##### Table of Contents



As filed with the Securities and Exchange Commission on
    November 9, 2007
 
 
 Registration No. 333-146391
 
 
   UNITED STATES SECURITIES AND
    EXCHANGE COMMISSION
 Washington, D.C.
    20549
    
   Amendment No. 1
 
 
 to
 
 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:
      o
  o
  o
  o
  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.




---



##### Table of Contents



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 NOVEMBER 9, 2007
 
 PROSPECTUS
 
  13,750,000
    Common Units
  Representing
    Limited Partner Interests
    
  Investing in our common units
    involves risks. Please read Risk Factors beginning
    on page 23.
 
    
    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 operate in a remote location
    without ready access to other markets for our crude oil
    production. 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. 
 
 Per Common Unit


TotalInitial 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.  30-day
  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
    UBS
    Investment Bank
    Wachovia
    Securities  ,
    2008




---



##### Table of Contents



Our
    Areas of Operation




---



##### Table of Contents



TABLE OF
    CONTENTS
  
 PageSUMMARY

1Resolute Energy Partners, LP

1Planned Operating and Development Activities

2Hedging Activities

3Our Management and Natural Gas Partners

3Our Business Strategies

4Our Competitive Strengths

4Summary of Risk Factors

4Management of Resolute Energy Partners, LP

6Principal Executive Offices and Internet
    Address

7Our Partnership Structure and Formation
    Transactions

8Summary of Conflicts of Interest and Fiduciary
    Duties

10Our General Partners Right to Receive
    Incentive Distributions

10The Offering

11Summary Historical and Pro Forma Financial
    Data

15Non-GAAP Financial Measures

19Summary Historical Operating and Reserve Data

21RISK FACTORS

23Risks Related to Our Business

23Risks Inherent in an Investment in Us

36Tax Risks to Common Unitholders

46CAUTIONARY NOTE REGARDING FORWARD-LOOKING
    STATEMENTS

50USE OF PROCEEDS

51CAPITALIZATION

52DILUTION

53OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON
    DISTRIBUTIONS

54General

54Our Minimum Quarterly Distribution Rate

56Unaudited Pro Forma Available Cash for Year Ended
    December 31, 2006, and Twelve Months Ended June 30,
    2007

58Estimated Cash Available for Distributions for
    the Year Ending December 31, 2008

61Assumptions and Considerations

65Operations and Revenue

66Capital Expenditures and Expenses

68Sensitivity Analysis

71PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING
    TO CASH DISTRIBUTIONS

75Distributions of Available Cash

75Operating Surplus and Capital Surplus

76Subordination Period

79Distributions of Available Cash from Operating
    Surplus During the Subordination Period

80Distributions of Available Cash from Operating
    Surplus After the Subordination Period

81General Partner Interest and Incentive
    Distribution Rights

81Percentage Allocations of Available Cash from
    Operating Surplus

82 
 i




---



##### Table of Contents



PageDistributions from Capital Surplus

82Adjustment to the Minimum Quarterly Distribution
    and Target Distribution Levels

83Distributions of Cash Upon Liquidation

83SELECTED HISTORICAL AND PRO FORMA FINANCIAL
    DATA

86MANAGEMENTS DISCUSSION AND ANALYSIS OF
    FINANCIAL CONDITION AND RESULTS OF OPERATIONS

89Overview

89How We Evaluate Our Operations

91Factors That Significantly Affect Our Results

94Results of Operations

96Six Months Ended June 30, 2007, Compared to
    the Six Months Ended June 30, 2006

97Year Ended December 31, 2006, Compared to
    the Year Ended December 31, 2005

99Year Ended December 31, 2005, Compared to
    the Period from January 22, 2004 (Inception) to
    December 31, 2004

100Liquidity and Capital Resources

102Revolving Credit Facility

104Contractual Obligations

105Off-Balance Sheet Obligations

106Critical Accounting Policies and Estimates

106Recent Accounting Pronouncements

109Quantitative and Qualitative Disclosures About
    Market Risk

109BUSINESS

111Greater Aneth Field

112Our Business Strategies

113Our Competitive Strengths

115Oil Recovery Overview

116Recent Development and Operating Activity

117Planned Operating and Development Activities

118Estimated Net Proved Reserves

121Production and Price History

123Productive Wells

124Acreage

124Drilling Results

124Relationship with the Navajo Nation

125Marketing and Customers

126Aneth Gas Processing Plant

127Title to Properties

128Competition

128Seasonality

128Environmental and Safety Matters and
    Regulation

129Laws and Regulations Pertaining to Oil and Gas
    Operations on Navajo Nation Lands

132Other Regulation of the Oil and Gas Industry

136Legal Proceedings

137Employees

137Offices

137 
 ii




---



##### Table of Contents



PageMANAGEMENT

138Management of Resolute Energy Partners, LP

138Directors and Executive Officers

139Reimbursement of Expenses of Our General
    Partner

141Executive Compensation

141Compensation of Directors

141Compensation Discussion and Analysis

142Long-Term Incentive Plan

142SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
    AND MANAGEMENT

147CERTAIN RELATIONSHIPS AND RELATED PARTY
    TRANSACTIONS

148Distributions and Payments to Our General Partner
    and its Affiliates

148Agreements Governing the Transactions

149Administrative Services Agreement

149Competition

150Indemnification Agreements with Our General
    Partners Executive Officers and Directors

150Procedures for Review, Approval and Ratification
    of Related Person Transactions

151Other Arrangements with Affiliates

151CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

152Conflicts of Interest

152Fiduciary Duties

157DESCRIPTION OF THE COMMON UNITS

160The Units

160Transfer Agent and Registrar

160Transfer of Common Units

160THE PARTNERSHIP AGREEMENT

162Organization and Duration

162Purpose

162Power of Attorney

162Cash Distributions

162Capital Contributions

162Voting Rights

163Limited Liability

164Issuance of Additional Securities

165Amendment of the Partnership Agreement

165Merger, Sale or Other Disposition of Assets

167Termination and Dissolution

168Liquidation and Distribution of Proceeds

168Withdrawal or Removal of the General Partner

169Transfer of General Partner Interest

170Transfer of Ownership Interests in the General
    Partner

170Transfer of Incentive Distribution Rights

170Change of Management Provisions

170Limited Call Right

171Meetings; Voting

171 
 iii




---



##### Table of Contents



PageStatus as Limited Partner

172Non-Eligible Holders; Redemption

172Indemnification

173Reimbursement of Expenses

173Books and Reports

174Right to Inspect Our Books and Records

174Registration Rights

174UNITS ELIGIBLE FOR FUTURE SALE

175MATERIAL TAX CONSEQUENCES

176Partnership Status

177Limited Partner Status

178Tax Consequences of Common Unit Ownership

178Tax Treatment of Operations

184Disposition of Common Units

188Uniformity of Common Units

190Tax-Exempt Organizations and Other Investors

190Administrative Matters

191State, Local and Other Tax Considerations

193INVESTMENT IN RESOLUTE ENERGY PARTNERS, LP BY
    EMPLOYEE BENEFIT PLANS

194UNDERWRITING

196Commissions and Expenses

196Option to Purchase Additional Common Units

196Lock-Up Agreements

197Offering Price Determination

198Indemnification

198Directed Unit Program

198Stabilization, Short Positions and Penalty
    Bids

198Electronic Distribution

199New York Stock Exchange

199Discretionary Sales

199Stamp Taxes

199Relationships/NASD Conduct Rules

200VALIDITY OF THE COMMON UNITS

201EXPERTS

201WHERE YOU CAN FIND MORE INFORMATION

202INDEX TO FINANCIAL STATEMENTS

F-1APPENDIX A  FORM OF FIRST AMENDED
    AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

A-1APPENDIX B  GLOSSARY OF TERMS

B-1APPENDIX C  REPORT OF NETHERLAND, SEWELL &
    ASSOCIATES, INC., INDEPENDENT PETROLEUM ENGINEERS

C-1Crude Oil Purchase and Sale AgreementCrude Oil Purchase and Sale AgreementConsent DecreeConsent DecreeBase Contract for Sale and Purchase of Natural GasConsent of Ehrhardt Keefe Steiner & Hottman PCConsent of Deloitte & Touche LLPConsent of Sproule Associates LimitedConsent of Netherland, Sewell & Associates, Inc.  iv




---



##### Table of Contents



v




---



##### Table of Contents



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 23 for more
    information about important risks that you should consider
    carefully before buying our common units. We include a glossary
    of some of the terms used in this prospectus as Appendix B.
    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
  2
    
 Oil Reserves toOil ProductionEstimated Net Proved Reserves as of June 30, 2007
    (MMBoe)





Ratio (in years)Proved














Average





ProvedProved


Developed














Net Daily





DevelopedDeveloped


Non-


Proved Undeveloped


Total


Production


Proved


ProducingProducing


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



17McElmo Creek Unit


13.8



0.1



7.6



0.6



8.2



22.1



2,481



25



15Ratherford Unit


5.9



4.5



11.6



0.6



12.2



22.6



1,689



42



9Total


29.4



4.7



40.9



3.1



44.0



78.1



5,878



39



15Future operating costs ($/Boe)(4)

$
25.16


$
17.87


$
7.63


$
5.90


$
7.51


$
14.78Future production taxes ($/Boe)(5)

$
8.43


$
8.64


$
9.28


$
8.94


$
9.25


$
8.91Future PUD development costs (in millions)(6)









$
209.1


$
50.4


$
259.5Future PUD development costs ($/Boe)(7)









$
5.11


$
16.26


$
5.90
 1




---



##### Table of Contents



(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)
    
    Determined by dividing our estimated future operating costs as
    of June 30, 2007, by total estimated net proved reserves as
    of June 30, 2007, for each reserve category. 
 
  (5)
    
    Determined by dividing our estimated future production taxes as
    of June 30, 2007, by total estimated net proved reserves as
    of June 30, 2007, for each reserve category. 
 
  (6)
    
    Future development costs include costs incurred in connection
    with 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. 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. 
 
  (7)
    
    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. 
    Planned
    Operating and Development Activities
 
  2 2 2 2 2 2 2 2 2
 
  2 2 2 2 2
 2




---



##### Table of Contents



2 2 2 2 2
 
  Hedging
    Activities
    Our
    Management and Natural Gas Partners
 3




---



##### Table of Contents



Our
    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.  Our
    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. 
  Summary
    of Risk Factors
 
 
   
 
  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. 
 
  
    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. 
 
  
    Our estimate of cash available for distributions for the twelve
    months ending December 31, 2008 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. 
 
  
    We will require substantial capital expenditures to replace our
    production and reserves, which will reduce our cash available
    for distribution. 
 
  
    A significant part of our development plan involves the
    implementation of our
    CO2
    projects. These projects are subject to numerous uncertainties,
    including risks related to our ability to purchase
    CO2,
    and may be less successful than planned. If we are not able to
    purchase
    CO2
    or if our
    CO2
    flood projects do not produce the results we expect, we may have
    to reduce the value of our reserves and we
 4




---



##### Table of Contents



may not have sufficient cash available to pay distributions at
    the minimum quarterly distribution rate or at all.  
    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.
    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.
    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.
    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.
    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.
    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.
    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.
    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.  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.
    Resolute Holdings and its affiliates, including Natural Gas
    Partners and its affiliates, are not limited in their ability to
    compete with us.
    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.
    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.
    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.
 5




---



##### Table of Contents




    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.
    Holders of our common units have limited voting rights and are
    not entitled to elect our general partner or its directors.
    Even if holders of our common units are dissatisfied, they
    cannot initially remove our general partner without its consent.
    You will experience immediate and substantial dilution of $15.60
    in tangible net book value per common unit.
    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.  Tax
    Risks to Common Unitholders
  
    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.
    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.
    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.
    You will be required to pay taxes on your share of our income
    even if you do not receive any cash distributions from us.
    Tax-exempt entities and
    non-U.S. persons
    face unique tax issues from owning our common units that may
    result in adverse tax consequences to them.
    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.
    A unitholder whose units are loaned to a short
    seller to cover a short sale of units may be considered as
    having disposed of those units. If so, he would no longer be
    treated for tax purposes as a partner with respect to those
    units during the period of the loan and may recognize gain or
    loss from the disposition.
    As a result 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.  Management
    of Resolute Energy Partners, LP
 6




---



##### Table of Contents



Principal
    Executive Offices and Internet Address
  (303) 534-4600.
 7




---



##### Table of Contents



Our
    Partnership Structure and Formation Transactions
     
  
    Resolute Aneth will distribute to Resolute Holdings
    $7.5 million of working capital, consisting of cash or
    accounts receivable; 
  
    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.
 8




---



##### Table of Contents



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
%
 9




---



##### Table of Contents



Summary
    of Conflicts of Interest and Fiduciary Duties
  General.
  
    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.    Partnership Agreement Modifications to Fiduciary
    Duties.
    Our
    General Partners Right to Receive Incentive
    Distributions
 10




---



##### Table of Contents



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.
 11




---



##### Table of Contents



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 68.7% and 80.0%, respectively, of the minimum
    quarterly distribution on our subordinated units during those
    periods (68.7% and 77.1%, respectively, assuming the
    underwriters exercise in full their option to purchase
    additional common units). For a calculation of our ability to
    make distributions to our unitholders based on our pro forma
    results for the year ended December 31, 2006 and the twelve
    months ended June 30, 2007, please read Our Cash
    Distribution Policy and Restrictions on Distributions. Due
    to the factors described in Managements Discussion
    and Analysis of Financial Condition and Results of
    Operations  Factors That Significantly Affect Our
    Results, our future results of operations may not be
    comparable to our predecessors historical results. 
 
  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 Distributions for the Year Ending
    December 31, 2008.
 12




---



##### Table of Contents



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. 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.
 13




---



##### Table of Contents



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 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.
 14




---



##### Table of Contents



Summary
    Historical and Pro Forma Financial Data
      
    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. 
   
    
    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 to Resolute Holdings of
    $7.5 million of working capital, consisting of cash or
    accounts receivable; 
  
    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
 15




---



##### Table of Contents



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.
 16




---



##### Table of Contents



Pro FormaChevron


Resolute Energy Partners Predecessor


Resolute EnergyProperties


January 22,














Partners, LPEleven Months


2004

















Six MonthsEnded


(Inception) to


Year Ended


Six Months Ended


Year Ended


EndedNovember 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


$
57,646Gas(3)


257



(179
)


681



836



331



242



851



242Other






101



2,094



3,735



1,350



2,371



4,516



2,371Total revenues


27,627



2,390



41,973



106,571



41,771



60,259



125,534



60,259Operating expenses:Lease operating(4)


6,526



658



8,734



24,857



9,405



16,507



27,181



16,507Workover






21



3,860



13,312



4,437



5,700



14,351



5,700Production taxes


2,972



340



2,772



7,806



3,062



4,536



9,279



4,536General and administrative(4)






2,415



3,281



6,015



2,172



34,617



5,613



32,960Depletion, depreciation, and amortization






407



4,680



11,071



4,140



7,915



12,150



7,641Accretion of asset retirement obligations






20



216



206



95



145



222



145Total operating expenses


9,498



3,861



23,543



63,267



23,311



69,420



68,796



67,489Operating 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



216Gain (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


$
34,212Balance 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







425,331Long-term debt






44,000



45,925



267,500



271,350



395,250







150,975Shareholders/Members/Partners equity
    (deficit)(5)






44,997



28,698



61,860



15,163



(45,008
)






185,367Cash Flow Data:Net cash provided by (used in):Operating activities





$
(2,225
)

$
11,516


$
31,756


$
5,296


$
16,694Investing 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
 17




---



##### Table of Contents



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 at
    F-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.
 18




---



##### Table of Contents



Non-GAAP Financial
    Measures
        
    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.      
    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.
 19




---



##### Table of Contents



Pro FormaResolute Energy Partners Predecessor


Resolute EnergyJanuary 22,














Partners, LP2004

















Six Months(Inception) to


Year Ended


Six Months Ended


Year Ended


EndedDecember 31,


December 31,


June 30,


December 31,


June 30,2004


2005


2006


2006


2007


2006


2007Net 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



4,810Income taxes


742



3,830



















Depletion, depreciation and amortization


407



4,680



11,071



4,140



7,915



12,150



7,641Accretion of asset retirement obligation


20



216



206



95



145



222



145Non-cash change in fair value of derivatives


(3,383
)


23,159



(13,291
)


21,930



21,874



(13,291
)


21,882Non-cash equity-based compensation expense


















32,663







31,099Other










(185
)


(64
)


(198
)






Adjusted EBITDA

$
(784
)

$
17,780


$
52,546


$
20,254


$
33,963


$
67,075


$
34,212Less:Cash interest expense


190



2,442



17,644



6,000



12,218Income taxes






4,572











Change in operating assets and liabilities


1,251



(750
)


3,146



8,958



5,051Net cash provided by (used in) operating activities

$
(2,225
)

$
11,516


$
31,756


$
5,296


$
16,694
 20




---



##### Table of Contents



Summary
    Historical Operating and Reserve Data
    Pro FormaChevron


Resolute Energy Partners Predecessor


Resolute EnergyProperties


January 22,














Partners, LPEleven Months


2004

















Six MonthsEnded


(Inception) to








Six Months Ended


Year Ended


EndedNovember 30,


December 31,


Year Ended December 31,


June 30,


December 31,


June 30,2004


2004(1)


2005


2006(2)


2006(2)


2007


2006(3)


2007Production Sales Data:Oil (MBbl)


731



60



720



1,588



606



973



1,881



973Gas (MMcf)(4)


470



(11
)


136



227



81



92



259



92Natural gas liquids (MBbl)






1



56



91



33



58



111



58Equivalent volumes (MBoe)


810



59



799



1,717



653



1,046



2,035



1,046Daily equivalent volumes (Boe/d)


2,425



1,922



2,189



4,704



3,608



5,779



5,575



5,779Average Realized Prices:Oil ($/Bbl)

$
37.44


$
44.62


$
46.53


$
62.72


$
61.80


$
61.64


$
62.48


$
61.64Gas ($/Mcf)


5.47







5.01



3.68



4.09



2.63



3.29



2.63Natural gas liquids ($/Bbl)






20.00



20.02



33.05



30.36



32.07



32.77



32.07Other Operating Data:Lease operating expenses ($/Boe)

$
8.06


$
11.15


$
10.93


$
14.48


$
14.40


$
15.78


$
13.36


$
15.78Workover expenses ($/Boe)






0.36



4.83



7.75



6.79



5.45



7.05



5.45Production 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.
 21




---



##### Table of Contents



As ofAs of December 31,


June 30,2004


2005


2006(1)


2007Estimated total proved reserves:Oil (MBbl)


17,827



23,500



78,357



77,792Gas (MMcf)


2,404



3,750



1,890



1,630Total (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 Financial
    Accounting Standards Board, which we refer to as the
    FASB (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 and FASB 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 ofAs of December 31,


June 30,2004


2005


2006


2007Oil ($/Bbl)

$
43.45


$
61.06


$
61.05


$
70.68Gas ($/MMBtu)


6.15



9.52



5.64



6.12
 22




---



##### Table of Contents



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.
      
    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.    
    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; 23




---



##### Table of Contents




    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.    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.
 
   
 
  Our
    estimate of cash available for distributions for the twelve
    months ending December 31, 2008 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.
 
 
  2
 
 
 
  We
    will require substantial capital expenditures to replace our
    production and reserves, which will reduce our cash available
    for distribution.
   24




---



##### Table of Contents



2 2 2
 
  A
    significant part of our development plan involves the
    implementation of our
    CO2
    projects. These projects are subject to numerous uncertainties,
    including risks related to our ability to purchase
    CO2,
    and may be less successful than planned. If we are not able to
    purchase
    CO2
    or if our
    CO2
    flood projects do not produce the results we expect, we may have
    to reduce the value of our reserves and we may not have
    sufficient cash available to pay distributions at the minimum
    quarterly distribution rate or at all.
 
  2
 
  2 2 2 2 2 2 2
 
 
  2
 
 25




---



##### Table of Contents



2 2 2 2 2 2 2 2 2 2 2
 
  2 2
  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.
   
   
       26




---



##### Table of Contents



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.
    
    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;
    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.      
    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.    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.
   27




---



##### Table of Contents



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.
        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.
   28




---



##### Table of Contents



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.
    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 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.
   29




---



##### Table of Contents



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.
    
    high costs, shortages or delivery delays of rigs, equipment,
    labor or other services;
    unexpected operational events
    and/or
    conditions;
    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.     30




---



##### Table of Contents



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.
    
    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.    Any
    acquisitions we complete are subject to substantial risks that
    could reduce our ability to make distributions to
    unitholders.
    
    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.       31




---



##### Table of Contents



Our
    future debt levels may limit our flexibility to obtain
    additional financing and pursue other business
    opportunities.
    
    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;
    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.  and/or
  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.
    
    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.   32




---



##### Table of Contents



2 3
  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.
    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.
     33




---



##### Table of Contents



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.
  2
  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.
     34




---



##### Table of Contents



clean-up clean-up clean-up clean-up
 
 
   
    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.
   35




---



##### Table of Contents



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.
   
  and/or 2
 
  We
    depend on a limited number of key personnel who would be
    difficult to replace.
 
   
  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.
   36




---



##### Table of Contents




    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;
    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 single class. At the closing of this
    offering, our general partner and its affiliates will own
    approximately 32.6% of our outstanding common units and 100% of
    our subordinated units, or 66.3% of all outstanding units,
    assuming the underwriters do not exercise their option to
    purchase additional 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;
    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; 37




---



##### Table of Contents




    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.    Resolute
    Holdings and its affiliates, including Natural Gas Partners and
    its affiliates, are not limited in their ability to compete with
    us.
    and/or
  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.
    
    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 consent to any merger
    or consolidation of the partnership or any amendment to the
    partnership agreement; 38




---



##### Table of Contents




    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,
    willful misconduct or, in the case of a criminal matter, with
    knowledge that the indemnitees conduct was unlawful. 
    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.
    
    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. 39




---



##### Table of Contents



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.
    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 a limited call right that may require you to
    sell your units at an undesirable time or price.
   40




---



##### Table of Contents



Control
    of our general partner may be transferred to a third party
    without unitholder consent. Any new equity owner of a
    controlling interest in our general partner would then be in a
    position to replace the board of directors and officers of our
    general partner with its own choices and to influence the
    decisions made by the board of directors and officers of our
    general partner.
    Holders
    of our common units have limited voting rights and are not
    entitled to elect our general partner or its
    directors.
    Even
    if holders of our common units are dissatisfied, they cannot
    initially remove our general partner without its
    consent.
  2 3
  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.
   41




---



##### Table of Contents



Your
    liability may not be limited if a court finds that unitholder
    action constitutes control of our business.
    
    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.    We
    have a holding company structure in which our subsidiaries
    conduct our operations and own our operating assets. As a
    result, our ability to make distributions to our unitholders
    depends on the performance of our subsidiaries and their ability
    to distribute funds to us, which may be restricted by
    contractual limitations and other legal and regulatory
    limitations.
    Unitholders
    may have liability to repay distributions that were wrongfully
    distributed to them.
  Section 17-607
  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.
   42




---



##### Table of Contents



An
    increase in interest rates and other factors may cause the
    market price of our common units to decline.
    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.
  180-day lock-up lock-up
  You
    will experience immediate and substantial dilution of $15.60 in
    tangible net book value per common unit.
    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.
   43




---



##### Table of Contents




    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.
         44




---



##### Table of Contents



We do
    not have any officers, directors or employees and rely solely on
    officers and directors of our general partner and employees of
    Resolute Holdings. The positions held by these officers and
    directors may give rise to fiduciary obligations that are in
    conflict with fiduciary obligations owed to us. These conflicts
    may not be resolved in our favor. Failure of such officers,
    directors and employees to devote sufficient attention to the
    management and operation of our business may adversely affect
    our financial results and our ability to make distributions to
    our unitholders.
      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.
     45




---



##### Table of Contents



Tax
    Risks to Common Unitholders
    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.
            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.
    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.
   46




---



##### Table of Contents



You
    will be required to pay taxes on your share of our income even
    if you do not receive any cash distributions from
    us.
    Tax
    gain or loss on the disposition of our common units could be
    more or less than expected.
    Tax-exempt
    entities and
    non-U.S.
    persons face unique tax issues from owning our common units that
    may result in adverse tax consequences to them.
  non-U.S. persons non-U.S. persons non-U.S. persons non-U.S. person,
  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.
   47




---



##### Table of Contents



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.
    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.
    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.
      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.
   48




---



##### Table of Contents



Schedule K-1s)
  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.
   49




---



##### Table of Contents



CAUTIONARY
    NOTE REGARDING FORWARD-LOOKING STATEMENTS
    
    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.     50




---



##### Table of Contents



USE
    OF PROCEEDS
    
    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.           51




---



##### Table of Contents



CAPITALIZATION
    
    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.    As of June 30, 2007Historical


Pro Forma(1)(Unaudited)(In thousands)Cash and cash equivalents

$



$
7,500Total long-term debt:Existing revolving credit facility(2)


170,250



Existing term loan facility


225,000



New revolving credit facility(2)






150,975Total


395,250



150,975Net parent investment/partners capital:Net parent investment


(45,008
)


Common unitholders  public






61,171Common unitholders  sponsor






29,659Subordinated units






90,830General partner interest






3,707Total partners equity (deficit)


(45,008
)


185,367Total 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.   52




---



##### Table of Contents



DILUTION
    Assumed initial public offering price per common unit





$
20.00Net 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


6.85Less: Pro forma net tangible book value per unit after the
    offering(2)






4.40Immediate 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.    Units Acquired


Total ConsiderationNumber


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. 53




---



##### Table of Contents



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.
  Definition of Available Cash.
  
    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.    Restrictions and Limitations on Cash
    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 54




---



##### Table of Contents




    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.
    Under
    Section 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. 
  
    Our ability to make distributions to our unitholders depends on
    the performance of our subsidiaries and their ability to
    distribute funds to us. The ability of our subsidiaries to make
    distributions to us may be restricted by, among other things,
    the provisions of existing and future indebtedness, applicable
    state partnership and limited liability company laws and other
    laws and regulations. Please read Risk Factors 
    Risks Inherent in an Investment in Us  We have a
    holding company structure in which our subsidiaries conduct our
    operations and own our operating assets. As a result, our
    ability to make distributions to our unitholders depends on the
    performance of our subsidiaries and their ability to distribute
    funds to us, which may be restricted by contractual limitations
    and other legal and regulatory limitations. 
 55




---



##### Table of Contents




    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
    Minimum Quarterly Distribution Rate
        56




---



##### Table of Contents



No Exercise of the Underwriters Option


Full Exercise of the Underwriters Optionto Purchase Additional Common Units


to Purchase Additional Common UnitsNumber of


Distributions


Number of


DistributionsUnits


One Quarter


Annualized


Units


One Quarter


AnnualizedPublicly held common units


13,750,000


$
4,812,500


$
19,250,000



15,812,500


$
5,534,375


$
22,137,500Common units held by Resolute Holdings


6,651,316



2,327,961



9,311,842



6,651,316



2,327,961



9,311,842Subordinated units held by Resolute Holdings


20,401,316



7,140,461



28,561,842



20,401,316



7,140,461



28,561,842General partner equivalent units


832,707



291,447



1,165,790



874,799



306,180



1,224,718Total


41,635,339


$
14,572,369


$
58,289,474



43,739,931


$
15,308,977


$
61,235,902             
    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 57




---



##### Table of Contents




    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
 
   
 
   
  Schedule K-1
     58




---



##### Table of Contents



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


for thefor the


Twelve MonthsYear Ended


EndedDecember 31,


June 30,2006


2007(In thousands)Net Income (Loss)(1)

$
58,234


$
27,284Interest expense(2)


9,760



9,760Depletion, depreciation and amortization


12,150



14,846Accretion of asset retirement obligation


222



255Non-cash component of change in fair value of derivative
    instruments


(13,291
)


(13,340
)Equity-based compensation expense






31,099Adjusted EBITDA


67,075



69,904Less:Interest expense


9,760



9,760Estimated maintenance capital expenditures(3)


7,408



7,680Incremental general and administrative expenses associated with
    being a public company(4)


3,075



3,075General and administrative expenses allocated to Resolute
    Holdings(5)


(2,323
)


(2,697
)Pro Forma Available Cash

$
49,155


$
52,086Annualized minimum quarterly distribution per unit

$
1.40


$
1.40Pro Forma Cash Distributions:(6)Distributions to public unitholders

$
19,250


$
19,250Distributions to our general partner and its affiliates


39,039



39,039Total distributions


58,289



58,289Shortfall of cash available to pay distributions before
    expansion capital expenditures

$
(9,134
)

$
(6,203
)Expansion capital expenditures(7)


232,480



54,844Borrowings to finance expansion capital expenditures(7)


232,480



54,844Shortfall

$
(9,134
)

$
(6,203
)  
    (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)
    
    Represents our estimate of the annual maintenance capital
    expenditures required to maintain our production over the
    long-term based on our estimated production levels and natural
    decline rates. Because our maintenance capital expenditures can
    be very irregular, the amount of our actual maintenance capital
    expenditures may differ substantially from period to period. 
 59




---



##### Table of Contents



(4)
    
    Reflects incremental general and administrative expenses that 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). 
 
  (5)
    
    Reflects general and administrative expenses that were incurred
    by Resolute Holdings that we believe would not be considered
    reimbursable expenses under the terms of our partnership
    agreement and our administrative services agreement, as such
    expenses were not incurred in conjunction with the provision of
    general and administrative services to us. For the year ended
    December 31, 2006, these expenses totaled
    $2.3 million, which included $1.3 million in
    compensation expense for employee time allocated to projects not
    related to our assets, $630,000 for professional services,
    including legal and audit related services, provided for
    activities of Resolute Holdings not related to our assets, and
    $220,000 for infrastructure costs, including rent and network
    expenses, allocated to Resolute Holdings in connection with its
    activities not related to our assets. For the twelve months
    ended June 30, 2007, general and administrative expenses
    allocated to Resolute Holdings totaled $2.7 million,
    including $1.6 million in compensation expense, $648,000 in
    professional services and $305,000 in infrastructure expenses.
    Resolute Holdings will determine the allocation of general and
    administrative expenses incurred between itself and us pursuant
    to the terms of our administrative services agreement and
    subject to the periodic review and approval of our general
    partner. 
 
  (6)
    
    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. 
 
  (7)
    
    Expansion capital expenditures include all capital expenditures
    incurred by Resolute Holdings during the relevant time period
    and allocated to us less estimated maintenance capital
    expenditures. Expansion capital expenditures include
    expenditures related to acquisitions as well as expenditures
    related to development of our assets. Expansion capital
    expenditures include the following amounts: 
  
 Pro Forma


Pro Formafor the


for theYear Ended


Twelve MonthsDecember 31,


Ended June 30,2006


2007Total capital expenditures of Resolute Holdings


242,388



62,624Less:Capital expenditures related to retained entities


2,356



Notes Receivable  Affiliated entities


144



100Total capital expenditures allocated to the partnership


239,888



62,524Less estimated maintenance capital expenditures


7,408



7,680Total expansion capital expenditures allocated to the partnership


232,480



54,844Expansion capital expenditures allocated to us is composed of
    the following:Acquisition related expansion capital expenditures:ExxonMobil acquisitionPurchase price


208,507



5,692Contingent payments (See Off-Balance Sheet Obligations on
    page 106)


4,000



7,930Total ExxonMobil acquisition


212,507



13,622Petroleum Synergy acquisition


1,487



Total acquisitions


213,994



13,622Escrow account  plugging and abandonment


7,500



1,537Field development


10,986



39,685Total expansion capital expenditures allocated to the partnership


232,480



54,844  
 60




---



##### Table of Contents



Estimated
    Cash Available for Distributions for the Year Ending
    December 31, 2008
           61




---



##### Table of Contents



Resolute
    Energy Partners, LP
    Estimated Cash Available to Pay Distributions
  
 Forecast for theYear EndingDecember 31, 2008(In thousands,except per unitamounts)Oil and gas revenue

$
150,615Operating expenses:Lease operating and workover expense


45,888Production taxes


11,365Total general and administrative expense allocated to the
    partnership(1)(2)


9,836Depletion, depreciation and amortization


17,711Accretion of asset retirement obligation


290Total operating expenses


85,090Operating income (expense)


65,525Other income (expense):Gain (loss) on derivative instruments(3)


2,405Interest expense(4)


(11,917
)Net income

$
56,013Adjustments to reconcile net income to cash available for
    distribution:Add:Interest expense(4)


11,917Depletion, depreciation and amortization


17,711Accretion of asset retirement obligation


290Non-cash component of change in fair value of derivative
    instruments(5)


Equity based compensation expense(2)


2,973Adjusted EBITDA


88,904Less:Interest expense(4)(6)


11,917Estimated maintenance capital expenditures(7)


7,617Cash available for distribution before expansion capital
    expenditures

$
69,370Annualized minimum quarterly distributions per unit

$
1.40Distributions to public common unitholders

$
19,250Distributions to our general partner and its affiliates


39,039Total distributions(6)

$
58,289 
 62




---



##### Table of Contents



Forecast for theYear EndingDecember 31, 2008(In thousands,except per unitamounts)Excess of cash available to pay distributions before expansion
    capital expenditures

$
11,081Expansion capital expenditures(7)

$
48,101Borrowings to finance expansion capital expenditures(7)


37,020Excess cash

$
Calculation of Minimum Estimated Adjusted EBITDA necessary to
    pay cash distributions at the minimum quarterly distribution
    rate:Adjusted EBITDA

$
88,904Excess of cash available for distributions before expansion
    capital expenditures


11,081Minimum Estimated Adjusted EBITDA necessary to pay cash
    distributions at the minimum quarterly distribution rate(7)

$
77,823  
   
  (1)
    
    We calculated the total general and administrative expense
    allocated to us with respect to the forecast period by
    estimating the total amount of general and administrative costs
    expected to be incurred by Resolute Holdings during the forecast
    period based on its historical general and administrative
    expense, adding to that estimate the incremental general and
    administrative expense of $3.1 million that we expect to
    incur to operate as a publicly traded partnership and
    subtracting from that estimate the $3.6 million of general
    and administrative expense of Resolute Holdings that we believe
    will not be allocated by Resolute Holdings and our general
    partner to us. 
 
  (2)
    
    Forecast general and administrative expense includes
    approximately $3.0 million for equity based compensation
    expense allocated to us by Resolute Holdings. This amount
    represents a non-cash charge to compensation expense pursuant to
    FAS 123R associated with equity based compensation anticipated
    to be recognized in 2008. 
 
  (3)
    
    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. 
 
  (4)
    
    Represents interest expense on average debt outstanding of
    $172.5 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%. If the interest
    rate used to calculate the interest on our credit facility
    borrowings were 1% higher or lower, our annual cash interest
    cost would increase or decrease, respectively, by approximately
    $1.8 million. 
 
  (5)
    
    No adjustment for the non-cash component of change in fair value
    of derivative instruments has been reflected because we assumed
    realized oil and gas sales prices for the year ending
    December 31, 2008 remain constant. See
    Assumptions and ConsiderationsOperations and
    RevenuePrices below. As a result, no unrealized gain
    or loss would be recognized during the forecast period because
    the fair value of derivative instruments would remain constant. 
 
  (6)
    
    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 $9.2 million and the
    Minimum Estimated Adjusted EBITDA necessary to pay cash
    distributions at the minimum quarterly distribution rate would
    increase to $78.0 million. 
 
  (7)
    
    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 and $7.6 million 
 63




---



##### Table of Contents



classified as estimated maintenance capital expenditures. The
    $7.6 million of estimated maintenance capital expenditures
    is an estimate of annual maintenance capital expenditures
    required to maintain our production over the long-term based on
    our estimated production levels and natural decline rates.
    Because our maintenance capital expenditures can be very
    irregular, the amount of our actual maintenance capital
    expenditures may differ substantially from period to period. 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. 
 
  (8)
    
    The following table sets forth, on a quarterly basis, how we
    calculate the Minimum Estimated Adjusted EBITDA necessary to pay
    cash distributions at the minimum quarterly distribution rate
    for each of the four quarters in the twelve-month period ending
    December 31, 2008. Our quarterly forecast is based on the
    same assumptions utilized for the preparation of the forecast
    for the twelve-month period ending December 31, 2008. Based
    on such assumptions, we believe that our results for each of the
    four quarters in the twelve-month period ending
    December 31, 2008 will be generally consistent from quarter
    to quarter. 
  
 Three Months Ending During the Year EndingDecember 31, 2008March 31,


June 30,


September 30,


December 31,Oil and gas revenue

$
35,679


$
36,891


$
38,370


$
39,675Operating expenses:Lease operating and workover expenses


11,438



11,456



11,487



11,508Production taxes


2,677



2,778



2,900



3,010Total general and administrative expense allocated to the
    partnership


2,425



2,452



2,479



2,479Depletion, depreciation and amortization


4,185



4,336



4,516



4,674Accretion of asset retirement obligation


73



73



73



73Total operating expenses


20,798



21,095



21,455



21,744Operating income


14,881



15,796



16,915



17,931Other income (expense)Gain (loss) on derivative instruments


593



600



606



606Interest expense


(2,727
)


(2,860
)


(3,052
)


(3,278
)Net income

$
12,747


$
13,536


$
14,469


$
15,259Adjustments to reconcile net income to cash available for
    distributions:Add:Depletion, depreciation and amortization


4,185



4,336



4,516



4,674Accretion of asset retirement obligation


73



73



73



73Equity based compensation expense


743



743



743



743Non-cash component of change in fair value of derivative
    instruments














Interest expense


2,727



2,860



3,052



3,278Adjusted EBITDA


20,475



21,548



22,853



24,027Less:Interest expense


2,727



2,860



3,052



3,278Estimated maintenance capital expenditures


1,800



1,865



1,942



2,010Cash available for distribution before expansion capital
    expenditures

$
15,948


$
16,823


$
17,859


$
18,739Distributions per unit

$
0.35


$
0.35


$
0.35


$
0.35Distributions to public common unitholders

$
4,812


$
4,812


$
4,812


$
4,812Distributions to our general partner and its affiliates


9,760



9,760



9,760



9,760Total distributions

$
14,572


$
14,572


$
14,572


$
14,572 
 64




---



##### Table of Contents



Three Months Ending During the Year EndingDecember 31, 2008March 31,


June 30,


September 30,


December 31,Excess of cash available to pay distributions before expansion
    capital expenditures

$
1,376


$
2,251


$
3,287


$
4,167Expansion capital expenditures

$
7,556


$
7,750


$
15,662


$
17,134Borrowings to finance expansion capital expenditures


6,180



5,499



12,375



12,967Excess cash

$



$



$



$
Calculation of Minimum Estimated Adjusted EBITDA necessary to
    pay cash distributions at the minimum quarterly distribution
    rate:Adjusted EBITDA

$
20,475


$
21,548


$
22,853


$
24,027Excess of cash available to pay distributions before expansion
    capital expenditures


1,376



2,251



3,287



4,167Minimum Estimated Adjusted EBITDA necessary to pay cash
    distributions at the minimum quarterly distribution rate

$
19,099


$
19,297


$
19,566


$
19,860  
  Assumptions
    and Considerations
     65




---



##### Table of Contents



Operations
    and Revenue
  Production.
  Pro Formafor the


ForecastTwelve Months


for theEnded


Year EndingJune 30,


December 31,2007


2008Annual production:Oil (MBbl)


1,955



2,239Gas (MMcf)


238



323Natural gas liquids (MBbl)


116



Total (MBoe)


2,111



2,293Average daily production:Oil (Bbl/d)


5,355



6,134Gas (Mcf/d)


651



884Natural gas liquids (Bbl/d)


317



Total (Boe/d)


5,781



6,281  
   
   66




---



##### Table of Contents



Prices.
  Pro Formafor the


ForecastTwelve Months


for theEnded


Year EndingJune 30,


December 31,2007


2008Average oil sales prices (dollars per Bbl):NYMEX oil price

$
63.84


$
68.50Realized oil sales price (excluding cash settlements of
    derivatives)


61.43



66.09Differential to NYMEX


(2.41
)


(2.41
)Realized oil sales price (including cash settlements of
    derivatives)

$
60.50


$
67.17Average gas sales prices (dollars per unit of measure):NYMEX gas price per MMBtu

$
6.70


$
7.73Differential to NYMEX gas


3.94



0.43Realized gas sales price per Mcf

$
10.64


$
8.16  
   
  Use of Derivative Financial
    Instruments.
  SwapsWeightedMBbl

Average PriceJanuary 2008  December 2008


1,259


$
70.41Percentage of estimated crude oil production


56.2
%    67




---



##### Table of Contents



Operating Revenues.
  
 Pro Formafor the


ForecastTwelve Months


for theEnded


Year EndingJune 30,


December 31,2007


2008Oil revenues

$
119,557


$
147,983Gas and natural gas liquids revenues

$
5,503


$
2,632Total oil and gas revenue

$
125,060


$
150,615Gain (loss) on derivative instruments


2,583



2,405Total operating revenue


127,643



153,020  
  Capital
    Expenditures and Expenses.
 
  Capital Expenditures.
 
  2 2 2
 
  non-producing
 
 68




---



##### Table of Contents



Oil and Gas Production Costs.
  
 Pro Formafor the


ForecastTwelve Months


for theEnded


Year EndingJune 30,


December 31,2007


2008Production expenses:Lease operating expense

$
25,486


$
26,535Workover expense


14,575



11,689Possessory interest and ad valorem taxes


6,473



7,664Total production expenses

$
46,534


$
45,888Production expenses (per Boe)

$
22.16


$
20.01  
 
  2
 
  Production Taxes.
  
 Pro Formafor the


ForecastTwelve Months


for theEnded


Year EndingJune 30,


December 31,2007


2008Oil and gas revenue, excluding the effect of our derivative
    financial instruments

$
125,060


$
150,615Weighted average production tax rate


7.42
%


7.55
%Production taxes

$
9,280


$
11,365  
   
  General and Administrative Expenses. non-cash
 
 69




---



##### Table of Contents



Schedule K-1
 
 
   
 
  Interest Expense.
 
   
   
  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; 70




---



##### Table of Contents




    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.
  Sensitivity
    Analysis
   71




---



##### Table of Contents



Production Volume Changes.
  
 Percentage of forecast net production90%


100%


110%Oil and gas revenue

$
135,553


$
150,615


$
165,677Operating ExpensesLease operating and workover expense


45,821



45,888



45,956Production taxes


10,228



11,365



12,501Total general and administrative expense allocated to the
    partnership


9,836



9,836



9,836Depletion, depreciation and amortization


15,940



17,711



19,482Accretion of asset retirement obligation


290



290



290Total operating expenses


82,115



85,090



88,065Operating Income


53,438



65,525



77,612Other income (expense)Gain (loss) derivative instruments


2,405



2,405



2,405Interest expense


(12,412
)


(11,917
)


(11,422
)Net Income

$
43,431


$
56,013


$
68,595Adjustments to reconcile net income to cash available for
    distributionsAdd:Interest Expense

$
12,412


$
11,917


$
11,422Depletion, depreciation and amortization


15,940



17,711



19,482Accretion of asset retirement obligation


290



290



290Non-cash component of change in fair value of derivative
    instruments










Equity based compensation expense


2,973



2,973



2,973Adjusted EBITDA


75,046



88,904



102,762Less:Interest expense


12,412



11,917



11,422Estimated maintenance capital expenditures


7,617



7,617



7,617Cash available for distribution before expansion capital
    expenditures


55,017



69,370



83,723Distributions per unit


1.40



1.40



1.40Distributions to public common unitholders


19,250



19,250



19,250Distributions to Resolute Holdings


39,039



39,039



39,039Total distributions


58,289



58,289



58,289Excess cash available to pay distributions before expansion
    capital expenditures


(3,272
)


11,081



25,434Expansion capital expenditures


48,101



48,101



48,101Borrowings to finance expansion capital expenditures


51,374



37,020



22,667Excess cash

$



$



$
  
 72




---



##### Table of Contents



Commodity Price Changes.
  
 NYMEX oil ($/Bbl)

$
55.00


$
60.00


$
68.50


$
70.00


$
75.00NYMEX gas ($/MMBtu)

$
6.00


$
6.50


$
7.73


$
8.00


$
8.50Oil and gas revenue


119,599



131,022



150,615



154,096



165,519Operating expensesLease operating and workover expense


45,888



45,888



45,888



45,888



45,888Production taxes


9,025



9,887



11,365



11,627



12,490Total general and administrative expense allocated to the
    partnership


9,836



9,836



9,836



9,836



9,836Depeletion, depreciation and amortization


17,711



17,711



17,711



17,711



17,711Accretion of asset retirement obligation


290



290



290



290



290Total operating expenses


82,750



83,612



85,090



85,352



86,215Operating Income


36,849



47,410



65,525



68,744



79,304Other income (expense)Gain (loss) derivative instruments


19,405



13,109



2,405



516



(5,780
)Interest expense


(12,256
)


(12,133
)


(11,917
)


(11,878
)


(11,755
)Net Income


43,998



48,386



56,013



57,382



61,769Adjustments to reconcile net income to cash available for
    distributionsAdd:Interest expense


12,256



12,133



11,917



11,878



11,755Depeletion, depreciation and amortization


17,711



17,711



17,711



17,711



17,711Accretion of asset retirement obligation


290



290



290



290



290Non-cash component of change in fair value of derivative
    instruments


















Equity based compensation expense


2,973



2,973



2,973



2,973



2,973Adjusted EBITDA


77,228



81,493



88,904



90,234



94,498Less:Interest expense


12,256



12,133



11,917



11,878



11,755Estimated maintenance capital expenditures


7,617



7,617



7,617



7,617



7,617Cash available for distribution before expansion capital
    expenditures


57,355



61,743



69,370



70,739



75,126Annualized mimimum quarterly distributions per unit


1.40



1.40



1.40



1.40



1.40Distributions to public common unitholders


19,250



19,250



19,250



19,250



19,250Distributions to Resolute Holdings


39,039



39,039



39,039



39,039



39,039Total distributions


58,289



58,289



58,289



58,289



58,289Excess cash available to pay distributions before expansion
    capital expenditures


(934
)


3,454



11,080



12,450



16,837Expansion capital expenditures


46,200



46,904



48,101



48,313



49,017Borrowings to finance expansion capital expenditures


47,134



43,450



37,021



35,863



32,180Excess cash


















  
   73




---



##### Table of Contents



2 2
 74




---



##### Table of Contents



PROVISIONS
    OF OUR PARTNERSHIP
    AGREEMENT RELATING TO CASH DISTRIBUTIONS
    Distributions
    of Available Cash
  General.
  Available Cash.
  
    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.    Intent to Distribute the Minimum Quarterly
    Distribution.
  General Partner Interest.
  Incentive Distribution Rights.
 75




---



##### Table of Contents



Operating
    Surplus and Capital Surplus
  General.
  Operating Surplus.
  
    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 acquisition 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 asset and ending on the earlier to occur of the date the
    capital asset is placed into service (or, with respect to
    non-producing reserves, the date the reserves begin producing
    hydrocarbons in commercial quantities) 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.         76




---



##### Table of Contents



Operating Expenditures.
  
    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.
 77




---



##### Table of Contents



Estimated Maintenance Capital
    Expenditures.
    
    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.
    Capital Surplus.
  
    borrowings that are not working capital borrowings; 78




---



##### Table of Contents




    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.
  Subordination
    Period
  General.
  Subordination Period.
  
    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.
  
    the subordination period will end and each subordinated unit
    will immediately convert into one common unit; 79




---



##### Table of Contents




    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.
    
    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.
  
    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);
    less
    any net increase in working capital borrowings with respect to
    that period; less
    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 increase in cash reserves for operating expenditures
    with respect to that period required by any debt instrument for
    the repayment of principal, interest or premium.    Distributions
    of Available Cash from Operating Surplus During the
    Subordination Period
    
    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; 80




---



##### Table of Contents




    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. 
 
   
 
  Distributions
    of Available Cash from Operating Surplus After the Subordination
    Period
 
    
    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. 
   
  General
    Partner Interest and Incentive Distribution Rights
          
    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; 81




---



##### Table of Contents




    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.  Percentage
    Allocations of Available Cash from Operating Surplus
    Marginal PercentageTotal Quarterly Distribution Per Unit

Interest in DistributionsTarget Amount

Unitholders


General PartnerMinimum 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.
  
    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. 82




---



##### Table of Contents



Effect of a Distribution from Capital
    Surplus.
 
    Adjustment
    to the Minimum Quarterly Distribution and Target Distribution
    Levels
    
    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.     
  Distributions
    of Cash Upon Liquidation
 
  General.
   83




---



##### Table of Contents



Maintenance of Capital Accounts.
  Manner of Adjustments for Gain.
  
    first, to the general partner and the holders of units
    who have negative balances in their capital accounts to the
    extent of and in proportion to those negative balances;
    second, 98% to the common unitholders, pro rata, and 2%
    to the general partner, until the capital account for each
    common unit is equal to the sum of: (1) the unrecovered
    initial unit price; (2) the amount of the minimum quarterly
    distribution for the quarter during which our liquidation
    occurs; and (3) any unpaid arrearages in payment of the
    minimum quarterly distribution;
    third,98% to the subordinated unitholders, pro rata, and
    2% to the general partner until the capital account for each
    subordinated unit is equal to the sum of: (1) the
    unrecovered initial unit price; and (2) the amount of the
    minimum quarterly distribution for the quarter during which our
    liquidation occurs;
    fourth, 98% to all unitholders, pro rata, and 2% to the
    general partner, until we allocate under this paragraph an
    amount per unit equal to: (1) the sum of the excess of the
    first target distribution per unit over the minimum quarterly
    distribution per unit for each quarter of our existence; less
    (2) the cumulative amount per unit of any distributions of
    available cash from operating surplus in excess of the minimum
    quarterly distribution per unit that we distributed 98% to the
    unitholders, pro rata, and 2% to the general partner, for each
    quarter of our existence;
    fifth, 85% to all unitholders, pro rata, and 15% to the
    general partner, until we allocate under this paragraph an
    amount per unit equal to: (1) the sum of the excess of the
    second target distribution per unit over the first target
    distribution per unit for each quarter of our existence; less
    (2) the cumulative amount per unit of any distributions of
    available cash from operating surplus in excess of the first
    target distribution per unit that we distributed 85% to the
    unitholders, pro rata, and 15% to the general partner for each
    quarter of our existence;
    sixth, 75% to all unitholders, pro rata, and 25% to the
    general partner, until we allocate under this paragraph an
    amount per unit equal to: (1) the sum of the excess of the
    third target distribution per unit over the second target
    distribution per unit for each quarter of our existence; less
    (2) the cumulative amount per unit of any distributions of
    available cash from operating surplus in excess of the second
    target distribution per unit that we distributed 75% to the
    unitholders, pro rata, and 25% to the general partner for each
    quarter of our existence; and 84




---



##### Table of Contents




    thereafter, 50% to all unitholders, pro rata, and 50% to
    the general partner.      Manner of Adjustments for Losses.
  
    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.    Adjustments to Capital Accounts.
 85




---



##### Table of Contents



SELECTED
    HISTORICAL AND PRO FORMA FINANCIAL DATA
      
    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. 
   
    
    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 to Resolute Holdings of
    $7.5 million of working capital, consisting of cash or
    accounts receivable; 
  
    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; 86




---



##### Table of Contents




    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.     Pro FormaResolute EnergyResolute Energy Partners Predecessor


Partners, LPChevron Properties


January 22,Eleven Months


2004

















Six MonthsYear Ended


Ended


(Inception) to


Year Ended


Six Months Ended


Year Ended


EndedDecember 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


$
57,646Gas(3)


389



257



(179
)


681



836



331



242



851



242Other










101



2,094



3,735



1,350



2,371



4,516



2,371Total revenues


25,267



27,627



2,390



41,973



106,571



41,771



60,259



125,534



60,259Operating expenses:Lease operating(4)


7,570



6,526



658



8,734



24,857



9,405



16,507



27,181



16,507Workover










21



3,860



13,312



4,437



5,700



14,351



5,700Production taxes


2,813



2,972



340



2,772



7,806



3,062



4,536



9,279



4,536General and administrative(4)










2,415



3,281



6,015



2,172



34,617



5,613



32,960Depletion, depreciation, and amortization










407



4,680



11,071



4,140



7,915



12,150



7,641Accretion of asset retirement obligations










20



216



206



95



145



222



145Total operating expenses


10,383



9,498



3,861



23,543



63,267



23,311



69,420



68,796



67,489Operating 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



216Gain (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
) 87




---



##### Table of Contents



Pro FormaResolute EnergyResolute Energy Partners Predecessor


Partners, LPChevron Properties


January 22,Eleven Months


2004

















Six MonthsYear Ended


Ended


(Inception) to


Year Ended


Six Months Ended


Year Ended


EndedDecember 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


$
34,212Balance 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







425,331Long-term debt










44,000



45,925



267,500



271,350



395,250







150,975Shareholders/members/partners equity
    (deficit)(5)










44,997



28,698



61,860



15,163



(45,008
)






185,367Cash Flow Data:Net cash provided by (used in):Operating activities









$
(2,225
)

$
11,516


$
31,756


$
5,296


$
16,694Investing 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 at
    F-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. 88




---



##### Table of Contents



MANAGEMENTS
    DISCUSSION AND ANALYSIS OF
 FINANCIAL CONDITION AND RESULTS OF OPERATIONS
  The historical financial statements included in this
    prospectus beginning on
    page 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. 2
      2
 89




---



##### Table of Contents



Our Acquisitions.
  Chevron Properties.
  ExxonMobil Properties. 2
  Our Financial Statements.
   90




---



##### Table of Contents



start-up
  Our Customer.
        How
    We Evaluate Our Operations
   91




---



##### Table of Contents



Production Levels, Trends and
    Prices.
        Reserve Volumes and Trends. 2 2
  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 92




---



##### Table of Contents



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.  Schedule K-1
  Operating Cash Flow.
  Adjusted EBITDA.
    
    assess the ability of our assets to generate cash sufficient to
    pay interest costs;
    support our indebtedness; 93




---



##### Table of Contents




    make cash distributions to our unitholders and general
    partner; and
    finance capital expenditures.      
    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. 
   
 
  Factors
    That Significantly Affect Our Results
 
     94




---



##### Table of Contents




    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.
    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 95




---



##### Table of Contents



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 and
    Schedule 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
    Resolute Energy Partners PredecessorJanuary 22,2004(Inception) to


Year Ended


Six Months EndedDecember 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


$
57,646Gas


(179
)


681



836



331



242Natural gas liquids


20



1,121



3,008



1,002



1,860Other


81



973



727



348



511Total revenues


2,390



41,973



106,571



41,771



60,259Operating expenses:Production:Lease operating


658



8,734



24,857



9,405



16,507Workover


21



3,860



13,312



4,437



5,700Production taxes


340



2,772



7,806



3,062



4,536General and administrative


2,415



3,281



6,015



2,172



34,617Depletion, depreciation, and amortization


407



4,680



11,071



4,140



7,915Accretion of asset retirement obligations


20



216



206



95



145Total operating expenses


3,861



23,543



63,267



23,311



69,420Operating income (loss)


(1,471
)


18,430



43,304



18,460



(9,161
)Other income (expense):Other income


51



147



546



262



266Gain (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
)   96




---



##### Table of Contents



Resolute Energy Partners PredecessorJanuary 22,2004(Inception) to


Year Ended


Six Months EndedDecember 31,


December 31,


June 30,2004(1)


2005


2006(2)


2006(2)


2007Production Sales Data:Oil (MBbl)


60



720



1,588



606



973Gas (MMcf)


(11
)


136



227



81



92Natural gas liquids (MBbl)


1



56



91



33



58Combined volumes (MBoe)


59



799



1,717



653



1,046Daily combined volumes (Boe/d)


1,922



2,189



4,704



3,608



5,779Average Realized Prices (including hedges):Oil ($/Bbl)

$
44.62


$
46.53


$
62.72


$
61.80


$
61.64Gas ($/Mcf)






5.01



3.68



4.09



2.63Average Costs ($/Boe):Lease operating expense

$
11.15


$
10.93


$
14.48


$
14.40


$
15.78Production tax expense


5.76



3.47



4.55



4.69



4.34Depletion, depreciation and amortization


6.90



5.86



6.45



6.34



7.57General 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 the Six Months
    Ended June 30, 2006
 
    Revenue.
 PercentageSix Months Ended June 30,


Increase2006


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
%)  
   
 97




---



##### Table of Contents



Operating Expenses.
 
 
   
 PercentageSix Months Ended June 30,


Increase2006


2007


(Decrease)Production expenses per Boe

$
25.89


$
25.57



(1.2
%)  
   
 PercentageSix Months Ended June 30,


Increase2006


2007


(Decrease)General and administrative expenses per Boe

$
3.33


$
33.09



894
%  
   
  Other Income (Expense).
 98




---



##### Table of Contents



Year
    Ended December 31, 2006, Compared to the Year Ended
    December 31, 2005
  Revenue.
  PercentageYear Ended December 31,


Increase2005


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
%  
   
  Operating Expenses.
  PercentageYear Ended December 31,


Increase2005


2006


(Decrease)Production expenses per Boe

$
19.23


$
26.78



39
%  99




---



##### Table of Contents



PercentageYear Ended December 31,


Increase2005


2006


(Decrease)General and administrative expenses per Boe

$
4.11


$
3.50



(15
%)    
   
  Other Income (Expense).
 
   
  Year
    Ended December 31, 2005, Compared to the Period from
    January 22, 2004 (Inception) to December 31,
    2004
  Revenue.
  January 22, 2004(Inception) to


Year Ended


PercentageDecember 31,


December 31,


Increase2004


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. 100




---



##### Table of Contents



Operating Expenses. per-unit per-unit
 
  January 22, 2004(Inception) to


Year Ended


PercentageDecember 31,


December 31,


Increase2004


2005


(Decrease)Production expenses per Boe

$
17.27


$
19.23



11.4
%     January 22, 2004(Inception) to


Year Ended


PercentageDecember 31,


December 31,


Increase2004


2005


(Decrease)General and administrative expenses per Boe

$
40.93


$
4.11



(90
%)    
   
  Other Income (Expense).
 101




---



##### Table of Contents



Liquidity
    and Capital Resources
       
   
  and/or
 
   
 102




---



##### Table of Contents



Cash Flows.
  Resolute Energy Partners PredecessorJanuary 22, 2004(Inception) to


Year Ended


Six Months EndedDecember 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


$
16,694Investing 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.
 
 
   
  2
 
   
 
  Investing Activities. 2
 
 
   
   103




---



##### Table of Contents



Financing Activities.
          Revolving
    Credit Facility
   104




---



##### Table of Contents




    maintain a consolidated current ratio of at least
    [     ] to
    [     ] at the end of any fiscal
    quarter; 
 
  
    not permit our ratio of consolidated indebtedness to
    consolidated Adjusted EBITDA to be greater than
    [     ] to
    [     ] at the end of each fiscal
    quarter; and 
 
  
    not permit our interest coverage ratio to be less than
    [     ] to
    [     ] at the end of each fiscal
    quarter. 
 
   
  Contractual
    Obligations
      
 Payments Due By Year (in $ millions)2007


2008


2009


2010


2011


After 2011


TotalNew revolving credit facility(1)






10.7



10.7



10.7



10.7



152.7



195.5ExxonMobil escrow agreement






1.4



1.4



1.3



1.2



5.1



10.4Asset retirement obligations(2)


1.0



0.8



0.1



0.1



0.1



5.6



7.7CO2
    purchases(3)


5.7



15.4



26.1



17.6



13.4



25.7



103.9Total


6.7



28.3



38.3



29.7



25.4



189.1



317.5  
 105




---



##### Table of Contents



(1)
    
    Calculation of obligations under the new revolving credit
    facility assumes total outstanding borrowings of
    $152.7 million, a LIBOR rate of 5.5% and a borrowing spread
    of 1.5%, resulting in a total interest rate of 7%. Assuming no
    change in outstanding borrowings under our new revolving credit
    facility, this results in annual interest expense of
    $10.7 million. Similar to our existing revolving credit
    facility, we expect the term of our new revolving credit
    facility to be five years.(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
    Critical
    Accounting Policies and Estimates
  F-18
  Oil and Gas Properties.
 106




---



##### Table of Contents



Oil and Gas Reserve Quantities. well-by-well
     107




---



##### Table of Contents



Derivative Instruments and Hedging
    Activities.
        Asset Retirement
    Obligations.
  Equity-Based Compensation.
 108




---



##### Table of Contents



Accounting for Stock Issued to
    Employees
    Recent
    Accounting Pronouncements
  Accounting for
    Uncertainty in Income Taxes
  Fair Value
    Measurements
  The Fair Value Option for Financial Assets and
    Financial Liabilities
  Quantitative
    and Qualitative Disclosures About Market Risk
    Commodity Price Risk and Hedging
    Arrangements.
   109




---



##### Table of Contents



2
        Interest Rate Risks.
 110




---



##### Table of Contents



BUSINESS
  2
    
 Estimated Net Proved Reservesas of June 30, 2007(MMBoe)





Oil Reserves to Oil Production Ratio (in years)Proved














Average





ProvedProved


Developed














Net Daily





DevelopedDeveloped


Non-


Proved Undeveloped


Total


Production


Proved


ProducingProducing


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



17McElmo Creek Unit


13.8



0.1



7.6



0.6



8.2



22.1



2,481



25



15Ratherford Unit


5.9



4.5



11.6



0.6



12.2



22.6



1,689



42



9Total


29.4



4.7



40.9



3.1



44.0



78.1



5,878



39



15Future operating costs ($/Boe)(4)

$
25.16


$
17.87


$
7.63


$
5.90


$
7.51


$
14.78Future production taxes ($/Boe)(5)

$
8.43


$
8.64


$
9.28


$
8.94


$
9.25


$
8.91Future PUD development costs (in millions)(6)









$
209.1


$
50.4


$
259.5Future PUD development costs ($/Boe)(7)









$
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)
    
    Determined by dividing our estimated future operating costs as
    of June 30, 2007, by total estimated net proved reserves as
    of June 30, 2007, for each reserve category. 
 
  (5)
    
    Determined by dividing our estimated future production taxes as
    of June 30, 2007, by total estimated net proved reserves as
    of June 30, 2007, for each reserve category. 
 111




---



##### Table of Contents



(6)
    
    Future development costs include costs incurred in connection
    with 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. 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. 
 
  (7)
    
    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. 
  Greater
    Aneth Field
    2
    
     112




---



##### Table of Contents



Aneth Unit. 80-acre 40-acre 2 2 2 2
 
  McElmo Creek Unit. 40-acre 2 2 2 2
 
  Ratherford Unit.
  Our
    Business Strategies
    Bring Currently Proved Undeveloped Reserves into
    Production.
 113




---



##### Table of Contents



2 2 2 2 2 2 2
 
  Increase Production and Improve Efficiency of Operations
    on our Existing Properties. 3-D
  Reduce Commodity Price Risk through
    Hedging.
 
  Maintain a Disciplined Financial
    Policy.
 
  Pursue Acquisitions of Mature Properties with Low-Risk
    Development Potential.
 114




---



##### Table of Contents



Our
    Competitive Strengths
    A High Quality Base of Long-Lived Oil Producing
    Properties.
  
    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. 2 2 2 2 newly-drilled 2 2 2 2
 
 
  Operating Control Over Our
    Properties.
 
 115




---



##### Table of Contents



Experienced Management Team with Operational,
    Transactional and Financial Experience in the Energy
    Industry.
  Our Relationship with Natural Gas
    Partners.
  Oil
    Recovery Overview
      2
  2 2 2
 116




---



##### Table of Contents



2 2
  2
  
  2 2 Oil & Gas Journals 2 2 2 2
  Recent
    Development and Operating Activity
   117




---



##### Table of Contents



3-D
  Planned
    Operating and Development Activities
  2
  CO2
    Floods. 2 2 2
 
  2 2 2 2 2 2 2 2 2 2
 
  Aneth Unit. 2 2 2 2 2 2 2
  McElmo Creek Unit. 2 2
 118




---



##### Table of Contents



2 2
  Ratherford Unit. 2 2
  2 2 2 2 2
  Estimated





EstimatedEstimated


Estimated


Future


Estimated


FutureFuture Capital


Future


Total Capital


Reserves


DevelopmentExpenditures


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


$
4.96Aneth Unit  Phase 3


11.9



9.2



21.1



3.4



6.21Aneth Unit  Phase 4


24.6



31.7



56.3



10.3



5.47McElmo Creek Unit


8.4



10.4



18.8



7.6



2.47Ratherford Unit


35.6



37.6



73.2



11.6



6.31Total

$
98.6


$
110.5


$
209.1



40.9


$
5.11   2 2
 
  2 2 2 2 2 2 make-up 2 2 2
 
 119




---



##### Table of Contents



2 2 2 2 2
  2 2 2
  make-up 2
  2 2
  Other Planned Activities.
 120




---



##### Table of Contents



Estimated
    Net Proved Reserves
      
    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.    lease-by-lease, field-by-field area-by-area
 121




---



##### Table of Contents



As of December 31,


As of June 30,2004


2005


2006(1)


2007Estimated net proved reserves:Oil (MBbl)


17,827



23,500



78,357



77,792Gas (MMcf)


2,404



3,750



1,890



1,630Total (MBoe)


18,228



24,125



78,672



78,064Proved 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 and FASB 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


2007Oil ($/Bbl)

$
43.45


$
61.06


$
61.05


$
70.68Gas ($/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 FASB (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.       122




---



##### Table of Contents



F-35
  Production
    and Price History
    
 Pro FormaResolute EnergyResolute Energy Partners Predecessor


Partners, LPChevron Properties


January 22,Eleven Months


2004

















Six MonthsEnded


(Inception) to








Six Months Ended


Year Ended


EndedNovember 30,


December 31,


Year Ended December 31,


June 30,


December 31,


June 30,2004


2004(1)


2005


2006(2)


2006(2)


2007


2006(3)


2007Production Sales Data:Oil (MBbl)


731



60



720



1,588



606



973



1,881



973Gas (MMcf)(4)


470



(11
)


136



227



81



92



259



92Natural gas liquids (MBbl)






1



56



91



33



58



111



58Equivalent volumes (MBoe)


810



59



799



1,717



653



1,046



2,035



1,046Daily equivalent volumes (Boe/d)


2,425



1,922



2,189



4,704



3,608



5,779



5,575



5,779Average Realized Prices(5):Oil ($/Bbl)

$
37.44


$
44.62


$
46.53


$
62.72


$
61.80


$
61.64


$
62.48


$
61.64Gas ($/Mcf)


5.47







5.01



3.68



4.09



2.63



3.29



2.63Natural gas liquids ($/Bbl)






20.00



20.02



33.05



30.36



32.07



32.77



32.07Other Operating Data:Lease operating expenses ($/Boe)

$
8.06


$
11.15


$
10.93


$
14.48


$
14.40


$
15.78


$
13.36


$
15.78Workover expenses ($/Boe)






0.36



4.83



7.75



6.79



5.45



7.05



5.45Production 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 123




---



##### Table of Contents



recognizing gas production of (11) MMcf during the period
    January 22, 2004 (Inception) to December 31, 2004.(5)
    
    Prices presented are average realized prices we received during
    the respective periods.  Productive
    Wells
    WellsUnit

Gross


NetAneth Unit


163



101McElmo Creek Unit


138



104Ratherford Unit


101



60Total


402



265   Acreage
    Developed Acreage(1)Net RevenueUnit

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
   124




---



##### Table of Contents



Relationship
    with the Navajo Nation
      
    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 our
    3-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.   125




---



##### Table of Contents



Aneth


McElmo Creek


RatherfordUnit


Unit


UnitChevron 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
   
   
 
   
 126




---



##### Table of Contents



Aneth
    Gas Processing Plant
      clean-up clean-up
 127




---



##### Table of Contents



clean-up. clean-up clean-up
  clean-up
  Title
    to Properties
    Competition
    Seasonality
   128




---



##### Table of Contents



Environmental
    and Safety Matters and Regulation
  General.
  
    require the acquisition of various permits before drilling
    commences or other operations are undertaken;
    require the installation of expensive pollution control
    equipment;
    restrict the types, quantities and concentration of various
    substances that can be released into the environment in
    connection with 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 Assessment
    and/or an
    Environmental Impact Statement.          Comprehensive Environmental Response, Compensation, and
    Liability Act.
 129




---



##### Table of Contents



Waste Handling.
    Air Emissions.
      Water Discharges.
   130




---



##### Table of Contents



P-20 well
  Underground Injection Control.
  Pipeline Integrity, Safety, and
    Maintenance.
 131




---



##### Table of Contents



Environmental Impact
    Assessments.
  Other Laws and Regulations. and/or Massachusetts, et al. v. EPA e.g. Massachusetts
    Occupational Safety and Health Act.
  Laws
    and Regulations Pertaining to Oil and Gas Operations on Navajo
    Nation Lands
  General.
 132




---



##### Table of Contents



The Federal
    Trust Responsibility.
  Tribal Sovereignty and Dependent
    Status.
          Federal Approvals of Certain Transactions Regarding Tribal
    Lands.
   133




---



##### Table of Contents



Federal Management and
    Oversight. 2
  Resources Committee of the Navajo Nation
    Council.
  Navajo Nation Minerals Department of the Division of
    Natural Resources.
  Taxation Within 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 84% of the Aneth Unit is subject to the Navajo
    Nation severance tax. The other 16% 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 134




---



##### Table of Contents



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.
  Navajo Preference in Employment
    Act.
  Navajo Business Opportunity Act.
  Navajo Environmental Laws.
  Thirty-Two Point Agreement.
  Moratorium on Future Oil and Gas Development Agreements
    and Exploration.
 135




---



##### Table of Contents



Other
    Regulation of the Oil and Gas Industry
    Drilling and Production.
  
    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.    Gas Sales and
    Transportation.
   136




---



##### Table of Contents



Legal
    Proceedings
    Employees
      Offices
   137




---



##### Table of Contents



MANAGEMENT
  Management
    of Resolute Energy Partners, LP
          
    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.   138




---



##### Table of Contents



Directors
    and Executive Officers
    
 Name

Age

Position with our general partnerNicholas J. Sutton


63


Chief Executive Officer and DirectorJames M. Piccone


57


President, General Counsel, Secretary and DirectorRichard F. Betz


45


Vice President, Business DevelopmentDale E. Cantwell


52


Vice President, OperationsTheodore Gazulis


53


Vice President and Chief Financial OfficerJames L. Kincaid, Jr.


42


Vice President, Marketing and TradingJanet W. Pasque


49


Vice President, LandKenneth A. Hersh


44


DirectorRichard L. Covington


49


Director  
 
   
  Nicholas J. Sutton
 139




---



##### Table of Contents



James M. Piccone
  Richard F. Betz
  Dale E. Cantwell
 
 
 
  Theodore Gazulis privately-held
 
 
  James L. Kincaid, Jr.
 
  Janet W. Pasque
 140




---



##### Table of Contents



Kenneth A. Hersh
  Richard L. Covington
  Reimbursement
    of Expenses of Our General Partner
    Executive
    Compensation
    Compensation
    of Directors
   141




---



##### Table of Contents



Compensation
    Discussion and Analysis
            Long-Term
    Incentive Plan
  General.
 142




---



##### Table of Contents



Awards
  Restricted Units and Phantom Units.
    and/or and/or
    Unit Options.
 143




---



##### Table of Contents



Unit Appreciation Rights.
     144




---



##### Table of Contents



Unit Awards.
  Other Unit-Based Awards.
  Substitution Awards.
  Substitution of Equity Appreciation
    Rights.
  Other
    Provisions
  Termination and Amendment of the
    Plan.
  Tax Withholding.
  Anti-Dilution Adjustments.
 145




---



##### Table of Contents



U.S. Federal Income Tax Consequences of Awards Under the
    Plan. and/or and/or
   146




---



##### Table of Contents



SECURITY
    OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
    
    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


PercentageCommon


of Common


Subordinated


Subordinated


of TotalUnits to be


Units to be


Units to be


Units to be


Units to beBeneficially


Beneficially


Beneficially


Beneficially


BeneficiallyName of Beneficial Owner(1)

Owned(2)


Owned


Owned


Owned


OwnedResolute 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. 147




---



##### Table of Contents



CERTAIN
    RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
    Distributions
    and Payments to Our General Partner and its Affiliates
    Formation
    Stage
 
  The consideration received by our general partner and its
    affiliates for the contribution of the assets and liabilities to
    us
    
     Resolute Aneth will distribute to Resolute Holdings
    $7.5 million of working capital, consisting of cash or
    accounts receivable; 
   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  Administrative Services Agreement 
    Reimbursement of General and Administrative Expenses. 
 148




---



##### Table of Contents



Withdrawal or removal of our general partner
    
    If our general partner withdraws or is removed, its general
    partner interest and its incentive distribution rights will
    either be sold to the new general partner for cash or converted
    into common units, in each case for an amount equal to the fair
    market value of those interests. Please read The
    Partnership Agreement  Withdrawal or Removal of the
    General Partner.  Liquidation Stage
  Liquidation
    
    Upon our liquidation, the partners, including our general
    partner, will be entitled to receive liquidating distributions
    according to their respective capital account balances.  Agreements
    Governing the Transactions
    Administrative
    Services Agreement
    
    our obligation to reimburse Resolute Holdings for all expenses
    incurred by Resolute Holdings (or payments made on our behalf)
    in conjunction with its provision of general and administrative
    services to us, including, but not limited to, our public
    company expenses and an allocated portion of the salary and
    benefits of the executive officers of our general partner and
    other employees of Resolute Holdings who perform services for us
    or on our behalf;
    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 for the officers and directors of our general
    partner; and
    our obligation to indemnify Resolute Holdings for certain
    liabilities.      Reimbursement of General and Administrative
    Expenses.
 149




---



##### Table of Contents



Contribution
    Agreement
 
 
   
  Competition
   
  Indemnification
    Agreements with Our General Partners Executive Officers
    and Directors
 
 
   
 150




---



##### Table of Contents



Procedures
    for Review, Approval and Ratification of Related Person
    Transactions
 
 
   
 
 
 
   
 
   
  Other
    Arrangements with Affiliates
 
   
 
 
 151




---



##### Table of Contents



CONFLICTS
    OF INTEREST AND FIDUCIARY DUTIES
  Conflicts
    of Interest
        
    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.   152




---



##### Table of Contents



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 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.
  and/or
  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.
   
 
 
  We do
    not have any officers, directors or employees and rely solely on
    officers and directors of our general partner and employees of
    Resolute Holdings. The positions held by these officers and
    directors may give rise to fiduciary obligations that are in
    conflict with fiduciary obligations owed to us. These conflicts
    may not be resolved in our favor. Failure of such officers,
    directors and employees to devote sufficient attention to the
    management and operation of our business may adversely affect
    our financial results and our ability to make distributions to
    our unitholders.
 
 
   
 153




---



##### Table of Contents



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.
    
    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; 
 
  
    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 a 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 our general partner or
    those other persons acted in bad faith or engaged in fraud,
    willful misconduct or, in the case of a criminal matter, with
    knowledge that the indemnitees conduct was unlawful. 
  Except
    in limited circumstances, our general partner has the power and
    authority to conduct our business without unitholder
    approval.
    
    the making of any expenditures, the lending or borrowing of
    money, the assumption or guarantee of or other contracting for,
    indebtedness and other liabilities, the issuance of evidences of
    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; 154




---



##### Table of Contents




    the selection and dismissal of employees and agents, outside
    attorneys, accountants, consultants and contractors and the
    determination of their compensation and other terms of
    employment or hiring;
    the maintenance of insurance for our benefit and the benefit of
    our partners;
    the formation of, or acquisition of an interest in, the
    contribution of property to, and the making of loans to, any
    limited or general partnerships, joint ventures, corporations,
    limited liability companies or other relationships;
    the control of any matters affecting our rights and obligations,
    including the bringing and defending of actions at law or in
    equity and otherwise engaging in the conduct of litigation,
    arbitration or mediation and the incurring of legal expense and
    the settlement of claims and litigation;
    the indemnification of any person against liabilities and
    contingencies to the extent permitted by law;
    the making of tax, regulatory and other filings, or rendering of
    periodic or other reports to governmental or other agencies
    having jurisdiction over our business or assets; and
    the entering into of agreements with any of its affiliates to
    render services to us or to itself in the discharge of its
    duties as our general partner.    Our
    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 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.      
    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.   155




---



##### Table of Contents



Our
    general partner determines which costs incurred by Resolute
    Holdings and its affiliates are reimbursable by
    us.
    Our
    partnership agreement does not restrict our general partner from
    causing us to pay it or its affiliates for any services rendered
    to us or entering into additional contractual arrangements with
    any of these entities on our behalf.
        Our
    general partner intends to limit its liability regarding our
    obligations.
    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.
   156




---



##### Table of Contents



Common
    unitholders will have no right to enforce obligations of our
    general partner and its affiliates under agreements with
    us.
    Our
    general partner decides whether to retain separate counsel,
    accountants, or others to perform services for us.
    Fiduciary
    Duties
      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 157




---



##### Table of Contents



institute the action or where an effort to cause a general
    partner to do so is not likely to succeed. In addition, the
    statutory or case law of some jurisdictions may permit a limited
    partner to institute legal action on behalf of himself and all
    other similarly situated limited partners to recover damages
    from a general partner for violations of its fiduciary duties to
    the limited partners.Partnership agreement modified standards
    
    Our partnership agreement contains provisions that waive or
    consent to conduct by our general partner and its affiliates
    that might otherwise raise issues about compliance with
    fiduciary duties or applicable law. For example, our partnership
    agreement provides that when our general partner is acting in
    its capacity as our general partner, as opposed to in its
    individual capacity, it must act in good faith and
    will not be subject to any other standard under applicable law.
    In addition, when our general partner is acting in its
    individual capacity, as opposed to in its capacity as our
    general partner, it may act without any fiduciary obligation to
    us or the unitholders whatsoever. These standards reduce the
    obligations to which our general partner would otherwise be held. 
  In addition to the other more specific provisions limiting the
    obligations of our general partner, our partnership agreement
    further provides that our general partner and its officers and
    directors will not be liable for monetary damages to us, our
    limited partners or assignees for errors of judgment or for any
    acts or omissions unless there has been a final and
    non-appealable judgment by a court of competent jurisdiction
    determining that the general partner or its officers and
    directors acted in bad faith or engaged in fraud, willful
    misconduct or, in the case of a criminal matter, with knowledge
    that the indemnitees conduct was unlawful. 
  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. 158




---



##### Table of Contents



159




---



##### Table of Contents



DESCRIPTION
    OF THE COMMON UNITS
  The
    Units
    Transfer
    Agent and Registrar
  Duties.
  
    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.    Resignation or Removal.
  Transfer
    of Common Units
    
    represents that the transferee has the capacity, power and
    authority to become bound by our partnership agreement;
    automatically agrees to be bound by the terms and conditions of,
    and is deemed to have executed, our partnership
    agreement; and
    gives the consents and approvals contained in our partnership
    agreement, such as the approval of all transactions and
    agreements that we are entering into in connection with our
    formation and this offering.   160




---



##### Table of Contents



161




---



##### Table of Contents



THE
    PARTNERSHIP AGREEMENT
      
    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
    Purpose
      Power
    of Attorney
    Cash
    Distributions
    Capital
    Contributions
   162




---



##### Table of Contents



Voting
    Rights
    
    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.    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 163




---



##### Table of Contents



consolidation with or into, or sale of all or substantially all
    of its assets, to such person. The approval of a majority of the
    common units, excluding common units held by the general partner
    and its affiliates, is required in other circumstances for a
    transfer of the general partner interest to a third party prior
    to 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
    
    to remove or replace the general partner;
    to approve some amendments to our partnership agreement; or
    to take other action under our partnership agreement;     164




---



##### Table of Contents



Issuance
    of Additional Securities
          Amendment
    of the Partnership Agreement
  General.
 165




---



##### Table of Contents



Prohibited Amendments.
  
    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.    No Unitholder Approval.
  
    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; 166




---



##### Table of Contents




    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;
    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.    
    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.
    Merger,
    Sale or Other Disposition of Assets
     167




---



##### Table of Contents



Termination
    and Dissolution
    
    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. 
   
  
    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
 
   
 168




---



##### Table of Contents



Withdrawal
    or Removal of the General Partner
      2 3 1 3
    
    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.   169




---



##### Table of Contents



Transfer
    of General Partner Interest
    
    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.    Transfer
    of Ownership Interests in the General Partner
    Transfer
    of Incentive Distribution Rights
    Change
    of Management Provisions
   170




---



##### Table of Contents




    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
    
    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.      Meetings;
    Voting
     171




---



##### Table of Contents



Status
    as Limited Partner
    Non-Eligible
    Holders; Redemption
       172




---



##### Table of Contents



Indemnification
    
    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.      Reimbursement
    of Expenses
     173




---



##### Table of Contents



Books
    and Reports
        Right
    to Inspect Our Books and Records
    
    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.    Registration
    Rights
   174




---



##### Table of Contents



UNITS
    ELIGIBLE FOR FUTURE SALE
      
    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.        lock-up
 175




---



##### Table of Contents



MATERIAL
    TAX CONSEQUENCES
            
    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). 176




---



##### Table of Contents



Partnership
    Status
          (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.   177




---



##### Table of Contents



Limited
    Partner Status
    
    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        Tax
    Consequences of Common Unit Ownership
  Flow-Through of Taxable Income.
  Treatment of
    Distributions.
 178




---



##### Table of Contents



and/or
  Ratio of Taxable Income to
    Distributions.
  
    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.
 179




---



##### Table of Contents



Limitations on Deductibility of
    Losses.
    activity-by-activity
   180




---



##### Table of Contents



Limitations on Interest Deductions.
  
    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.      Entity-Level Collections.
  Allocation of Income, Gain, Loss and
    Deduction.
   181




---



##### Table of Contents




    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.    Treatment of Short Sales.
  
    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.    Alternative Minimum Tax.
  Tax Rates.
 182




---



##### Table of Contents



Section 754 Election.
  Regulation Section 1.167(c)-1(a)(6),
  non-amortizable Regulation Section 1.167(c)-1(a)(6),
   183




---



##### Table of Contents



Tax
    Treatment of Operations
  Accounting Method and Taxable Year.
  Depletion Deductions.
   184




---



##### Table of Contents



Deductions for Intangible Drilling and Development
    Costs.
  60-month 60-month
   185




---



##### Table of Contents



Deduction for U.S. Production
    Activities. Form W-2
      Form W-2 Form W-2
  Form W-2
  Lease Acquisition Costs.
 186




---



##### Table of Contents



Geophysical Costs. 24-month
  Operating and Administrative Costs.
  Qualified Enhanced Oil Recovery Project
    Credits.
  Tax Basis, Depreciation and
    Amortization.
        Valuation and Tax Basis of Our
    Properties.
 187




---



##### Table of Contents



Disposition
    of Common Units
  Recognition of Gain or Loss.
         188




---



##### Table of Contents




    a short sale;
    an offsetting notional principal contract; or
    a futures or forward contract with respect to the partnership
    interest or substantially identical property.    Allocations Between Transferors and
    Transferees.
      Notification Requirements.
  Constructive Termination. Schedule K-1s)
 189




---



##### Table of Contents



Uniformity
    of Common Units
  Regulation Section 1.167(c)-1(a)(6).
  Regulation Section 1.167(c)-1(a)(6),
  Tax-Exempt
    Organizations and Other Investors
       190




---



##### Table of Contents



Form W-8
      Administrative
    Matters
  Information Returns and Audit
    Procedures. Schedule K-1,
       191




---



##### Table of Contents



Nominee Reporting.
  
    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.    Accuracy-Related Penalties.
    
    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.   192




---



##### Table of Contents



Reportable Transactions.
    
    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.    State,
    Local and Other Tax Considerations
     193




---



##### Table of Contents



INVESTMENT
    IN RESOLUTE ENERGY PARTNERS, LP BY EMPLOYEE BENEFIT
    PLANS
  non-U.S.
  
    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.          (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; 194




---



##### Table of Contents



(b)
    the entity is an operating company, 
    i.e., it is primarily engaged in the production or sale of a
    product or service other than the investment of capital either
    directly or through a majority-owned subsidiary or
    subsidiaries; or  (c)
    there is no significant investment by benefit plan investors,
    which is defined to mean that less than 25% of the value of each
    class of equity interest is held by the employee benefit plans
    referred to above that are subject to ERISA, IRAs and similar
    vehicles that are subject to Section 4975 of the Internal
    Revenue Code.     195




---



##### Table of Contents



UNDERWRITING
    Number ofUnderwriters

Common UnitsLehman Brothers Inc.UBS Securities LLCWachovia Capital Markets, LLCTotal


13,750,000     
    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
    No Exercise


Full ExercisePer common unitTotal         Option
    to Purchase Additional Common Units
   196




---



##### Table of Contents



Lock-Up
    Agreements
    180-day
  
    during the last 17 days of the
    180-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 the
    180-day
    restricted period, we announce that we will release earnings
    results during the
    16-day
    period beginning on the last day of the
    180-day
    period,  18-day
  lock-up lock-up
  180-day lock-up lock-up lock-up lock-up
 197




---



##### Table of Contents



Offering
    Price Determination
    
    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
    Directed
    Unit Program
  180-day lock-up Lock-Up
  Stabilization,
    Short Positions and Penalty Bids
    
    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 units
    and/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 198




---



##### Table of Contents



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.      Electronic
    Distribution
  and/or
  and/or
  New
    York Stock Exchange
    Discretionary
    Sales
    Stamp
    Taxes
   199




---



##### Table of Contents



Relationships/NASD
    Conduct Rules
 
   
   200




---



##### Table of Contents



VALIDITY
    OF THE COMMON UNITS
    EXPERTS
 
   
     
   
   201




---



##### Table of Contents



WHERE
    YOU CAN FIND MORE INFORMATION
  Form S-l 1-800-SEC-0330. http://www.sec.gov.
   202




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS, LP
  INDEX
    TO FINANCIAL STATEMENTS
 PageRESOLUTE ENERGY PARTNERS, LPIntroduction


F-2Unaudited Pro Forma Condensed Consolidated
    Balance Sheet as of June 30, 2007


F-3Unaudited Pro Forma Condensed Consolidated
    Statement of Operations for the year ended December 31,
    2006


F-5Unaudited Pro Forma Condensed Consolidated
    Statement of Operations for the six months ended June 30,
    2007


F-6Notes to Unaudited Pro Forma Condensed
    Consolidated Financial Statements


F-7RESOLUTE ENERGY PARTNERS PREDECESSORAnnual Financial Statements:Report of Independent Registered Public
    Accounting Firm


F-13Report of Independent Registered Public
    Accounting Firm


F-14Combined Balance Sheets as of December 31,
    2005 and 2006


F-15Consolidated 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-16Consolidated 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-17Consolidated 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-18Notes 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-20Interim Financial Statements:Condensed Combined Balance Sheets (Unaudited) as
    of June 30, 2007


F-42Condensed Combined Statements of Operations
    (Unaudited) for the six months ended June 30, 2006 and
    2007


F-43Condensed 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-44Condensed Combined Statements of Cash Flows
    (Unaudited) for the six months ended June 30, 2006 and
    2007


F-45Notes to the Unaudited Condensed Combined
    Financial Statements


F-47RESOLUTE ENERGY PARTNERS, LPReport of Independent Registered Public
    Accounting Firm


F-56Balance Sheet as of September 26, 2007


F-57Note to Balance Sheet


F-58RESOLUTE ENERGY GP, LLCReport of Independent Registered Public
    Accounting Firm


F-59Balance Sheet as of September 26, 2007


F-60Note to Balance Sheet


F-61CHEVRON PROPERTIESReport of Independent Registered Public
    Accounting Firm


F-62Statements of Revenues and Direct Operating
    Expenses for the year ended December 31, 2003 and the
    eleven-month period ended November 30, 2004


F-63Notes to the Statements of Revenues and Direct
    Operating Expenses


F-64EXXONMOBIL PROPERTIESReport of Independent Registered Public
    Accounting Firm


F-67Audited 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-68Notes to the Statements of Revenues and Direct
    Operating Expenses


F-69  F-1




---



##### Table of Contents



Resolute
    Energy Partners, LP
  Unaudited
    Pro Forma Condensed Consolidated Financial Statements
  Introduction
             F-2




---



##### Table of Contents



Resolute
    Energy Partners, LP
  Unaudited Pro Forma Condensed Consolidated Balance Sheet
 As of June 30, 2007
  Predecessor








Offering and


Resolute EnergyHistorical


Elimination of


Resolute Energy


Financing


Partners, LPFinancial


Retained


Partners, LP


Pro Forma


Pro Forma,Statements


Subsidiaries(a)


Pro Forma


Adjustments


as AdjustedAssetsCurrent assets:Cash and cash equivalents

$



$



$



$
275,000
(b)

$(17,875
)(c)(3,350
)(d)(246,275
)(e)150,975
(f)(150,975
)(g)


7,500Accounts receivable:Trade receivables


32,541



(161
)


32,380



(7,500
)(h)


24,880Other  Navajo Nation Oil and Gas Company


667







667







667Derivative instruments


13,580







13,580







13,580Other current assets


1,008



(949
)


59







59Total current assets


47,796



(1,110
)


46,686







46,686Property and equipment, at cost:Oil and gas properties, full cost method of accountingUnproved


11,884



(11,884
)Proved


380,895







380,895







380,895Accumulated depletion, depreciation and amortization


(23,116
)






(23,116
)






(23,116
)Net oil and gas properties


369,663



(11,884
)


357,779







357,779Other property and equipment


3,584



(2,022
)


1,562







1,562Accumulated depreciation


(959
)


815



(144
)






(144
)Net other property and equipment


2,625



(1,207
)


1,418







1,418Net property and equipment


372,288



(13,091
)


359,197







359,197Other assets:Restricted cash


9,446







9,446







9,446Deferred financing costs


5,214







5,214



(5,214
)(i)2,000
(g)


2,000Notes receivable  affiliated entities


2,140



(2,140
)Deferred offering costs


618







618



(618
)(j)Derivative instruments


7,659







7,659







7,659Other assets


398



(55
)


343







343Total other assets


25,475



(2,195
)


23,280



(3,832
)


19,448Total assets

$
445,559


$
(16,396
)

$
429,163


$
(3,832
)

$
425,331    F-3




---



##### Table of Contents



Resolute
    Energy Partners, LP
  Unaudited
    Pro Forma Condensed Consolidated Balance Sheet
 As of
    June 30, 2007
  Predecessor








Offering and


Resolute EnergyHistorical


Elimination of


Resolute Energy


Financing


Partners, LPFinancial


Retained


Partners, LP


Pro Forma


Pro Forma,Statements


Subsidiaries(a)


Pro Forma


Adjustments


as AdjustedLiabilities and
    Shareholders/Members/Partners EquityCurrent liabilities:Cash overdraft

$
4,940


$
(4,940
)

$



$



$Accounts payable and accrued expenses


26,655



(268
)


26,387







26,387Interest payable


1,467







1,467







1,467Accrued purchase price payable  ExxonMobil acquisition


1,778







1,778







1,778Oil and gas sales payable


4,273







4,273







4,273Asset retirement obligations


1,521







1,521







1,521Derivative instruments


14,022







14,022







14,022Accounts payable  Intercompany


617



(617
)










Total current liabilities


55,273



(5,825
)


49,448







49,448Non-current liabilities:Long term debt


395,250







395,250



(170,250
)(e)(76,025
)(e)150,975
(f)(148,975
)(g)150,975Asset retirement obligations


6,228







6,228







6,228Derivative instruments


33,313







33,313







33,313Contingent tax liability


491



(491
)Other


12



(12
)Total long-term liabilities


435,294



(503
)


434,791



(244,275
)


190,516Total liabilities


490,567



(6,328
)


484,239



(244,275
)


239,964Shareholders/Members/Partners Equity:Common stock*






Additional paid in capital


1,481



(1,481
)Accumulated deficit


(11,299
)


11,299Member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)


3,707Limited partners interest:Public  common














61,171
(k)


61,171Holdings  common














29,659
(k)


29,659Holdings  subordinated














90,830
(k)


90,830Total shareholders/members/partners equity


(45,008
)


(10,068
)


(55,076
)


240,443



185,367Total 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.   F-4




---



##### Table of Contents



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 EnergyHistorical


Elimination of





Pro Forma


Financing


Partners, LPFinancial


Retained


ExxonMobil


Resolute Energy


Pro Forma


Pro Forma,Statements


Subsidiaries(a)


Properties


Partners, LP


Adjustments


as AdjustedRevenue:Oil sales

$
102,000


$



$
18,167


$
120,167






$
120,167Gas sales


836







15



851







851Other


3,735







781



4,516







4,516Total revenue


106,571







18,963



125,534







125,534Operating expenses:Lease operating


24,857







2,324



27,181







27,181Workover


13,312







1,039



14,351







14,351Production taxes


7,806







1,473



9,279







9,279General and administrative


6,015



(402
)






5,613







5,613Depletion, depreciation and amortization


11,071



(375
)


1,454
(l)


12,150







12,150Accretion of asset retirement obligations


206







16
(m)


222







222Total operating expenses


63,267



(777
)


6,306



68,796







68,796Income from operations


43,304



777



12,657



56,738







56,738Other income (expense):Other income


546



(185
)






361







361Gain (loss) on derivative instruments


10,895











10,895







10,895Interest 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



1,496Net income

$
36,624


$
600


$
7,564


$
44,788


$
13,446


$
58,234General partners interest in net income





















$
1,165Limited partners interest in net income:Common units





















$
28,562Subordinated units





















$
28,507Net income per limited partners unit:Common units





















$
1.40Subordinated units





















$
1.40Weighted average number of limited partner units outstanding:Common units






















20,401.3Subordinated units






















20,401.3Total






















40,802.6    F-5




---



##### Table of Contents



Resolute
    Energy Partners, LP
  Unaudited Pro Forma Condensed Consolidated Statement of
    Operations
 For the six months ended June 30, 2007
  Predecessor








Offering and


Resolute EnergyHistorical


Elimination of


Resolute Energy


Financing


Partners, LPFinancial


Retained


Partners, LP


Pro Forma


Pro Forma,Statements


Subsidiaries(a)


Pro Forma


Adjustments


as AdjustedRevenue:Oil sales

$
57,646


$



$
57,646


$



$
57,646Gas sales


242







242







242Other


2,371







2,371







2,371Total revenue


60,259







60,259







60,259Operating expenses:Lease operating


16,507







16,507







16,507Workover


5,700







5,700







5,700Production taxes


4,536







4,536







4,536General and administrative


34,617



(1,657
)


32,960







32,960Depletion, depreciation and amortization


7,915



(274
)


7,641







7,641Accretion of asset retirement obligations


145







145







145Total operating expenses


69,420



(1,931
)


67,489







67,489Income (loss) from operations


(9,161
)


1,931



(7,230
)






(7,230
)Other income (expense):Other income


266



(50
)


216







216Gain (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


















20,401.3Subordinated units


















20,401.3Total


















40,802.6    F-6




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS, LP
  Notes to Unaudited Pro Forma Condensed Consolidated Financial
    Statements
  Note 1 
    Basis of
    Presentation, Transactions and the Offering      
    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




---



##### Table of Contents



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.          Note 2 
    Pro Forma
    Adjustments               F-8




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS, LP
  Notes to Unaudited Condensed Pro Forma Financial
    Statements  (Continued)
                          Note 3 
    Pro Forma
    Net Income (Loss) per Unit   F-9




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS, LP
  Notes to Unaudited Condensed Pro Forma Financial
    Statements  (Continued)
   
  Note 4 
    Administrative
    Services Agreement 
 
   
 
 
 
  
    the Partnerships 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; 
 
  
    the Partnerships 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 
 
  
    the Partnerships obligation to indemnify Resolute Holdings
    for certain liabilities. 
 
   
 
   
 
   
 
  Note 5 
    Pro forma
    unaudited estimated proved oil and natural gas
    reserves 
 
   
 F-10




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS, LP
  Notes to Unaudited Condensed Pro Forma Financial
    Statements  (Continued)
 
   
 
   
  
 Resolute Energy Partners, LPOilOil


Gas


EquivalentMBbl


MMcf


MboeProved reserves  January 1, 2006


23,500



3,750



24,125Purchases of minerals in place


35,790



1,905



36,107Production


(1,881
)


(259
)


(1,923
)Extensions, discoveries, improved recovery and other


13,571



(1,992
)


13,239Revisions of previous estimates


7,377



(1,513
)


7,124Proved reserves  December 31, 2006


78,357



1,891



78,672Proved developed reserves  December 31, 2006


32,232



6,065



33,243  
 
 
 
  Note 6 
    Pro forma
    unaudited standardized measure of discounted future net cash
    flows related to proved oil and natural gas reserves 
 
   
 
   
 
   
 
   
 
   
 
   
 F-11




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS, LP
  Notes to Unaudited Condensed Pro Forma Financial
    Statements  (Continued)
 
   
 
   
 
   
  
 Resolute EnergyPartners, LPEstimated future cash inflows

$
4,610Future production costs


(1,618
)Future development costs


(192
)Future income taxes


Future net cash flows


2,80010% annual discount for estimated timing of cash flows


(1,822
)Standardized measure of discounted future net cash flows

$
978  
 
   
  
 Resolute EnergyPartners, LPPro forma standardized measure January 1, 2006

$
841Sale of oil and gas produced, net of production costs


(74
)Net changes in prices and production costs


12Extensions, discoveries, and improved recoveries


176Purchases of minerals in place


Development costs incurred during the year


23Changes in estimated future development costs


(127
)Revisions of previous quantity estimates


96Accretion of discount


33Sales of reserves in place


Net change in income taxes


Changes in production rates and other


(2
)Pro forma standardized measure December 31, 2006

$
978  
 
 
 
 
 F-12




---



##### Table of Contents



REPORT
    OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
  To the Board
    of Directors and the Managing Member of
    Resolute Energy Partners Predecessor
    Denver, Colorado
          
 F-13




---



##### Table of Contents



REPORT
    OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
   To the Board
    of Directors and the Managing Member of
    Resolute Energy Partners Predecessor
    Denver, Colorado
 
    
   
   
     April 27,
    2007, except for Note 10 which is as of September 26,
    2007
    Denver, Colorado
 F-14




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Combined
    Balance Sheets
    (in thousands)
  
 December 31,2005


2006AssetsCurrent assets:Cash and cash equivalents

$



$
3,691Accounts receivable:Trade receivables


10,105



26,527Other  Navajo Nation Oil and Gas Company






444Related party  Holdings


32



Derivative instruments






1,843Other current assets


200



414Total current assets


10,337



32,919Property and equipment, at cost:Oil and gas properties, full cost method of accountingUnproved


5,657



8,848Proved


92,111



334,668Accumulated depletion, depreciation  and amortization


(4,847
)


(15,507
)Net oil and gas properties


92,921



328,009Other property and equipment


1,269



2,940Accumulated depreciation


(241
)


(652
)Net other property and equipment


1,028



2,288Net property and equipment


93,949



330,297Other assets:Restricted cash






7,728Deferred financing costs, net of accumulated amortization of
    $103 and $579, respectively


277



3,090Notes receivable  affiliated entities


2,000



2,144Deferred offering costs






500Other assets






55Total other assets


2,277



13,517Total assets

$
106,563


$
376,733Liabilities and Shareholders/Members EquityCurrent liabilities:Cash overdraft

$
383


$
Accounts payable and accrued expenses


6,819



24,704Interest payable


213



2,963Accrued purchase price payable  acquisition of
    ExxonMobil Properties






1,778Oil and gas sales payable


1,571



4,016Current tax liability


862



Asset retirement obligations


12



1,328Derivative instruments


2,339



4,710Accounts payable  Holdings






359Total current liabilities


12,199



39,858Non-current liabilities:Long term debt


45,925



267,500Asset retirement obligations


2,305



6,118Derivative instruments


17,436



1,355Other






42Total long-term liabilities


65,666



275,015Total liabilities


77,865



314,873Commitments and contingenciesShareholders/members equity:Common stock, $0.01 par value, 1,000 shares authorized
    and issued






Additional paid-in capital  Resources


1,481



1,481Accumulated deficit  Resources


(10,340
)


(10,565
)Members equity


37,557



70,944Total shareholders/members equity


28,698



61,860Total liabilities and shareholders/members equity

$
106,563


$
376,733  
   F-15




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Consolidated
    and Combined Statements of Operations
    (in thousands)
  
 January 22, 2004(Inception) through


For the Year EndedDecember 31,


December 31,2004


2005


2006Revenue:Oil and gas sales

$
2,390


$
41,973


$
106,571Operating expenses:Lease operating


658



8,734



24,857Workover


21



3,860



13,312Production taxes


340



2,772



7,806General and administrative


2,415



3,281



6,015Depletion, depreciation and amortization


407



4,680



11,071Accretion of asset retirement obligations


20



216



206Total operating expenses


3,861



23,543



63,267Income (loss) from operations


(1,471
)


18,430



43,304Other income (expense):Other income


51



147



546Gain (loss) on derivative instruments


3,592



(28,852
)


10,895Interest 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
)


36,624Income 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  
   F-16




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
    Consolidated and Combined Statements of
    Shareholders/Members Equity
    (in thousands, except for shares)
  TotalAdditional


Accumulated





Shareholders/Common Stock


Paid-in


Earnings


Members


MembersShares


Amount*


Capital


(Deficit)


Equity


EquityBalances January 22, 2004 (Inception)





$



$



$



$



$
Capital contributions










43,757











43,757Issuance of common stock


1,000



















Net income














1,240







1,240Balances at December 31, 2004


1,000


$



$
43,757


$
1,240


$



$
44,997Capital contributions










351











351Net 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



7,336Net Loss  Resources














(7,203
)






(7,203
)Balances at December 31, 2005


1,000


$



$
1,481


$
(10,340
)

$
37,557


$
28,698Distributions to Holdings from Aneth


















(3,462
)


(3,462
)Net income














(225
)


36,849



36,624Balances 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.   F-17




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Consolidated and Combined Statements of Cash Flows
 (in
    thousands)
  
 January 22, 2004(Inception) through


For the Year EndedDecember 31,


December 31,2004


2005


2006Operating activities:Net income (loss)

$
1,240


$
(16,650
)

$
36,624Adjustments to reconcile net income (loss) to net cash provided
    (used) by operating activities:Depletion, depreciation  and amortization


408



4,680



11,071Amortization of deferred financing costs






103



477Deferred income taxes


742



(742
)


Unrealized gain/loss on derivative instruments


(3,383
)


23,159



(13,291
)Accretion of asset retirement obligations


20



216



206Other










(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



14,216Oil and gas sales payable


458



1,113



2,445Cash overdraft






383



(383
)Increase in accounts payable  Holdings










391Current tax liability






862



(862
)Net cash provided by (used in) operating activities

$
(2,225
)

$
11,516


$
31,756Investing 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
)  
     F-18




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Consolidated
    and Combined Statements of Cash Flows (continued)
 (in
    thousands)
  January 22, 2004(Inception) through


For the Year EndedDecember 31,


December 31,2004


2005


2006Financing activities:

$



$



$Deferred offering costs










(500
)Deferred financing costs










(3,290
)Proceeds from bank borrowings


44,000



19,605



337,730Issuance 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


$
214,323Net increase (decrease) in cash and cash equivalents

$
611


$
(611
)

$
3,691Cash and cash equivalents at beginning of year






611



Cash and cash equivalents at end of year

$
611


$



$
3,691Supplemental disclosures of cash flow information:Cash paid during the year for:Interest

$
67


$
2,199


$
14,776Income taxes

$



$
3,708


$
862Supplemental schedule of non-cash investing and financing
    activities:Acquisition of ExxonMobil properties:Increase to asset retirement obligations

$



$



$
5,302Increase to accrued purchase price payable, net of accrued
    purchase price receivable

$



$



$
1,333Increase (decrease) to asset retirement obligations

$
4,286


$
(2,192
)

$
390Increase in accrued capital expenditures

$
2,399


$



$
5,649      F-19




---



##### Table of Contents



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
    Basis
    of Presentation and Principles of
    Consolidation
        Assumptions,
    Judgments and Estimates
   
   
 F-20




---



##### Table of Contents



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
    Cash
    Equivalents
    Concentration
    of Credit Risk
 
   
  Oil
    and Gas Properties
 
   
   F-21




---



##### Table of Contents



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)
               F-22




---



##### Table of Contents



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)
 
   
  Other
    Property and Equipment
    Asset
    Retirement Obligations
  Accounting for Asset Retirement Obligations
  Accounting for Conditional Asset Retirement Obligations Accounting for Asset Retirement
    Obligations and/or
   F-23




---



##### Table of Contents



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)
    2004


2005


2006Asset retirement obligations at beginning of period

$



$
4,306


$
2,317Accretion expense


20



216



206Liabilities settled






(12
)


(769
)Liabilities assumed in acquisition of Chevron Properties


4,286







Liabilities assumed in acquisition of ExxonMobilProperties










5,302Revisions to previous estimates






(2,193
)


390Asset retirement obligations at end of period


4,306



2,317



7,446Less current asset retirement obligations


(529
)


(12
)


(1,328
)Long-term asset retirement obligations

$
3,777


$
2,305


$
6,118   Impairment
    of Long-Lived Assets
  Accounting for the
    Impairment or Disposal of Long-Lived Assets
  Deferred
    Financing Costs
    Derivative
    Instruments
    Accounting for Derivative Instruments
    and Hedging Activities
 F-24




---



##### Table of Contents



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)
        Revenue
    Recognition
    General
    and Administrative Expenses
    Income
    Taxes
   F-25




---



##### Table of Contents



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)
  Industry
    Segment and Geographic Information
    New
    Accounting Pronouncements
  Accounting for
    Uncertainty in Income Taxes
    Fair Value Measurements,
  Share-Based Payment Accounting
    for Stock-Based Compensation Accounting for Stock
    Issued to Employees
  The
    Fair Value Option for Financial Assets and Financial Liabilities including an amendment of FASB Statement
    No. 115
 F-26




---



##### Table of Contents



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)
  Reclassifications
    Note 2 
    Note Receivable from Resolute Holdings, LLC
 
   
  Note 3 
    Acquisitions
  Chevron
    Acquisition
      Oil and gas properties

$
85,831Buildings and equipment


328Vehicles


88Total purchase price allocation

$
86,247  F-27




---



##### Table of Contents



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)
    McElmo


RatherfordAneth Unit


Creek Unit


UnitChevron 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
    Acquisition
  2
   F-28




---



##### Table of Contents



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 and gas properties

$
219,148Buildings and equipment


680Asset retirement obligation


(5,302
)Total purchase price allocation

$
214,526       McElmo


RatherfordAneth Unit


Creek Unit


UnitExxonMobil 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
%      F-29




---



##### Table of Contents



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)
      December 31,2005


2006Total revenues

$
109,681


$
125,534Net income

$
32,745


$
29,581   Note 4 
    Long-Term Debt
    December 31,2005


2006Credit agreementsFirst Lien Facility

$
45,925


$
142,500Second Lien Facility






125,000Total long-term debt

$
45,925


$
267,500        F-30




---



##### Table of Contents



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 5 
    Income Taxes
   F-31




---



##### Table of Contents



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)
    January 22,2004(Inception)through


For the Year EndedDecember 31,


December 31,2004


2005


2006Current 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
)

$
       
 January 22,2004(Inception)through


For the Year EndedDecember 31,


December 31,2004


2005


2006U.S. statutory income tax expense

$
674


$
(4,384
)

$
State income tax expense


68



695



Tax credits






(120
)


Gain on transfer of Aneth to Resolute Holdings






2,195



Unrealized hedge loss transferred to Resolute Holdings






8,300



Aneth income not subject to corporate tax






(2,788
)


Other






(68
)


Total

$
742


$
3,830


$
  
 F-32




---



##### Table of Contents



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
    Members
    Equity
    Additional
    Paid-in Capital
      Incentive
    Interests
   F-33




---



##### Table of Contents



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)
    Incentive UnitsJanuary 22, 2004


Granted


19,169,207Forfeited


December 31, 2004


19,169,207Granted


1,345,783Forfeited


December 31, 2005


20,514,990Granted


Forfeited


(656,480
)Redistributed


656,480December 31, 2006


20,514,990     Equity
    Appreciation Rights
      Note 7 
    Employee Benefit Plan
    Note 8 
    Derivative Instruments
   F-34




---



##### Table of Contents



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)
      Commodity
    Swaps and Put Options
        Unrealized gain on crude oil swaps

$
3,383Cash settlements of crude oil swaps


209Net gain on derivative instruments

$
3,592     Unrealized loss on crude oil swaps

$
(23,159
)Cash settlements of crude oil swaps


(5,693
)Net loss on derivative instruments

$
(28,852
)    F-35




---



##### Table of Contents



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)
    Unrealized loss on crude oil puts

$
(419
)Unrealized gain on crude oil swaps


13,710Total unrealized gain


13,291Cash 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     Oil (NYMEX WTI)Weighted AverageYear

Bbl per day


Hedge Price Per Bbl2007


1,250


$
40.732008


1,000


$
39.33     Oil (NYMEX WTI)Weighted AverageYear

Bbl per day


Hedge Price Per Bbl2007


2,000


$
60.00     Oil (NYMEX WTI)Weighted AverageYear

Bbl per day


Hedge Price Per Bbl2007


200


$
65.602007


500


$
72.452007


500


$
72.602007


500


$
72.742007


400


$
72.702007


200


$
76.25 F-36




---



##### Table of Contents



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 AverageYear

Bbl per day


Hedge Price Per Bbl2008


200


$
64.602008


500


$
70.752008


500


$
70.802008


500


$
70.702008


300


$
71.072008


200


$
74.152009


500


$
69.402009


500


$
69.302009


500


$
69.502009


250


$
71.002009


250


$
70.752009


250


$
71.522009


350


$
70.802009


300


$
70.002009


200


$
73.102010


500


$
68.252010


500


$
68.502010


250


$
69.102010


250


$
69.152010


350


$
70.002010


350


$
69.102010


200


$
72.002010


150


$
70.152010


350


$
69.00   Note 9 
    Commitments and Contingencies
  2 2 2 2
   F-37




---



##### Table of Contents



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 10 
    Supplemental Oil and Gas Information (unaudited)
  Costs
    Incurred in Oil and Gas Producing Activities:
    December 31,2004


2005


2006Development costs

$
679


$
14,156


$
60,744Exploration










Acquisitions:Proved


90,533







219,296Unproved


15



5,657



3,191Total

$
91,227


$
19,813


$
283,231     
 December 31,2005


2006Proved oil and gas properties

$
92,111


$
334,668Unevaluated oil and gas properties, not subject to amortization


5,657



8,848Accumulated depletion, depreciation and amortization


(4,847
)


(15,507
)Oil and gas properties, net

$
92,921


$
328,009  
  Oil
    and Gas Reserve Quantities:
   F-38




---



##### Table of Contents



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)
   
   
  
 OilOil


Gas


EquivalentMBbl


MMcf


MBoeProved reserves as of January 22, 2004 (Inception):










Purchases of minerals in place


18,455



2,265



18,833Production


(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



18,228Purchases of minerals in place










Production


(720
)


(136
)


(743
)Extensions, discoveries, improved recovery and other additions(2)


6,771



(2,030
)


6,433Revisions of previous estimates


(378
)


3,512



207Proved reserves as of December 31, 2005:


23,500



3,750



24,125Purchases of minerals in place


35,497



1,873



35,809Production


(1,588
)


(227
)


(1,625
)Extensions, discoveries, improved recovery and other additions(2)


13,571



(1,992
)


13,239Revisions of previous estimates(1)


7,377



(1,513
)


7,124Proved reserves as of December 31, 2006:


78,357



1,891



78,672Proved developed reserves:As of December 31, 2004


11,973



1,461



12,216As of December 31, 2005


13,447



4,260



14,157As of December 31, 2006


32,232



6,065



33,243  
    (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. 
  (2)
    
    Negative gas reserves arise from the addition of undeveloped oil
    reserves through our
    CO2
    injection project and the resulting contamination of a portion
    of our developed gas reserves. This contamination caused some of
    our developed gas reserves to become unsellable and thus a
    reduction in gas reserves was recorded to accurately reflect our
    total proved reserves. 
  Standardized
    Measure of Discounted Future Net Cash Flows Relating to Proved
    Oil and Gas Reserves:
   F-39




---



##### Table of Contents



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)
                    December 31,2004


2005


2006(In millions)Future cash inflows

$
744


$
1,432


$
4,610Future production costs


(315
)


(553
)


(1,618
)Future development costs


(29
)


(61
)


(192
)Future income taxes










Future net cash flows


400



818



2,80010% annual discount for estimated timing of cash flows


(201
)


(493
)


(1,822
)Standardized measure of discounted future net cash flows

$
199


$
325


$
978  F-40




---



##### Table of Contents



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)
    January 22, 2004(Inception) through


For the Year EndedDecember 31


December 31,2004


2005


2006(In millions)Standardized measure, beginning of year

$



$
199


$
325Sales of oil and gas produced, net of production costs


(1
)


(27
)


(61
)Net changes in prices and production costs


(41
)


89



12Extensions, discoveries and other, including infill reserves in
    an existing proved field, net of production costs






93



176Purchase of minerals in place


247







503Development costs incurred during the year






2



23Changes in estimated future development costs






(29
)


(127
)Revisions of previous quantity estimates


(6
)


4



96Accretion of discount






20



33Sales 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-41




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Condensed Combined Balance Sheets (Unaudited)
 (in
    thousands)
 
 Pro FormaJune 30,


June 30,2007


2007(a)AssetsCurrent assets:Cash and cash equivalents

$



$
Accounts receivable:Trade receivables


32,541



32,541Other  Navajo Nation Oil and Gas Company


667



667Derivative instruments


13,580



13,580Other current assets


1,008



1,008Total current assets


47,796



47,796Property and equipment, at cost:Oil and gas properties, full cost method of accountingUnproved


11,884



11,884Proved


380,895



380,895Accumulated depletion, depreciation and amortization


(23,116
)


(23,116
)Net oil and gas properties


369,663



369,663Other property and equipment


3,584



3,584Accumulated depreciation


(959
)


(959
)Net other property and equipment


2,625



2,625Net property and equipment


372,288



372,288Other assets:Restricted cash


9,446



9,446Deferred financing costs, net of accumulated amortization of $906


5,214



5,214Notes receivable  affiliated entities


2,140



2,140Deferred offering costs


618



618Derivative instruments


7,659



7,659Other assets


398



398Total other assets


25,475



25,475Total assets

$
445,559


$
445,559Liabilities and Shareholders/Members Equity
    (Deficit)Current liabilities:Cash overdraft

$
4,940


$
4,940Accounts payable and accrued expenses


26,655



26,655Distribution payable  affiliate






7,500Interest payable


1,467



1,467Accrued purchase price payable  ExxonMobil acquisition


1,778



1,778Oil and gas sales payable


4,273



4,273Asset retirement obligations


1,521



1,521Derivative instruments


14,022



14,022Accounts payable  Holdings


617



617Total current liabilities


55,273



62,773Non-current liabilities:Long term debt


395,250



395,250Asset retirement obligations


6,228



6,228Derivative instruments


33,313



33,313Contingent tax liability


491



491Other


12



12Total long-term liabilities


435,294



435,294Total liabilities


490,567



498,067Commitments and contingenciesShareholders/members equity (deficit):Common stock, $0.01 par value, 1,000 shares authorized
    and issued






Additional paid-in capital  Resources


1,481



1,481Accumulated 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.   F-42




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Condensed Combined Statements of Operations (Unaudited)
 (in
    thousands)
  
 For theSix Months EndedJune 30,2006


2007Revenue:Oil sales

$
40,090


$
57,646Gas sales


331



242Other


1,350



2,371Total revenue


41,771



60,259Operating expenses:Lease operating


9,405



16,507Workover


4,437



5,700Production taxes


3,062



4,536General and administrative


2,172



34,617Depletion, depreciation and amortization


4,140



7,915Accretion of asset retirement obligations


95



145Total operating expenses


23,311



69,420Income (loss) from operations


18,460



(9,161
)Other income (expense):Other income


262



266Loss 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
)  
   F-43




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Condensed Combined Statements of
    Shareholders/Members Equity (Deficit) (Unaudited)
 (in
    thousands)
  TotalShareholders/Additional





Members


MembersCommon Stock


Paid-in


Accumulated


Equity


EquityShares


Amount*


Capital


Deficit


(Deficit)


(Deficit)Balances at January 1, 2007


1,000







1,481



(10,565
)


70,944


$
61,860Distributions to Holdings from Aneth


















(100,006
)


(100,006
)Equity-based compensation


















34,597



34,597Adoption 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.   F-44




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Condensed Combined Statements of Cash Flows (Unaudited)
 (in
    thousands)
  
 For the Six MonthsEnded June 30,2006


2007Operating activities:Net loss

$
(11,996
)

$
(40,981
)Adjustments to reconcile net income (loss) to net cash provided
    by operating activities:Depletion, depreciation and amortization


4,140



7,915Amortization of deferred financing costs


149



327Equity-based compensation






32,663Unrealized (gain) loss on derivative instruments


21,930



21,874Accretion of asset retirement obligation


95



145Other


(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



257Cash overdraft


(383
)


4,940Increase in accounts payable  related party


83



258Net cash provided by operating activities


5,296



16,694Investing 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
)


4Increase in restricted cash


(7,500
)


(1,537
)Net cash used for investing activities


(225,324
)


(45,560
)  
     F-45




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Condensed
    Combined Statements of Cash Flows (Unaudited) (continued)
 (in
    thousands)
  For the Six MonthsEnded June 30,2006


2007Financing activities:Deferred offering costs


(316
)


(118
)Deferred financing costs


(3,156
)


(2,451
)Proceeds from bank borrowings


309,350



170,650Payment of bank borrowings


(83,925
)


(42,900
)Distribution to Holdings from Aneth


(1,537
)


(100,006
)Net cash provided by financing activities


220,416



25,175Net increase (decrease) in cash and cash equivalents


388



(3,691
)Cash and cash equivalents at beginning of the period






3,691Cash and cash equivalents at end of the period

$
388


$
Supplemental disclosures of cash flow information:Cash paid during the period for:Interest

$
2,657


$
13,714Income 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


$
3,712Increase (decrease) to asset retirement obligations

$
390


$
254Increase in accrued capital expenditures

$
350


$
3,915      F-46




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Notes to Unaudited Condensed Combined Financial
    Statements
  Note 1 
    The
    Company and Business  Description
    of the Business
    Note 2 
    Basis
    of Presentation and Significant Accounting
    Policies  Basis
    of Presentation
        Pro
    Forma Information
    Assumptions,
    Judgments, and Estimates
     F-47




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Notes to
    Unaudited Condensed Combined Financial
    Statements  (Continued)
 
   
  Oil
    and Gas Producing Activities
  
       
   
  Industry
    Segment and Geographic Information
   F-48




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Notes to
    Unaudited Condensed Combined Financial
    Statements  (Continued)
    New
    Accounting Pronouncement
  Accounting for Uncertain Tax Position  An
    Interpretation of FAS No. 109, Accounting for Income
    Taxes
  non-U.S. income
      Fair Value Measurements,
  Share-Based Payment Accounting for Stock-Based
    Compensation Accounting for Stock Issued to
    Employees
  The
    Fair Value Option for Financial Assets and Financial Liabilities including an amendment of FASB Statement
    No. 115
 F-49




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Notes to
    Unaudited Condensed Combined Financial
    Statements  (Continued)
    Note 3 
    Acquisitions
    and Divestitures  2007
    Acquisitions
    2006
    Acquisitions
  Acquisition of the ExxonMobil Properties  2
      Oil and gas properties

$
222,860Buildings and equipment


680Asset retirement obligation


(5,302
)Total purchase price allocation

$
218,238      F-50




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Notes to
    Unaudited Condensed Combined Financial
    Statements  (Continued)
      McElmo


RatherfordAneth Unit


Creek Unit


UnitExxonMobil 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
%       Divestitures
   F-51




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Notes to
    Unaudited Condensed Combined Financial
    Statements  (Continued)
  Note 4 
    Shareholders
    / Members Equity (Deficit)  Incentive
    Interests
    Tier II-V
      WeightedNon-Vested


AverageIncentive Units


Fair ValueNon-vested, at January 1, 2007


20,514,990


$
Granted






Vested


13,379,610


$
33,639,975Forfeited






Non-vested, at June 30, 2007


7,135,380


$
14,868,025   Equity
    Appreciation Rights
     F-52




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Notes to
    Unaudited Condensed Combined Financial
    Statements  (Continued)
    Note 5 
    Long-Term
    Debt    June 30,Credit agreements:

2007First Lien Facility

$
170,250Second Lien Facility


225,000Total long-term debt

$
395,250   First
    Lien Facility
    Second
    Lien Facility
   F-53




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Notes to
    Unaudited Condensed Combined Financial
    Statements  (Continued)
      Note 6 
    Asset
    Retirement Obligations    Asset retirement obligations at January 1, 2007

$
7,446Accretion expense


145Liabilities settled


(96
)Revisions to previous estimates


254Asset retirement obligations at June 30, 2007

$
7,749   Note 7 
    Derivative
    Instruments        Commodity
    Swaps and Put Options
   F-54




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS PREDECESSOR
  Notes to
    Unaudited Condensed Combined Financial
    Statements  (Continued)
    2006


2007Unrealized 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
)


1,968Realized loss on crude oil puts


(705
)


(758
)Total realized gain


(2,639
)


1,210Net loss on derivative instruments

$
(24,569
)

$
(19,541
)   Note 8 
    Commitments
    and Contingencies  2 2 2 2
    CommitmentYear

(in millions)2007

$
5.72008


15.42009


26.12010


17.62011


13.4Thereafter


25.7$
103.9      F-55




---



##### Table of Contents



REPORT
    OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
                 F-56




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS, LP
  Balance Sheet
 September 26,
    2007
  ASSETSCash

$
1,000Total assets

$
1,000   PARTNERS EQUITYPartners capital:Limited partner

$
980General partner


20Total partners capital

$
1,000    F-57




---



##### Table of Contents



RESOLUTE
    ENERGY PARTNERS, LP
    Note to Balance Sheet
    September 26, 2007
  (1)
    Organization     F-58




---



##### Table of Contents



REPORT
    OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
  To the Board
    of Directors of
    Resolute Energy GP, LLC
    Denver, Colorado
          
 F-59




---



##### Table of Contents



RESOLUTE
    ENERGY GP, LLC
  Balance Sheet
 September 26,
    2007
  ASSETSCash

$
980Investment in Resolute Energy Partners, LP


20Total assets

$
1,000   MEMBERS EQUITYMembers equity


1,000Total members equity

$
1,000    F-60




---



##### Table of Contents



RESOLUTE
    ENERGY GP, LLC
    Note to Balance Sheet
    September 26, 2007
  (1)
    Organization     F-61




---



##### Table of Contents



REPORT
    OF INDEPENDENT REGISTERED
    PUBLIC ACCOUNTING FIRM
  
               F-62




---



##### Table of Contents



CHEVRON
    PROPERTIES
  Statements
    of Revenues and Direct Operating Expenses
  For the Year


For the ElevenEnded


Months EndedDecember 31,


November 30,2003


2004Revenues  oil and gas production

$
25,266,630


$
27,626,768Direct operating expensesLease operating expense


7,569,340



6,526,130Production and ad valorem taxes


2,813,168



2,972,408Total direct operating expenses


10,382,508



9,498,538Revenues in excess of direct operating expenses

$
14,884,122


$
18,128,230    F-63




---



##### Table of Contents



CHEVRON
    PROPERTIES
  Notes
    to the Statements of Revenues and Direct Operating
    Expenses
  Note 1 
    Operations, Organization, and Basis of
    Presentation
       
   
  Use
    of Estimates
    Note 2 
    Omitted Financial Information
 
  Rule 3-01 Regulation S-X.
 
  Note 3 
    Supplemental Disclosures on Oil and Gas Exploration, Development
    and Production Activities (Unaudited)
  Reserves
    Gas


OilMMcf


MBblProved developed reserves


1,492



12,308Proved undeveloped reserves






Total proved reserves


1,492



12,308   F-64




---



##### Table of Contents



CHEVRON
    PROPERTIES
  Notes to
    the Statements of Revenues and Direct Operating
    Expenses  (Continued)
  Gas


OilMMcf


MBblProved reserves as of January 1, 2003


1,440



11,242Production in 2003


(556
)


(820
)Revisions


484



334Proved reserves as of December 31, 2003


1,368



10,756Production for eleven months ended November 30, 2004


(432
)


(673
)Revisions


556



2,225Proved 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
    As of


As ofDecember 31,


November 30,2003


2004(In thousands)Future cash inflows

$
320,072


$
572,445Future production costs


(191,225
)


(283,363
)Future development costs


(1,614
)


(222
)Future net cash flows


127,233



288,86010% 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-65




---



##### Table of Contents



CHEVRON
    PROPERTIES
  Notes to
    the Statements of Revenues and Direct Operating
    Expenses  (Continued)
     For the Year


For the ElevenEnded


Months EndedDecember 31,


November 30,2003


2004(In thousands)Beginning of period

$
64,106


$
65,670Sales 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



65,178Development costs incurred


1,656



1,392Revisions of quantity estimates


2,485



27,512Changes in production rates and other


(900
)


(15,453
)Accretion of discount


6,411



6,567End of period

$
65,670


$
132,738  F-66




---



##### Table of Contents



REPORT
    OF INDEPENDENT REGISTERED
    PUBLIC ACCOUNTING FIRM
                  F-67




---



##### Table of Contents



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


$
16,658,179Direct operating expensesLease operating expense


9,908,790



11,889,669



12,511,167



2,926,030



3,247,802Production and ad valorem taxes


5,395,302



6,305,998



8,019,769



1,787,552



2,011,965Total direct operating expenses


15,304,092



18,195,667



20,530,936



4,713,582



5,259,767Revenues in excess of direct operating expenses

$
29,656,759


$
32,788,170


$
47,177,008


$
10,378,062


$
11,398,412    F-68




---



##### Table of Contents



EXXONMOBIL
    PROPERTIES
  Notes to the Statements of Revenues and Direct Operating
    Expenses
  Note 1 
    Operations,
    Organization, and Basis of Presentation       
   
    Use
    of Estimates
    Note 2 
    Omitted
    Financial Information 
  Rule 3-01 Regulation S-X.
 
 F-69




---



##### Table of Contents



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
    Gas


OilMMcf


MBblProved developed reserves


732



14,848Proved undeveloped reserves






1,122Total proved reserves


732



15,970   Gas


OilMMcf


MBblProved reserves as of January 1, 2003


1,272



14,278Production in 2003


(1,295
)


(1,436
)Revisions


1,177



501Proved reserves as of December 31, 2003


1,154



13,343Production in 2004


(1,101
)


(1,222
)Revisions


1,035



2,202Proved reserves as of December 31, 2004


1,088



14,323Production in 2005


(1,145
)


(1,201
)Revisions


789



1,726Improved/enhanced recovery






1,122Proved reserves as of December 31, 2005


732



15,970   Standardized
    Measure of Discounted Future Net Cash Flows Relating to Proved
    Oil and Gas Reserves
   F-70




---



##### Table of Contents



EXXONMOBIL
    PROPERTIES
  Notes to
    the Statements of Revenues and Direct Operating
    Expenses  (Continued)
    As of December 31,2003


2004


2005(In thousands)Future cash inflows

$
398,738


$
583,115


$
932,447Future production costs


(253,079
)


(326,911
)


(435,629
)Future development costs


(227
)


(13
)


(4,908
)Future net cash flows


145,432



256,191



491,91010% 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     For the Year Ended December 31,2003


2004


2005(In thousands)Beginning of year

$
89,173


$
87,750


$
145,166Sales 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



92,363Extensions and discoveries and improved recovery, net of future
    costs










8,117Changes in estimated future development costs










(1,556
)Development costs incurred


232



213



13Revisions of quantity estimates


4,529



25,305



34,781Changes in production rates and other


6,650



16,082



18Accretion of discount


8,917



8,775



14,517End of year

$
87,750


$
145,166


$
246,242  F-71




---



##### Table of Contents



APPENDIX A
  FIRST
    AMENDED AND RESTATED
    AGREEMENT OF LIMITED PARTNERSHIP
    OF
    RESOLUTE ENERGY PARTNERS, LP
 A-1




---



##### Table of Contents



APPENDIX B
  GLOSSARY
    OF TERMS
  2-D
    seismic or
    3-D
    seismic. 3-D 2-D
  adjusted operating surplus.
  
    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.
  (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, provided, further,
  Bbl.
  Bbl/d.
  Bcf.
 B-1




---



##### Table of Contents



Boe.
  Btu or British thermal unit.
  capital account.
  capital surplus.
 
  closing price.
 
  completion.
  cumulative common unit arrearage.
  current market price.
  developed acreage.
  development well.
  dry hole.
  environmental assessment (EA).
  environmental impact statement (EIS).
 B-2




---



##### Table of Contents



formation.
  field. and/or
  GAAP.
  gross acres or gross wells.
  horizontal drilling.
  interim capital transactions.
  (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.
 
  MBoe.
 
  Mcf.
  Mcf/d.
  MMBbl.
  MMBoe.
  MMBtu.
  MMcf.
  Natural gas liquids.
  net acres or net wells.
  NYMEX.
  operating expenditures.
 B-3




---



##### Table of Contents



(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.
  (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 acquisition 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 asset and ending on the earlier to occur of the date the
    capital asset is placed into service (or, with respect to
    non-producing reserves, the date the reserves begin producing
    hydrocarbons in commercial quantities) 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.
  productive well.
  prospect.
 B-4




---



##### Table of Contents



proved developed non-producing reserves
    (PDNP).
  proved developed reserves (PDP). Rule 4-10(a)(3) Regulation S-X,
    proved reserves. Rule 4-10(a)(2) Regulation S-X,
    (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-oil
    and/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). Rule 4-10(a)(4) Regulation S-X,
    recompletion.
 B-5




---



##### Table of Contents



reservoir. and/or
  royalty interest.
  standardized measure.
  subordination period.
  (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.
  working capital borrowings.
  working interest.
  workover.
 B-6




---



##### Table of Contents



NSA Letterhead

Chairman EmeritusClarence M. NetherlandChairman & CEOFrederic D. SewellPresident & COOC.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
    Regulation S-X Rule 4-10(a)
    Future Net Revenue (M$)Net Reserves





PresentOil


Gas





WorthCategory

(MBBL)


(MMCF)


Total


at 10%Proved DevelopedProducing


28,717.1



4,023.8



988,335.4



505,782.1Non-Producing


4,528.0



1,151.3



183,567.5



76,624.3Proved Undeveloped


44,547.3



(3,545.4
)(1)


2,024,175.2



576,925.4Total 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.    unit-by-unit
    4500
    Thanksgiving 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 C-1




---



##### Table of Contents



C-2




---



##### Table of Contents



By:
    /s/  C.H.
    (Scott) Rees III     By:
    /s/  David
    T. Miller       DTM:JAT
 C-3




---



##### Table of Contents








---



##### Table of Contents



PART II
  INFORMATION
    NOT REQUIRED IN THE PROSPECTUS
  Item 13.
    Other Expenses of Issuance and Distribution.
    SEC registration fee

$
10,195NASD filing fee


33,706New 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 General
    Partners Board of Directors.
 
  Section 17-108
    Item 15.
    Recent Sales of Unregistered Securities.
   II-1




---



##### Table of Contents



Item 16.
    Exhibits.
    
 ExhibitNumber



Description1
.1**



Form of Underwriting Agreement2
.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, 20052
.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, 20043
.1*



Certificate of Limited Partnership of Resolute Energy Partners,
    LP3
.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)5
.1**



Opinion of Vinson & Elkins L.L.P. as to the legality
    of the securities being registered8
.1**



Opinion of Vinson & Elkins L.L.P. relating to tax
    matters10
.1**



Form of Revolving Credit Facility10
.2**



Form of Resolute Energy Partners, LP Long-Term Incentive Plan10
.3**



Form of Contribution, Conveyance and Assumption Agreement10
.4**



Form of Administrative Services Agreement10
.5**



Form of Indemnification Agreement between Resolute Energy
    Partners, LP and each executive officer and independent director
    of its general partner10
.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*



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
.9*



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)10
.10***



Crude Oil Purchase and Sale Agreement, Giant Contract Number
    4895-RMS-P, Amendment 1, by and between Resolute Natural
    Resources Company and Giant Industries, Inc. dated May 31,
    200710
.11***



Crude Oil Purchase and Sale Agreement, Giant Contract Number
    4206-RMS-P, Amendment 3, by and between Resolute Natural
    Resources Company and Giant Industries, Inc. dated May 31,
    200710
.12***



Consent Decree, entered into June 2005, relating to alleged
    violations of the federal Clean Air Act10
.13***



Consent Decree, entered into August 2004, relating to alleged
    violations of the federal Clean Water Act10
.14***



Base Contract for Sale and Purchase of Natural Gas between
    Odyssey Energy Services, LLC and Resolute Natural Resources
    Company dated September 1, 2005 
 II-2




---



##### Table of Contents



ExhibitNumber



Description21
.1**



List of Subsidiaries of Resolute Energy Partners, LP23
.1***



Consent of Ehrhardt Keefe Steiner & Hottman PC23
.2***



Consent of Deloitte & Touche LLP23
.3***



Consent of Sproule Associates Limited23
.4***



Consent of Netherland, Sewell & Associates, Inc.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  
   
  *
    
    Previously filed. 
 
  **
    
    To be filed by amendment. 
 
  ***
    
    Filed herewith. 
  
    
    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) of
    Regulation 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.
        (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. II-3




---



##### Table of Contents



Form 10-K
 II-4




---



##### Table of Contents



SIGNATURES
 
   
    
  Nicholas
    J. Sutton
   Title:
    Chief Executive Officer 
   
  
 Signature

Title/s/  Nicholas
    J. SuttonNicholas
    J. Sutton

Chief Executive Officer (Principal Executive Officer)
    and Director/s/  Theodore
    GazulisTheodore
    Gazulis

Chief Financial Officer (Principal Financial Officer and
    Principal Accounting Officer)/s/  James
    PicconeJames
    Piccone

Director*Kenneth
    A. Hersh

Director*Richard
    L. Covington

Director*By:

/s/  James
    PicconeJames
    Piccone  
 II-5




---



##### Table of Contents



EXHIBIT INDEX
  
 ExhibitNumber



Description1
.1**



Form of Underwriting Agreement2
.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, 20052
.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, 20043
.1*



Certificate of Limited Partnership of Resolute Energy Partners,
    LP3
.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)5
.1**



Opinion of Vinson & Elkins L.L.P. as to the legality
    of the securities being registered8
.1**



Opinion of Vinson & Elkins L.L.P. relating to tax
    matters10
.1**



Form of Revolving Credit Facility10
.2**



Form of Resolute Energy Partners, LP Long-Term Incentive Plan10
.3**



Form of Contribution, Conveyance and Assumption Agreement10
.4**



Form of Administrative Services Agreement10
.5**



Form of Indemnification Agreement between Resolute Energy
    Partners, LP and each executive officer and independent director
    of its general partner10
.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*



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
.9*



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)10
.10***



Crude Oil Purchase and Sale Agreement, Giant Contract Number
    4895-RMS-P, Amendment 1, by and between Resolute Natural
    Resources Company and Giant Industries, Inc. dated May 31,
    200710
.11***



Crude Oil Purchase and Sale Agreement, Giant Contract Number
    4206-RMS-P, Amendment 3, by and between Resolute Natural
    Resources Company and Giant Industries, Inc. dated May 31,
    200710
.12***



Consent Decree, entered into June 2005, relating to alleged
    violations of the federal Clean Air Act10
.13***



Consent Decree, entered into August 2004, relating to alleged
    violations of the federal Clean Water Act10
.14***



Base Contract for Sale and Purchase of Natural Gas between
    Odyssey Energy Services, LLC and Resolute Natural Resources
    Company dated September 1, 200521
.1**



List of Subsidiaries of Resolute Energy Partners, LP23
.1***



Consent of Ehrhardt Keefe Steiner & Hottman PC




---



##### Table of Contents



ExhibitNumber



Description23
.2***



Consent of Deloitte & Touche LLP23
.3***



Consent of Sproule Associates Limited23
.4***



Consent of Netherland, Sewell & Associates, Inc.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  
   
  *
    
    Previously filed. 
 
  **
    
    To be filed by amendment. 
 
  ***
    
    Filed herewith. 
  
    
    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) of
    Regulation 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.