro forma condensed consolidated financial statements are based on the audited financial statements of Resolute Energy Partners Predecessor included elsewhere in this prospectus. The historical consolidated and combined financial statements of Resolute Energy Partners Predecessor include the results of the Retained Subsidiaries, consisting of two exploration companies, WYNR, LLC and BWNR, LLC, and one operating company, Resolute Natural Resources Company, all owned by Resolute Holdings. The two exploration companies hold oil and gas leases with no reserves or production attributable to them and have conducted very little activity since their organization. The operating company holds no oil or gas leases. The Retained Subsidiaries will not be contributed to the Partnership in connection with the closing of this offering. The pro forma condensed consolidated statements of operations for the year ended December 31, 2006, and for the six months ended June 30, 2007, have been prepared to reflect the elimination as of January 1, 2006, of the Retained Subsidiaries from the consolidated and combined financial information of Resolute Energy Partners Predecessor. The pro forma condensed consolidated balance sheet as of June 30, 2007, has been prepared to reflect the same elimination as though it occurred on June 30, 2007. The unaudited pro forma condensed consolidated financial statements of Resolute Energy Partners, LP give pro forma effect to the following significant transactions:

•  the acquisition of the ExxonMobil Properties as though that acquisition had occurred on January 1, 2006, in the case of the condensed consolidated statements of operations, or as of June 30, 2007, in the case of the condensed consolidated balance sheet;

•  the retention by Resolute Holdings of the Retained Subsidiaries and $7.5 million of working capital;

•  the contribution by Resolute Holdings to Resolute Energy Operating, LLC of Resolute Aneth, and the contribution to us of Resolute Energy Operating, LLC by Resolute Holdings and Resolute Energy GP, LLC (the Partnership’s general partner) in exchange for issuance of 6,651,316 common units and 20,401,316 subordinated units, representing a 65% limited partner interest in the Partnership, a 2% general partner interest and all of the Partnership’s incentive distribution rights;

•  the sale of 13,750,000 common units to the public, representing an aggregate 33.0% limited partner interest in the Partnership;

•  the use of the proceeds from this offering to (1) repay all $170.3 million of outstanding indebtedness under the existing revolving credit facility and $74.0 million of outstanding indebtedness under the

F-7

RESOLUTE ENERGY PARTNERS, LP

Notes to Unaudited Condensed Pro Forma Financial Statements — (Continued)

existing term loan facility and (2) replenish the $7.5 million of working capital previously distributed to Resolute Holdings; and

•  the borrowing of $151.0 million of indebtedness under the new revolving credit facility to repay the remaining balance under the existing term loan facility, which does not include $1.7 million of net additional indebtedness incurred or expected to be incurred subsequent to June 30, 2007, and prior to the completion of this offering.

The Partnership Properties contributed to the Partnership are recorded at historical cost in a manner similar to a reorganization of entities under common control.

The statements of revenues and direct operating expenses for the ExxonMobil Properties do not include depreciation, depletion and amortization, exploration expense, general administrative expenses or interest expenses. However, these costs have been included on a pro forma basis. The pro forma statements of operations, however, are not necessarily indicative of the Partnership’s operations going forward, because these statements necessarily exclude various operating expenses attributable to the ExxonMobil Properties.

The Partnership believes that the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to such transactions.

These unaudited pro forma condensed consolidated financial statements do not purport to represent what the Partnership’s financial position or results of operations would have been if the transactions had occurred on June 30, 2007, or January 1, 2006, respectively. These unaudited pro forma condensed consolidated financial statements should be read in conjunction with the historical consolidated and combined financial statements of Resolute Energy Partners Predecessor and notes thereto, the audited statements of revenues and direct operating expenses of the Chevron Properties and the audited statements of revenues and direct operating expenses of the ExxonMobil Properties included elsewhere in this prospectus.

Note 2 — Pro Forma Adjustments

The following adjustments have been made to the accompanying unaudited pro forma condensed consolidated balance sheet as of June 30, 2007 and the unaudited pro forma condensed consolidated statements of operations for the year ended December 31, 2006 and for the six months ended June 30, 2007:

(a) Reflects the retention by Resolute Holdings of the Retained Subsidiaries. The principal assets retained were unproved oil and gas properties ($11.9 million), other property and equipment ($2.0 million) and a related party receivable ($2.1 million). The principal liability retained was a cash overdraft ($4.9 million). The retention also results in a net decrease in total shareholder’s/member’s/partners’ equity ($10.1 million). The most significant eliminating entry in the statement of operations is the reduction of general and administrative expenses attributable to the Retained Subsidiaries of $1.7 million for the six months ended June 30, 2007.

(b) Reflects estimated gross proceeds to the Partnership of $275.0 million from the issuance and sale of 13,750,000 common units at an assumed initial public offering price of $20.00 per unit.

(c) Reflects estimated underwriting discount and structuring fee of $17.9 million.

(d) Reflects estimated expenses of $3.4 million associated with the Offering and related formation transactions.

(e) Represents repayment of $246.3 million of long term debt with the net proceeds of the Offering. This amount consists of full repayment of the existing revolving credit facility in the amount of $170.3 million and partial repayment of the existing term loan facility in the amount of $76.0 million.

(f) Reflects borrowings under the new revolving credit facility.

F-8

RESOLUTE ENERGY PARTNERS, LP

Notes to Unaudited Condensed Pro Forma Financial Statements — (Continued)

(g) Reflects the repayment of the outstanding balance of $149.0 million under the existing term loan facility and the payment of $2.0 million of arrangement fees under the new revolving credit facility, which will be capitalized and amortized over the life of the new revolving credit facility.

(h) Reflects retention of $7.5 million of working capital by Resolute Holdings immediately prior to the Offering.

(i) Represents write-off of $5.2 million of previously expended and capitalized deferred financing costs associated with the existing revolving credit facility and the existing term loan facility.

(j) Represents offset of $0.6 million of deferred offering costs previously expended and capitalized against proceeds from the Offering.

(k) Reflects the conversion of $185.4 million of member interests into $3.7 million of general partner interests (2.0%), $61.2 million of public common units (33.0%), $29.7 million of common units held by Resolute Holdings (16.0%) and $90.8 million of subordinated units held by Resolute Holdings (49.0%).

(l) Reflects the adjustment of additional depletion, depreciation and amortization of oil and gas properties associated with the acquisition of the ExxonMobil Properties on a unit-of-production basis over the remaining life of total proved reserves.

(m) Reflects the accretion of discount expense related to the estimated asset retirement obligations for wells and facilities assumed in the acquisition of the ExxonMobil Properties.

(n) Reflects estimated incremental interest expense associated with borrowings of $92.1 million under the Partnership’s amended and restated senior secured credit facility and a new $125.0 million senior secured term loan as if the acquisition of the ExxonMobil Properties occurred on January 1, 2006. The applicable effective interest rates for the senior secured credit facility and the senior secured term loan were 7.12% and 10.36%, respectively.

(o) Represents the incremental amortization of the deferred financing costs over the term of the Partnerships credit facility as if the acquisition of the ExxonMobil Properties occurred on January 1, 2006.

(p) Reflects the elimination of interest expense on the indebtedness repaid with the proceeds of this Offering and borrowings and incurrence of indebtedness on borrowings of $151.0 million under our new revolving credit facility at an assumed rate of 6.03% (LIBOR plus 150 basis points). A change in the interest rate of 1% would have increased or decreased the net interest expense by $1.5 million for the year ended December 31, 2006 and $0.8 million for the six months ended June 30, 2007.

(q) Represents the elimination of amortized debt issuance costs associated with the Partnership’s original indebtedness under the existing revolving credit facility and term loan facility.

(r) Represents the amortization of debt issuance costs over the term of the Partnership’s new revolving credit facility.

Note 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 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. The calculations assumed that (1) the minimum quarterly distribution of $0.35 per quarter was paid on all common units and subordinated units for each quarter during the periods presented and (2) the number of common and subordinated units outstanding was 40,802,632, of which the public was assumed to hold 13,750,000 common units and Resolute

F-9

RESOLUTE ENERGY PARTNERS, LP

Notes to Unaudited Condensed Pro Forma Financial Statements — (Continued)

Holdings was assumed to hold 6,651,316 common units and 20,401,316 subordinated units. The common units and subordinated units each represent 49% of the limited partner interests. All units were assumed to have been outstanding since January 1, 2006. 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 Offering. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain target distribution levels, 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-10

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and the Managing Member of
Resolute Energy Partners Predecessor
Denver, Colorado

We have audited the accompanying combined balance sheet of Resolute Energy Partners Predecessor (the “Companies”) as of December 31, 2006, and the related combined statements of operations, shareholder’s/member’s equity, and cash flows for the year then ended. The combined financial statements include the accounts of Resolute Natural Resources Company and three related companies, Resolute Aneth, LLC, WYNR, LLC and BWNR, LLC. These companies are under common ownership and common management. These financial statements are the responsibility of the Companies’ management. Our responsibility is to express an opinion on these financial statements 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 financial statements are free of material misstatement. The Companies are not required to have, nor were we engaged to perform, an audit of their 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 Companies’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such combined financial statements present fairly, in all material respects, the combined financial position of Resolute Energy Partners Predecessor as of December 31, 2006, and the combined results of their operations and their combined cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

April 27, 2007
Denver, Colorado

F-11

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and the Managing Member of
Resolute Energy Partners Predecessor
Denver, Colorado

We have audited the accompanying combined balance sheets of Resolute Energy Partners Predecessor (the “Companies”) as of December 31, 2005 and 2004, and the related consolidated and combined statements of operations, changes in shareholder’s/member’s equity and cash flows for the year ended December 31, 2005 and for the period from January 22, 2004 (inception) through December 31, 2004. The combined financial statements include the accounts of Resolute Natural Resources Company and three related companies, Resolute Aneth, LLC, WYNR, LLC and BWNR, LLC. These companies are under common ownership and common management. These financial statements are the responsibility of the Companies’ 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 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 Companies are not required to have, nor were we engaged to perform, an audit of their 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 Companies’ 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated and combined financial statements referred to above present fairly, in all material respects, the combined financial position of Resolute Energy Partners Predecessor as of December 31, 2005 and 2004, and the consolidated and combined results of their operations and cash flows for the year ended December 31, 2005 and for the period from January 22, 2004 (inception) through December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

/s/ Ehrhardt Keefe Steiner & Hottman PC

April 27, 2007, except for Note 10 which is as of September 26, 2007
Denver, Colorado

F-12

RESOLUTE ENERGY PARTNERS PREDECESSOR

Combined Balance Sheets
(in thousands)

	December 31,
	2005			2006
Assets
Current assets:
Cash and cash equivalents	$	—		$	3,691
Accounts receivable:
Trade receivables		10,105			26,527
Other — Navajo Nation Oil and Gas Company		—			444
Related party — Holdings		32			—
Derivative instruments		—			1,843
Other current assets		200			414
Total current assets		10,337			32,919
Property and equipment, at cost:
Oil and gas properties, full cost method of accounting
Unproved		5,657			8,848
Proved		92,111			334,668
Accumulated depreciation, depletion and amortization		(4,847	)		(15,507	)
Net oil and gas properties		92,921			328,009
Other property and equipment		1,269			2,940
Accumulated depreciation		(241	)		(652	)
Net other property and equipment		1,028			2,288
Net property and equipment		93,949			330,297
Other assets:
Restricted cash		—			7,728
Deferred financing costs, net of accumulated amortization of $103 and $579, respectively		277			3,090
Notes receivable — affiliated entities		2,000			2,144
Deferred offering costs		—			500
Other assets		—			55
Total other assets		2,277			13,517
Total assets	$	106,563		$	376,733
Liabilities and Shareholder’s/Member’s Equity
Current liabilities:
Cash overdraft	$	383		$	—
Accounts payable and accrued expenses		6,819			24,704
Interest payable		213			2,963
Accrued purchase price payable — acquisition of ExxonMobil Properties		—			1,778
Oil and gas sales payable		1,571			4,016
Current tax liability		862			—
Asset retirement obligations		12			1,328
Derivative instruments		2,339			4,710
Accounts payable — Holdings		—			359
Total current liabilities		12,199			39,858
Non-current liabilities:
Long term debt		45,925			267,500
Asset retirement obligations		2,305			6,118
Derivative instruments		17,436			1,355
Other		—			42
Total long-term liabilities		65,666			275,015
Total liabilities		77,865			314,873
Commitments and contingencies
Shareholder’s/member’s equity:
Common stock, $0.01 par value, 1,000 shares authorized and issued		—			—
Additional paid-in capital — Resources		1,481			1,481
Accumulated deficit — Resources		(10,340	)		(10,565	)
Member’s equity		37,557			70,944
Total shareholder’s/member’s equity		28,698			61,860
Total liabilities and shareholder’s/member’s equity	$	106,563		$	376,733

See notes to consolidated and combined financial statements

F-13

RESOLUTE ENERGY PARTNERS PREDECESSOR

Consolidated and Combined Statements of Operations
(in thousands)

	January 22, 2004
	(Inception) through			For the Year Ended
	December 31,			December 31,
	2004			2005			2006
Revenue:
Oil and gas sales	$	2,390		$	41,973		$	106,571
Operating expenses:
Lease operating		658			8,734			24,857
Workover		21			3,860			13,312
Production taxes		340			2,772			7,806
General and administrative		2,415			3,281			6,015
Depreciation, depletion and amortization		407			4,680			11,071
Accretion of asset retirement obligations		20			216			206
Total operating expenses		3,861			23,543			63,267
Income (loss) from operations		(1,471	)		18,430			43,304
Other income (expense):
Other income		51			147			546
Gain (loss) on derivative instruments		3,592			(28,852	)		10,895
Interest expense		(190	)		(2,442	)		(17,644	)
Amortization of deferred financing costs		—			(103	)		(477	)
Total other income (expense)		3,453			(31,250	)		(6,680	)
Income (loss) before income taxes		1,982			(12,820	)		36,624
Income taxes:
Current income tax expense		—			(4,572	)		—
Deferred income tax (expense) benefit		(742	)		742			—
Total income tax expense		(742	)		(3,830	)		—
Net income (loss)	$	1,240		$	(16,650	)	$	36,624

See notes to consolidated and combined financial statements

F-14

RESOLUTE ENERGY PARTNERS PREDECESSOR
Consolidated and Combined Statements of Shareholder’s/Member’s Equity
(in thousands, except for shares)

														Total
					Additional			Accumulated						Shareholder’s/
	Common Stock				Paid-in			Earnings			Member’s			Member’s
	Shares		Amount*		Capital			(Deficit)			Equity			Equity
Balances January 22, 2004 (Inception)		—	$	—	$	—		$	—		$	—		$	—
Capital contributions		—		—		43,757			—			—			43,757
Issuance of common stock		1,000		—		—			—			—			—
Net income		—		—		—			1,240			—			1,240
Balances at December 31, 2004		1,000	$	—	$	43,757		$	1,240		$	—		$	44,997
Capital contributions		—		—		351			—			—			351
Net loss — Aneth January 1, 2005 through September 14, 2005		—		—		—			(16,783	)		��			(16,783	)
Distribution of member’s equity to Holdings		—		—		(42,627	)		12,406			30,221			—
Net income — Aneth September 15, 2005 through December 31, 2005		—		—		—			—			7,336			7,336
Net Loss — Resources		—		—		—			(7,203	)		—			(7,203	)
Balances at December 31, 2005		1,000	$	—	$	1,481		$	(10,340	)	$	37,557		$	28,698
Distributions to Holdings from Aneth		—		—		—			—			(3,462	)		(3,462	)
Net income		—		—		—			(225	)		36,849			36,624
Balances at December 31, 2006		1,000	$	—	$	1,481		$	(10,565	)	$	70,944		$	61,860

* The par value amount of Resources common stock outstanding for the periods presented is less than $500 and is therefore presented as $0 above due to rounding.

See notes to consolidated and combined financial statements

F-15

RESOLUTE ENERGY PARTNERS PREDECESSOR

Consolidated and Combined Statements of Cash Flows

(in thousands)

	January 22, 2004
	(Inception) through			For the Year Ended
	December 31,			December 31,
	2004			2005			2006
Operating activities:
Net income (loss)	$	1,240		$	(16,650	)	$	36,624
Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities:
Depreciation, depletion and amortization		408			4,680			11,071
Amortization of deferred financing costs		—			103			477
Deferred income taxes		742			(742	)		—
Unrealized gain/loss on derivative instruments		(3,383	)		23,159			(13,291	)
Accretion of asset retirement obligations		20			216			206
Other		—			—			(185	)
Change in operating assets and liabilities:
Accounts receivable		(2,167	)		(7,970	)		(16,422	)
Other current assets		(139	)		(61	)		(2,476	)
Other long-term assets		—			—			(55	)
Accounts payable and accrued expenses		596			6,423			14,216
Oil and gas sales payable		458			1,113			2,445
Cash overdraft		—			383			(383	)
Increase in accounts payable — Holdings		—			—			391
Current tax liability		—			862			(862	)
Net cash provided by (used in) operating activities	$	(2,225	)	$	11,516		$	31,756
Investing activities:
Acquisition of oil and gas properties from ExxonMobil		—			—			(212,507	)
Acquisition of oil and gas properties from Petroleum Synergy		—			—			(1,487	)
Acquisition of oil and gas properties from Chevron		(83,848	)		(2,399	)		—
Acquisition, exploration and development expenditures		(15	)		(9,411	)		(18,394	)
Purchase of other property and equipment		(678	)		(592	)		(2,356	)
Notes receivable — affiliated entities		—			(2,000	)		(144	)
Increase in restricted cash		—			—			(7,500	)
Net cash used for investing activities	$	(84,541	)	$	(14,402	)	$	(242,388	)

(continued)

See notes to consolidated and combined financial statements

F-16

RESOLUTE ENERGY PARTNERS PREDECESSOR

Consolidated and Combined Statements of Cash Flows (continued)

(in thousands)

	January 22, 2004
	(Inception) through			For the Year Ended
	December 31,			December 31,
	2004			2005			2006
Financing activities:	$			$			$
Deferred offering costs		—			—			(500	)
Deferred financing costs					—			(3,290	)
Proceeds from bank borrowings		44,000			19,605			337,730
Issuance costs		(380	)		—			(2,780	)
Payment of bank borrowings		—			(17,680	)		(113,375	)
Proceeds from capital contributions		43,757			—			—
Capital contributions		—			350			—
Distribution to Holdings from Aneth		—			—			(3,462	)
Net cash provided by financing activities	$	87,377		$	2,275		$	214,323
Net increase (decrease) in cash and cash equivalents	$	611		$	(611	)	$	3,691
Cash and cash equivalents at beginning of year		—			611			—
Cash and cash equivalents at end of year	$	611		$	—		$	3,691
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest	$	67		$	2,199		$	14,776
Income taxes	$	—		$	3,708		$	862
Supplemental schedule of non-cash investing and financing activities:
Acquisition of ExxonMobil properties:
Increase to asset retirement obligations	$	—		$	—		$	5,302
Increase to accrued purchase price payable, net of accrued purchase price receivable	$	—		$	—		$	1,333
Increase (decrease) to asset retirement obligations	$	4,286		$	(2,192	)	$	390
Increase in accrued capital expenditures	$	2,399		$	—		$	5,649

(concluded)

See notes to consolidated and combined financial statements

F-17

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006

Note 1 — Description of Business and Summary of Significant Accounting Policies

Description of the Business

Resolute Energy Partners Predecessor includes the following companies: Resolute Natural Resources Company (“Resources”), a Delaware corporation incorporated on January 22, 2004, Resolute Aneth, LLC (“Aneth”), a Delaware limited liability company established on November 12, 2004, WYNR, LLC (“WYNR”), a Delaware limited liability company established on August 25, 2005, and BWNR, LLC (“BWNR”), a Delaware limited liability company established on August 19, 2005 (together, “Resolute” or the “Companies”). Resolute Energy Partners Predecessor is engaged in the acquisition, exploration, development, and production of oil, gas and hydrocarbon liquids. Resolute’s primary oil and gas producing property consists of operated working interests in Greater Aneth Field located in southeastern Utah.

Basis of Presentation and Principles of Consolidation

From inception through September 14, 2005, the consolidated financial statements included the accounts of Resources and its consolidated subsidiaries, the most significant of which was Aneth. All intercompany balances and transactions were eliminated.

On September 15, 2005, ownership of Aneth was transferred from Resources to Resolute Holdings, LLC (“Holdings”), a Delaware limited liability company. Consequently, the member’s equity of Aneth, previously consolidated with Resources, has been separately reflected to disclose the ownership by Holdings in the consolidated and combined balance sheets and statements of shareholder’s/member’s equity. Through December 31, 2005, Aneth and Resources each existed as wholly-owned subsidiaries of Holdings. The 2006 combined financial statements include the accounts of Resources and the three related companies: Aneth, WYNR and BWNR. These companies are under common ownership and common management. The financial statements as of and for the year ended December 31, 2005, present the combined financial position of Resources and Aneth, including its two wholly-owned subsidiaries, WYNR and BWNR.

On February 7, 2006, Resolute Holdings Sub, LLC (“Sub”), a Delaware limited liability company, was formed as a wholly-owned subsidiary of Holdings. On April 16, 2006, ownership of Resources and Aneth was transferred from Holdings to Sub. Also on April 16, 2006, ownership of WYNR and BWNR was transferred from Aneth to Sub. The transfers had no impact on the comparability of the consolidated and combined financial statements.

Assumptions, Judgments and Estimates

In the course of preparing the consolidated and combined financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events. Accordingly, actual results could differ from amounts previously established.

Significant estimates with regard to the consolidated and combined financial statements include the estimated carrying value of unproved properties, the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, the estimated cost and timing related to asset retirement obligations and the estimated fair value of derivative assets and liabilities and depreciation, depletion and amortization.

F-18

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

Fair Value of Financial Instruments

The carrying amount of Resolute’s financial instruments, namely cash and cash equivalents, accounts receivable and accounts payable, approximate their fair value because of the short-term nature of these instruments. Resolute estimated that the fair market value of its note receivable from an affiliated entity was approximately $221,000 less than its total book value of $2,000,000 at December 31, 2006. The long-term debt has a recorded value that approximates its fair market value since its variable interest rate is tied to current market rates. The fair value of derivative instruments is estimated based on market conditions in effect at the end of the reporting period.

Cash Equivalents

For purposes of reporting cash flows, Resolute considers all highly liquid investments with original maturities of three months or less at date of purchase to be cash equivalents. Resolute periodically maintains cash and cash equivalents in bank deposit accounts and money market funds which may be in excess of federally insured amounts. Resolute has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.

Concentration of Credit Risk

Financial instruments that potentially subject Resolute to concentrations of credit risk consist primarily of trade and production receivables. To date, Resolute has not incurred a loss relating to these concentrations of credit risk. For the period January 22, 2004, (Inception) through December 31, 2004, and the years ended December 31, 2005 and 2006, Resolute derived 94%, 94% and 96%, respectively, of its total revenues from Giant Refining Company under two contracts, each covering about one-half of Resolute’s production and each with a six-month term that automatically renews on a month-to-month basis subject to termination on 180 days notice. If Resolute were compelled to sell its crude oil to an alternative market, costs associated with the transportation of its production would increase, and such increase could materially and negatively affect its operations. The concentration of credit risk in a single industry affects the overall exposure to credit risk because customers may be similarly affected by changes in economic or other conditions. Resolute has not experienced significant credit losses on receivables and, therefore, has not established an allowance for doubtful accounts. Commodity derivative contracts expose Resolute to the credit risk of non-performance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, each of which is a financial institution participating in Resolute’s bank credit agreement.

Oil and Gas Properties

Resolute uses the full cost method of accounting for oil and gas producing activities. All costs incurred in the acquisition, exploration and development of properties, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities, are capitalized within the cost center. Resolute did not capitalize any overhead costs during 2004, 2005 or 2006. Expenditures for maintenance and repairs are charged to lease operating expense in the period incurred.

Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of

F-19

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense, as appropriate. There were no provisions for impairment of unproved oil and gas properties in 2004, 2005 or 2006.

Pursuant to full cost accounting rules, Resolute must perform a ceiling test each quarter on its proved oil and gas assets. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, and a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, an impairment charge would be recognized to the extent of the excess capitalized costs. There were no provisions for impairment of proved oil and gas properties in 2004, 2005 or 2006.

No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil and gas properties and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center.

Depreciation, depletion and amortization of oil and gas properties is computed on the unit-of-production method based on proved reserves. Amortizable costs include estimates of future development costs of proved undeveloped reserves and asset retirement obligations.

Other Property and Equipment

Other property and equipment are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the assets. Office furniture, automobiles, and computer hardware and software are depreciated from three to five years. Field offices are depreciated from fifteen to twenty years. Leasehold improvements are depreciated, using the straight line method, over the shorter of the lease term or the useful life of the asset. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation and amortization are removed from the accounts.

Asset Retirement Obligations

Resolute follows the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 143,Accounting for Asset Retirement Obligations. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, with a corresponding increase in the carrying amount of the related long-lived asset. Resolute’s asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment and site restoration associated with its oil and gas properties. Capitalized costs are depleted as a component of the full cost pool using the units-of-production method. Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability.

Resolute adopted Financial Accounting Standards Board (“FASB”) Interpretation No. (“FIN”) 47,Accounting for Conditional Asset Retirement Obligations, on January 1, 2005. FIN 47 clarified the accounting for conditional asset retirement obligations under SFAS 143,Accounting for Asset Retirement Obligations. A

F-20

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

conditional asset retirement obligation is an unconditional legal obligation to perform an activity in which the timingand/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires an entity to recognize a liability for a conditional asset retirement obligation if the amount can be reasonably estimated. Resolute’s adoption of FIN 47 did not have a material impact on the financial statements.

For the period ended December 31, 2004, Resolute recorded an increase to net property and equipment of $4.3 million, with a corresponding increase to the asset retirement obligation primarily in connection with the acquisition of the Chevron Properties. For the year ended December 31, 2005, Resolute recorded a decrease to net property and equipment of approximately $2.2 million, with a corresponding reduction to asset retirement obligations due to a change in the estimate related to the economic lives of the wells. For the year ended December 31, 2006, Resolute recorded an increase to net property and equipment of approximately $5.3 million, with a corresponding increase to the asset retirement obligation, primarily in connection with Resolute’s acquisition of the ExxonMobil Properties.

The following table summarizes the activities for Resolute’s asset retirement obligations (in thousands):

	2004			2005			2006
Asset retirement obligations at beginning of period	$	—		$	4,306		$	2,317
Accretion expense		20			216			206
Liabilities settled		—			(12	)		(769	)
Liabilities assumed in acquisition of Chevron Properties		4,286			—			—
Liabilities assumed in acquisition of ExxonMobil
Properties		—			—			5,302
Revisions to previous estimates		—			(2,193	)		390
Asset retirement obligations at end of period		4,306			2,317			7,446
Less current asset retirement obligations		(529	)		(12	)		(1,328	)
Long-term asset retirement obligations	$	3,777		$	2,305		$	6,118

Impairment of Long-Lived Assets

Resolute follows SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, which requires impairment losses to be recorded on long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amount of such assets. In the evaluation of the fair value and future benefits of long-lived assets, Resolute performs an analysis of the anticipated undiscounted future net cash flows of the related long-lived assets. If the carrying value of the related asset exceeds the undiscounted cash flows, the carrying value is reduced to its fair value. There were no provisions for impairment in 2004, 2005 and 2006.

Deferred Financing Costs

Deferred financing costs are amortized over the estimated lives of the related obligations or, in certain circumstances, accelerated if the obligation is refinanced, using the straight line method which approximates the effective interest method. The unamortized balance of these costs was approximately $0.3 million and $3.1 million as of December 31, 2005 and 2006, respectively.

F-21

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

Derivative Instruments

Resolute enters into commodity derivative contracts to manage its exposure to oil and gas price volatility. Commodity derivative contracts may take the form of futures contracts, swaps or options. Realized and unrealized gains and losses from Resolute’s price risk management activities are recognized in other income with realized gains and losses recognized in the period in which the related production is sold. 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 financing activity in the statement of cash flows.

SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, requires recognition of all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of a derivative will be recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses on derivative hedging instruments must be recorded in either other comprehensive income or current earnings, depending on the nature and designation of the instrument. Presently, Resolute management has determined that the benefit of the financial statement presentation available under the provisions of SFAS No. 133, which may allow for its derivative instruments to be reflected as cash flow hedges, is not commensurate with the administrative burden required to support that treatment. As a result, Resolute marked its derivative instruments to fair value during 2004, 2005 and 2006 in accordance with the provisions of SFAS No. 133 and recognized the changes in fair market value in earnings. The gain (loss) on derivative instruments reflected in the consolidated and combined statement of operations incorporates both the realized and unrealized values.

Contemporaneously with entry into a hedge, management assesses the administrative effort required to account for its derivative instruments under the provisions of SFAS No. 133 and compares it to the financial statement presentation benefit, as discussed above. Management intends to re-evaluate Resolute’s current practice of not designating derivatives as hedges from time to time.

Resolute recognizes the fair value of its derivative instruments as assets or liabilities on the balance sheet. The accounting treatment for the changes in fair value is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge and upon whether or not the derivative qualifies as an effective hedge. Changes in fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. For fair value hedges, to the extent the hedge is effective, there is no effect on the statement of operations because changes in fair value of the derivative offset changes in the fair value of the hedged item. For derivative instruments that do not qualify as fair value hedges or cash flow hedges, changes in fair value are recognized in earnings.

Revenue Recognition

Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred and if the collectibility of the revenue is probable. Revenues from the production of gas properties in which Aneth has an interest with other producers are recognized on the basis of Aneth’s net working interest (entitlement method). If significant, net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as receivables. There were no significant imbalances at either December 31, 2005 or 2006.

General and Administrative Expenses

General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to working interest owners of the oil and gas properties operated by Resolute.

F-22

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

Income Taxes

Resources uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial accounting bases and tax bases of assets and liabilities. The tax benefits of tax loss carryforwards and other deferred taxes are recorded as an asset to the extent that management assesses the utilization of such assets to be more likely than not. When the future utilization of some portion of the deferred tax asset is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded deferred tax assets. Resolute, organized as a corporation, is the only taxable entity in the combined statements. The other three, Aneth, WYNR and BWNR, were organized as limited liability companies. As limited liability companies, Aneth, WYNR and BWNR are tax flow-through entities and, therefore, the related tax obligation, if any, is borne by the owners.

Industry Segment and Geographic Information

Resolute has evaluated how it is organized and managed and identified only one operating segment, which is the exploration for and production of crude oil, gas and natural gas liquids. Resolute considers gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of Resolute’s operations and assets are located in the United States, and all of its revenues are attributable to domestic customers.

New Accounting Pronouncements

In July 2006, the FASB adopted FIN 48,Accounting for Uncertainty in Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition of positions taken or expected to be taken in income tax returns. Only tax positions meeting a “more-likely-than-not” threshold of being sustained are recognized under FIN 48.

FIN 48 also provides guidance on de-recognition, classification of interest and penalties, and accounting and disclosures for annual and interim financial statements. FIN 48 is effective for Resolute in the year beginning January 1, 2007. The cumulative effect of the changes arising from the initial application of FIN 48 is required to be reported as an adjustment to the opening balance of retained earnings in the period of adoption. Resolute believes that adoption will not have a material impact on the financial statements.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements, which establishes a single authoritative definition of fair value, sets out a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 requires companies to disclose the fair value of their financial instruments according to fair value hierarchy. This statement does not require any new fair value measurements, but will remove inconsistencies in fair value measurement between various accounting pronouncements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Resolute is currently evaluating the effect that this statement will have on Resolute’s financial statements and any other factors influencing the overall business environment.

In December 2004, the FASB issued SFAS No. 123R,Share-Based Payment (“SFAS 123R”). This statement is a revision of SFAS No. 123,Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees(“APB 25”), and its related implementation guidance. SFAS 123R requires a company to measure the grant date fair value of equity awards given to employees in exchange for services and recognize that cost, less estimated forfeitures, over the period that such services are performed. Prior to adopting SFAS 123R, Resolute accounted for stock-based compensation under APB 25. Resolute adopted SFAS 123R on January 1, 2006 using the prospective

F-23

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

transition method. As of December 31, 2006, Resolute had no stock-based compensation expenses associated with its incentive compensation plans.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities— including an amendment of FASB Statement No. 115, which permits entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in the fair value of that item in subsequent reporting periods must be recognized in current earnings. SFAS No. 159 also establishes presentation and disclosure requirements designed to draw comparisons between entities that elect different measurement attributes for similar types of assets and liabilities. SFAS No. 159 will be effective for Resolute on January 1, 2008. Resolute has not assessed the impact of SFAS No. 159 on its financial statements.

Reclassifications

Certain amounts in the 2004 and 2005 consolidated and combined financial statements have been reclassified to conform to current year presentation.

Note 2 — Note Receivable from Resolute Holdings, LLC

On April 1, 2005, Holdings entered into a joint venture arrangement with Wachovia Investment Holdings, LLC (“Wachovia”) to form an oil and gas marketing and trading company, Odyssey Energy Services, LLC (“Odyssey”), owned 40% by Holdings and 60% by Wachovia. Holdings made an initial capital contribution of $2.0 million, and agreed to be responsible for up to a total of $10.0 million of additional capital to cover certain potential liabilities. Holdings borrowed $2.0 million from Resources, which loan was evidenced by a note. Terms of the note include annual payment of interest at a rate of 4.09% and maturing no later than April 13, 2011, the maturity date of Resolute’s First Lien Facility agreement. Interest income recognized on the note was $59,000 and $88,000 during 2005 and 2006, respectively. The note has been pledged as collateral to Resolute’s First Lien Facility agreement. Odyssey provides certain marketing services to Aneth, including the nomination and sale of Aneth’s natural gas production. In addition, Odyssey negotiates and manages Aneth’s derivative contracts.

Note 3 — Acquisitions

Chevron Acquisition

On November 30, 2004, Aneth acquired from Chevron Corporation and its affiliates (“Chevron”) 75% of Chevron’s interests in the Greater Aneth Field located in southeastern Utah (the “Chevron Properties”). Resolute estimated that the proved net oil and gas reserves acquired with the Chevron Properties were approximately 18,833 MBoe (unaudited), of which 68% (unaudited) were classified as proved developed and the remaining amounts were classified as proved undeveloped. Aneth had no proved reserves prior to the acquisition of the Chevron Properties. The purchase price was allocated to assets based on the fair values at the date of acquisition, as estimated by management. The Chevron acquisition was accounted for using the purchase method of accounting and has been included in the consolidated and combined financial statements of Resolute since the date of acquisition. The total purchase price, including transaction costs, of $86.2 million was allocated to proved oil and gas properties, buildings and vehicles.

F-24

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

The Chevron acquisition was effective as of September 1, 2004, and the purchase price was adjusted for net revenues from that date until closing. Final settlement of the purchase price adjustments occurred in November 2005. The following table presents the allocation of the acquisition costs based on their fair values at the time of acquisition (in thousands):

Oil and gas properties	$	85,831
Buildings and equipment		328
Vehicles		88
Total purchase price allocation	$	86,247

Pursuant to a “Cooperative Agreement” between Resolute and Navajo Nation Oil and Gas Company (“NNOG”), NNOG has options (as discussed below) to purchase certain of Resolute’s interests in the Chevron Properties at various payout points. Each payout point is generally defined as that point at which Resolute has recovered from its net revenue received, a certain percentage, shown below, of all acquisition costs and subsequent costs charged to Resolute under the operating agreement. These option amounts are shown below:

				McElmo			Ratherford
	Aneth Unit			Creek Unit			Unit
Chevron Properties:
Option 1 (100% Payout)		5.30	%		1.50	%		0.30	%
Option 2 (150% Payout)		5.30	%		1.50	%		0.30	%
Option 3 (200% Payout)		5.30	%		1.50	%		0.30	%
Total		15.90	%		4.50	%		0.90	%

At each payout point, NNOG may purchase up to 10% of Resolute’s interest in the Chevron Properties. The options are not exercisable prior to the fourth anniversary of the closing of the acquisition of the Chevron Properties, except that the first option becomes exercisable if Resolute commences an effort to sell Aneth and such sale is consummated. Each option is exercisable for sixty days following Resolute providing notice of the occurrence of the relevant payout point. The option price is based on the Fair Market Value (as defined) of the interest to be acquired. NNOG also has a right of first negotiation concerning any proposed sale of the related assets of Resolute.

Resources is the operator of the Aneth Unit comprising most of the Chevron Properties.

ExxonMobil Acquisition

On April 14, 2006, Aneth acquired from Exxon Mobil Corporation and its affiliates (“ExxonMobil”) 75% of ExxonMobil’s interests in the Greater Aneth Field, along with various other related assets, including ExxonMobil’s interest in the Aneth gas compression facility, its interest in a CO₂ pipeline which serves the field, and office facilities in Cortez, Colorado (collectively, the “ExxonMobil Properties”). As a result of this purchase, Resources became operator of the Ratherford and McElmo Creek Units in Greater Aneth Field while continuing as operator of the Aneth Unit.

Resolute estimated that the proved net oil and gas reserves acquired with the ExxonMobil Properties were approximately 35,356 MBoe (unaudited), of which 55% (unaudited) were classified as proved developed and the remaining 45% (unaudited) were classified as proved undeveloped. The purchase price was allocated to assets based on the fair values at the date of acquisition, as estimated by management. The acquisition of the ExxonMobil Properties was accounted for using the purchase method of accounting and has been included in the consolidated and combined financial statements of Resolute since the date of acquisition. The purchase

F-25

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

price, including transaction costs and contingent consideration, of $214.5 million was allocated primarily to proved oil and gas properties.

The acquisition of the ExxonMobil Properties was effective as of January 1, 2005, and the purchase price was adjusted for net revenues from that date until closing. Final settlement of the purchase price adjustments occurred in October 2006. The following table presents the allocation of the purchase price at December 31, 2006 based on estimated fair market values of the assets acquired and liabilities assumed (in thousands):

Oil and gas properties	$	219,148
Buildings and equipment		680
Asset retirement obligation		(5,302	)
Total purchase price allocation	$	214,526

In order to finance the acquisition of the ExxonMobil Properties, on April 14, 2006, Resolute entered into an amended and restated $300.0 million senior secured credit facility (the “First Lien Facility”) and a new $125.0 million senior secured term loan (the “Second Lien Facility”). Proceeds from the two credit facilities were used to repay outstanding indebtedness under Resolute’s existing credit facility, to finance the acquisition of the ExxonMobil Properties and for general working capital purposes (See Note 4).

Pursuant to a “Cooperative Agreement” between Resolute and NNOG, NNOG has options (as discussed below) to purchase certain of Resolute’s interests in the ExxonMobil Properties at various payout points. Payout point is generally defined as that point at which Resolute has recovered from its net revenue received, all acquisition costs and subsequent costs charged to Resolute under the operating agreement. These option amounts are shown below:

				McElmo			Ratherford
	Aneth Unit			Creek Unit			Unit
ExxonMobil Properties:
Option 1 (100% Payout)		0.75	%		6.00	%		5.60	%
Option 2 (150% Payout)		0.75	%		6.00	%		5.60	%
Option 3 (200% Payout)		0.75	%		6.00	%		5.60	%
Total		2.25	%		18.00	%		16.80	%

At each payout point, NNOG may purchase up to 10% of Resolute’s interest in the ExxonMobil Properties. The options are not exercisable prior to the fourth anniversary of the closing of the acquisition of the ExxonMobil Properties closing, except that the first option becomes exercisable if Resolute commences an effort to sell the ExxonMobil Properties and such sale is consummated. Each option is exercisable for sixty days following Resolute’s providing notice of the occurrence of the relevant payout point. The option price is based on the Fair Market Value (as defined in the agreement) of the interest to be acquired. NNOG also has a right of first negotiation concerning any proposed sale of the related assets of Resolute.

In addition to the cash purchase price, terms of the Purchase and Sale Agreement pursuant to which Resolute acquired the ExxonMobil Properties provide for certain monthly contingent payments to ExxonMobil through December 2007. The contingent payments are equal to the amount by which prices for West Texas Sour (“WTS”) crude oil exceeds $40.00 per barrel in any given month, multiplied by production from the ExxonMobil Properties. As specified in the Purchase and Sale Agreement, WTS prices are limited to a maximum of $49.00 per barrel (a maximum differential of $9.00 per barrel), and monthly production is limited to 98,765 barrels. Therefore, the maximum monthly contingent payment to ExxonMobil is $888,889, or $666,667 net to Aneth’s interest. Aneth has recorded the liability for the contingent consideration when the

F-26

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

amount is determinable beyond a reasonable doubt. As additional contingent payment liability is recognized and recorded, the cost of the acquisition is adjusted and additional cost is reflected in oil and gas properties.

Under the terms of the Purchase and Sale Agreement for the ExxonMobil Properties, Resolute and NNOG were required to fund an escrow account sufficient to complete abandonment, well plugging, site restoration and related obligations arising from ownership of the acquired interests. The contribution required at the date of acquisition of $10,000,000, or $7,500,000 net to Aneth’s interest, is included in restricted cash in the consolidated and combined balance sheets as of December 31, 2006. Aneth is required to make additional deposits to the escrow account annually. Beginning in 2007 and continuing through 2016, Aneth must fund approximately $1.8 million. In years after 2016, Aneth must fund additional payments averaging approximately $0.9 million until 2031. Total contributions from the date of acquisition through 2031 will aggregate $53,392,000, or $40,044,000 net to the Aneth interest. Annual interest earned in the escrow account becomes part of the balance and reduces the payment amount required for funding the escrow account each year.

The following table presents the pro forma operating results for years ended December 31, 2005 and 2006. The years ended December 31, 2005 and 2006 give effect as if the acquisition of the ExxonMobil Properties had occurred January 1, 2005 and January 1, 2006, respectively. The pro forma results shown below are not necessarily indicative of the operating results that would have occurred if the transaction had occurred on such date. The pro forma adjustments made are based on certain assumptions that Resolute believes are reasonable based on currently available information (unaudited; in thousands):

	December 31,
	2005		2006
Total revenues	$	109,681	$	125,534
Net income	$	32,745	$	29,581

Note 4 — Long-Term Debt

Long-term debt consisted of the following at December 31, 2005 and 2006 (in thousands):

	December 31,
	2005		2006
Credit agreements
First Lien Facility	$	45,925	$	142,500
Second Lien Facility		—		125,000
Total long-term debt	$	45,925	$	267,500

On September 24, 2004, Resolute entered into a credit facility with a syndicate of banks led by Wachovia Bank, National Association and Citibank NA. The credit facility was amended and restated on September 15, 2005, and subsequently on April 14, 2006.

In order to finance the ExxonMobil acquisition, on April 14, 2006, Aneth entered into an amended and restated $300.0 million senior secured credit facility (the “First Lien Facility”) and a new $125.0 million senior secured term loan (the “Second Lien Facility”). Proceeds from the two credit facilities were used to repay outstanding indebtedness under Aneth’s existing credit facility, to finance the ExxonMobil acquisition and for general working capital purposes.

The First Lien Facility is with a syndicate of banks led by Wachovia Bank, National Association and Citibank NA. Availability under the facility is governed by a borrowing base. The determination of the borrowing base is made by the lenders taking into consideration the estimated value of Resolute’s oil and gas

F-27

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

properties in accordance with the lenders’ customary practices for oil and gas loans. The borrowing base is re-determined semi-annually, and the amount available for borrowing could be increased or decreased as a result of such re-determinations. Under certain circumstances either Resolute or the lenders may request an interim re-determination. As of December 31, 2005 and 2006, the borrowing base was $65.0 and $210.0 million respectively. Unused availability under the borrowing base as of December 31, 2005 and 2006, was $19.1 and $66.8 million respectively. As of April 20, 2007, Resolute had drawn down an additional net $9.2 million under the borrowing base, resulting in an unused availability of $57.6 million. The borrowing base availability has been reduced by a letter of credit issued to a vendor for $0.7 million at both December 31, 2006 and April 20, 2007. The First Lien Facility matures on the fifth anniversary of closing (April 13, 2011) and, to the extent that the borrowing base, as adjusted from time to time, exceeds the outstanding balance, no repayments of principal are required prior to maturity. At Aneth’s option, the outstanding balance under the First Lien Facility accrues interest at either (a) the London Interbank Offered Rate, plus a margin which varies from 1.25% to 1.875%, or (b) the greater of (i) the Administrative Agent’s Prime Rate, (ii) the Administrative Agent’s Base CD rate plus 1%, or (iii) the Federal Funds Effective Rate plus 0.5% (the “Alternative Base Rate”), plus a margin which varies from 0% to 0.375%. Each such margin is based on the level of utilization under the borrowing base. As of December 31, 2005 and 2006, the rate on the outstanding balance under the facility was 6.23% and 7.12%, respectively. The First Lien Facility is collateralized by substantially all of the proved oil and gas assets of Aneth, and is guaranteed by Resources, Sub, WYNR and BWNR.

The Second Lien Facility is with Citibank NA. The Second Lien Facility is a single draw term loan and Aneth drew down the entire $125.0 million face amount of the facility at closing. The Second Lien Facility matures on the sixth anniversary of closing (April 14, 2012) and no repayments of principal are required before that date. Aneth may make optional prepayments; however in the first year after closing any prepayments will be subject to a prepayment penalty of 1% of the amount prepaid. Once repaid, the amounts may not be reborrowed. At Aneth’s option, balances outstanding under the Second Lien Facility accrue interest at the London Interbank Offered Rate, plus a margin of 5.0% or the Alternative Base Rate, plus a margin of 4.0%. As of December 31, 2006, the interest rate was 10.36%. The Second Lien Facility is collateralized by substantially all of the proved oil and gas assets of Aneth, and is guaranteed by Resources Sub, WYNR and BWNR. The claim of the Second Lien Facility lenders on the collateral is explicitly subordinated to the claim of the First Lien Facility lenders.

Each of the facilities includes terms and covenants that place limitations on certain types of activities, the payment of dividends, and require satisfaction of certain financial tests. Resolute was in compliance with the terms and covenants as of December 31, 2006.

Note 5 — Income Taxes

Resources recognizes deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated and combined financial statements or tax returns. Deferred tax assets and liabilities are determined based on the differences between the financial statement and tax basis of assets and liabilities using the enacted tax rates in effect for the year in which the differences are expected to reverse. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that are not expected to be realized based on available evidence. Aneth, BWNR and WYNR are pass-through entities for federal and state income tax purposes. As such, neither current nor deferred income taxes are recognized by these entities.

F-28

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

Prior to September 15, 2005, Resources had temporary differences resulting primarily from book tax differences in operating losses, property and equipment, and derivative assets and liabilities attributed to its ownership of Aneth. On September 15, 2005, Resources transferred ownership of Aneth to Holdings. As a result of this transfer, no significant historical book tax differences remained on the books of Resources. Hence, the provision for taxes for the year ended December 31, 2005, were the result of operations prior to September 15, 2005. Subsequent to September 15, 2005, no provision for taxes has been made and no deferred tax assets or liabilities exist on the books of Resources. The provision for income taxes is as follows (in thousands):

	January 22,
	2004
	(Inception)
	through			For the Year Ended
	December 31,			December 31,
	2004			2005			2006
Current income tax (expense) benefit:
Federal	$	—		$	(3,979	)	$	—
State		—			(593	)		—
Total current		—			(4,572	)		—
Deferred income tax (expense) benefit:
Federal		(676	)		676			—
State		(66	)		66			—
Total deferred		(742	)		742			—
Provision for income taxes	$	(742	)	$	(3,830	)	$	—

As of December 31, 2006, Resolute had no federal or state regular or alternative minimum tax loss carryforwards, and no statutory depletion carryforwards.

Income tax expense differed from amounts that would result from applying the U.S. statutory income tax rate (35%) to income before taxes as follows (in thousands):

	January 22,
	2004
	(Inception)
	through			For the Year Ended
	December 31,			December 31,
	2004			2005			2006
U.S. statutory income tax expense	$	674		$	4,601		$	—
State income tax expense		4			(461	)		—
Tax credits		(171	)		364			—
Derivatives		(1,154	)		(6,316	)		—
Depletion		(15	)		(314	)		—
Other		(80	)		(1	)		—
311(b) gain		—			(2,166	)		—
Net operating loss		—			463			—
Total	$	(742	)	$	(3,830	)	$	—

F-29

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

Note 6 — Shareholder’s/Member’s Equity and Equity Based Awards

Common Stock

At December 31, 2004, 2005 and 2006, Resources had 1,000 shares of common stock, par value $0.01 per share, authorized, issued and outstanding, and the sole shareholder was Holdings.

Member’s Equity

At December 31, 2005, Holdings was the sole member of Aneth, and Aneth was the sole member of WYNR and BWNR. At December 31, 2006, Holdings was the sole member of Aneth, WYNR and BWNR.

Additional Paid-in Capital

During 2004, cash totaling approximately $43.8 million was raised from members of Holdings, and contributed to Resolute for the purpose of partially financing the acquisition of oil and gas properties.

During 2005, cash totaling approximately $0.4 million was raised from members of Holdings, and contributed to Resources for working capital and other purposes. In connection with the distribution of the membership interest in Aneth from Resources to Holdings, additional paid-in capital was reduced by $42.7 million, and resulted in a balance of $1.5 million as of December 31, 2005 and 2006.

Incentive Interests

“Incentive Units” were granted by Holdings to certain of its members who are also officers, as well as to other employees of Resources. The Incentive Units are intended to be “profits interests” and compensation for services provided to the Companies. There are five tiers of Incentive Units; Tier I units vest ratably over three years, but are subject to forfeiture if payout is not realized. Tier I payout is realized at the return of members’ invested capital and a specified rate of return. Tiers II through V vest upon certain specified multiples of cash payout. Incentive Units are forfeited if an employee of Resolute is either terminated for cause or resigns as an employee. All Incentive Units will be automatically forfeited on the Incentive Interest Expiration Date, as defined, if payout has not occurred on or before that date. Depending on circumstances, the Incentive Interest Expiration Date is the fifth, seventh, or ninth anniversary of the inception of Holdings. During 2006, certain units were forfeited and redistributed.

F-30

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

A summary of the activity associated with the Resolute’s Incentive Unit plan during 2004, 2005 and 2006 is as follows:

	Incentive Units
January 22, 2004		—
Granted		19,169,207
Forfeited		—
December 31, 2004		19,169,207
Granted		1,345,783
Forfeited		—
December 31, 2005		20,514,990
Granted		—
Forfeited		(656,480	)
Redistributed		656,480
December 31, 2006		20,514,990

Resolute has not assigned any value nor recognized any compensation expense related to these Incentive Units because Resolute believes it is not probable that any distributions will be made in respect of such Incentive Units prior to the forfeiture of such Incentive Units and because of management’s opinion that distributions sufficient to achieve payout, as defined, would not occur without the sale or recapitalization of the Companies.

Equity Appreciation Rights

Equity Appreciation Rights (or “EARs”) were granted by Sub to certain of Resources’ employees commencing in November of 2006. These rights are contract rights to a certain portion of future distributions of profit by Sub. These EARs do not vest except with respect to distributions actually made, and are forfeited upon an employee’s separation from Resolute. During 2006, 3,000,000 EARs were authorized and 1,455,000 were issued.

Resolute has not assigned any value or recognized any compensation expense related to these EARs because Resolute believes it is not probable that any distributions will be made in respect of such EARs prior to the forfeiture of such EARs, and because of management’s opinion that distributions sufficient to cause a distribution with respect to the EARs would not occur without the sale or recapitalization of Resolute.

Note 7 — Employee Benefit Plan

Effective January 1, 2005, Resolute established a 401(k) plan for all eligible employees. For the period from January 22, 2004 (Inception) through December 31, 2004 and the years ended December 31, 2005 and 2006, Resolute contributed $0, $0 and $233,000, respectively, in connection with matching of employee contributions.

Note 8 — Derivative Instruments

For the period from January 22, 2004 (Inception) through December 31, 2004 and the years ended December 31, 2005 and 2006, Resolute has not elected to designate derivative instruments as cash flow hedges under the provisions of SFAS No. 133. As a result, these derivative instruments are marked to market at the

F-31

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

end of each reporting period and changes in the fair value are recorded in the accompanying consolidated and combined statements of operations.

Aneth is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed below. However, the counterparties to Aneth’s derivative transactions are banks that are among Resolute’s lenders and, therefore, Resolute does not anticipate such nonperformance. Additionally, because the counterparties are secured with respect to any hedge obligation that Aneth may have to them, Aneth does not anticipate having to provide additional margin protection.

Commodity Swaps and Put Options

Resolute periodically hedges a portion of its oil production through swaps, the purchase of put options and other such agreements. The purpose of the hedges is to provide a measure of stability to Aneth’s cash flows in an environment of volatile oil prices and to manage Aneth’s exposure to commodity price risk.

Terms of Resolute’s bank credit facility, prior to the amendment in April 2006, required Resolute to enter into fixed-for-floating swaps for at least 70% of its production for the years 2005 through 2007. In addition, Resolute can enter into other forms of derivatives for an additional 10% of its production during that period. Commencing in 2008, forms of hedging will be at the discretion of Resolute, not to exceed 80% of its anticipated production. Purchased put options were considered in the calculation of whether Resolute has met the 70% test. However, because such purchased put options do not give rise to a payment obligation on the part of the Resolute, they are not considered in the calculation of the 80% ceiling.

The following constitutes amounts comprising the gain (loss) on derivative instruments reflected in other income (expense) in the consolidated statements of operations for the period January 22, 2004 (Inception) through December 31, 2004 (in thousands):

Unrealized gain on crude oil swaps	$	3,383
Cash settlements of crude oil swaps		209
Net gain on derivative instruments	$	3,592

At December 31, 2005, Resolute had a derivative liability of $19.8 million, of which $2.3 million and $17.5 million were classified as current and long-term, respectively. The fair value of the swap contracts was calculated using NYMEX WTI prices in effect at December 31, 2005. The following constitutes amounts comprising the gain (loss) on derivative instruments reflected in other income (expense) in the consolidated and combined statements of operations for the year ended December 31, 2005 (in thousands):

Unrealized loss on crude oil swaps	$	(23,159	)
Cash settlements of crude oil swaps		(5,693	)
Net loss on derivative instruments	$	(28,852	)

At December 31, 2006, Resolute had a derivative asset of $1.8 million (oil put premium of $2.2 million, net of unrealized loss of $0.4 million), which was classified as a current asset. Resolute also had a derivative liability at December 31, 2006 of $6.1 million, related to swap contracts, of which $4.7 million and $1.4 million were classified as current and long-term liabilities, respectively. The fair value of the swap contracts was calculated using NYMEX WTI prices in effect at December 31, 2006. The following constitutes

F-32

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

amounts comprising the gain (loss) on derivative instruments reflected in other income (expense) in the combined statement of operations for the year ended December 31, 2006 (in thousands):

Unrealized loss on crude oil puts	$	(419	)
Unrealized gain on crude oil swaps		13,710
Total unrealized gain		13,291
Cash settlements of crude oil swaps		(172	)
Realized loss on crude oil puts		(1,846	)
Loss from sale of crude oil puts		(378	)
Total realized loss		(2,396	)
Net gain on derivative instruments	$	10,895

Subsequent to closing the acquisition of the Chevron Properties, Resolute entered into certain commodity swaps. Of those commodity swaps transacted at that time, the following contracts, all of which represent annual contracts expiring on the last calendar day of each respective year, remain outstanding as of December 31, 2006:

			Oil (NYMEX WTI)
			Weighted Average
Year	Bbl per day		Hedge Price Per Bbl
2007		1,250	$	40.73
2008		1,000	$	39.33

Prior to closing the acquisition of the ExxonMobil Properties, Resolute purchased put options. Of the put options purchased at that time, the following contract, which represents an annual contract expiring on the last calendar day of the year, remained outstanding as of December 31, 2006:

			Oil (NYMEX WTI)
			Weighted Average
Year	Bbl per day		Hedge Price Per Bbl
2007		2,000	$	60.00

Subsequent to closing the acquisition of the ExxonMobil Properties, Resolute entered into certain commodity swaps. Of the commodity swaps transacted at that time, the following contracts, all of which represent annual contracts expiring on the last calendar day of each respective year, remained outstanding as of December 31, 2006:

			Oil (NYMEX WTI)
			Weighted Average
Year	Bbl per day		Hedge Price Per Bbl
2007		200	$	65.60
2007		500	$	72.45
2007		500	$	72.60
2007		500	$	72.74
2007		400	$	72.70
2007		200	$	76.25

F-33

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

			Oil (NYMEX WTI)
			Weighted Average
Year	Bbl per day		Hedge Price Per Bbl
2008		200	$	64.60
2008		500	$	70.75
2008		500	$	70.80
2008		500	$	70.70
2008		300	$	71.07
2008		200	$	74.15
2009		500	$	69.40
2009		500	$	69.30
2009		500	$	69.50
2009		250	$	71.00
2009		250	$	70.75
2009		250	$	71.52
2009		350	$	70.80
2009		300	$	70.00
2009		200	$	73.10
2010		500	$	68.25
2010		500	$	68.50
2010		250	$	69.10
2010		250	$	69.15
2010		350	$	70.00
2010		350	$	69.10
2010		200	$	72.00
2010		150	$	70.15
2010		350	$	69.00

Note 9 — Commitments and Contingencies

Resolute entered into two take-or-pay purchase agreements, each with a different supplier, under which Resolute has committed to buy specified volumes of CO₂. The purchased CO₂ is for use in Resolute’s enhanced tertiary recovery projects in the Greater Aneth Field. In each case, Resolute is obligated to purchase a minimum daily volume of CO₂ or pay for any deficiencies at the price in effect when delivery was to have occurred. The CO₂ volumes planned for use on the enhanced recovery projects exceed the minimum daily volumes provided in this take-or-pay purchase agreement. Therefore, Resolute expects to avoid any payments for deficiencies.

One contract was effective July 1, 2006, and has a four year term. As of December 31, 2006, future commitments under this purchase agreement amounted to approximately $5.0 million per year for 2007, 2008 and 2009 and $2.5 million in 2010, based on prices in effect at December 31, 2006. The second contract was entered into on May 25, 2005, and amended on January 1, 2007, and has a one year term. Future commitments under this purchase agreement amounted to approximately $1.2 million through 2007 based on prices in effect on January 1, 2007.

F-34

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

Future rental payments for office facilities under the remaining terms of non-cancelable operating leases as of December 31, 2006 were approximately $477,000, $512,000, $489,000, $471,000 and $394,000 for the years ending December 31, 2007, 2008, 2009, 2010 and 2011, respectively.

For the years ended December 31, 2004, 2005 and 2006, rental payments charged to expense amounted to approximately $107,000, $210,000 and $602,000, respectively. Rental payments include month-to-month leases of office facilities. There are no leases that are accounted for as capital leases.

Note 10 — Supplemental Oil and Gas Information (unaudited)

Costs Incurred in Oil and Gas Producing Activities:

Costs incurred in oil and gas property acquisition, exploration and development activities are summarized as follows (in thousands):

	December 31,
	2004		2005		2006
Development costs	$	679	$	14,156	$	60,744
Exploration		—		—		—
Acquisitions:
Proved		90,533		—		219,296
Unproved		15		5,657		3,191
Total	$	91,227	$	19,813	$	283,231

Net capitalized costs related to Resolute’s oil and gas producing activities were as follows (in thousands):

	December 31,
	2005			2006
Proved oil and gas properties	$	92,111		$	334,668
Unevaluated oil and gas properties, not subject to amortization		5,657			8,848
Accumulated depreciation, depletion and amortization		(4,847	)		(15,507	)
Oil and gas properties, net	$	92,921		$	328,009

Oil and Gas Reserve Quantities:

The following table presents our estimated net proved oil and gas reserves and the present value of such estimated net proved reserves as of December 31, 2004, 2005, and 2006. The reserve data as of December 31, 2004 and 2005 are based on reports prepared by Resolute and audited by Sproule Associates Inc., independent petroleum engineers. The reserve data as of December 31, 2006, were prepared by Resolute and audited by Netherland, Sewell & Associates, Inc., independent petroleum engineers. Users of this information should be aware that the process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions to be made in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure reserves estimates reported represent the most accurate assessments possible, the subjective decisions

F-35

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Presented below is a summary of the changes in estimated reserves:

							Oil
	Oil			Gas			Equivalent
	MBbl			MMcf			MBoe
Proved reserves as of January 22, 2004 (Inception):		—			—			—
Purchases of minerals in place		18,455			2,265			18,833
Production		(60	)		11			(59	)
Extensions, discoveries, improved recovery and other additions		—			—			—
Revisions of previous estimates		(567	)		128			(546	)
Proved reserves as of December 31, 2004:		17,828			2,404			18,228
Purchases of minerals in place		—			—			—
Production		(720	)		(136	)		(743	)
Extensions, discoveries, improved recovery and other additions		6,771			(2,030	)		6,433
Revisions of previous estimates		(378	)		3,512			207
Proved reserves as of December 31, 2005:		23,500			3,750			24,125
Purchases of minerals in place		35,497			1,873			35,809
Production		(1,588	)		(227	)		(1,625	)
Extensions, discoveries, improved recovery and other additions		13,571			(1,992	)		13,239
Revisions of previous estimates(1)		7,377			(1,513	)		7,124
Proved reserves as of December 31, 2006:		78,357			1,891			78,672

(1) This upward revision is due to an increase in the estimated recovery of the CO₂ projects, partially offset by a lower estimated recovery from the drilling program.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:

The following summarizes the policies used in the preparation of the accompanying oil and gas reserves disclosures, standardized measures of discounted future net cash flows from proved oil and gas reserves and the reconciliations of standardized measures from year to year. The information disclosed, as prescribed by the SFAS No. 69, “Disclosures about Oil and Gas Producing Activities,” is an attempt to present the information in a manner comparable with industry peers.

The information is based on estimates of proved reserves attributable to Resolute’s interest in oil and gas properties as of December 31 of the years presented. These estimates were prepared by Resolute and audited by independent petroleum engineers. Proved reserves are estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

(1) Estimates were made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions.

(2) The estimated future cash flows was compiled by applying year-end prices of crude oil and gas relating to Resolute’s proved reserves to the year-end quantities of those reserves.

F-36

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

(3) The future cash flows were reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions.

(4) Future income tax expenses were based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and gas properties, other deductions, credits and allowances relating to Resolute’s proved oil and natural gas reserves.

(5) Future net cash flows were discounted to present value by applying a discount rate of 10%.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of Resolute’s oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The following summary sets forth Resolute’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in SFAS No. 69:

	December 31,
	2004			2005			2006
	(In millions)
Future cash inflows	$	744		$	1,432		$	4,610
Future production costs		(315	)		(553	)		(1,618	)
Future development costs		(29	)		(61	)		(192	)
Future income taxes		—			—			—
Future net cash flows		400			818			2,800
10% annual discount for estimated timing of cash flows		(201	)		(493	)		(1,822	)
Standardized measure of discounted future net cash flows	$	199		$	325		$	978

F-37

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Consolidated and Combined Financial Statements
For the Period January 22, 2004 (Inception) through December 31, 2004,
and the Years Ended December 31, 2005 and 2006 — (Continued)

The principal sources of change in the standardized measure of discounted future net cash flows are:

	January 22, 2004
	(Inception) through			For the Year Ended
	December 31			December 31,
	2004			2005			2006
	(In millions)
Standardized measure, beginning of year	$	—		$	199		$	325
Sales of oil and gas produced, net of production costs		(1	)		(27	)		(61	)
Net changes in prices and production costs		(41	)		89			12
Extensions, discoveries and other, including infill reserves in an existing proved field, net of production costs		—			93			176
Purchase of minerals in place		247			—			503
Development costs incurred during the year		—			2			23
Changes in estimated future development costs		—			(29	)		(127	)
Revisions of previous quantity estimates		(6	)		4			96
Accretion of discount		—			20			33
Sales of reserves in place		—			—			—
Net change in income taxes		—			—			—
Changes in timing and other		—			(26	)		(2	)
Standardized measure, end of year	$	199		$	325		$	978

F-38

RESOLUTE ENERGY PARTNERS PREDECESSOR

Condensed Combined Balance Sheets (Unaudited)

(in thousands)

				Pro Forma
	June 30,			June 30,
	2007			2007(a)
Assets
Current assets:
Cash and cash equivalents	$	—		$	—
Accounts receivable:
Trade receivables		32,541			32,541
Other — Navajo Nation Oil and Gas Company		667			667
Derivative instruments		13,580			13,580
Other current assets		1,008			1,008
Total current assets		47,796			47,796
Property and equipment, at cost:
Oil and gas properties, full cost method of accounting
Unproved		11,884			11,884
Proved		380,895			380,895
Accumulated depreciation, depletion and amortization		(23,116	)		(23,116	)
Net oil and gas properties		369,663			369,663
Other property and equipment		3,584			3,584
Accumulated depreciation		(959	)		(959	)
Net other property and equipment		2,625			2,625
Net property and equipment		372,288			372,288
Other assets:
Restricted cash		9,446			9,446
Deferred financing costs, net of accumulated amortization of $906		5,214			5,214
Notes receivable — affiliated entities		2,140			2,140
Deferred offering costs		618			618
Derivative instruments		7,659			7,659
Other assets		398			398
Total other assets		25,475			25,475
Total assets	$	445,559		$	445,559
Liabilities and Shareholder’s/Member’s Equity (Deficit)
Current liabilities:
Cash overdraft	$	4,940		$	4,940
Accounts payable and accrued expenses		26,655			26,655
Distribution payable — affiliate		—			7,500
Interest payable		1,467			1,467
Accrued purchase price payable — ExxonMobil acquisition		1,778			1,778
Oil and gas sales payable		4,273			4,273
Asset retirement obligations		1,521			1,521
Derivative instruments		14,022			14,022
Accounts payable — Holdings		617			617
Total current liabilities		55,273			62,773
Non-current liabilities:
Long term debt		395,250			395,250
Asset retirement obligations		6,228			6,228
Derivative instruments		33,313			33,313
Contingent tax liability		491			491
Other		12			12
Total long-term liabilities		435,294			435,294
Total liabilities		490,567			498,067
Commitments and contingencies
Shareholder’s/member’s equity (deficit):
Common stock, $0.01 par value, 1,000 shares authorized and issued		—			—
Additional paid-in capital — Resources		1,481			1,481
Accumulated deficit — Resources		(11,299	)		(11,299	)
Member’s equity (deficit)		(35,190	)		(42,690	)
Total shareholder’s/member’s equity (deficit)		(45,008	)		(52,508	)
Total liabilities and shareholder’s/member’s equity (deficit)	$	445,559		$	445,559

(a) The pro forma balance sheet information as of June 30, 2007 gives effect to the distribution of $7.5 million of working capital to Holdings prior to the closing of the initial public offering. See Note 2.

See notes to condensed combined financial statements

F-39

RESOLUTE ENERGY PARTNERS PREDECESSOR

Condensed Combined Statements of Operations (Unaudited)

(in thousands)

	For the
	Six Months Ended
	June 30,
	2006			2007
Revenue:
Oil sales	$	40,090		$	57,646
Gas sales		331			242
Other		1,350			2,371
Total revenue		41,771			60,259
Operating expenses:
Lease operating		9,405			16,507
Workover		4,437			5,700
Production taxes		3,062			4,536
General and administrative		2,172			34,617
Depreciation, depletion and amortization		4,140			7,915
Accretion of asset retirement obligations		95			145
Total operating expenses		23,311			69,420
Income (loss) from operations		18,460			(9,161	)
Other income (expense):
Other income		262			266
Loss on derivative instruments		(24,569	)		(19,541	)
Interest expense		(6,000	)		(12,218	)
Amortization of deferred financing costs		(149	)		(327	)
Total other expense		(30,456	)		(31,820	)
Net loss	$	(11,996	)	$	(40,981	)

See notes to condensed combined financial statements

F-40

RESOLUTE ENERGY PARTNERS PREDECESSOR

Condensed Combined Statements of Shareholder’s/Member’s Equity (Deficit) (Unaudited)

(in thousands)

													Total
													Shareholder’s/
					Additional					Member’s			Member’s
	Common Stock				Paid-in		Accumulated			Equity			Equity
	Shares		Amount*		Capital		Deficit			(Deficit)			(Deficit)
Balances at January 1, 2007		1,000		—		1,481		(10,565	)		70,944		$	61,860
Distributions to Holdings from Aneth		—		—		—		—			(100,006	)		(100,006	)
Equity-based compensation								—			34,597			34,597
Adoption of FIN 48								(478	)		—			(478	)
Net loss		—		—		—		(256	)		(40,725	)		(40,981	)
Balances at June 30, 2007		1,000	$	—	$	1,481	$	(11,299	)	$	(35,190	)	$	(45,008	)

*  The par value amount of Resources common stock outstanding for the periods presented is less than $500 and is therefore presented as $0 above due to rounding.

See notes to condensed combined financial statements

F-41

RESOLUTE ENERGY PARTNERS PREDECESSOR

Condensed Combined Statements of Cash Flows (Unaudited)

(in thousands)

	For the Six Months
	Ended June 30,
	2006			2007
Operating activities:
Net loss	$	(11,996	)	$	(40,981	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		4,140			7,915
Amortization of deferred financing costs		149			327
Equity-based compensation		—			32,663
Unrealized (gain) loss on derivative instruments		21,930			21,874
Accretion of asset retirement obligation		95			145
Other		(64	)		(198	)
Change in operating assets and liabilities:
Accounts receivable		(15,757	)		(6,014	)
Other current assets		(4,679	)		(594	)
Other long-term assets		(55	)		(343	)
Accounts payable and accrued expenses		9,497			(3,555	)
Oil and gas sales payable		2,336			257
Cash overdraft		(383	)		4,940
Increase in accounts payable — related party		83			258
Net cash provided by operating activities		5,296			16,694
Investing activities:
Acquisition of oil and gas properties from ExxonMobil		(202,815	)		(3,930	)
Acquisition of oil and gas properties from Petroleum Synergy		(1,487	)		—
Acquisition, exploration and development expenditures		(12,963	)		(39,493	)
Purchase of other property and equipment		(519	)		(604	)
Notes receivable — affiliated entities		(40	)		4
Increase in restricted cash		(7,500	)		(1,537	)
Net cash used for investing activities		(225,324	)		(45,560	)

(continued)

See notes to condensed combined financial statements

F-42

RESOLUTE ENERGY PARTNERS PREDECESSOR

Condensed Combined Statements of Cash Flows (Unaudited) (continued)

(in thousands)

	For the Six Months
	Ended June 30,
	2006			2007
Financing activities:
Deferred offering costs		(316	)		(118	)
Deferred financing costs		(3,156	)		(2,451	)
Proceeds from bank borrowings		309,350			170,650
Payment of bank borrowings		(83,925	)		(42,900	)
Distribution to Holdings from Aneth		(1,537	)		(100,006	)
Net cash provided by financing activities		220,416			25,175
Net increase (decrease) in cash and cash equivalents		388			(3,691	)
Cash and cash equivalents at beginning of the period		—			3,691
Cash and cash equivalents at end of the period	$	388		$	—
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest	$	2,657		$	13,714
Income taxes	$	—		$	—
Supplemental schedule of non-cash investing and financing activities:
Acquisition of the ExxonMobil Properties:
Increase to asset retirement obligations	$	5,302		$	—
Increase to accrued purchase price payable, net of accrued purchase price receivable	$	1,333		$	3,712
Increase (decrease) to asset retirement obligations	$	390		$	254
Increase in accrued capital expenditures	$	350		$	3,915

(concluded)

See notes to condensed combined financial statements

F-43

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Unaudited Condensed Combined Financial Statements

Note 1 — The Company and Business

Description of the Business

Resolute Energy Partners Predecessor includes the following companies: Resolute Natural Resources Company (“Resources”), a Delaware corporation incorporated on January 22, 2004, Resolute Aneth, LLC (“Aneth”), a Delaware limited liability company established on November 12, 2004, WYNR, LLC (“WYNR”), a Delaware limited liability company established on August 25, 2005, and BWNR, LLC (“BWNR”), a Delaware limited liability company established on August 19, 2005. Resources, Aneth, WYNR and BWNR (together, “Resolute” or the “Companies”) are wholly owned subsidiaries of Resolute Holdings, LLC (“Holdings”), a Delaware limited liability company established January 22, 2004. Resolute is engaged in the acquisition, exploration, development, and production of oil, gas and hydrocarbon liquids. Resolute’s primary oil and gas producing property consists of operated working interests in Greater Aneth Field located in southeastern Utah.

Note 2 — Basis of Presentation and Significant Accounting Policies

Basis of Presentation

On February 7, 2006, Resolute Holdings Sub, LLC (“Sub”), a Delaware limited liability company, was formed as a wholly-owned subsidiary of Holdings. On April 16, 2006, ownership of Resources and Aneth was transferred from Holdings to Sub. Also on April 16, 2006, ownership of WYNR and BWNR was transferred from Aneth to Sub. The 2006 combined financial statements include the accounts of Resources and the three related companies: Aneth, WYNR and BWNR. These companies are under common ownership and common management. The transfers had no impact on the comparability of the combined financial statements.

The accompanying unaudited condensed combined interim financial statements of Resolute have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial reporting. Except as disclosed herein, there has been no material change in the information disclosed in the notes to Resolute’s combined financial statements for the year ended December 31, 2006. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of the interim financial information have been included. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

The accounting policies followed by Resolute are set forth in Note 1 to Resolute’s combined financial statements for the year ended December 31, 2006 and are supplemented throughout this document. These unaudited condensed combined interim financial statements are to be read in conjunction with the combined financial statements and notes included therewith for the year ended December 31, 2006.

Pro Forma Information

The pro forma balance sheet information as of June 30, 2007 gives effect to the distribution of $7.5 million of working capital to Holdings prior to the closing of the initial public offering.

Assumptions, Judgments, and Estimates

The preparation of the combined interim financial statements in conformity with GAAP requires management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events. Accordingly, actual results could differ from amounts previously established.

Significant estimates with regard to the combined interim financial statements include the estimated carrying value of unproved properties, the estimate of proved oil and gas reserve volumes and the related

F-44

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Unaudited Condensed Combined Financial Statements — (Continued)

present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, the estimated cost and timing related to asset retirement obligations and the estimated fair value of derivative assets and liabilities and depreciation, depletion and amortization.

Oil and Gas Producing Activities

Resolute uses the full cost method of accounting for oil and gas producing activities. All costs incurred in the acquisition, exploration and development of properties, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals, the fair value of estimated future costs of site restoration, dismantlement and abandonment activities and a portion of general and administrative expenses are capitalized within the cost center. Capitalized general and administrative costs include salaries, employee benefits, costs of consulting services and other specifically identifiable costs and do not include costs related to production operations, general corporate overhead or similar activities. Resolute capitalized general and administrative costs of $0 and $1.9 million directly related to its acquisition, exploration and development activities during the six months ended June 30, 2006 and 2007, respectively. Expenditures for maintenance and repairs are charged to lease operating expense in the period incurred.

Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized or is reported as a period expense, as appropriate. There were no provisions for impairment of unproved oil and gas properties for the six months ended June 30, 2006 and 2007.

Pursuant to full cost accounting rules, Resolute must perform a ceiling test each quarter on its proved oil and gas assets. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, and a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, an impairment charge would be recognized to the extent of the excess capitalized costs. There were no provisions for impairment of proved oil and gas properties in the six months ended June 30, 2006 or 2007, respectively.

No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil properties and the gain significantly alters the relationship between capitalized costs and proved oil reserves of the cost center.

Depreciation, depletion and amortization of oil and gas properties is computed on the unit-of-production method based on proved reserves. Amortizable costs include estimates of future development costs of proved undeveloped reserves and asset retirement obligations.

Industry Segment and Geographic Information

Resolute has evaluated how it is organized and managed and identified only one operating segment, which is the exploration for and production of crude oil, gas and natural gas liquids. Resolute considers

F-45

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Unaudited Condensed Combined Financial Statements — (Continued)

gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of Resolute’s operations and assets are located in the United States, and all of its revenues are attributable to domestic customers.

New Accounting Pronouncement

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertain Tax Position — An Interpretation of FAS No. 109, Accounting for Income Taxes” (“FIN 48”). FIN 48 clarifies the accounting for income taxes recognized and presents guidance on a recognition threshold and measurement for the financials statements and tax position taken or expected to be taken in a tax return. Tax positions are evaluated in accordance with FIN 48 in a two-step process. Resolute determines whether a tax position is more likely than not (greater than 50 percent) to be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. Resolute then determines the amount of benefit to recognize. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.

Resolute files U.S. Federal and various state income tax returns. Resolute had not been subject to U.S. federal, state and local, ornon-U.S. income tax examinations by tax authorities for years prior to and including 2005. As of June 30, 2007, no taxing authority has proposed any significant adjustments to Resolute’s tax positions. Resolute has no significant current tax examinations in process.

Resolute adopted the provisions of FIN 48 on January 1, 2007. Resolute reviewed all open tax years for all jurisdictions. As a result of the implementation of FIN 48, Resolute recognized approximately $478,000, including accrued interest and penalties of $92,000, as a contingent liability. The change was accounted for as an increase to the January 1, 2007 balance of accumulated deficit. Through the period ending June 30, 2007, there have been no material changes to the liability. The total contingent income tax liabilities and accrued interest is reflected in the Condensed Combined Balance Sheet as of June 30, 2007 in “Contingent tax liability.”

Resolute recognizes penalties and interest accrued related to contingent tax liabilities as a contingent tax liability. During the period ended June 30, 2007, Resolute recognized approximately $13,000 of accrued interest expense as contingent tax liabilities.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements, which establishes a single authoritative definition of fair value sets out a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 requires companies to disclose the fair value of their financial instruments according to fair value hierarchy. This statement does not require any new fair value measurements, but will remove inconsistencies in fair value measurement between various accounting pronouncements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Resolute is currently evaluating the effect that this statement will have on the Resolute’s financial statements and any other factors influencing the overall business environment.

In December 2004, the FASB issued SFAS No. 123R,Share-Based Payment. This Statement is a revision of SFAS No. 123,Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees, and its related implementation guidance. SFAS 123R requires a company to measure the grant date fair value of equity awards given to employees in exchange for services and recognize that cost, less estimated forfeitures, over the period that such services are performed. Prior to adopting SFAS 123R, Resolute accounted for stock-based compensation under APB 25. On January 1, 2006, Resolute adopted the prospective transition method.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities— including an amendment of FASB Statement No. 115(“SFAS 159”), which permits entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value

F-46

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Unaudited Condensed Combined Financial Statements — (Continued)

that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparisons between entities that elect different measurement attributes for similar types of assets and liabilities. SFAS 159 is effective for Resolute on January 1, 2008. Resolute has not assessed the impact of SFAS 159 on our financial statements.

Note 3 — Acquisitions and Divestitures

2007 Acquisitions

There were no acquisitions during the six months ended June 30, 2007.

2006 Acquisitions

Acquisition of the ExxonMobil Properties —On April 14, 2006, Aneth acquired from Exxon Mobil Corporation and its affiliates (“ExxonMobil”) 75% of the ExxonMobil interests in the Greater Aneth Field, (the “ExxonMobil Properties”) along with various other related assets, including ExxonMobil’s interest in the Aneth gas compression facility, its interest in a CO₂ pipeline which serves the field, and office facilities in Cortez, Colorado. As a result of this purchase, Resources became operator of the Ratherford and McElmo Creek Units in Greater Aneth Field while continuing as operator of the Aneth Unit.

The proved net estimated oil and gas reserves acquired with the ExxonMobil Properties were approximately 35,356 MBoe, of which 55.2% were classified as proved developed and the remaining 44.8% were classified as proved undeveloped. The purchase price was allocated to assets based on the fair values at the date of acquisition, as estimated by management. The acquisition of the ExxonMobil Properties was accounted for using the purchase method of accounting and has been included in the combined financial statements of Resolute since the date of acquisition. The purchase price, including transaction costs and contingent consideration, of $218.2 million was allocated primarily to proved oil and gas properties.

The acquisition of the ExxonMobil Properties was effective as of January 1, 2005, and the purchase price was adjusted for net revenues from that date until closing. Final settlement of the purchase price adjustments occurred in October 2006. The following table presents the allocation of the purchase price at June 30, 2007 based on estimated fair market values of the assets acquired and liabilities assumed (in thousands):

Oil and gas properties	$	222,860
Buildings and equipment		680
Asset retirement obligation		(5,302	)
Total purchase price allocation	$	218,238

In order to finance the acquisition of the ExxonMobil Properties, on April 14, 2006, Resolute entered into an amended and restated $300.0 million senior secured credit facility (the “First Lien Facility”) and a new $125.0 million senior secured term loan (the “Second Lien Facility”). Proceeds from the two credit facilities were used to repay outstanding indebtedness under Resolute’s existing credit facilities, to finance the acquisition of the ExxonMobil Properties and for general working capital interests (see Note 5).

In connection with the acquisition of the ExxonMobil Properties, pursuant to the terms of the Cooperative Agreement, Resolute granted Navajo Nation Oil and Gas Company (“NNOG”) three separate but substantially similar purchase options. Each purchase option entitles NNOG to purchase from Resolute up to 10% of Resolute’s interest in the ExxonMobil Properties. Each purchase option entitles NNOG to purchase, for a limited period of time, the applicable portion of Resolute’s interest in the ExxonMobil Properties at Fair Market Value (as defined in the agreement), which is determined without giving effect to the existence of the

F-47

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Unaudited Condensed Combined Financial Statements — (Continued)

Navajo Nation preferential purchase right or the fact that the properties are located within the Navajo Nation. Each option becomes exercisable based upon Resolute’s achieving a certain multiple of payout of the relevant acquisition costs, subsequent capital costs and ongoing operating costs attributable to the applicable working interests. Revenue applicable to the determination of payout includes the effect of Resolute’s hedging program. The multiples of payout that trigger the exercisability of the purchase option are 100%, 150% and 200%. The options are not exercisable prior to four years from the acquisition except in the case of a sale of such assets by, or a change of control of, Aneth. In that case, the first option for 10% would be accelerated and the other options would terminate. Assuming the purchase options are not accelerated due to a change of control of Aneth, Resolute expects that the initial payout associated with the purchase options granted in connection with the ExxonMobil Properties will occur no sooner than 2013.

The following table demonstrates the maximum net undivided working interest in each of the Aneth Unit, the McElmo Creek Unit and the Ratherford Unit that NNOG could acquire upon exercising each of its purchase options under the Cooperative Agreement. The exercise by NNOG of its purchase options in full would not give it the right to remove Resolute as operator of any of the units.

				McElmo			Ratherford
	Aneth Unit			Creek Unit			Unit
ExxonMobil Properties:
Option 1 (100% Payout)		0.75	%		6.00	%		5.60	%
Option 2 (150% Payout)		0.75	%		6.00	%		5.60	%
Option 3 (200% Payout)		0.75	%		6.00	%		5.60	%
Total		2.25	%		18.00	%		16.80	%

In addition to the cash purchase price, terms of the Purchase and Sale Agreement pursuant to which Resolute acquired the ExxonMobil Properties provide for certain monthly contingent payments to ExxonMobil through December 2007. The contingent payments are equal to the amount by which prices for West Texas Sour (“WTS”) crude oil exceed $40.00 per barrel in any given month, multiplied by production from the ExxonMobil Properties assets. As specified in the Purchase and Sale Agreement, WTS prices are limited to a maximum of $49.00 per barrel (a maximum differential of $9.00 per barrel), and monthly production is limited to 98,765 barrels. Therefore, the maximum monthly contingent payment to ExxonMobil is $888,889, or $666,667 net to Aneth’s interest. Aneth has recorded the liability for the contingent consideration when the amount is determinable beyond a reasonable doubt. As additional contingent payment liability is recognized and recorded, the cost of the acquisition is adjusted and additional cost is reflected in oil and gas properties.

Under the terms of the purchase agreement for the acquisition of the ExxonMobil Properties, Resolute and NNOG were required to fund an escrow account sufficient to complete abandonment, well plugging, site restoration and related obligations arising from ownership of the acquired interests. The contribution required at the date of acquisition of $10.0 million, or $7.5 million net to Aneth’s interest, is included in restricted cash in the combined balance sheets as of June 30, 2007. Aneth is required to make additional deposits to the escrow account annually. Beginning in 2007 and continuing through 2016, Aneth must fund approximately $1.8 million per year. In years after 2016, Aneth must fund additional payments averaging approximately $0.9 million per year until 2031. Total contributions from the date of acquisition through 2031 will aggregate $53.4 million or $40.0 million net to Aneth’s interest. Annual interest earned in the escrow account becomes part of the balance and reduces the payment amount required for funding the escrow account each year. As of June 30, 2007, Aneth has funded the contractual amount required to meet its future obligation, approximately $1.7 million.

F-48

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Unaudited Condensed Combined Financial Statements — (Continued)

Divestitures

There were no significant divestitures during the six months periods ended June 30, 2006 or June 30, 2007.

Note 4 — Shareholder’s / Member’s Equity (Deficit)

Incentive Interests

“Incentive Units” were granted by Holdings to certain of its members who are also officers, as well as to other employees of Resources. The Incentive Units are intended to be “profits interests” and compensation for services provided to the Companies. There are five tiers of Incentive Units; Tier I units vest ratably over three years, but are subject to forfeiture if payout is not realized. Tier I payout is realized at the return of members’ invested capital and a specified rate of return. Tiers II through V vest upon certain specified multiples of cash payout. Incentive Units are forfeited if an employee of Resolute is either terminated for cause or resigns as an employee. All Incentive Units, will be automatically forfeited on the Incentive Interest Expiration Date, as defined, if payout has not occurred on or before that date. Depending on circumstances, the Incentive Interest Expiration Date is the fifth, seventh, or ninth anniversary of the inception of Holdings.

On June 27, 2007, Holdings made a capital distribution of $100 million to its equity owners from the proceeds of the amended and restated second lien credit agreement described in Note 5. This distribution caused both the Tier I payout to be realized and the Tier I Incentive Units to vest. As a result of the distribution, management has determined thatTier II-V incentive unit payouts are probable of occurring.

During the six month period ended June 30, 2007, Resolute recorded $32.7 million of equity based compensation expense in the condensed combined statements of operations. Approximately $32.4 million of this expense was recorded in general and administrative expense with the remaining $0.3 million recorded to lease operating expense. An additional $1.9 million of equity compensation expense was capitalized and recorded in oil and gas properties. Resolute amortizes the estimated fair value of the Incentive Units over the remaining estimated vesting period using the straight-line method. The estimated weighted average fair value remaining of the Incentive Units was calculated using a discounted future net cash flows model. During the six months ended June 30, 2007, 13,379,342 Tier I Incentive Units vested. Total unrecognized compensation cost related to our non-vested Incentive Units totaled $13.9 million as of June 30, 2007, which is expected to be recognized over a weighted-average period of 2.8 years, 4.0 years, 4.8 years and 5.0 years for the Tier II, Tier III, Tier IV and Tier V Incentive Units, respectively.

A summary of the status and activity of non-vested Incentive Units of Holdings for the six-month period ended June 30, 2007, is as follows:

			Weighted
	Non-Vested		Average
	Incentive Units		Fair Value
Non-vested, at January 1, 2007		20,514,990	$	—
Granted		—		—
Vested		13,379,610	$	33,639,975
Forfeited		—		—
Non-vested, at June 30, 2007		7,135,380	$	14,868,025

Equity Appreciation Rights

Equity Appreciation Rights (or “EARs”) were granted by Sub to certain of Resources’ employees commencing in November of 2006. These rights are contract rights to a certain portion of future distributions by Sub. These EARs do not vest except with respect to distributions actually made, and are forfeited upon an

F-49

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Unaudited Condensed Combined Financial Statements — (Continued)

employee’s separation from Resolute. During the six month period ended June 30, 2007, 431,562 EARs were issued and there were 1,918,662 issued and outstanding as of June 30, 2007.

Resolute has not assigned any value or recognized any compensation expense related to these EARs because Resolute believes it is not probable that any distributions will be made in respect of such EARs prior to the forfeiture of such EARs, and because of management’s opinion that distributions sufficient to cause a distribution with respect to the EARs would not occur without additional external financing or the sale of Resolute.

Note 5 — Long-Term Debt

Long-term debt consisted of the following (in thousands):

	June 30,
Credit agreements:	2007
First Lien Facility	$	170,250
Second Lien Facility		225,000
Total long-term debt	$	395,250

First Lien Facility

The First Lien Facility specifies a maximum borrowing base as determined by the lenders. The determination of the borrowing base takes into consideration the estimated value of Aneth’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. The borrowing base is re-determined semi-annually, and the amount available for borrowing could be increased or decreased as a result of such re-determinations. Under certain circumstances either Aneth or the lenders may request an interim re-determination. As of June 30, 2007, the borrowing base was $205.0 million. Unused availability under the borrowing base as of June 30, 2007, was $33.9 million. As of September 21, 2007, Aneth has repaid a total of $9.0 million under the borrowing base, resulting in an unused availability of $42.9 million. The borrowing base availability has been reduced by a letter of credit issued to a vendor for $0.9 million at both June 30, 2007 and September 21, 2007. The First Lien facility matures on the fifth anniversary of closing (April 13, 2011) and, to the extent that the borrowing base, as adjusted from time to time, exceeds the outstanding balance, no repayments of principal are required prior to maturity. At Aneth’s option, the outstanding balance under the First Lien facility accrues interest at either (a) the London Interbank Offered Rate, plus a margin which varies from 1.25% to 1.875%, or (b) the greater of (i) the Administrative Agent’s Prime Rate, (ii) the Administrative Agent’s Base CD rate plus 1%, or (iii) the Federal Funds Effective Rate plus 0.5% (the “Alternative Base Rate”), plus a margin which varies from 0% to 0.375%. Each such margin is based on the level of utilization under the borrowing base. As of June 30, 2007, the effective interest rate on the outstanding balance under the facility was 7.30%. The First Lien Facility is collateralized by substantially all of the proved oil and gas assets of Aneth, and is guaranteed by Resolute and Sub.

Second Lien Facility

On June 26, 2007, Aneth amended and restated its Second Lien Facility agreement. The amended Second Lien Facility increased the single draw term loan from a maximum of $125.0 million to $225.0 million and extended the maturity date from April 14, 2012, to June 26, 2013, the sixth anniversary of closing, with no repayments of principal required before such date. Aneth drew down the additional $100 million face amount of the amended facility at closing. At Aneth’s option, balances outstanding under the Second Lien Facility accrues interest at either (a) the adjusted London Interbank Offered Rate plus the applicable margin of 4.5%, or (b) the greater of (i) the Administrative Agent’s Prime Rate, (ii) the Administrative Agent’s Base CD rate plus 1%, or (iii) the Alternative Base Rate, plus the applicable margin of 3.5%. Aneth may make optional

F-50

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Unaudited Condensed Combined Financial Statements — (Continued)

prepayments. In the first year after closing, Aneth will not be subject to prepayment penalties. However, for a period of one year starting on June 27, 2008, such prepayments will be subject to a prepayment penalty of 1% of the amount prepaid. Thereafter no prepayment penalty will be assessed. Once repaid, the amounts may not be reborrowed. As of June 30, 2007, the effective interest rate was 9.86%. The Second Lien Facility is collateralized by substantially all of the proved oil and gas assets of Aneth, and is guaranteed by Resolute and Sub. The claim of the Second Lien Facility lenders on the collateral is explicitly subordinated to the claim of the First Lien Facility lenders.

Each of the facilities includes terms and covenants that place limitations on certain types of activities, the payment of dividends, and require satisfaction of certain financial tests. Aneth was in compliance with the terms and covenants as of June 30, 2007.

Note 6 — Asset Retirement Obligations

Resolute’s asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment and site restoration associated with its oil and gas properties. Capitalized costs are depleted as a component of the full cost pool using the units-of-production method. Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability. The following table summarizes the activities for Resolute’s asset retirement obligations (in thousands):

Asset retirement obligations at January 1, 2007	$	7,446
Accretion expense		145
Liabilities settled		(96	)
Revisions to previous estimates		254
Asset retirement obligations at June 30, 2007	$	7,749

Note 7 — Derivative Instruments

Aneth periodically hedges a portion of its oil production through swaps, the purchase of put options and other such agreements. The purpose of the hedges is to provide a measure of stability to Aneth’s cash flows in an environment of volatile oil prices and to manage Aneth’s exposure to commodity price risk. Realized gains and losses and changes in the fair value of derivative instruments from Aneth’s price risk management activities are recognized in other income (expense). 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 financing activity in the statement of cash flows.

For the period ended June 30, 2006 and 2007, respectively, Aneth has not elected to designate derivative instruments as cash flow hedges under the provisions of SFAS No. 133. As a result, these derivative instruments are marked to market at the end of each reporting period and changes in the fair value are recorded in the accompanying combined statements of operations in other income (expense).

Aneth is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed below. However, the counterparties to Aneth’s derivative transactions are banks that are among Aneth’s lenders and, therefore, Aneth does not anticipate such nonperformance. Additionally, because the counterparties are secured with respect to any hedge obligation that Aneth may have to them, Aneth does not anticipate having to provide additional margin protection.

Commodity Swaps and Put Options

At June 30, 2007, Aneth had derivative assets of approximately $21.2 million, of which $13.6 million was classified as a current asset and $7.6 million was classified as a long term asset. Aneth also had a derivative liability at June 30, 2007 of approximately $47.3 million, related to swap contracts, of which $14.0 million

F-51

RESOLUTE ENERGY PARTNERS PREDECESSOR

Notes to Unaudited Condensed Combined Financial Statements — (Continued)

and $33.3 million were classified as current and long-term liabilities, respectively. The fair value of the swap contracts were calculated using NYMEX WTI prices in effect at June 30, 2006 and 2007. The following constitutes amounts comprising the gain (loss) on derivative instruments reflected in other income (expense) in the combined statements of operations for the six months ended June 30, 2006 and 2007 (in thousands):

	2006			2007
Unrealized loss on crude oil puts	$	(2,367	)	$	(239	)
Unrealized loss on crude oil swaps		(19,563	)		(20,512	)
Total unrealized loss		(21,930	)		(20,751	)
Cash settlements of crude oil and natural gas swaps		(1,934	)		1,968
Realized loss on crude oil puts		(705	)		(758	)
Total realized gain		(2,639	)		1,210
Net loss on derivative instruments	$	(24,569	)	$	(19,541	)

Note 8 — Commitments and Contingencies

Resolute has entered into two take-or-pay purchase agreements, each with a different supplier, under which Resolute has committed to buy specified volumes of CO₂. The purchased CO₂ is for use in Resolute’s enhanced tertiary recovery projects in Greater Aneth Field. In each case, Resolute is obligated to purchase a minimum daily volume of CO₂ or pay for any deficiencies at the price in effect when delivery was to have occurred. The CO₂ volumes planned for use on the enhanced recovery projects exceed the minimum daily volumes provided in this take-or-pay purchase agreement. Therefore, Resolute expects to avoid any payments for deficiencies.

One contract was effective July 1, 2006, and has a four year term. As of June 30, 2007, future commitments under this purchase agreement amounted to approximately $3.0 million, $4.8 million, $4.8 million, and $4.8 million; per year for 2007, 2008, 2009 and 2010 respectively, based upon prices in effect at June 30, 2007. The second contract, which was amended on July 1, 2007 has a ten year term. Future commitments under this purchase agreement amounted to approximately $86.5 million through June 2016 based on prices in effect on June 30, 2007. The annual minimum obligation by year is as follows:

	Commitment
Year	(in millions)
2007	$	5.7
2008		15.4
2009		26.1
2010		17.6
2011		13.4
Thereafter		25.7
	$	103.9

Future rental payments for office facilities under the remaining terms of non-cancelable operating leases as of June 30, 2007, were approximately $477,000, $512,000, $489,000, $471,000 and $394,000 for the years ending December 31, 2007, 2008, 2009, 2010 and 2011, respectively.

For the six months ended June 30, 2006 and 2007, rental payments charged to expense amounted to approximately $122,700 and $322,157, respectively. Rental payments include month-to-month leases of office facilities. There are no leases that are accounted for as capital leases.

F-52

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Resolute Energy Partners, LP

Denver, Colorado

We have audited the accompanying balance sheet of Resolute Energy Partners, LP (the “Partnership”) as of September 26, 2007. 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 Resolute Energy Partners, LP as of September 26, 2007 in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Denver, Colorado

September 27, 2007

F-53

RESOLUTE ENERGY PARTNERS, LP

Balance Sheet

September 26, 2007

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-54

RESOLUTE ENERGY PARTNERS, LP
Note to Balance Sheet
September 26, 2007

(1)   Organization

Resolute Energy Partners, LP (the “Partnership”), is a Delaware limited partnership formed on September 13, 2007, to acquire Resolute Energy Operating, LLC, including its subsidiary, Resolute Aneth, LLC. The Partnership’s general partner is Resolute Energy GP, LLC. 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 units of Resolute Energy Operating, LLC, as well as a 2% general partner interest and incentive distribution rights in the Partnership to Resolute Energy GP, LLC.

F-55

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of
Resolute Energy GP, LLC
Denver, Colorado

We have audited the accompanying balance sheet of Resolute Energy GP, LLC (the “Company”) as of September 26, 2007. This financial statement is the responsibility of the Company’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 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 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 Resolute Energy GP, LLC as of September 26, 2007 in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Denver, Colorado
September 27, 2007

F-56

RESOLUTE ENERGY GP, LLC

Balance Sheet

September 26, 2007

ASSETS
Cash	$	980
Investment in Resolute Energy Partners, LP		20
Total assets	$	1,000

MEMBER’S EQUITY
Member’s equity		1,000
Total member’s equity	$	1,000

See accompanying note to balance sheet

F-57

RESOLUTE ENERGY GP, LLC
Note to Balance Sheet
September 26, 2007

(1)   Organization

Resolute Energy GP, LLC (the “General Partner”) is a Delaware limited liability partnership formed on September 13, 2007 to become the General Partner of Resolute Energy Partners, LP. The General Partner has invested $20 in Resolute Energy Partners, LP (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 interests, pursuant to a public offering. In addition, the Partnership will issue subordinated units and incentive distribution rights.

F-58

REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Resolute Natural Resources Company
Denver, Colorado

We have audited the accompanying statements of revenues and direct operating expenses of the properties (the “Chevron Properties”) acquired by Resolute Aneth, LLC (the “Company”) from ChevronTexaco for the year ended December 31, 2003, and the eleven months ended November 30, 2004. These statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statements. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 2 to the statements and are not intended to be a complete presentation of the Company’s interests in the Chevron Properties described above.

In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses, described in Note 2, of the Chevron Properties for the year ended December 31, 2003, and the eleven months ended November 30, 2004, in conformity with accounting principles generally accepted in the United States of America.

/s/ Ehrhardt Keefe Steiner & Hottman PC

February 2, 2007

Denver, Colorado

F-59

CHEVRON PROPERTIES

Statements of Revenues and Direct Operating Expenses

	For the Year		For the Eleven
	Ended		Months Ended
	December 31,		November 30,
	2003		2004
Revenues — oil and gas production	$	25,266,630	$	27,626,768
Direct operating expenses
Lease operating expense		7,569,340		6,526,130
Production and ad valorem taxes		2,813,168		2,972,408
Total direct operating expenses		10,382,508		9,498,538
Revenues in excess of direct operating expenses	$	14,884,122	$	18,128,230

See notes to the statements of revenues and direct operating expenses

F-60

CHEVRON PROPERTIES

Notes to the Statements of Revenues and Direct Operating Expenses

Note 1 — Operations, Organization, and Basis of Presentation

The accompanying statements represent the interests in the revenues and direct operating expenses of the oil and natural gas producing properties acquired by Resolute Aneth, LLC (the “Company”) from ChevronTexaco on November 30, 2004, effective September 1, 2004. The properties are referred to herein as the “Chevron Properties.”

Oil and gas revenues and direct operating expenses relate to the Company’s net revenue interests and net working interests, respectively, in the Chevron Properties. With respect to gas sales, the sales method is used for recording revenues. Under this approach, each party recognizes revenue based on actual sales regardless of its proportionate share of the related sales. The revenue from oil and gas production has been based on historical product prices at the point of sale using the net revenue and working interests purchased by the Company. The effect on revenues of gas imbalances is not material.

Direct operating expenses include payroll, lease and well repairs, production and ad valorem taxes, maintenance, utilities and other direct operating expenses.

During the periods presented, the Chevron Properties were not accounted for as a separate entity. Certain costs such as depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expenses, interest expense and corporate taxes were not allocated to the Chevron Properties.

Use of Estimates

The process of preparing financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions regarding certain types of revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts.

Note 2 — Omitted Financial Information

Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America are not presented as such information is not available on an individual property basis and not meaningful to the Chevron Properties. Historically, no allocation of general and administrative, interest, corporate taxes, accretion of asset retirement obligations, depreciation, depletion and amortization was made to the Chevron Properties. Accordingly, the statements are presented in lieu of the financial statements required underRule 3-01 of the Securities and Exchange CommissionRegulation S-X.

Note 3 — Supplemental Disclosures on Oil and Gas Exploration, Development and Production Activities (Unaudited)

Reserves

The following table summarizes the net ownership interests in estimated quantities of the proved oil and gas reserves of the Chevron Properties at November 30, 2004 (the closing date), estimated by the Company’s petroleum engineers.

	Gas		Oil
	MMcf		MBbl
Proved developed reserves		1,492		12,308
Proved undeveloped reserves		—		—
Total proved reserves		1,492		12,308

F-61

CHEVRON PROPERTIES

Notes to the Statements of Revenues and Direct Operating Expenses — (Continued)

	Gas			Oil
	MMcf			MBbl
Proved reserves as of January 1, 2003		1,440			11,242
Production in 2003		(556	)		(820	)
Revisions		484			334
Proved reserves as of December 31, 2003		1,368			10,756
Production for eleven months ended November 30, 2004		(432	)		(673	)
Revisions		556			2,225
Proved reserves as of November 30, 2004		1,492			12,308

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following table presents the Standardized Measure of Discounted Future Net Cash Flows before future income taxes from proved oil and gas reserves of the Chevron Properties. As prescribed by the Financial Accounting Standards Board, the amounts shown are based on prices and costs at January 1, 2003, December 31, 2003 and November 30, 2004, and assume continuation of existing economic conditions. A discount factor of 10% was used to reflect the timing of future net cash flow. Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the fields. Accordingly, the estimates of future net cash flows from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results. Further, since prices and costs do not remain static, and no price or cost changes have been considered, and future production and development costs are estimates to be incurred in developing and producing the estimated proved oil and gas reserves, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other oil and gas producers.

	As of			As of
	December 31,			November 30,
	2003			2004
	(In thousands)
Future cash inflows	$	320,072		$	572,445
Future production costs		(191,225	)		(283,363	)
Future development costs		(1,614	)		(222	)
Future net cash flows		127,233			288,860
10% annual discount for estimating timing of cash flows		(61,563	)		(156,122	)
Standardized measure (before income taxes) of discounted future net cash flows relating to proved oil and gas reserves	$	65,670		$	132,738

F-62

CHEVRON PROPERTIES

Notes to the Statements of Revenues and Direct Operating Expenses — (Continued)

Changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	For the Year			For the Eleven
	Ended			Months Ended
	December 31,			November 30,
	2003			2004
	(In thousands)
Beginning of period	$	64,106		$	65,670
Sales of oil and natural gas produced, net of production expenses		(14,884	)		(18,128	)
Net change in sales and transfer prices, net of production costs		6,796			65,178
Development costs incurred		1,656			1,392
Revisions of quantity estimates		2,485			27,512
Changes in production rates and other		(900	)		(15,453	)
Accretion of discount		6,411			6,567
End of period	$	65,670		$	132,738

F-63

REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Resolute Natural Resources Company

Denver, Colorado

We have audited the accompanying statements of revenues and direct operating expenses of the properties (the “ExxonMobil Properties”) acquired by Resolute Aneth, LLC (the “Company”) from ExxonMobil for the years ended December 31, 2003, 2004 and 2005. These statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statements. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 2 to the statements and are not intended to be a complete presentation of the Company’s interests in the ExxonMobil Properties described above.

In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses, described in Note 2, of the ExxonMobil Properties for the years ended December 31, 2003, 2004 and 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ Ehrhardt Keefe Steiner & Hottman PC

February 2, 2007

Denver, Colorado

F-64

EXXONMOBIL PROPERTIES

Statements of Revenues and Direct Operating Expenses

	For the Year Ended December 31,						For the Three Months Ended March 31,
	2003		2004		2005		2005		2006
							(Unaudited)
Revenues — oil and gas production	$	44,960,851	$	50,983,837	$	67,707,944	$	15,091,644	$	16,658,179
Direct operating expenses
Lease operating expense		9,908,790		11,889,669		12,511,167		2,926,030		3,247,802
Production and ad valorem taxes		5,395,302		6,305,998		8,019,769		1,787,552		2,011,965
Total direct operating expenses		15,304,092		18,195,667		20,530,936		4,713,582		5,259,767
Revenues in excess of direct operating expenses	$	29,656,759	$	32,788,170	$	47,177,008	$	10,378,062	$	11,398,412

See notes to the statements of revenues and direct operating expenses

F-65

EXXONMOBIL PROPERTIES

Notes to the Statements of Revenues and Direct Operating Expenses

Note 1 — Operations, Organization, and Basis of Presentation

The accompanying statements represent the interests in the revenues and direct operating expenses of the oil and natural gas producing properties acquired by Resolute Aneth, LLC (the “Company”) from ExxonMobil on April 16, 2006, effective January 1, 2005. The properties are referred to herein as the “ExxonMobil Properties.”

Oil and gas revenues and direct operating expenses relate to the Company’s net revenue interests and net working interests, respectively, in the ExxonMobil Properties. With respect to gas sales, the sales method is used for recording revenues. Under this approach, each party recognizes revenue based on actual sales regardless of its proportionate share of the related sales. The revenue from oil and gas production has been based on historical product prices at the point of sale using the net revenue and working interests purchased by the Company. The effect on revenues of gas imbalances is not material.

Direct operating expenses include payroll, lease and well repairs, production and ad valorem taxes, maintenance, utilities and other direct operating expenses.

During the periods presented, the ExxonMobil Properties were not accounted for as a separate entity. Certain costs such as depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expenses, interest expense and corporate taxes were not allocated to the ExxonMobil Properties.

The accompanying statements of revenues and direct operating expenses for the three months ended March 31, 2005 and 2006 are unaudited, and in the opinion of management, reflect all adjustments that are necessary for a fair presentation of the revenues and direct operating expenses for the periods presented. The direct operating results for the three months ended March 31, 2005 and 2006 are not necessarily indicative of the direct operating results for the entire year.

Use of Estimates

The process of preparing financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions regarding certain types of revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts.

Note 2 — Omitted Financial Information

Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America are not presented as such information is not available on an individual property basis and not meaningful to the ExxonMobil Properties. Historically, no allocation of general and administrative, interest, corporate taxes, accretion of asset retirement obligations, depreciation, depletion and amortization was made to the ExxonMobil Properties. Accordingly, the statements are presented in lieu of the financial statements required underRule 3-01 of the Securities and Exchange CommissionRegulation S-X.

F-66

EXXONMOBIL PROPERTIES

Notes to the Statements of Revenues and Direct Operating Expenses — (Continued)

Note 3 — Supplemental Disclosures on Oil and Gas Exploration, Development and Production Activities (Unaudited)

Reserves

The following table summarizes the net ownership interests in estimated quantities of the proved oil and gas reserves of the ExxonMobil Properties at December 31, 2005, estimated by the Company’s petroleum engineers.

	Gas		Oil
	MMcf		MBbl
Proved developed reserves		732		14,848
Proved undeveloped reserves		—		1,122
Total proved reserves		732		15,970

	Gas			Oil
	MMcf			MBbl
Proved reserves as of January 1, 2003		1,272			14,278
Production in 2003		(1,295	)		(1,436	)
Revisions		1,177			501
Proved reserves as of December 31, 2003		1,154			13,343
Production in 2004		(1,101	)		(1,222	)
Revisions		1,035			2,202
Proved reserves as of December 31, 2004		1,088			14,323
Production in 2005		(1,145	)		(1,201	)
Revisions		789			1,726
Improved/enhanced recovery		—			1,122
Proved reserves as of December 31, 2005		732			15,970

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following table presents the Standardized Measure of Discounted Future Net Cash Flows before future income taxes from proved oil and gas reserves of the ExxonMobil Properties. As prescribed by the Financial Accounting Standards Board, the amounts shown are based on prices and costs at January 1, 2003, December 31, 2003, 2004, and 2005, and assume continuation of existing economic conditions. A discount factor of 10% was used to reflect the timing of future net cash flow. Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the fields. Accordingly, the estimates of future net cash flows from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results. Further, since prices and costs do not remain static, and no price or cost changes have been considered, and future production and development costs are estimates to be incurred in developing and producing the estimated proved oil and gas reserves, the

F-67

EXXONMOBIL PROPERTIES

Notes to the Statements of Revenues and Direct Operating Expenses — (Continued)

results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other oil and gas producers.

	As of December 31,
	2003			2004			2005
	(In thousands)
Future cash inflows	$	398,738		$	583,115		$	932,447
Future production costs		(253,079	)		(326,911	)		(435,629	)
Future development costs		(227	)		(13	)		(4,908	)
Future net cash flows		145,432			256,191			491,910
10% annual discount for estimating timing of cash flows		(57,682	)		(111,025	)		(245,668	)
Standardized Measure (before income taxes) of discounted future net cash flows relating to proved oil and gas reserves	$	87,750		$	145,166		$	246,242

Changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	For the Year Ended December 31,
	2003			2004			2005
	(In thousands)
Beginning of year	$	89,173		$	87,750		$	145,166
Sales of oil and natural gas produced, net of production expenses		(29,387	)		(32,788	)		(47,177	)
Net change in sales and transfer prices, net of production costs		7,636			39,829			92,363
Extensions and discoveries and improved recovery, net of future costs		—			—			8,117
Changes in estimated future development costs		—			—			(1,556	)
Development costs incurred		232			213			13
Revisions of quantity estimates		4,529			25,305			34,781
Changes in production rates and other		6,650			16,082			18
Accretion of discount		8,917			8,775			14,517
End of year	$	87,750		$	145,166		$	246,242

F-68

APPENDIX A

FIRST AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

RESOLUTE ENERGY PARTNERS, LP

A-1

APPENDIX B

GLOSSARY OF TERMS

2-D seismic or3-D seismic.  Interpretive geophysical data that depict the subsurface strata in two dimensions or three dimensions, respectively.3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than2-D seismic.

adjusted operating surplus.  For any period, adjusted operating surplus means

•  operating surplus generated with respect to that period (excluding the operating surplus “basket” of $25 million described in (a)(1) under the definition of operating surplus);plus

•  any net reduction 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 decrease in working capital borrowings with respect to that period;plus

•  any net reduction 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.

available cash.  For any quarter ending prior to liquidation:

(a)  the sum of:

(1)	all cash and cash equivalents of Resolute Energy Partners, LP 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 Resolute Energy Partners, LP and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made after the end of 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 Resolute Energy Partners, LP and its subsidiaries, including amounts for maintenance and expansion capital expenditures and debt reduction;
(2)	comply with applicable law or any debt instrument or other agreement or obligation to which Resolute Energy Partners, LP or any of its subsidiaries is a party or its assets are subject; and
(3)	provide funds for distributions to our unitholders and to our general partner 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.

Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, used in this offering memorandum in reference to crude oil or other liquid hydrocarbons. Bbl is also used to refer to multiple barrels of crude oil or other liquid hydrocarbons.

Bbl/d.  Barrels of crude oil production per day.

Bcf.  One billion cubic feet of gas.

B-1

Boe.  Barrels of oil equivalent, with six thousand cubic feet of gas being equivalent to one barrel of oil.

Btu or British thermal unit.  The amount of thermal energy required to raise the temperature of one pound of water at its maximum density (which occurs at a temperature of 39.1 degrees Fahrenheit) by one degree Fahrenheit.

capital account.  The capital account maintained for a partner under the partnership agreement. The capital account of a partner for a common unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that common unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in Resolute Energy Partners, LP held by a partner.

capital surplus.  All available cash distributed by Resolute Energy Partners, LP 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 Resolute Energy Partners, LP on that date will be deemed to be capital surplus, which will generally have been generated by interim capital transactions.

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 the over-the-counter market, as reported by the New York Stock Exchange 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.

completion.  The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

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.

developed acreage.  The number of acres that are allocated or assignable to productive wells or wells capable of production.

development well.  A well drilled within the proved area of an oil or gas reservoir, or which extends a proved reservoir, to the depth of a stratigraphic horizon known to be productive.

dry hole.  A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.

environmental assessment (EA).  A study that can be required pursuant to federal law prior to drilling a well or conducting certain other projects.

environmental impact statement (EIS).  A more detailed study that can be required pursuant to federal law of the potential direct, indirect and cumulative impacts of a project that may be made available for public review and comment.

B-2

formation.  A succession of sedimentary beds that were deposited under the same general geologic conditions.

field.  An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural featureand/or stratigraphic condition.

GAAP.  Generally Accepted Accounting Principles in the United States.

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

horizontal drilling.  Drilling wells at angles greater than 70 degrees from vertical.

interim capital transactions.  The following transactions if they occur prior to liquidation:

(a)	borrowings (other than working capital 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 Resolute Energy Partners, LP or any of its subsidiaries;
(b)	sales of equity interests by Resolute Energy Partners, LP or any of its subsidiaries; and
(c)	sales or other voluntary or involuntary dispositions of any assets of Resolute Energy Partners, LP or any of its subsidiaries (other than sales of oil and gas production, disposition of assets made in connection with plugging and abandoning wells and site reclamation, sales of inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets);
(d)	the termination of commodity hedge contracts and interest rate swap agreements prior to their respective termination dates;
(e)	capital contributions; and
(f)	corporate reorganizations or restructurings.

MBbl.  One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf.  One thousand cubic feet of gas.

Mcf/d.  One Mcf per day.

MMBbl.  One million barrels of crude oil or other liquid hydrocarbons.

MMBoe.  One million barrels of oil equivalent.

MMBtu.  One million British Thermal Units.

MMcf.  One million cubic feet of gas.

Natural gas liquids.  Components of natural gas that are liquid at surface, consisting primarily of ethane, propane, isobutane, normal butane and natural gasoline.

net acres or net wells.  The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

NYMEX.  New York Mercantile Exchange.

operating expenditures.  All of the cash expenditures of Resolute Energy Partners, LP and its subsidiaries, including, but not limited to, lease and well operating expenses, taxes, reimbursements of its general partner and Resolute Holdings, payments made in the ordinary course of business under interest rate and commodity derivative financial investments, non-pro rata repurchase of units, interest payments and estimated

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maintenance capital expenditures, repayment of working capital borrowings and debt service payments. Operating expenditures will not include:

(a)	actual repayment of working capital borrowings deducted from operating surplus that were deemed to have been repaid at the end of the twelve-month period following the borrowing;
(b)	payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings;
(c)	actual maintenance capital expenditures;
(d)	expansion capital expenditures;
(e)	payment of transaction expenses relating to transactions that do not generate operating surplus; or
(f)	distributions to partners.

operating surplus.  For any period prior to liquidation, on a cumulative basis and without duplication:

(a)  the sum of:

(1)	an amount equal to $25 million;
(2)	all cash receipts of Resolute Energy Partners, LP and its subsidiaries for the period beginning on the closing date of its initial public offering and ending with the last day of that period, other than cash receipts from interim capital transactions;
(3)	working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; and
(4)	cash distributions paid on equity issued to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset is placed into service or the date that it is abandoned or disposed of;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;
(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 Resolute Energy Partners, LP or its subsidiaries or disbursements on behalf of Resolute Energy Partners, LP or its 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; and
(3)	all working capital borrowings not repaid within twelve months after having been incurred.

plugging and abandonment.  Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

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

prospect.  A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

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proved developed non-producing reserves (PDNP).  Proved developed reserves expected to be recovered from zones behind casing in existing wells.

proved developed reserves (PDP).  Has the meaning given to such term inRule 4-10(a)(3) ofRegulation S-X, which defines proved developed reserves as:

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

proved reserves.  Has the meaning given to such term inRule 4-10(a)(2) ofRegulation S-X, which defines proved reserves as:

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i)	Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oiland/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii)	Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii)	Estimates of proved reserves do not include the following: (A) Oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

proved undeveloped reserves (PUD).  Has the meaning given to such term inRule 4-10(a)(4) ofRegulation S-X, which defines proved undeveloped reserves as:

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

recompletion.  The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

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reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oiland/or gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

royalty interest.  An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.

standardized measure.  The present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows using pricing and costs in effect on the specified date.

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 December 31, 2012 for 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 $1.40 (the annualized minimum quarterly distribution) 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 $1.40 (the annualized minimum quarterly distribution) on all of the common units and subordinated units that were outstanding during those periods on a fully diluted basis and the related distributions on our general partner’s 2% general partner interest; and
(3)	there are no outstanding cumulative common units arrearages.

(b)	in certain cases on an earlier date, but not prior to December 31, 2010.
(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.

undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

working capital borrowings.  Borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than additional working capital borrowings.

working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

workover.  Operations that are conducted on a producing well to restore or increase production.

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Chairman Emeritus
Clarence M. Netherland

Chairman & CEO
Frederic D. Sewell

President & COO
C.H. (Scott) Rees III Executive Committee
G. Lance Binder — Dallas
Danny D. Simmons — Houston
P. Scott Frost — Dallas
Dan Paul Smith — Dallas
Joseph J. Spellman — Dallas
Thomas J. Tella II — Dallas

August 31, 2007

Mr. David Clouatre
Resolute Natural Resources Company
1675 Broadway, Suite 1950
Denver, Colorado 80202

Dear Mr. Clouatre:

In accordance with your request, we have audited the estimates prepared by Resolute Natural Resources Company (Resolute), as of June 30, 2007, of the proved reserves and future revenue to the Resolute interest in certain oil and gas properties located in Greater Aneth Field, Utah. These estimates are based on the price and cost parameters discussed in subsequent paragraphs of this letter. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC)Regulation S-XRule 4-10(a) and subsequent staff interpretations and guidance. The estimates of reserves and future revenue have been prepared in accordance with the definitions and guidelines of the SEC and, with the exception of the exclusion of future income taxes, conform to the Statement of Financial Accounting Standards No. 69 (FASB 69). This is a revision of our report dated August 27, 2007. The Resolute estimates in this report have been revised to reflect the exclusion of the oil price hedge contracts.

The following table sets forth Resolute’s estimates of the net reserves and future net revenue, as of June 30, 2007, for the audited properties:

						Future Net Revenue (M$)
	Net Reserves							Present
	Oil		Gas					Worth
Category	(MBBL)		(MMCF)			Total		at 10%
Proved Developed
Producing		28,717.1		4,023.8			988,335.4		505,782.1
Non-Producing		4,528.0		1,151.3			183,567.5		76,624.3
Proved Undeveloped		44,547.3		(3,545.4	)(1)		2,024,175.2		576,925.4
Total Proved		77,792.4		1,629.7			3,196,078.2		1,159,331.9

Totals may not add because of rounding.

(1) Negative gas reserves are due to sales eliminated by proved undeveloped CO₂ expansion projects.

The oil reserves shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

When compared on aunit-by-unit basis, some of the estimates of Resolute are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. However, in our opinion the estimates of Resolute’s proved reserves and future revenue shown herein are, in the aggregate, reasonable and have been prepared in

4500Thanksgiving Tower • 1601 Elm Street • Dallas, Texas 75201-4754 • Ph: 214-969-5401 • Fax: 214-969-5411 nsai@nsai-petro.com

1221 Lamar Street, Suite 1200 • Houston, Texas 77010-3072 • Ph: 713.654-4950 • Fax: 713-654-4951 netherlandsewell.com

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accordance with generally accepted petroleum engineering and evaluation principles. These principles are set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We are satisfied with the methods and procedures used by Resolute in preparing the June 30, 2007, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Resolute.

The estimates shown herein are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. Resolute’s estimates do not include probable or possible reserves that may exist for these properties, nor do they include any consideration of undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Oil prices used by Resolute are based on a June 30, 2007, NYMEX West Texas Intermediate futures price of $70.68 per barrel and are adjusted by unit for quality, transportation fees, and a regional price differential. This is consistent with Resolute’s contractual arrangements. We have undertaken our evaluation using a June 30, 2007, Cushing, Oklahoma, West Texas Intermediate posted price of $67.25 per barrel, adjusted by unit for quality, transportation fees, and a regional price differential, and have found that Resolute’s evaluation using NYMEX pricing does not materially vary from our evaluation. Gas prices used by Resolute are based on a June 30, 2007, El Paso San Juan spot price of $6.115 per MMBTU and are adjusted by unit for energy content and processing fees.

Lease and well operating costs used by Resolute are based on historical operating expense records and include only direct lease- and field-level costs. These costs include the estimates of costs to be incurred at and below the district and field levels, but do not include the per-well overhead expenses allowed under joint operating agreements nor do they include the headquarters general and administrative overhead expenses of Resolute. Resolute’s estimates of capital costs are included as required for workovers, new development wells, and production equipment.

It should be understood that our audit does not constitute a complete reserves study of the oil and gas properties of Resolute. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of all properties. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by Resolute with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Our audit did not include a review of Resolute’s overall reserves management processes and practices.

In evaluating the information at our disposal concerning this audit, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geologic. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geologic data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by Resolute, are on file in our office. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists with respect to Resolute Natural Resources Company as provided in the Standards Pertaining to the Estimating and Auditing of Oil and

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Gas Reserves Information promulgated by the Society of Petroleum Engineers. We do not own an interest in these properties and are not employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

By:  /s/  C.H. (Scott) Rees III

C.H. (Scott) Rees III, P.E.

President and Chief Operating Officer

By:  /s/  David T. Miller

David T. Miller, P.E.

Vice President

Date Signed: August 31, 2007

DTM:JAT

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PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than underwriting discounts and commissions) 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, the NASD filing fee, the amounts set forth below are estimates.

SEC registration fee	$	10,195
NASD filing fee		33,706
New York Stock Exchange listing fee		*
Printing and engraving expenses		*
Fees and expenses of legal counsel		*
Accounting fees and expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*
Total	$	*

* To be provided by amendment.

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 Eight of the Underwriting Agreement filed as an exhibit to this registration statement in which Resolute Energy Partners, LP and certain of its affiliates 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.

In addition, we intend to enter into indemnification agreements with each of the executive officers and directors of our general partner. Each indemnification agreement will require us to indemnify each indemnitee to the fullest extent permitted by our partnership agreement. This means, among other things, that we must indemnify the executive officer or director against expenses (including attorneys’ fees), judgments, penalties, fines and amounts paid in settlement that are actually and reasonably incurred in an action, suit or proceeding by reason of the fact that the person is or was an executive officer or a director of our general partner or is or was serving at our general partner’s request as a director, officer, employee or agent of another corporation or other entity if the indemnitee meets the standard of conduct provided in our partnership agreement. Also as permitted under our partnership agreement, the indemnification agreements require us to advance expenses in defending such an action provided that the executive officer or director undertakes to repay the amounts if the person ultimately is determined not to be entitled to indemnification from us. We will also make the indemnitee whole for taxes imposed on the indemnification payments and for costs in any action to establish indemnitee’s right to indemnification, whether or not wholly successful.

Item 15. Recent Sales of Unregistered Securities.

On September 24, 2007, in connection with the formation of Resolute Energy Partners, LP (the “Partnership”), the Partnership issued to (i) Resolute Energy GP, LLC the 2% general partner interest in the

II-1

Partnership for a non-interest bearing promissory note with a face amount of $20 due September 30, 2007, and (ii)  Resolute Holdings Sub, LLC the 98% limited partner interest in the Partnership for $980. In each case, 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.

Item 16. Exhibits.

The following documents are filed as exhibits to this registration statement:

Exhibit
Number				Description
	1	.1*	—	Form of Underwriting Agreement
	2	.1†	—	Purchase and Sale Agreement between Exxon Mobil Corporation, ExxonMobil Oil Corporation, Mobil Exploration and Producing North America Inc., Mobil Producing Texas & New Mexico Inc. and Mobil Exploration & Producing U.S. Inc. and Resolute Aneth, LLC — 75% and Navajo Nation Oil and Gas Company — 25% dated January 1, 2005
	2	.2†	—	Asset Sale Agreement Aneth Unit, Rutherford Unit and McElmo Creek Unit, San Juan County, Utah between Chevron U.S.A. Inc. (as seller) and Resolute Natural Resources Company and Navajo Nation Oil and Gas Company, Inc. (as Buyer) dated October 22, 2004
	3	.1	—	Certificate of Limited Partnership of Resolute Energy Partners, LP
	3	.2*	—	Form of Amended and Restated Limited Partnership Agreement of Resolute Energy Partners, LP (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)
	3	.3	—	Certificate of Formation of Resolute Energy GP, LLC
	3	.4*	—	Form of Amended and Restated Limited Liability Agreement of Resolute Energy GP, LLC
	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*	—	Form of Revolving Credit Facility
	10	.2*	—	Form of Resolute Energy Partners, LP Long-Term Incentive Plan
	10	.3*	—	Form of Contribution, Conveyance and Assumption Agreement
	10	.4*	—	Form of Administrative Services Agreement
	10	.5*	—	Form of Indemnification Agreement between Resolute Energy Partners, LP and each executive officer and independent director of its general partner
	10	.6	—	Cooperative Agreement between Resolute Natural Resources Company and Navajo Nation Oil and Gas Company dated October 22, 2004 (portions of this exhibit have been omitted pursuant to a request for confidential treatment)
	10	.7	—	First Amendment of Cooperative Agreement between Resolute Aneth, LLC and Navajo Nation Oil and Gas Company, Inc. dated October 21, 2005 (portions of this exhibit have been omitted pursuant to a request for confidential treatment)
	10	.8*	—	Crude Oil Purchase and Sale Agreement between Giant Refining Company and Resolute Natural Resources Company dated April 20, 2006
	10	.9	—	Carbon Dioxide Sale and Purchase Agreement by and between ExxonMobil Gas & Power Marketing Company (a division of Exxon Mobil Corporation), as agent for Mobil Producing Texas & New Mexico, Inc. (“Seller”) and Resolute Aneth, LLC (“Buyer”) dated July 1, 2006, as amended (portions of this exhibit have been omitted pursuant to a request for confidential treatment)
	10	.10	—	Product Sale and Purchase Contract by and between Resolute Natural Resources Company (Buyer) and Kinder Morgan CO2 Company, L.P. (Seller) dated July 1, 2007 (portions of this exhibit have been omitted pursuant to a request for confidential treatment)
	21	.1*	—	List of Subsidiaries of Resolute Energy Partners, LP
	23	.1	—	Consent of Ehrhardt Keefe Steiner & Hoffman PC
	23	.2	—	Consent of Deloitte & Touche LLP
	23	.3	—	Consent of Sproule Associates Limited
	23	.4	—	Consent of Netherland, Sewell & Associates, Inc.

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Exhibit
Number				Description
	23	.5*	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
	23	.6*	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
	24	.1	—	Powers of Attorney (contained onpage II-4)

*

To be filed by amendment.

†

The Purchase and Sale Agreement filed as Exhibit 2.1 and the Asset Sale Agreement filed as Exhibit 2.2 omit certain of the schedules and exhibits to each of the Purchase and Sale Agreement and the Asset Sale Agreement in accordance with Item 601(b)(2) ofRegulation S-K. A list briefly identifying the contents of all omitted schedules and exhibits is included with each of the Purchase and Sale Agreement and the Asset Sale Agreement filed as Exhibit 2.1 and 2.2, respectively. Resolute Energy Partners, LP agrees to furnish supplementally a copy of any omitted schedule or exhibit to the Securities and Exchange Commission upon request.

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 Resolute Energy GP, LLC or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Resolute Energy GP, LLC 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 byForm 10-K for the first full fiscal year of operations of the partnership.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on September 28, 2007.

Resolute Energy Partners, LP

By: Resolute Energy GP,
LLC its General Partner

By: 

/s/  Nicholas J. Sutton

Name:     Nicholas J. Sutton

Title:  Chief Executive Officer

Each person whose signature appears below appoints Nicholas J. Sutton and James M. Piccone, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons on September 28, 2007.

Signature	Title
/s/  Nicholas J. Sutton Nicholas J. Sutton	Chief Executive Officer (Principal Executive Officer) and Director
/s/  Theodore Gazulis Theodore Gazulis	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
/s/  James Piccone James Piccone	Director
/s/  Kenneth A. Hersh Kenneth A. Hersh	Director
/s/  Richard L. Covington Richard L. Covington	Director

II-4

EXHIBIT INDEX

Exhibit
Number				Description
	1	.1*	—	Form of Underwriting Agreement
	2	.1†	—	Purchase and Sale Agreement between Exxon Mobil Corporation, ExxonMobil Oil Corporation, Mobil Exploration and Producing North America Inc., Mobil Producing Texas & New Mexico Inc. and Mobil Exploration & Producing U.S. Inc. and Resolute Aneth, LLC — 75% and Navajo Nation Oil and Gas Company — 25% dated January 1, 2005
	2	.2†	—	Asset Sale Agreement Aneth Unit, Rutherford Unit and McElmo Creek Unit, San Juan County, Utah between Chevron U.S.A. Inc. (as seller) and Resolute Natural Resources Company and Navajo Nation Oil and Gas Company, Inc. (as Buyer) dated October 22, 2004
	3	.1	—	Certificate of Limited Partnership of Resolute Energy Partners, LP
	3	.2*	—	Form of Amended and Restated Limited Partnership Agreement of Resolute Energy Partners, LP (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)
	3	.3	—	Certificate of Formation of Resolute Energy GP, LLC
	3	.4*	—	Form of Amended and Restated Limited Liability Agreement of Resolute Energy GP, LLC
	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*	—	Form of Revolving Credit Facility
	10	.2*	—	Form of Resolute Energy Partners, LP Long-Term Incentive Plan
	10	.3*	—	Form of Contribution, Conveyance and Assumption Agreement
	10	.4*	—	Form of Administrative Services Agreement
	10	.5*	—	Form of Indemnification Agreement between Resolute Energy Partners, LP and each executive officer and independent director of its general partner
	10	.6	—	Cooperative Agreement between Resolute Natural Resources Company and Navajo Nation Oil and Gas Company dated October 22, 2004 (portions of this exhibit have been omitted pursuant to a request for confidential treatment)
	10	.7	—	First Amendment of Cooperative Agreement between Resolute Aneth, LLC and Navajo Nation Oil and Gas Company, Inc. dated October 21, 2005 (portions of this exhibit have been omitted pursuant to a request for confidential treatment)
	10	.8*	—	Crude Oil Purchase and Sale Agreement between Giant Refining Company and Resolute Natural Resources Company dated April 20, 2006
	10	.9	—	Carbon Dioxide Sale and Purchase Agreement by and between ExxonMobil Gas & Power Marketing Company (a division of Exxon Mobil Corporation), as agent for Mobil Producing Texas & New Mexico, Inc. (“Seller”) and Resolute Aneth, LLC (“Buyer”) dated July 1, 2006, as amended (portions of this exhibit have been omitted pursuant to a request for confidential treatment)
	10	.10	—	Product Sale and Purchase Contract by and between Resolute Natural Resources Company (Buyer) and Kinder Morgan CO2 Company, L.P. (Seller) dated July 1, 2007 (portions of this exhibit have been omitted pursuant to a request for confidential treatment)
	21	.1*	—	List of Subsidiaries of Resolute Energy Partners, LP
	23	.1	—	Consent of Ehrhardt Keefe Steiner & Hoffman PC
	23	.2	—	Consent of Deloitte & Touche LLP
	23	.3	—	Consent of Sproule Associates Limited
	23	.4	—	Consent of Netherland, Sewell & Associates, Inc.

II-5

Exhibit
Number				Description
	23	.5*	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
	23	.6*	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
	24	.1	—	Powers of Attorney (contained onpage II-4)

*

To be filed by amendment.

†

The Purchase and Sale Agreement filed as Exhibit 2.1 and the Asset Sale Agreement filed as Exhibit 2.2 omit certain of the schedules and exhibits to each of the Purchase and Sale Agreement and the Asset Sale Agreement in accordance with Item 601(b)(2) ofRegulation S-K. A list briefly identifying the contents of all omitted schedules and exhibits is included with each of the Purchase and Sale Agreement and the Asset Sale Agreement filed as Exhibit 2.1 and 2.2, respectively. Resolute Energy Partners, LP agrees to furnish supplementally a copy of any omitted schedule or exhibit to the Securities and Exchange Commission upon request.

II-6