Company Quick10K Filing
Resolute Energy
Price37.52 EPS-1
Shares23 P/E-27
MCap869 P/FCF6
Net Debt707 EBIT-10
TEV1,576 TEV/EBIT-159
TTM 2018-09-30, in MM, except price, ratios
10-Q 2018-09-30 Filed 2018-11-05
10-Q 2018-06-30 Filed 2018-08-06
10-Q 2018-03-31 Filed 2018-05-07
10-K 2017-12-31 Filed 2018-03-12
10-Q 2017-09-30 Filed 2017-11-06
10-Q 2017-06-30 Filed 2017-08-07
10-Q 2017-03-31 Filed 2017-05-03
10-K 2016-12-31 Filed 2017-03-13
10-Q 2016-09-30 Filed 2016-11-07
10-Q 2016-06-30 Filed 2016-08-08
10-Q 2016-03-31 Filed 2016-05-09
10-K 2015-12-31 Filed 2016-03-07
10-Q 2015-09-30 Filed 2015-11-09
10-Q 2015-06-30 Filed 2015-08-10
10-Q 2015-03-31 Filed 2015-05-11
10-K 2014-12-31 Filed 2015-03-05
10-Q 2014-09-30 Filed 2014-11-10
10-Q 2014-06-30 Filed 2014-08-11
10-Q 2014-03-31 Filed 2014-05-12
10-K 2013-12-31 Filed 2014-03-10
10-Q 2013-09-30 Filed 2013-11-05
10-Q 2013-06-30 Filed 2013-08-05
10-Q 2013-03-31 Filed 2013-05-06
10-Q 2012-06-30 Filed 2012-08-06
10-Q 2012-03-31 Filed 2012-05-08
10-Q 2011-09-30 Filed 2011-11-07
10-Q 2011-06-30 Filed 2011-08-08
10-Q 2011-03-31 Filed 2011-05-06
10-K 2010-12-31 Filed 2011-03-15
10-Q 2010-09-30 Filed 2010-11-15
10-Q 2010-06-30 Filed 2010-08-12
10-Q 2010-03-31 Filed 2010-05-11
10-K 2009-12-31 Filed 2010-03-30
8-K 2019-03-01
8-K 2019-02-22
8-K 2019-02-14
8-K 2019-02-11
8-K 2018-11-19
8-K 2018-11-18
8-K 2018-10-11
8-K 2018-09-30
8-K 2018-09-14
8-K 2018-06-30
8-K 2018-06-19
8-K 2018-06-11
8-K 2018-05-15
8-K 2018-05-09
8-K 2018-04-05
8-K 2018-03-31
8-K 2018-03-16
8-K 2018-03-12
8-K 2018-02-26
8-K 2018-02-13
8-K 2018-02-08
8-K 2018-01-01

REN 10K Annual Report

Part I
Item 1. and 2. Business and Properties
Item 1A. Risk Factors
Item 3. Legal Proceedings
Item 4. Reserved
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitive and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Goverance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions and Director Independence
Item 14. Principal Accounting Fee and Services
Part IV
Item 15. Exhibits, Financial Statement Schedules
Note 1 - Organization and Nature of Business
Note 2 - Basis of Presentation and Summary of Significant Accounting Policies
Note 3 - Acquisitions and Divestitures
Note 4 - Earnings per Share
Note 5 - Marketable Securities Held in Trust
Note 6 - Related Party Transactions
Note 7 - Long Term Debt
Note 8 - Income Taxes
Note 9 - Stockholders' Equity and Equity Based Awards
Note 10 - Employee Benefits
Note 11 - Derivative Instruments
Note 12 - Fair Value Measurements
Note 13 - Commitments and Contingencies
Note 14 - Oil and Gas Producing Activities
Note 15 - Supplemental Oil and Gas Information (Unaudited)
Note 16 - Quarterly Financial Data (Unaudited)
Note 1 - Description of The Companies and Business
Note 2 - Basis of Presentation and Significant Accounting Policies
Note 3 - Acquisitions
Note 4 - Asset Retirement Obligations
Note 5 - Related Party Transactions
Note 6 - Long Term Debt
Note 7 - Income Taxes
Note 8 - Shareholder'S/Member's Equity and Equity Based Awards
Note 9 - Defined Contribution Plan
Note 10 - Derivative Instruments
Note 11 - Fair Value Measurements
Note 12 - Commitments and Contingencies
Note 13 - Oil and Gas Producing Activities
Note 14 - Supplemental Oil and Gas Information (Unaudited)
EX-12.1 d80587exv12w1.htm
EX-21 d80587exv21.htm
EX-23.1 d80587exv23w1.htm
EX-23.2 d80587exv23w2.htm
EX-23.3 d80587exv23w3.htm
EX-31.1 d80587exv31w1.htm
EX-31.2 d80587exv31w2.htm
EX-32 d80587exv32.htm
EX-99.1 d80587exv99w1.htm

Resolute Energy Earnings 2010-12-31

Balance SheetIncome StatementCash Flow
1.71.30.90.40.0-0.42013201520172019
Assets, Equity
0.20.10.0-0.0-0.1-0.22013201520172019
Rev, G Profit, Net Income
0.30.20.0-0.1-0.3-0.42013201520172019
Ops, Inv, Fin

10-K 1 d80587e10vk.htm FORM 10-K e10vk
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
 
 
 
 
FORM 10-K
 
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2010
OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from     to     
 
Commission File No. 001-34464
 
 
 
 
RESOLUTE ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
 
     
Delaware
  27-0659371
(State or other Jurisdiction of Incorporation or Organization)   (I.R.S. Employer Identification Number)
     
1675 Broadway, Suite 1950 Denver, CO
  80202
(Address of Principal Executive Offices)
  (Zip Code)
 
(303) 534-4600
 
(Registrant’s telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Act:
 
       
Title of Each Class
   
Name of Exchange on Which Registered
Common Stock, par value $0.0001 per share
    New York Stock Exchange
Warrants, each exercisable for one share of Common Stock
    New York Stock Exchange
       
 
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act Yes o No þ
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 of the Exchange Act Yes o No þ
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
 
Indicate by check mark if delinquent filers pursuant to item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, indefinite proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
     
Large accelerated filer o
  Accelerated filer þ
Non-accelerated filer o
  Smaller reporting company o
(Do not check if a smaller reporting company)
   
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
 
The aggregate market value of registrant’s common stock held by non-affiliates on June 30, 2010, computed by reference to the price at which the common stock was last sold as posted on the New York Stock Exchange, was $405.2 million.
 
As of March 10, 2011, 56,345,041 shares of the Registrant’s $0.0001 par value Common Stock were outstanding.
 
The following documents are incorporated by reference herein: Portions of the definitive Proxy Statement of Resolute Energy Corporation to be filed pursuant to Regulation 14A of the general rules and regulations under the Securities Exchange Act of 1934, as amended, for the 2011 annual meeting of stockholders (“Proxy Statement”) are incorporated by reference into Part III of this Form 10-K.
 


Table of Contents

 
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
This Annual Report on Form 10-K contains “forward-looking statements” as that term is defined in the Private Securities Litigation Reform Act of 1995. The use of any statements containing the words “anticipate,” “intend,” “believe,” “estimate,” “project,” “expect,” “plan,” “should” or similar expressions are intended to identify such statements. Forward-looking statements included in this report relate to, among other things, expected future production, expenses and cash flows in 2011 and beyond, the nature, timing and results of capital expenditure projects, amounts of future capital expenditures, our plans with respect to future acquisitions, our future debt levels and liquidity, future derivative activities and future compliance with covenants under our revolving credit facility. Although we believe that the expectations reflected in such forward-looking statements are reasonable, those expectations may prove to be incorrect. Disclosure of important factors that could cause actual results to differ materially from our expectations, or cautionary statements, are included under the heading “Risk Factors” in this report. All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, we undertake no obligation to update any forward-looking statement. Factors that could cause actual results to differ materially from our expectations include, among others, those factors referenced in the “Risk Factors” section of this report and such things as:
 
  •  volatility of oil and gas prices, including reductions in prices that would adversely affect our revenue, income, cash flow from operations, liquidity and reserves;
 
  •  inaccuracy in reserve estimates and expected production rates;
 
  •  discovery and development of, and our ability to replace oil and gas reserves;
 
  •  our future cash flow, liquidity and financial position;
 
  •  the success of our business and financial strategy, derivative strategies and plans;
 
  •  the amount, nature and timing of our capital expenditures, including future development costs;
 
  •  Availability of capital and financing;
 
  •  the effectiveness and results of our CO2 flood program;
 
  •  the success of the development plan and production from our oil and gas properties and particularly the Aneth Field Properties;
 
  •  the timing and amount of future production of oil and gas;
 
  •  the completion and success of exploratory drilling in the Bakken trend of the Williston Basin;
 
  •  availability of drilling, completion and production equipment;
 
  •  our operating costs and other expenses;
 
  •  the success in marketing oil and gas;
 
  •  competition in the oil and gas industry;
 
  •  operational problems, or uninsured or underinsured losses affecting our operations;
 
  •  the impact and costs related to compliance with or changes in laws or regulations governing our oil and gas operations;
 
  •  our relationship with the Navajo Nation, the local Navajo community in the area where we operate and Navajo Nation Oil and Gas Company, as well as the timing of when certain purchase rights held by Navajo Nation Oil and Gas Company become exercisable;
 
  •  the impact of weather and the occurrence of disasters, such as fires, floods and other events and natural disasters;
 
  •  environmental liabilities;


Table of Contents

 
  •  anticipated CO2 supply which is currently sourced exclusively from Kinder Morgan CO2 Company, L.P. (“Kinder Morgan”);
 
  •  risks related to our level of indebtedness;
 
  •  developments in oil and gas-producing countries;
 
  •  loss of senior management or technical personnel;
 
  •  acquisitions and other business opportunities (or the lack thereof) that may be presented to and pursued by us;
 
  •  risk factors discussed or referenced in this report; and
 
  •  other factors, many of which are beyond our control.


 

 
TABLE OF CONTENTS
 
                 
  PART I --              
  Item 1. and 2.     Business and Properties     1  
  Item 1A.     Risk Factors     28  
  Item 3.     Legal Proceedings     44  
  Item 4.     Reserved     44  
  PART II --              
  Item 5.     Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     45  
  Item 6.     Selected Financial Data     47  
  Item 7.     Management’s Discussion and Analysis of Financial Condition and Results of Operations     48  
  Item 7A.     Quantitative and Qualitative Disclosures About Market Risk     60  
  Item 8.     Financial Statements and Supplementary Data     61  
  Item 9.     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     61  
  Item 9A.     Controls and Procedures     61  
  Item 9B.     Other Information     62  
  PART III --              
  Item 10.     Directors, Executive Officers and Corporate Governance     62  
  Item 11.     Executive Compensation     62  
  Item 12.     Security Ownership of Certain Beneficial Owners and Mangement and Related Stockholder Matters     62  
  Item 13.     Certain Relationships and Related Transactions and Director Independence     62  
  Item 14.     Principal Accounting Fees and Services     62  
  PART IV --              
  Item 15.     Exhibits, Financial Statement Schedules     63  
 EX-12.1
 EX-21
 EX-23.1
 EX-23.2
 EX-23.3
 EX-31.1
 EX-31.2
 EX-32
 EX-99.1


Table of Contents

PART I
 
Item 1. and 2. BUSINESS AND PROPERTIES
 
RESOLUTE’S BUSINESS
 
Resolute Energy Corporation (“Resolute” or the “Company”), a Delaware corporation incorporated on July 28, 2009, was formed to consummate a business combination with Hicks Acquisition Company I, Inc. (“HACI”), a Delaware corporation incorporated on February 26, 2007. HACI was a blank check company that was formed to acquire through a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination, one or more businesses or assets. HACI’s initial public offering (the “Offering”) was consummated on October 3, 2007. HACI had not engaged in any operations or generated any operating revenue prior to the business combination with Resolute.
 
On September 25, 2009 (the “Acquisition Date”), HACI consummated a business combination under the terms of a Purchase and IPO Reorganization Agreement (“Acquisition Agreement”) with Resolute and Resolute Holdings Sub, LLC (“Sub”), whereby, through a series of transactions, HACI’s stockholders collectively acquired a majority of the outstanding shares of Resolute common stock (the “Resolute Transaction”). As a result of the Resolute Transaction, Resolute owned, directly or indirectly, 100% of the equity interests of Resolute Natural Resources Company, LLC (“Resources”), WYNR, LLC (“WYNR”), BWNR, LLC (“BWNR”), RNRC Holdings, Inc. (“RNRC”), and Resolute Wyoming, Inc. (“RWI”) (formerly known as Primary Natural Resources, Inc. (“PNR”)), and owned a 99.996% equity interest in Resolute Aneth, LLC (“Aneth”), (collectively “Predecessor Resolute”). The entities comprising Predecessor Resolute prior to the Resolute Transaction were wholly owned by Sub (except for Aneth, which was 99.996% owned by Sub), which in turn is a wholly-owned subsidiary of Resolute Holdings, LLC (“Holdings”). Under accounting principles generally accepted in the United States (“GAAP”), HACI was the accounting acquirer. Effective December 31, 2010, Aneth became a wholly-owned subsidiary of the Company.
 
Resolute is an independent oil and gas company engaged in the exploration, exploitation and development of its oil and gas properties located in Utah, Wyoming, North Dakota and, to a lesser extent, properties in Alabama and Oklahoma. Approximately 88% of Resolute’s revenue is generated from the sale of oil production. Resolute’s main focus is on increasing reserves and production from its properties located in Utah (its “Aneth Field Properties”), North Dakota (its “Bakken Properties”) and Wyoming and Oklahoma (its “Wyoming Properties”), while improving efficiency and controlling operational costs.
 
Resolute has completed a number of exploitation projects that have increased its proved developed reserve base, and it has plans for additional expansion and enhancement projects. Resolute plans to further expand its reserve base through a focused acquisition strategy by looking to acquire properties that have upside potential through development drilling and exploitation projects and through the acquisition, exploration and exploitation of acreage that appears to contain relatively low risk and repeatable drilling opportunities. Also, Resolute seeks to reduce the effect of short-term commodity price fluctuations on its cash flow through the use of various derivative instruments.
 
Resolute’s largest asset, constituting 92% of its proved reserves, is its ownership of working interests in Greater Aneth Field (“Aneth Field”), a mature, long-lived oil producing field located in the Paradox Basin on the Navajo Reservation in southeast Utah. Resolute owns a majority of the working interests in, and is the operator of, three federal production units covering approximately 43,000 gross acres. These are the Aneth Unit, in which Resolute owns a 62% working interest, the McElmo Creek Unit, in which Resolute owns a 75% working interest, and the Ratherford Unit, in which Resolute owns a 59% working interest. Resolute believes that significantly more oil can be recovered from its Aneth Field Properties through industry standard secondary and tertiary recovery techniques. As of December 31, 2010, Resolute had interests in, and operated 397 gross (260 net) active producing wells and 334 gross (218 net) active water and CO2 injection wells in its Aneth Field Properties. The crude oil produced from the Aneth Field Properties is generally characterized as light, sweet crude oil that is highly desired as a refinery blending feedstock.


1


Table of Contents

Resolute’s Wyoming Properties are largely located in the Powder River Basin of Wyoming and constitute approximately 7% of Resolute’s net proved reserves. Hilight Field, anchoring the Wyoming production and reserves, produces oil and gas from the Muddy formation as well as shallow coalbed methane (“CBM”). Resolute also owns properties in eastern Wyoming and Oklahoma that produce oil and gas. As of December 31, 2010, the Wyoming Properties consisted of 465 gross (418 net) active producing wells and 8 gross (6 net) active water injection wells and Resolute operates all but 6 gross (1 net) wells. In addition, Resolute holds exploration leasehold rights in Wyoming’s Big Horn Basin.
 
As of December 31, 2010, Resolute had acquired interests in approximately 83,452 gross (24,965 net leasehold) acres in Williams and McKenzie Counties, North Dakota. These leaseholds are located within the Bakken shale trend of the Williston Basin. Although the Middle Bakken formation is the primary objective of the Company’s exploration activities, secondary objectives include the Three Forks, Madison and Red River formations. During 2010, the Company acquired an interest in one completed well and participated in drilling and completing one horizontal well. Additionally, Resolute is party to a contract with Marathon Oil Corporation (“Marathon”), under which it has earned an additional 3,870 net acres as of January 16, 2011. As of December 31, 2010, Resolute had interests in, but was not the operator of 2 gross (0.5 net) active wells. The Company participated in drilling activities on five additional wells during 2010 which are expected to be completed during 2011, and anticipates participating in drilling and completing between fourteen to sixteen new wells in 2011.
 
As of December 31, 2010, Resolute’s estimated net proved reserves were approximately 64.7 million equivalent barrels of oil (“MMBoe”), of which approximately 39% were proved developed producing reserves and approximately 78% were oil. The pre-tax PV-10 of Resolute’s net proved reserves at December 31, 2010, was $848 million and the standardized measure of its estimated net proved reserves as of December 31, 2010, was $587.0 million. For additional information about the calculation of Resolutes’s PV-10 and its standardized measure, please read “Business and Properties — Estimated Net Proved Reserves.”
 
The following table sets forth summary information attributable to Resolute’s estimated net proved reserves that is derived from its December 31, 2010, reserve report which was developed by Resolute and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers.
 
                                                         
                                        Average Net
 
    Estimated Net Proved Reserves as of December 31, 2010     Daily
 
    Proved
    Proved
                            Production
 
    Developed
    Developed
    Proved Undeveloped           Total
    (Boe per day)
 
    Producing     Non-Producing     CO2     Drilling     Total     Proved     (1)  
 
Aneth Field Properties (MMBoe)
    22.1       8.3       29.0       0.4       29.4       59.8       5,682  
Wyoming Properties (MMBoe)
    2.8       1.0             1.0       1.0       4.8       1,787  
Bakken Properties (MMBoe)
    0.1                               0.1       9  
Total (MMBoe)
    25.0       9.3       29.0       1.4       30.4       64.7       7,478  
Future operating costs ($/Boe)(2)
  $  28.71     $  11.75     $  8.34     $  8.52     $  8.35     $  16.72        
Future production taxes ($/Boe)(3)
  $ 10.13     $ 9.09     $ 8.48     $ 6.37     $ 8.38     $ 9.16        
Future PUD development costs (millions)(4)
              $  375.6     $ 22.9     $ 398.6              
Future PUD development costs ($/Boe)(5)
              $ 12.96     $  16.69     $  13.13              
 
 
1) For the year ended December 31, 2010.
 
2) Determined by dividing Resolute’s estimated future operating costs as of December 31, 2010, by total estimated net proved reserves as of December 31, 2010, for each reserve category.
 
3) Determined by dividing Resolute’s estimated future production taxes as of December 31, 2010, by total estimated net proved reserves as of December 31, 2010, for each reserve category.
 
4) Future development costs include costs incurred in connection with the initiation, extension and expansion of CO2 flood projects, including CO2 purchases, drilling of development wells, upgrades to field infrastructure, workovers of producing wells and recompletion of existing wells into new producing zones.
 
5) Determined by dividing Resolute’s estimated total future development costs related to reserves classified as proved undeveloped by total estimated net proved undeveloped reserves as of December 31, 2010.


2


Table of Contents

 
Resolute’s Business Strategies
 
Bring Proved Developed Non-Producing and Proved Undeveloped Reserves into Production. At December 31, 2010, Resolute had estimated net proved reserves of approximately 39.7 MMBoe that were classified as proved developed non-producing and proved undeveloped. An estimated 37.4 MMBoe, or 94% of those reserves, are attributable to recoveries associated with expansions, extensions and processing of the tertiary recovery CO2 floods that are currently in operation on Resolute’s Aneth Field Properties. Resolute incurred approximately $37.3 million of capital expenditures related to the Aneth Field Properties during 2010, and Resolute expects to incur an additional $446.7 million of capital expenditures over the next 29 years (including purchases of CO2), in connection with bringing those incremental reserves attributable to Resolute’s CO2 flood projects into production. Resolute’s current plan anticipates approximately $198.4 million of these future capital expenditures will be incurred from 2011 through 2013.
 
Increase Production and Improve Efficiency of Operations on Resolute’s Existing Properties. Resolute’s management team has experience in managing operationally intensive oil and gas properties. As the operator of the Aneth Field Properties, Resolute has the ability to directly manage its costs, control the timing of its exploitation activities and effectively implement programs to increase production and improve the efficiency of its operations. For example, Predecessor Resolute initiated a program to actively work with vendors to reduce labor and material costs. Predecessor Resolute also conducted a proprietary 3-D seismic survey of the Aneth Unit in 2007, which is the first 3-D seismic survey covering Aneth Field. Resolute expects that the data obtained from this seismic survey will provide information to enable it to more efficiently develop and improve the recovery from its Aneth Field Properties. In addition, soon after Predecessor Resolute acquired properties from Chevron and ExxonMobil and became the operator of the Aneth, McElmo Creek and Ratherford Units, Predecessor Resolute undertook a program of repair and maintenance of those producing assets. As a result of these efforts, Resolute has seen a reduction in well workover costs. Also, because Resolute is the operator of three federal units in Aneth Field, it has been able to assemble a critical mass of employees and projects and allocate its resources across a broader area in a more efficient manner than was previously the case when each unit had a different operator.
 
Pursue Acquisitions of Properties with Development Potential. From inception, Predecessor Resolute’s goal was to grow its reserve base through a focused acquisition strategy. It completed three significant acquisitions, two in Utah and one in Wyoming. Substantially all of its Aneth Field Properties were acquired through significant purchases in November 2004 and April 2006. Predecessor Resolute then acquired its Wyoming Properties in July 2008. Resolute will continue to look to acquire similar producing properties in the continental United States that have upside potential through relatively low-risk development drilling and exploitation projects. It believes its knowledge of various operating areas, strong management and staff and solid industry relationships will allow it to find, capitalize on and integrate strategic acquisition opportunities in various areas.
 
Acquire and Explore Properties in Oil Prone Areas. Resolute has acquired leasehold interests in the Williston Basin that are prospective for oil production in the Middle Bakken formation as well as other formations. Resolute intends to explore these properties and to acquire, explore and develop other properties in areas of the United States that are prospective for production of oil or natural gas liquids (“NGL”).
 
Reduce Commodity Price Risk through Derivatives. Resolute seeks to reduce the effect of short-term commodity price fluctuations and achieve less volatile and more predictable cash flows through the use of various derivative instruments such as swaps, puts, calls and collars. Resolute expects to continue to use these financial arrangements to reduce its commodity price risk. As of December 31, 2010, Resolute had in place oil swaps covering approximately 60% of its anticipated 2011 oil production at a weighted average price of $68.26 per Bbl, oil collars covering approximately 5% of its anticipated 2011 oil production with a floor of $80.00 per Bbl and a ceiling of $90.00 per Bbl, gas swaps covering approximately 47% of its anticipated 2011 gas production at a weighted average price of $9.32 per MMBtu, and gas basis derivatives at a weighted average price of $1.40 per MMBtu covering approximately 57% of its anticipated 2011 gas production. Additional instruments are also in place for future years. See “Item 7A Quantitative and Qualitative Disclosures about Market Risk” for additional information.


3


Table of Contents

Competitive Strengths
 
A High Quality Base of Long-Lived Oil Producing Properties. The Aneth Field Properties have several characteristics that Resolute believes will provide a stable production platform with which to fund its development and growth activities:
 
  •   The properties are expected to have a long productive life. As of December 31, 2010, the proved developed producing reserves had a reserves-to-production ratio of approximately 11 years and the total proved reserves had a reserves-to-production ratio of 29 years.
 
  •   The light, sweet crude oil produced from its Aneth Field Properties is more attractive to refineries than the heavy or sour crude oil found in many areas, including the Permian Basin.
 
Properties with Significant Low-Risk and Low-Cost Development Opportunities. As of December 31, 2010, approximately 39.7 MMBoe, or 61% of Resolute’s estimated net proved reserves, were classified as proved developed non-producing or proved undeveloped. An estimated 37.4 MMBoe, or 94% of those reserves, are attributable to recoveries associated with expansions, extensions and processing of the tertiary recovery CO2 floods that are currently in operation on Resolute’s Aneth Field Properties. Resolute’s current development plan for its Aneth Field Properties indicates that in five years the daily production rate, on a Boe basis, should be 84% higher than the average production rate achieved during the twelve months ended December 31, 2010. After that, Resolute expects the production rate to remain relatively stable for approximately five years and then begin a natural decline. Resolute believes these development projects, particularly its planned CO2 flood projects, are relatively low risk compared to other conventional drilling-focused exploration and production activities, in large part because of the successful results of the McElmo Creek Unit CO2 flood program that has been in operation since 1985 and because of the observed response from the CO2 flood expansion Resolute has undertaken in the Aneth Unit. Following the initiation of the CO2 flood project in the McElmo Creek Unit in 1985, oil production from the unit increased by approximately 30% over a thirteen year period (approximately 22% as a result of the CO2 flood project and approximately 8% as a result of 24 newly drilled wells). Production then returned to a state of natural decline in 1998. Because of similar geological characteristics across Resolute’s Aneth Field Properties, Resolute expects to achieve analogous incremental reserves in Aneth Unit as were seen in McElmo Creek Unit, but at accelerated production rates, due to the higher rate of CO2 injection in Resolute’s Aneth Unit project.
 
Operating Control Over the Resolute Properties. Resolute is the operator of the Aneth, McElmo Creek and Ratherford Units. As a result of having a critical mass of employees, projects, and operating control across the three federal units encompassing approximately 43,000 acres, it has the ability to utilize its employees on a prioritized basis. Because Resolute is the operator of all of its Aneth Field Properties, it believes it can attract contract services, materials and equipment from a broader market and negotiate more favorable terms than would otherwise be available. Resolute also has the ability to control the timing, scope and costs of development projects undertaken in its Aneth Field Properties. Resolute also operates Hilight Field and most of its other Wyoming Properties.
 
Experienced Management Team with Operational, Transactional and Financial Experience in the Energy Industry. With an average industry work experience of more than 25 years, the senior management team of Resolute has considerable experience in acquiring, exploring, exploiting, developing and operating oil and gas properties, particularly in operationally intensive oil and gas fields. Three members of its senior management who formed Holdings in 2004 previously worked together as part of the senior management team of HS Resources, Inc., an independent oil and gas company that was listed on the New York Stock Exchange and primarily operated in the Denver-Julesburg Basin in northeast Colorado. HS Resources conducted resource development programs, managed and enhanced a gas gathering and processing system and built a hydrocarbon physical marketing and transportation business. Its development activities included drilling new wells, deepening wells and recompleting and refracturing existing wells to add reserves and enhance production. HS Resources also had an active program of acquiring producing properties and properties with development potential. HS Resources was acquired by Kerr-McGee Corporation in 2001.


4


Table of Contents

Aneth Field
 
Aneth Field, located in San Juan County, Utah, was discovered by Texaco in 1956 and was subsequently developed by several large integrated oil companies. It is the largest oil field in the Paradox Basin. Resolute’s Aneth Field Properties cover approximately 43,000 acres and during the twelve months ended December 31, 2010, gross production from the Aneth Field Properties averaged 9,690 barrels of oil per day.
 
The primary producing horizon in Aneth Field is the Pennsylvanian-age Desert Creek formation, which is a carbonate algal-mound formation with an average depth of approximately 5,525 feet. While there is some reservoir heterogeneity in Aneth Field, development of the reserves generally has been accomplished with well-tested methodologies, including drilling and infilling vertical wells, horizontal drilling, waterflood activities and CO2 flooding. For administrative, organizational and operational reasons, in 1961 Aneth Field was divided into four separate federal production units to facilitate efficient development of the field and recovery of reserves. The three units that Resolute operates, the Aneth Unit, the McElmo Creek Unit and the Ratherford Unit, which constitute Resolute’s Aneth Field Properties, possess substantially similar geologic and operating characteristics.
 
Predecessor Resolute acquired its Aneth Field Properties primarily through two significant acquisitions. In November 2004, it acquired a 53% operating working interest in the Aneth Unit, a 15% non-operating working interest in the McElmo Creek Unit and a 3% non-operating working interest in the Ratherford Unit (“Chevron Properties”). In the April 2006 acquisition, it acquired an additional 7.5% non-operating working interest in the Aneth Unit, a 60% operating working interest in the McElmo Creek Unit and a 56% operating working interest in the Ratherford Unit (“ExxonMobil Properties”).
 
Predecessor Resolute acquired its Aneth Field Properties in connection with its strategic alliance with Navajo Nation Oil and Gas Company, Inc. (” NNOG”), an oil and gas company owned by the Navajo Nation. NNOG maintains a minority interest in each of the Chevron Properties and the ExxonMobil Properties and possesses options to purchase additional minority interests in those properties from Resolute under certain circumstances. Please read “Resolute’s Business — Relationship with the Navajo Nation.”
 
Aneth Unit. During the twelve months ended December 31, 2010, Aneth Unit production averaged approximately 3,613 barrels of oil per day (gross) from 161 gross (99 net) active producing wells. Additionally, Resolute operates 150 gross (93 net) active injection wells in the Aneth Unit. Since the discovery of oil at the site in 1956, the Aneth Unit has produced a total of approximately 154 MMBbl of oil. Aneth Unit was originally developed with vertical wells drilled on 80-acre spacing and was infill drilled to 40-acre spacing in the 1970s. Since unitization in 1961, the unit has been under waterflood. Between 1994 and 1998, an affiliate of Texaco operated the Aneth Unit and drilled 43 multi-lateral horizontal wells (23 producers and 20 injectors). Most of these horizontal wells were utilized to create a horizontal waterflood pattern on the eastern side of the unit. In 1998, the injectors in two square miles of the Aneth Unit were converted to a water-alternating-gas CO2 pilot project to assess the possibility of a field-wide CO2 injection flood program. The multi-lateral horizontal wells and the pilot CO2 program were successful in increasing production rate and adding reserves, however, the pilot CO2 program was never expanded into a unit-wide program. Predecessor Resolute became operator of the Aneth Unit on December 1, 2004, and has been successful in reducing the decline rate such that the average daily gross oil production from the Aneth Unit as a whole has remained relatively constant since the time of acquisition.
 
McElmo Creek Unit. During the twelve months ended December 31, 2010, McElmo Creek Unit production averaged approximately 3,925 barrels of oil per day (gross) from 139 gross (104 net) active producing wells. Resolute operates 107 gross (80 net) active injection wells on the McElmo Creek Unit. Since its discovery, the McElmo Creek Unit has produced a total of approximately 164 MMBbl of oil. The McElmo Creek Unit has been under waterflood since the early 1960s and prior operators commenced infill drilling to 40-acre spacing during the 1970s. A stabilized oil production decline trend was established for the waterflood over approximately seven years prior to the initiation of a CO2 flood program in 1985. Following the initiation of the CO2 flood project in the McElmo Creek Unit in 1985, oil production from the unit increased by approximately 30% over a 13 year period (approximately 22% as a result of the CO2 flood project and approximately 8% as a result of 24 newly drilled wells). Production then returned to a state of natural decline in 1998. Prior to Predecessor Resolute’s acquisition of the ExxonMobil Properties, the McElmo Creek Unit was operated by ExxonMobil. Predecessor Resolute became operator of the McElmo Creek Unit on June 1, 2006, and was successful in increasing the average daily


5


Table of Contents

gross production rate. This was due to a number of factors, including its efforts to return wells to operation, improve artificial lift capacity at producing wells, improve compressor run times, increase production from new horizontal drilling, reduce freeze problems in the winter months and increase CO2 injection.
 
Ratherford Unit. During the twelve months ended December 31, 2010, Ratherford Unit production averaged approximately 2,152 barrels of oil per day (gross) from 97 gross (57 net) active producing wells. Resolute operates 77 gross (45 net) active injection wells on the Ratherford Unit. Since discovery, the Ratherford Unit has produced a total of approximately 103 MMBbl of oil. The core of the Ratherford Unit has been developed with horizontal wells, while the edges of the unit have been developed with vertical wells. Predecessor Resolute became operator of the Ratherford Unit on June 1, 2006, and was successful in increasing the average daily gross production rate. This increase in production resulted from a number of factors, including its efforts to improve artificial lift capacity at producing wells, increase production from new horizontal drillings, return wells to operation and increase water injection resulting from injection well cleanouts.
 
Wyoming Properties
 
Resolute’s Wyoming Properties consist of three units in Hilight Field, minor non-unitized Muddy formation production in the Hilight area, non-unitized CBM production in the Hilight area and twelve other small fields in Wyoming. Resolute also owns interests in two small fields in Oklahoma. All but one of the Wyoming Properties are operated by Resolute.
 
Hilight Field consists of the Jayson Unit, the Grady Unit, the Central Hilight Unit and the South Hilight Unit. Resolute has an 82.7% working interest in the Jayson Unit, an 82.5% working interest in the Grady Unit and a 98.5% working interest in Central Hilight Unit. The Jayson, Grady and Central Hilight Units cover an area of almost 50,000 acres, and are operated by Resolute. Hilight Field was discovered by Inexco Oil Company in 1969, was developed on 160-acre spacing, unitized in 1971-1972 and underwent waterflood between 1972 and the mid-1990s. As of December 31, 2010, there were 145 gross (137 net) active producing wells, and cumulative production through December 31, 2010 from Resolute’s three operated units was 68 MMBbl of oil and 150 Bcf of gas. Average daily gross production for the twelve months ending December 31, 2010 was 217 Bbl of oil and 9,651 Mcf of gas per day. Net proved reserves assigned to these properties as of December 31, 2010 were 4.8 MMBoe. Muddy formation sandstones form the main reservoir in the field. Average depth to the Muddy formation is approximately 9,100 ft. Minor production also comes from the Upper Cretaceous Niobrara, Upper Cretaceous Turner and Pennsylvanian Minnelusa reservoirs. Recent activity includes 21 infill wells, including three horizontal laterals drilled by the prior operator in 2006 and 2007, and seven Muddy re-stimulation, or refrac projects performed in 2010. The Company anticipates performing 19 to 21 Muddy refracs between 2011 and 2013. Future activity may include the continuation of the infill and refrac programs, new drilling to extend the field boundaries, and exploration for unconventional oil from the overlying Niobrara Carbonate and Mowry shales. The Company recompleted two Mowry wells in 2010 and anticipates recompleting an additional six Mowry wells in 2011.
 
Resolute’s CBM production in the Hilight area comes from 262 gross (241 net) producing wells, of which 175 gross (162 net) were shut-in as of December 31, 2010. Average daily gross production for the twelve months ending December 31, 2010, was 1,923 Mcf per day. Although it varies from well to well, Resolute has an average of approximately 91% working interest in its Hilight area CBM properties. No net proved reserves were attributable to these wells as of December 31, 2010. The Wyodak-Anderson coals of the Paleocene Fort Union formation are the reservoir for this shallow gas reserve. Average depth of the reservoir is less than 500 feet. Recent activity by the prior operator includes seventeen wells that were drilled to extend the central portion of the field to the east. Since Predecessor Resolute took over operations, the CBM field has undergone downsizing and reconfiguration in an attempt to find the most economic balance between lease operating expenses and production.
 
Resolute also has working interests in twelve small fields in Wyoming and two in Oklahoma. Currently, Resolute operates wells in Campbell, Carbon, Natrona and Crook counties, Wyoming, and Dewey and Woodward counties, Oklahoma. During the twelve months ending December 31, 2010, these properties produced an average of approximately 256 barrels of oil per day from 58 gross (40 net) active producing wells. In addition,


6


Table of Contents

there are 5 gross (3 net) active water injection wells. Net proved reserves assigned to these properties as of December 31, 2010 were 1.7 MBoe.
 
Williston Basin Properties
 
As of December 31, 2010, Resolute has acquired interests in approximately 83,452 gross (29,465 net leasehold) acres in Williams and McKenzie Counties, North Dakota, the majority of which is undeveloped. This acreage is located within the Bakken shale trend of the Williston Basin. Although the Middle Bakken formation is the primary objective of the Company’s exploration activities, secondary objectives include the Three Forks, Madison and Red River formations. Additionally, Resolute is party to a contract with Marathon Oil Corporation (“Marathon”) under which it has earned an additional 3,870 net acres as of January 16, 2011. For 2011, Resolute has allocated approximately $42 million for acreage acquisition, drilling and completion activities in this area, and expects to participate in drilling and completing between fourteen to sixteen horizontal wells during 2011.
 
Exploration Properties
 
Big Horn Basin Properties. Predecessor Resolute developed a grassroots exploration concept in early 2005 to target an unconventional oil resource in the Mowry shale of the Big Horn Basin in northwest Wyoming. Since that time, the Mowry shale has become an emerging oil play over a larger area in northern Wyoming and southern Montana. Predecessor Resolute entered into an area of mutual interest agreement effective November 1, 2006, with Fidelity Exploration and Production Company (“Fidelity”) covering acreage in the southeast part of the basin where 22,644 gross acres were jointly acquired on a 50-50 basis. That agreement has expired, but the acreage remains subject to a joint operating agreement for its remaining term. In addition, both Resolute and Fidelity independently control additional leaseholds in the adjacent areas. The emerging Mowry shale oil resource play is the primary reservoir target; and the Frontier and Phosphoria formations are secondary reservoir targets. A well to test the Mowry is tentatively planned for 2011. Resolute has not yet commenced development of this asset. As of December 31, 2010, Resolute holds 80,353 gross (69,731 net) acres in the play with all of its leased properties having at least five years remaining on the lease term.
 
Black Warrior Basin Properties. In mid-2005, Predecessor Resolute initiated an exploration program in the Black Warrior Basin of northwest Alabama that targeted unconventional gas resources in the Devonian Chattanooga shale, the Mississippian Floyd shale, and the Pennsylvanian Pottsville coals. Approximately 32,754 net acres are currently leased. Predecessor Resolute drilled a vertical well in April 2007 that penetrated all three objectives and was cased without a completion attempt. It later entered into a participation agreement with Huber Energy LLC (“Huber”), effective June 26, 2008, under which Huber can earn an interest in the acreage by incurring all costs on specific development activities. Huber re-entered Resolute’s vertical well and completed the Chattanooga shale and recovered gas, but at uneconomic rates. The well is currently shut-in. Huber acquired proprietary 2-D seismic data in July 2009 for risk reduction on potential future operational activities targeting the Chattanooga and Floyd shales. Huber has re-entered four CBM wells and drilled one new well to date; but has not yet completed these wells. The Pottsville formation has been producing CBM from adjacent areas since the early 1980s.
 
Oil Recovery Overview
 
When an oil field is first produced, the oil typically is recovered as a result of natural pressure within the producing formation. The only natural force present to move the crude oil through the reservoir rock to the wellbore is the pressure differential between the higher pressure in the rock formation and the lower pressure in the wellbore. Various types of pumps are often used to reduce pressure in the wellbore, increasing the pressure differential. At the same time, there are many factors that act to impede the flow of crude oil, depending on the nature of the formation and fluid properties, such as pressure, porosity, permeability, viscosity and water saturation. This stage of production, referred to as “primary recovery,” recovers only a small fraction of the crude oil originally in place in a producing formation.
 
Many, but not all, oil fields are amenable to assistance from a waterflood, a form of “secondary recovery,” which is used to maintain reservoir pressure and to help sweep oil to the wellbore. In a waterflood, some of the wells are used to inject water into the reservoir while other wells are used to produce the fluid. As the waterflood


7


Table of Contents

matures, the fluid produced contains increasing amounts of water and decreasing amounts of oil. Surface equipment is used to separate the oil from the water, with the oil going to pipelines or holding tanks for sale and the water being recycled to the injection facilities. Primary recovery followed by secondary recovery usually produces between 15% and 40% of the crude oil originally in place in a producing formation.
 
A third stage of oil recovery is called “tertiary recovery” or “enhanced oil recovery” (“EOR”). In addition to maintaining reservoir pressure, this type of recovery seeks to alter the properties of the oil in ways that facilitate production. The three major types of tertiary recovery are chemical flooding, thermal recovery (such as a steamflood) and miscible displacement involving CO2 or hydrocarbon injection.
 
In a CO2 flood, CO2 is liquefied under high pressure and injected into the reservoir. The CO2 then mixes with the oil in a way that increases the mobilization of bypassed oil while also reducing the oil’s viscosity. The lighter components of the oil vaporize into the CO2 while the CO2 also condenses into the oil. In this manner, the two fluids become miscible, mixing to form a homogeneous fluid that is mobile and has lower viscosity and lower interfacial tension, thus facilitating the migration of oil and gas to the producer wells.
 
Miscible CO2 flooding was first commercially successful with Chevron’s 1972 miscible CO2 flood in the SACROC field in Scurry County, Texas. According to the Oil & Gas Journal’s 2010 Worldwide EOR Survey, there were 109 miscible CO2 projects in the United States that produced an estimated 272,000 barrels of oil per day during 2010. In addition to Resolute’s projects in its Aneth Field Properties, CO2 projects are located in Texas, Oklahoma, New Mexico, Colorado, Wyoming, Michigan, Louisiana and Mississippi. Six companies, Occidental Petroleum, Kinder Morgan, Amerada Hess, Chevron, Anadarko Petroleum and Denbury Resources are responsible for the majority of the estimated daily production from these CO2 projects.
 
Planned Operating and Development Activities
 
Resolute has prepared a development program for its Aneth Field Properties that includes CO2 flooding, field infrastructure enhancements, recompletions, workovers of producing and injection wells, infill drilling and waterflood enhancement. The application of each of these activities and technologies has been successfully established in various locations within the Aneth Field Properties, and the development plans have been designed to enhance or extend projects that were tested or initiated by the previous operators but were never fully completed due to such factors as lack of fieldwide operatorship and lower commodity prices. Resolute believes that its close working relationship with NNOG and the Navajo Nation will enhance its ability to advance development of its Aneth Field Properties.
 
CO2 Floods. A major component of planned activity over the next several years involves extensions and expansions of the CO2 floods initiated by the major oil companies, first in the McElmo Creek Unit in 1985 and then in the Aneth Unit in 1998. The McElmo Creek Unit CO2 flood is virtually unit-wide, whereas the Aneth Unit CO2 flood was limited to a pilot project covering approximately two square miles in the northeast corner of that unit.
 
Aneth Field — Gas Processing. Currently there are two types of gas production in Aneth Field, saleable gas and contaminated gas. The saleable gas stream has low levels of CO2 while the contaminated gas stream has high levels of CO2 which prevents it from being sold. This contaminated gas stream currently is compressed and re-injected into the reservoir. As Resolute continues its CO2 injection and expansion plans, the volume of contaminated gas will significantly increase. This contaminated stream is rich in NGL, which represents a valuable product.
 
The Aneth and McElmo Creek Units exhibit similar geologic characteristics. As a result, Resolute expects its Aneth Unit CO2 flood to achieve results analogous to those achieved in the McElmo Creek CO2 flood program, adjusted for operational and timing differences. Therefore, Resolute has modeled its estimate of increased incremental proved developed non-producing and proved undeveloped reserves based upon the results achieved in the McElmo Creek Unit CO2 flood. It also has modeled its projection of increased rate of oil production based upon the oil production response of the McElmo Creek Unit as a function of the rate of CO2 injection. The oil production rate response is related to the rate at which CO2 is injected. The McElmo Creek CO2 project was initiated in 1985 with a relatively low rate of CO2 injection, and therefore experienced an oil production rate response that was lower than what might have been achieved had CO2 been injected at a higher rate. Resolute


8


Table of Contents

estimates that the rate of oil production will increase faster at the Aneth Unit than the production response experienced at the McElmo Creek Unit because of Resolute’s plan to inject CO2 volumes at a greater rate at the Aneth Unit than at the McElmo Creek Unit.
 
Aneth Unit. Oil response continues to increase in Aneth Unit Phase 1, 2 and 3 of the CO2 expansion project and the Company anticipates completing the Aneth Central Gas Plant rebuild which will process all recycled gas from the expansion project, by the end of the second quarter of 2011. Initially the new plant will dehydrate and recover valuable condensate from the recycled gas stream. Eventually, the plant will be expanded to strip CO2 and hydrocarbon gas from the stream. The hydrocarbon gas and condensate will be sold adding income streams to the field economics and the CO2 will be reinjected into the producing zone. Phase 4 of the CO2 expansion project began during the fourth quarter of 2010 and will continue through 2011.
 
McElmo Creek Unit. Beginning in early 2010, Resolute began recompleting a subzone of the Desert Creek formation in McElmo Creek Unit, with notable increases to production. This recompletion program is expected to carry on through 2013, with further increases in production expected. Reservoir properties collected from these recompletions, such as fluid deliverability, oil cut and reservoir pressure, are being used to refine and optimize the plan to develop and flood the zone with CO2, which will involve construction and rebuilding of infrastructure to accommodate the incremental production.
 
Ratherford Unit. The Ratherford Unit is still producing under water flood. Resolute continues to evaluate the incremental value of this property, including potential CO2 flooding, infill drilling and recompletions of unswept reserves. In 2011, the Company plans to drill two wells in the Desert Creek formation to analyze the best method to extract these reserves.
 
The following table sets forth, as of December 31, 2010, Resolute’s estimate of the future capital expenditures, net to its interest, for construction, well work and other costs and for purchases of CO2 required to implement its CO2 flood projects in two of the units of its Aneth Field Properties through 2039. The following table also sets forth the estimated net proved developed non-producing and proved undeveloped reserves included in Resolute’s reserve report as of December 31, 2010, which Resolute anticipates will be produced as a result of these projects. Resolute incurred $37.3 million of capital expenditures related to the Aneth Field Properties during 2010, and Resolute expects to incur an additional $446.7 million of capital expenditures over the next 29 years (including purchases of CO2), in connection with bringing into production those incremental proved developed non-producing and proved undeveloped reserves attributable to its CO2 flood project. Resolute has entered into a CO2 purchase contract with Kinder Morgan CO2 Company, L.P. (“Kinder Morgan”) for a substantial portion of the CO2 it expects to use in connection with its CO2 flood projects. In order to further these CO2 flood projects, Resolute expects to incur approximately $198.4 million of these future capital expenditures from 2011 through 2013.
 
                                         
    Estimated
          Estimated
          Estimated
 
    Future
    Estimated
    Future Total
    Estimated
    Future
 
    Capital
    Future CO2
    Capital
    Reserves
    Development
 
    Expenditures     Purchases     Expenditures     (MMBoe)     Cost ($/Boe)  
    (in millions, except as otherwise indicated)  
 
Aneth Unit — Phase 1, 2 and 3
  $ 7.7     $ 60.9     $ 68.6       8.3     $ 8.32  
Aneth Unit — Phase 4 and Plant
    77.8       136.0       213.8       17.0       12.54  
McElmo Creek Unit – DC IIC and Plant
    86.6       77.7       164.3       12.1       13.58  
                                         
Total
  $  172.1     $  274.6     $  446.7       37.4     $  11.94  
 
As Resolute advances its CO2 projects, the injected CO2 will displace an increasing portion of the water currently being injected in the waterflood operation. Resolute needs to safely dispose of that water, and, to that end, has drilled a water disposal well with four horizontal laterals. Engineering studies have indicated that this initial well should be able to handle most of the incremental water production. To protect against the possibility that the first water disposal well might become incapable of handling all volumes of water to be disposed of, Resolute is presently in the process of securing permits to drill a second water disposal well to handle any excess water disposal needs. The Company anticipates drilling this well sometime in 2012.


9


Table of Contents

The success of Resolute’s CO2 projects also depends on acquiring adequate amounts of CO2. The CO2 purchase contract with Kinder Morgan provides a significant portion of the anticipated CO2 required through 2020 to pursue CO2 projects and to continue its existing CO2 floods. The contract runs through December 31, 2020 and has a variable schedule of committed contract quantities intended to make available the expected requirements of Phase 1, 2, 3 and 4 of Resolute’s Aneth Unit CO2 project as well as the requirements of its expansion project in the McElmo Creek Unit. The Kinder Morgan contract maximum daily quantities range from a high of approximately 60,000 Mcf per day in 2012, declining to approximately 11,500 Mcf per day during 2020, the last year of the contract.
 
Resolute is required to take, or pay for if not taken, 75% of the total of the maximum daily quantities for each month during the term of the Kinder Morgan contract. There are make-up provisions allowing any take-or-pay payments it makes to be applied against future purchases for specified periods of time. Resolute does not have the right to resell CO2 required to be purchased under the Kinder Morgan contract. As of December 31, 2010, Resolute had made no payments under this contract for CO2 volumes for which it had not yet taken delivery.
 
The CO2 that Resolute purchases for its use is delivered to it through the McElmo Creek Pipeline. This pipeline is approximately 25 miles in length and runs directly from McElmo Dome Field to Resolute’s McElmo Creek Unit. Pipelines within the Aneth Field Properties are used to distribute the CO2 to the Aneth Unit. Resolute owns a 75% interest in, and is the operator of, the McElmo Creek Pipeline. The current pipeline capacity is 70,000 Mcf per day.
 
Wyoming Properties. Resolute has prepared a multi-year development plan for the Wyoming Properties. At Hilight Field, the previous operator was successful in adding new reserves by stimulating the Muddy formation. Resolute has continued this program with seven refracs completed during 2010 and 19 to 21 refracs scheduled to be completed between 2011 and 2013. The repair and maintenance program will continue, and the reconfiguration of certain water discharge facilities is scheduled to be completed in 2011. In addition to this program, Resolute plans to test and develop the Mowry oil shale. The Company recompleted two Mowry wells in 2010 and plans to recomplete six additional wells in 2011. At the Hilight area CBM property, no new operational activities will be planned until after the results of the field reconfiguration, which was implemented on a trial basis beginning in April 2009, are fully analyzed. Additionally, the Company plans to drill between 19 and 21 proved undeveloped reserve locations between 2012 and 2013.
 
Estimated Net Proved Reserves
 
Reserve estimates as of December 31, 2010, were prepared by Resolute and audited by NSAI, Resolute’s independent petroleum engineers. Please read “Risk Factors — Risks Related to Resolute’s Business, Operations and Industry” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Resolute” in evaluating the material presented below.
 
Resolute’s reserve report was prepared under the direct supervision of Resolute’s Vice President of Reservoir Engineering, who is a qualified reserve estimator and auditor. The report was based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geoscience and engineering data, and other information as prescribed by the SEC. The reserve estimates were reviewed internally by senior management. An audit of the reserve estimates was performed by NSAI.
 
The professional qualifications of Resolute’s Vice President of Reservoir Engineering meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include: Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines, 1982; registered professional engineer with the State of Colorado since 1987; member of Society of Petroleum Engineers since 1980; more than 28 years of practical petroleum engineering experience; more than 28 years of practical experience in estimating and evaluating reserves information with at least six of these years being in charge of estimating and evaluating reserves.
 
The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader in petroleum property analysis for industry, financial organizations and government agencies. NSAI was founded in


10


Table of Contents

1961 and is registered to perform consulting petroleum engineering services by the Texas Board of Professional Engineers Registration. Within NSAI, the technical person primarily responsible for the NSAI audit is David Miller. Mr. Miller has been practicing consulting petroleum engineering at NSAI since 1997. He is a Registered Professional Engineer in the State of Texas and has more than 29 years of practical experience in petroleum engineering, with more than 13 years experience in the estimation and evaluation of reserves. He graduated from the University of Kentucky in 1981 with a Bachelor of Science degree in Civil Engineering and from Southern Methodist University in 1994 with a Master of Business Administration degree. Mr. Miller meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
 
A report of NSAI regarding its audit of the estimates of proved reserves at December 31, 2010, has been filed as Exhibit 99.1 to this report and is incorporated herein.
 
The following table presents Resolute’s estimated net proved oil, gas and NGL reserves and the present value of its estimated net proved reserves as of December 31, 2010, all according to standards set by the Securities and Exchange Commission (“SEC”). The standardized measure shown in the table below is not intended to represent the current market value of Resolute’s estimated oil and gas reserves. Resolute’s estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC.
 
                                 
    Utah     Wyoming     North Dakota     Total  
 
Estimated net proved developed reserves:
                               
Oil (MBbl)
         30,026       741       51       30,818  
Gas (MMcf)
    1,232       12,690       46       13,968  
NGL (MBbl)
    200       965             1,165  
                                 
MBoe
    30,432       3,821       59       34,312  
                                 
Estimated net proved undeveloped reserves:
                               
Oil (MBbl)
    19,235       165       14       19,414  
Gas (MMcf)
    21,698       3,406       26       25,130  
NGL (MBbl)
    6,493       261             6,754  
                                 
MBoe
    29,345       993       19       30,357  
                                 
Estimated net proved reserves:
                               
Oil (MBbl)
    49,261       906       65       50,232  
Gas (MMcf)
    22,930            16,096                 72            39,098  
NGL (MBbl)
    6,693       1,226             7,919  
                                 
MBoe
    59,777       4,815       77       64,669  
                                 
PV-10 ($ in millions)(1)(3)
                          $ 848  
Discounted future income taxes
                            (261 )
                                 
Standardized measure ($ in millions)(1)(2)
                          $ 587  
                                 
 
 
1) In accordance with SEC and Financial Accounting Standards Board (“FASB”) requirements, Resolute’s estimated net proved reserves and standardized measure at December 31, 2010, were determined utilizing prices equal to the 2010 twelve-month unweighted arithmetic average of first day of the month prices, such prices deemed to be “current” by the SEC and FASB, resulting in an average NYMEX oil price of $79.43 per Bbl of oil and an average Henry Hub spot market gas price of $4.38 per MMBtu.
 
2) Standardized measure is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC and FASB, less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Calculation of standardized measure does not give effect to derivatives transactions. For a description of Resolute’s derivatives transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Resolute — Quantitative and Qualitative Disclosures About Market Risk.”


11


Table of Contents

 
3) PV-10 is a non-GAAP measure and incorporates all elements of the standardized measure, but excludes the effect of income taxes. Management believes that pre-tax cash flow amounts are useful for evaluative purposes since future income taxes, which are affected by a company’s unique tax position and strategies, can make after-tax amounts less comparable.
 
Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled within five years from known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production. The Company developed 0.6 MMBoe of proved undeveloped reserves during 2010. Facility construction and well development activities began on two large CO2 flood projects in 2010 and will continue over the next few years. These projects comprise approximately 58% of our proved undeveloped reserves.
 
The data in the above table represent estimates only. Oil and gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserves estimates may vary, perhaps significantly, from the quantities of oil and gas that are ultimately recovered. Please read “Risk Factors — Risks Related to Resolute’s Business, Operations and Industry.”
 
Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate present value, which is required by SEC and FASB pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
 
Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Therefore, without reserve additions in excess of production through successful exploitation and development activities or acquisitions, Resolute’s reserves and production will ultimately decline over time. Please read “Risk Factors — Risks Related to Resolute’s Business, Operations and Industry” and “Note 15 — Supplemental Oil and Gas Information (unaudited)” to the audited consolidated financial statements of Resolute for a discussion of the risks inherent in oil and gas estimates and for certain additional information concerning Resolute’s estimated proved reserves.
 
At December 31, 2010, no proved undeveloped reserves have remained undeveloped for more than five years.
 
Proved reserves reported by Resolute of 64.7 MMBoe at December 31, 2010, represent a 1% increase over the 64.4 MMBoe reported at December 31, 2009. Production during 2010 reduced proved reserves by 2.7 MMBoe, while revisions of previous estimates increased proved reserves by 2.8 MMBoe. Commodity pricing was the principal factor leading to the revisions in proved reserves. In accordance with SEC requirements, the reserves at December 31, 2010, utilized prices of $79.43 per barrel of oil and $4.38 per MMBtu, as compared to prices of $61.18 per barrel of oil and $3.87 per MMBtu of gas at December 31, 2009.
 
Resolute incurred development costs of $48 million in 2010 as compared to the $23 million incurred in 2009 (including Predecessor Resolute), primarily due to increased activity and capital spending related to the CO2 expansion project in 2010.
 
The following table sets forth Resolute’s net proved reserves at December 31, 2010, based on SEC requirements as identified below in the footnotes to the table.
 
         
    SEC Case  
 
Proved oil and NGL reserves (MMBbl)
    58.2  
Proved gas reserves (Bcf)
    39.1  
Proved equivalents (MMBoe)
    64.7  
PV-10 (millions)
    $848  


12


Table of Contents

The SEC Case utilized prices equal to the twelve-month unweighted arithmetic average of first day of the month prices, resulting in an average NYMEX oil price of $79.43 per Bbl of oil and an average Henry Hub spot market gas price of $4.38 per MMBtu of gas.
 
Production and Price History
 
The table below summarizes Resolute and Predecessor Resolute’s operating data for 2010, 2009 and 2008.
 
                                   
    Resolute       Predecessor Resolute  
            For the 267 day
       
    Year Ended
      period ended
    Year Ended
 
    December 31,       September 24,     December 31,  
    2010     2009       2009     2008  
Production Sales Data:
                                 
Oil (MBbl)
    2,089       543         1,444       2,049  
Gas and NGL (MMcfe)
    3,843       958         3,400       4,645  
Combined volumes (MBoe)
    2,730       703         2,011       2,823  
Daily combined volumes (Boe per day)
    7,478       7,172         7,530       7,712  
                                   
Average Realized Prices (excluding derivative settlements):
                                 
Oil ($/Bbl)
  $ 73.22     $ 69.11       $ 50.32     $ 94.47  
Gas and NGL ($/Mcfe)
    5.32       5.10         3.73       7.59  
                                   
Average Production Costs ($/Boe):
                                 
Lease operating expense
  $ 18.91     $ 23.03       $ 16.84     $ 20.04  
Production and ad valorem taxes
    8.85       8.26         6.42       10.42  
 
Productive Wells
 
The following table sets forth information as of December 31, 2010, relating to the productive wells in which Resolute owns a working interest. Productive wells consist of producing wells and wells capable of producing, including wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which Resolute has a working interest, and net wells are the sum of Resolute’s working interests owned in gross wells. In addition to the wells set forth below, as of December 31, 2010, Resolute had interests in and operated 334 gross (218 net) active water and CO2 injection wells on the Aneth Field Properties, and 8 gross (6 net) active water injection wells associated with the Wyoming Properties.
 
                 
    Producing Wells  
Area
  Gross     Net  
 
Aneth Field Properties
    397       260  
Wyoming Properties
    465       418  
Bakken Properties
    2       1  
                 
Total
    864       679  
                 


13


Table of Contents

Acreage
 
All of Resolute’s leasehold acreage is categorized as developed or undeveloped. The following table sets forth information as of December 31, 2010, relating to the Company’s leasehold acreage:
 
                         
    Developed Acreage (1)  
                Average Net
 
Area
  Gross (2)     Net (3)     Revenue Interest (4)  
 
Aneth Field Unit acreage (UT)
    43,218       28,122       56 %
Hilight Field Unit acreage (WY)
    49,608       45,421       77 %
Hilight area non-unit acreage (WY)
    3,482       3,308       85 %
Other non-unit acreage (WY and OK)
    7,024       4,525       61 %
North Dakota acreage
    720       344       38 %
                         
Total
    104,052       81,720          
                         
 
                         
    Undeveloped Acreage (5)  
                Average Net
 
Area
  Gross (2)     Net (3)     Revenue Interest (4)  
 
South Hilight deep rights (WY)
    1,640       1,600       80 %
Big Horn Basin acreage (WY)
    80,353       69,731       86 %
Black Warrior Basin acreage (AL)
    40,109       32,754       82 %
Other non-unit acreage (WY, OK and UT)
    2,639       2,543       81 %
North Dakota acreage
    82,732       29,121       38 %
                         
Total
    207,473       135,749          
                         
 
Approximately 16,685 net acres of undeveloped acreage expires in 2011 and approximately 3,817 and 24,182 net acres expire in 2012 and 2013, respectively. Approximately 14,000 net acres that expire in 2011 relate to acreage in the Black Warrior Basin in Alabama.
 
 
1) Developed acreage is acreage attributable to wells that are capable of producing oil or gas.
 
2) The number of gross acres is the total number of acres in which Resolute owns a working interest and/or unitized interest.
 
3) Net acres are calculated as the sum of Resolute’s working interests in gross acres.
 
4) The net revenue interest is the percentage of total production to which Resolute is entitled after reductions for burdens on production such as royalties and overriding royalties.
 
5) Undeveloped acreage includes leases either within their primary term or held by production.
 
Drilling Results
 
Resolute drilled 1 productive gross (0.5 net) well in 2010. Resolute did not engage in drilling exploratory or developmental wells during 2009. Predecessor Resolute did not engage in drilling in 2009 and 2008.
 
Relationship with the Navajo Nation
 
The purchase of Resolute’s Aneth Field Properties was facilitated by Predecessor Resolute’s strategic alliance with NNOG and, through NNOG, the Navajo Nation. The Navajo Nation formed NNOG, a wholly-owned corporate entity, under Section 17 of the Indian Reorganization Act. Resolute supplies NNOG with acquisition, operational and financial expertise and NNOG helps Resolute communicate and interact with the Navajo Nation agencies.
 
Resolute’s strategic alliance with NNOG is embodied in a Cooperative Agreement that Predecessor Resolute entered into with NNOG in 2004 to facilitate Resolute and NNOG’s joint acquisition of the Chevron Properties.


14


Table of Contents

The agreement was amended subsequently to facilitate the joint acquisition of the ExxonMobil Properties. Among other things, this agreement provides that:
 
  •  Resolute and NNOG will cooperate on the acquisition and subsequent development of their respective properties in Aneth Field.
 
  •  NNOG will assist Resolute in dealing with the Navajo Nation and its various agencies, and Resolute will assist NNOG in expanding its financial expertise and its operating capabilities. Since Predecessor Resolute and NNOG acquired the Aneth Field Properties, NNOG has helped facilitate interaction between Resolute and the Navajo Nation Minerals Department and other agencies of the Navajo Nation.
 
  •  NNOG has a right of first negotiation in the event of a proposed sale or change of control of Resolute or a sale by Resolute of all or substantially all of its Chevron Properties or ExxonMobil Properties. This right is separate from and in addition to the statutory preferential purchase right held by the Navajo Nation.
 
In addition to the above provisions, Predecessor Resolute granted NNOG three separate but substantially similar purchase options. Each purchase option entitles NNOG to purchase from Resolute up to 10% of the undivided working interests that Resolute acquired from Chevron or ExxonMobil, as applicable, as to each unit in the Aneth Field Properties. Each purchase option entitles NNOG to purchase at fair market value, for a limited period of time, the applicable portion of the undivided working interest Resolute acquired. The fair market value is to be determined without giving effect to the existence of the Navajo Nation statutory preferential purchase right or the fact that the properties are located on the Navajo Reservation. Each option becomes exercisable based upon Resolute’s achieving payout multiples of the relevant acquisition costs, subsequent capital costs and ongoing operating costs attributable to the applicable working interests. Revenue applicable to the determination of payout includes the effect of Resolute’s derivative program. The multiples of payout that trigger the exercisability of the purchase options with respect to each of the Chevron Properties and the ExxonMobil Properties are 100%, 150% and 200%. The options are not exercisable prior to four years from the relevant acquisition except in the case of a sale of such assets by, or a change of control of, Resolute. In that case, the first option for 10% would be accelerated and the other options would terminate.
 
As of December 31, 2010, the payout balance on the Chevron Properties was approximately $48.9 million and the payout balance on the ExxonMobil Properties was approximately $78.9 million. Assuming the purchase options are not accelerated due to a change of control of Resolute, and assuming Resolute continues to develop its Aneth Field Properties in accordance with its plans, Resolute expects that the initial payout associated with the purchase options would not occur for a number of years.
 
The following table demonstrates the maximum net undivided working interest in each of the Aneth Unit, the McElmo Creek Unit and the Ratherford Unit that NNOG could acquire from Resolute upon exercising each of its purchase options under the Cooperative Agreement. The exercise by NNOG of its purchase options in full would not give it the right to remove Resolute as operator of any of Resolute’s Aneth Field Properties.
 
                         
    Aneth Unit     McElmo Creek Unit     Ratherford Unit  
 
Chevron Properties:
                       
Option 1 (100% Payout)
    5.30 %     1.50 %     0.30 %
Option 2 (150% Payout)
    5.30 %     1.50 %     0.30 %
Option 3 (200% Payout)
    5.30 %     1.50 %     0.30 %
                         
Total
    15.90 %     4.50 %     0.90 %
                         
ExxonMobil Properties:
                       
Option 1 (100% Payout)
    0.75 %     6.00 %     5.60 %
Option 2 (150% Payout)
    0.75 %     6.00 %     5.60 %
Option 3 (200% Payout)
    0.75 %     6.00 %     5.60 %
                         
Total
    2.25 %     18.00 %     16.80 %
                         


15


Table of Contents

Marketing and Customers
 
Aneth Field. Resolute currently sells all of its crude from its Aneth Field Properties to a single customer, Western Refining Southwest, Inc. (“Western”), a subsidiary of Western Refining, Inc. under a contract with a primary term that ended on August 31, 2010. This contract which was effective September 1, 2009, provides for a fixed differential to the NYMEX price for crude oil of $6.25 per Bbl. This contract continues month-to-month after August 31, 2010, with either party having the right to terminate upon ninety days’ notice. The contract may also be terminated by Western upon sixty days notice, if Western’s right of way agreements with the Navajo Nation are declared invalid and either Western is prevented from using such rights-of way or the Navajo Nation declares Western to be in trespass with respect to such rights-of-way. Resolute is currently negotiating a long term contract with Western, but we cannot give any assurance that we will be able to reach an agreement with Western that incorporates favorable terms or at all on such a contract.
 
Western refines Resolute’s crude oil at Western’s 26,000 barrel per day refinery in Gallup, New Mexico. Resolute’s production is transported to the refinery via the Running Horse crude oil pipeline owned by NNOG to a terminal known as Bisti, approximately 20 miles south of Farmington, New Mexico, that serves the refinery. The Resolute and NNOG oil has been jointly marketed to Western. The combined Resolute and NNOG volumes are approximately 8,000 barrels of oil per day.
 
Resolute’s Aneth Field crude oil is a sweet, light crude oil that is particularly well suited to be refined in Western’s refinery. Although Resolute has sold all of its crude oil production to Western since Predecessor Resolute acquired the Chevron Properties in November 2004, and despite the value of Resolute’s crude oil production to Western, Resolute cannot be certain that the commercial relationship with Western will continue for the indefinite future, and Resolute cannot be certain that the refinery will not suffer significant down-time or be closed. If for any reason Western is unable or unwilling to purchase Resolute’s crude oil production, Resolute has other alternatives for marketing its crude oil production. Resolute has been working with NNOG to establish alternative transportation and markets for Resolute’s crude oil. NNOG completed construction of a high volume truck loading facility located at the terminal end of NNOG’s Running Horse Pipeline that will be operative and capable of loading all of Resolute and NNOG’s production. Crude oil can be trucked a relatively short distance from the loading facility to rail loading sites near and south of Gallup, New Mexico, or longer distances to refineries or oil pipelines in southern New Mexico and west Texas. Resolute can also transport its crude oil by various combinations of truck, pipeline and rail from its Aneth Field Properties to markets north in Utah, Colorado and Wyoming. The cost of selling Resolute’s crude oil to alternative markets in the short term would result in a greater differential to the NYMEX price for crude oil than Resolute currently receives. If Resolute chooses or is forced to sell to these alternative markets for a longer period of time, these costs could be lowered significantly. Under long term arrangements, which may require the investment of capital, Resolute believes it would realize a NYMEX differential substantially equivalent to the current differential realized in the price received from Western.
 
Resolute’s gas production is minimally processed in the field and then sent via pipeline to the San Juan River Gas Plant for further processing. Resolute sells its gas at daily market prices to numerous purchasers at the tailgate of the plant, and it receives a contractually specified percentage of the proceeds from the sale of NGL and plant products.
 
Wyoming. Resolute sells the majority of its crude oil in Wyoming to Enterprise Crude Oil LLC and minor amounts to other purchasers in a competitive market. The price it receives relative to the NYMEX price varies depending on supply and demand differentials in the relevant geographic areas in which Resolute’s wells are located and the quality of Resolute’s crude oil. Resolute’s conventional gas in Wyoming comes from Hilight Field and is sold to Anadarko Petroleum Corporation Fort Union Gas Plant. Resolute receives a percentage of proceeds for the liquids sold by the plant, and Resolute can either take its residue gas in kind or market it through Anadarko. Resolute is currently selling its gas through Anadarko. Resolute’s CBM gas also comes from the Hilight area and is minimally conditioned at the Fort Union Gas Plant and is sold through Anadarko. Resolute receives the Colorado Interstate Gas Company index price for all the gas it sells.
 
Derivatives. Resolute enters into derivative transactions from time to time with unaffiliated third parties for portions of its crude oil and gas production to achieve more predictable cash flows and to reduce exposure to


16


Table of Contents

short-term fluctuations in oil and gas prices. For more a detailed discussion, please read — “Resolute’s Business Strategies — Pursue Acquisitions of Properties with Low-Risk Development Potential, Management’s Discussion and Analysis of Financial Condition and Results of Operations of Resolute — Overview” and “— Quantitative and Qualitative Disclosures About Market Risk.”
 
Other Factors. The market for Resolute’s production depends on factors beyond its control, including domestic and foreign political conditions, the overall level of supply of and demand for oil and gas, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of transportation facilities and overall economic conditions. The oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
 
Aneth Gas Processing Plant
 
Resolute has an interest in gas gathering and compression facilities located within and adjacent to its Aneth Field Properties. Collectively called the Aneth Gas Processing Plant, the facility comprises: a) an active gas compression operation currently operated by Resolute and b) a larger complex of inactive, decommissioned and partially dismantled gas processing plant facilities for which Chevron remains the operator of record. In 2006, Chevron began the process of demolishing the inactive portions of the Aneth Gas Processing Plant. It continues to manage the project, and it retains a 39% interest in all demolition and environmental clean-up expenses. Resolute acquired ExxonMobil’s 25% interest in the decommissioned plant and is responsible for that portion of decommissioning and cleanup costs. Activities performed to date include removal of asbestos-containing building and insulation materials, partial dismantling of inactive gas plant buildings and facilities, and limited remediation of hydrocarbon-affected soil.
 
As of December 31, 2010, Resolute estimates the total cost to fully decommission the inactive portion of the Aneth Gas Processing Plant site to be $24.4 million, of which approximately $20.9 million had already been incurred and paid for. The remaining demolition liability net to Resolute’s interest is $0.9 million. Demolition activities are scheduled to be concluded in 2011. These costs do not include any costs for clean-up or remediation of the subsurface. The Aneth Gas Processing Plant site was previously evaluated by the Environmental Protection Agency (“EPA”) for possible listing on the National Priorities List (“NPL”), of sites contaminated with hazardous substances with the highest priority for clean-up under the Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”). Based on its investigation, the EPA concluded no further investigation was warranted and that the site was not required to be listed on the NPL. The Navajo Environmental Protection Agency now has primary jurisdiction over the Aneth Gas Processing Plant site. Resolute cannot predict whether it will require further investigation and possible clean-up, and the ultimate clean-up liability may be affected by the Navajo Nation’s recent enactment of a Navajo CERCLA. The Navajo CERCLA, in some cases, imposes broader obligations and liabilities than the federal CERCLA. Resolute has been advised by Chevron that a significant portion of the subsurface clean-up or remediation costs, if any, would be covered by an indemnity from the prior owner of the plant, and Chevron has provided Resolute with a copy of the pertinent purchase agreement that appears to support its position. Resolute cannot predict, however, whether any subsurface remediation will be required or what the cost of this clean-up or remediation could be. Additionally, it cannot be certain whether any of such costs will be reimbursable to it pursuant to the indemnity of the prior owner. Please read also — “Resolute’s Business — Environmental, Health and Safety Matters and Regulation — Waste Handling.”
 
Title to Properties
 
In connection with Predecessor Resolute’s acquisition of the Chevron Properties and the ExxonMobil Properties, it obtained attorneys’ title opinions showing good and defensible title in the seller to at least 80% of the proved reserves of the acquired properties as shown in the relevant reserve reports presented by the sellers. Predecessor Resolute also reviewed land files and public and private records on substantially all of the acquired properties containing proved reserves. It performed similar title and land file reviews prior to acquiring the Wyoming Properties; however, the prior title opinions available for it to review and update constituted 62% of the proved reserves of the acquired properties and only the public records for these properties were reviewed. Resolute believes it has satisfactory title to all of its material proved properties in accordance with standards


17


Table of Contents

generally accepted in the industry. Prior to completing an acquisition of proved hydrocarbon leases in the future, it intends to perform title reviews on the most significant leases, and, depending on the materiality of properties, it may obtain a new title opinion or review previously obtained title opinions.
 
The Aneth Field Properties are subject to a statutory preferential purchase right for the benefit of the Navajo Nation to purchase at the offered price any Navajo Nation oil and gas lease or working interest in such a lease at the time a proposal is made to transfer the lease or interest. This could make it more difficult to sell Resolute’s oil and gas leases and, therefore, could reduce the value of the Aneth Field leases if it were to attempt to sell them.
 
Resolute’s properties are also subject to certain other encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and gas industry. It believes that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from its interest in these properties or will materially interfere with the intended operation of its business.
 
Competition
 
Competition is intense in all areas of the oil and gas industry. Major and independent oil and gas companies actively bid for desirable properties, as well as for the equipment and labor required to operate and develop such properties. Many of Resolute’s competitors have financial and personnel resources that are substantially greater than its own, and such companies may be able to pay more for productive properties and to define, evaluate, bid for and purchase a greater number of properties than Resolute’s financial or human resources permit. Resolute’s ability to acquire additional properties and to discover reserves in the future will depend on its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
 
Seasonality
 
Resolute’s operations have not historically been subject to seasonality in any material respect.
 
Environmental, Health and Safety Matters and Regulation
 
General. Resolute is subject to various stringent and complex federal, tribal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment, and protection of human health and safety. These laws and regulations may, among other things:
 
  •  require the acquisition of various permits before drilling commences or other operations are undertaken;
 
  •  require the installation of expensive pollution control equipment;
 
  •  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.
 
These laws and regulations may also restrict the rate of oil and gas production to a level below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.
 
Governmental authorities have the power to enforce compliance with environmental laws, regulations and permits, and violations are subject to injunctive action, as well as administrative, civil and criminal penalties. The effects of these laws and regulations, as well as other laws or regulations that may be adopted in the future, could have a material adverse impact on Resolute’s business, financial condition and results of operations.


18


Table of Contents

Resolute believes its operations are in substantial compliance with all existing environmental, health and safety laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on its financial condition and results of operations. Spills or releases may occur, however, in the course of its operations. There can be no assurance that Resolute will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property, persons and the environment, nor can there be any assurance that the passage of more stringent laws or regulations in the future will not have a negative effect on Resolute’s business, financial condition, or results of operations.
 
The following is a summary of the more significant existing environmental, health and safety laws and regulations to which oil and gas business operations are generally subject and with which compliance may have a material adverse effect on Resolute’s capital expenditures, earnings or competitive position, as well as a discussion of certain matters that specifically affect its operations.
 
Comprehensive Environmental Response, Compensation, and Liability Act. CERCLA, also known as the “Superfund law,” and comparable tribal and state laws may impose strict, joint and several liability, without regard to fault, on classes of persons who are considered to be responsible for the release of CERCLA hazardous substances into the environment. These persons include the owner or operator of the site where a release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Such claims may be filed under CERCLA, as well as state common law theories or state laws that are modeled after CERCLA. In the course of its operations, Resolute generates waste that may fall within the definition of hazardous substances under CERCLA, as well as under the recently adopted Navajo Nation CERCLA which, unlike the federal CERCLA, defines hazardous substances to include crude oil and other hydrocarbons, thereby subjecting Resolute to potential liability under CERCLA, tribal and state law equivalents to CERCLA and common law. Therefore, governmental agencies or third parties could seek to hold Resolute responsible for all or part of the costs to clean up a site at which such hazardous substances may have been released or deposited, or other damages resulting from a release.
 
Waste Handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable tribal and state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and many of the other wastes associated with the exploration, development and production of crude oil or gas are currently exempt under federal law from regulation as hazardous wastes and instead are regulated under RCRA’s non-hazardous waste provisions. It is possible, however, that oil and gas exploration and production wastes now classified federally as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in Resolute’s operating expenses, which could have a material adverse effect on the results of operations and financial position. Also, in the course of operations, Resolute generates some amounts of industrial solid wastes, such as paint wastes, waste solvents, and waste oils, that may be regulated as hazardous wastes under RCRA, tribal and state laws and regulations.
 
Resolute has an interest in the Aneth Gas Processing Plant located in the Aneth Unit. This gas plant consists of a non-operational portion of the plant that is in the process of being decommissioned and removed by Chevron and an operational portion dedicated to compression. Resolute is responsible for a portion of the costs of decommissioning and removal and clean-up of the non-operational portion of the plant and any restoration and other costs related to the operational processing facilities. For additional information related to Resolute’s obligations related to this plant, please read “Business and Properties — Aneth Gas Processing Plant.”
 
Air Emissions. The federal Clean Air Act and comparable tribal and state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. These regulatory programs may require Resolute to install expensive emissions control equipment, modify its operational practices and obtain permits for existing operations, and before commencing construction on a new or modified source of air emissions such laws may require Resolute to reduce its emissions at existing facilities. As a result, Resolute


19


Table of Contents

may be required to incur increased capital and operating costs. Federal, tribal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated tribal and state laws and regulations.
 
In June 2005, the EPA and ExxonMobil entered into a consent decree settling various alleged violations of the federal Clean Air Act associated with ExxonMobil’s prior operation of the McElmo Creek Unit. In response, ExxonMobil submitted amended Title V and Prevention of Significant Deterioration (“PSD”) permit applications for the McElmo Creek Unit main flare and other sources, and also paid a civil penalty and costs associated with a Supplemental Environmental Project, or “SEP.” Pursuant to the consent decree, upgrades to the main flare were completed in May 2006 by ExxonMobil, and all of the remaining material compliance measures of the consent decree have been met by Resolute. The EPA is processing the Title V and PSD permit applications. Resolute remains subject to the consent decree, including stipulated penalties for violations of emissions limits and compliance measures set forth in the consent decree. Resolute expects the consent decree to be terminated in 2011.
 
Actual air emissions reported for these facilities are in material compliance with emission limits contained in the draft permits and the consent decree when emissions associated with qualified equipment malfunctions are taken into account.
 
Water Discharges. The federal Water Pollution Control Act, or the Clean Water Act, and analogous tribal and state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States, including wetlands. The discharge of pollutants into regulated waters is prohibited by the Clean Water Act, except in accordance with the terms of a permit issued by the EPA or an authorized tribal or state agency. Federal, tribal and state regulatory agencies can impose administrative, civil and criminal penalties for unauthorized discharges or non- compliance with discharge permits or other requirements of the Clean Water Act and analogous tribal and state laws and regulations.
 
In addition, the Oil Pollution Act of 1990, or OPA, augments the Clean Water Act and imposes strict liability for owners and operators of facilities that are the source of a release of oil into waters of the United States. OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. For example, operators of oil and gas facilities must develop, implement, and maintain facility response plans, conduct annual spill training for employees and provide varying degrees of financial assurance to cover costs that could be incurred in responding to oil spills. In addition, owners and operators of oil and gas facilities may be subject to liability for cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.
 
In August 2004, the EPA and ExxonMobil entered into a consent decree settling alleged violations of the federal Clean Water Act related to past spills of produced water and crude oil from the McElmo Creek and Ratherford Units and failure to prepare and implement Spill Prevention, Control and Countermeasure Plans. ExxonMobil paid a civil penalty and costs to implement a SEP, and made improvements to the production and injection systems. The consent decree was terminated by the EPA in 2009.
 
In November 2001, the EPA issued an administrative order to ExxonMobil for removal and remediation of crude oil and hydrocarbon affected ground water released as a result of a shallow casing leak at the McElmo Creek P-20 well in January 2001. In response, ExxonMobil performed various site assessment activities and began recovering crude oil from the ground water. Resolute is obligated to complete the ground water monitoring and remedial activities required under the administrative order, at an estimated cost of approximately $100,000 per year, with anticipated closure to occur in 2012.
 
Underground Injection Control. Resolute’s underground injection operations are subject to the federal Safe Drinking Water Act, as well as analogous tribal and state laws and regulations. Under Part C of the Safe Drinking Water Act, the EPA established the Underground Injection Control program, which established the minimum program requirements for tribal and state programs regulating underground injection activities. The Underground Injection Control program includes requirements for permitting, testing, monitoring, recordkeeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. Federal, tribal and state regulations require Resolute to obtain a permit from applicable regulatory agencies to operate its underground injection wells. Resolute believes it has obtained


20


Table of Contents

the necessary permits from these agencies for its underground injection wells and that it is in substantial compliance with permit conditions and applicable federal, tribal and state rules. Nevertheless, these regulatory agencies have the general authority to suspend or modify one or more of these permits if continued operation of one of the underground injection wells is likely to result in pollution of freshwater, the substantial violation of permit conditions or applicable rules, or leaks to the environment. Although Resolute monitors the injection process of its wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties for property damages and personal injuries.
 
Pipeline Integrity, Safety, and Maintenance. Resolute’s ownership interest in the McElmo Creek Pipeline has caused it to be subject to regulation by the federal Department of Transportation, or the DOT, under the Hazardous Liquid Pipeline Safety Act and comparable state statutes, which relate to the design, installation, testing, construction, operation, replacement and management of hazardous liquid pipeline facilities. Any entity that owns or operates such pipeline facilities must comply with such regulations, permit access to and copying of records, and file reports and provide required information. The DOT may assess fines and penalties for violations of these and other requirements imposed by its regulations. Resolute believes it is in material compliance with all regulations imposed by the DOT pursuant to the Hazardous Liquid Pipeline Safety Act. Pursuant to the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, the DOT was required to issue new regulations by December 31, 2007, setting forth specific integrity management program requirements applicable to low stress hazardous liquid pipelines. Resolute believes that these new regulations, which have yet to be issued, will not have a material adverse effect on its financial condition or results of operations.
 
Environmental Impact Assessments. Significant federal decisions, such as the issuance of federal permits or authorizations for many oil and gas exploration and production activities are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of Resolute’s current exploration and production activities, as well as proposed exploration and development plans on federal lands, require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay any oil and gas development projects.
 
Other Laws and Regulations
 
Climate Change. Recent scientific studies have suggested that emissions of gases commonly referred to as “greenhouse gases” or “GHG”, including CO2, nitrogen dioxide and methane, may be contributing to warming of the Earth’s atmosphere. Other nations have already agreed to regulate emissions of GHG pursuant to the United Nations Framework Convention on Climate Change, (“UNFCCC”) and the Kyoto Protocol, an international treaty (not including the United States) pursuant to which many UNFCCC member countries have agreed to reduce their emissions of GHG to below 1990 levels by 2012. In response to such studies and international action, the U.S. Congress is now considering legislation to reduce emissions of GHG, and the EPA has promulgated a mandatory GHG reporting rule that took effect January 1, 2010. As finalized, the mandatory reporting rule (MRR) does not require reporting by Resolute for its operations in Aneth Field. However, on March 23, 2010, EPA proposed several amendments to the MRR that would trigger reporting requirements for the Company. Among the proposed amendments are provisions that would apply to operators that inject CO2 for enhanced oil recovery and geologic sequestration, regardless of the magnitude of associated CO2 emissions, and also to operators of oil and natural gas systems that emit more than 25,000 metric tons of CO2-equivalent GHG across an entire producing basin, based on the aggregated GHG emissions of all facilities in a basin under common control of an operator. On June 26, 2009, the House of Representatives passed H.R. 2454, the Waxman-Markey “American Clean Energy and Security Act of 2009,” which would require 17% reduction in GHG emission by “covered entities” by 2020, relative to 2005 GHG emission levels, and create an elaborate system of allocated and tradable emission allowances and offsets to achieve mandated reductions of up to 80% by the year 2050. Companion legislation is being considered in the Senate, and a consensus bill could be developed later in


21


Table of Contents

2010. Prior to this legislative action on climate change by the U.S. Congress, a number of states chose not to wait for Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of GHG, primarily through the planned development of GHG emission inventories and/or regional cap and trade programs. For example, on August 22, 2007, the Western Climate Initiative, which is comprised of a number of Western states and Canadian provinces, including the State of Utah, issued a GHG reduction goal statement seeking to collectively reduce regional GHG emissions to 15% below 2005 levels by 2020. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007, in Massachusetts, et al. v. EPA, the EPA may be required to regulate GHG emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of GHG. The Court’s holding in Massachusetts v. EPA that GHG fall under the federal Clean Air Act’s definition of “air pollutant” also may result in future regulation of GHG emissions from stationary sources under Clean Air Act programs, due to EPA’s recent “endangerment finding” that links global warming to man-caused emissions of GHG and concludes there is an endangerment to public health and the environment that requires regulatory action. The passage or adoption of new legislation or regulations that restrict emissions of GHG or require reporting of such emissions in areas where Resolute conducts business could adversely affect its operations.
 
Department of Homeland Security. The Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security (“DHS”), to issue regulations establishing risk-based performance standards for the security at chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS is in the process of adopting regulations that will determine whether some of Resolute’s facilities or operations will be subject to additional DHS-mandated security requirements. Presently, it is not possible to accurately estimate the costs Resolute could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.
 
Occupational Safety and Health Act. Resolute is subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes that strictly govern protection of the health and safety of workers. The Occupational Safety and Health Administration’s hazard communication standard, the Emergency Planning and Community Right-to-Know Act, and similar state statutes require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and the public. Resolute believes that it is in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.
 
Laws and Regulations Pertaining to Oil and Gas Operations on Navajo Nation Lands
 
General. Laws and regulations pertaining to oil and gas operations on Navajo Nation lands derive from both Navajo law and federal law, including federal statutes, regulations and court decisions, generally referred to as federal Indian law.
 
The Federal Trust Responsibility. The federal government has a general trust responsibility to Indian tribes regarding lands and resources that are held in trust for such tribes. The trust responsibility may be a consideration in courts’ resolution of disputes regarding Indian trust lands and development of oil and gas resources on Indian reservations. Courts may consider the compliance of the Secretary of the U.S. Department of the Interior, or the Interior Secretary, with trust duties in determining whether leases, rights-of-way, or contracts relative to tribal land are valid and enforceable.
 
Tribal Sovereignty and Dependent Status. The United States Constitution vests in Congress the power to regulate the affairs of Indian tribes. Indian tribes hold a sovereign status that allows them to manage their internal affairs, subject to the ultimate legislative power of Congress. Tribes are therefore often described as domestic dependent nations, retaining all attributes of sovereignty that have not been taken away by Congress. Retained sovereignty includes the authority and power to enact laws and safeguard the health and welfare of the tribe and its members and the ability to regulate commerce on the reservation. In many instances, tribes have the inherent power to levy taxes and have been delegated authority by the United States to administer certain federal health, welfare and environmental programs.
 
Because of their sovereign status, Indian tribes also enjoy sovereign immunity from suit and may not be sued in their own courts or in any other court absent Congressional abrogation or a valid tribal waiver of such


22


Table of Contents

immunity. The United States Supreme Court has ruled that for an Indian tribe to waive its sovereign immunity from suit, such waiver must be clear, explicit and unambiguous.
 
NNOG is a federally chartered corporation incorporated under Section 17 of the Indian Reorganization Act and is wholly owned by the Navajo Nation. Section 17 corporations generally have broad powers to sue and be sued. Courts will review and construe the charter of a Section 17 corporation to determine whether the tribe has either universally waived the corporation’s sovereign immunity, or has delegated that power to the Section 17 corporation.
 
The NNOG federal charter of incorporation provides that NNOG shares in the immunities of the Navajo Nation, but empowers NNOG to waive such immunities in accordance with processes identified in the charter. NNOG has contractually waived its sovereign immunity, and certain other immunities and rights it may have regarding disputes with Resolute relating to certain of the Aneth Field Properties, in the manner specified in its charter. Although the NNOG waivers are similar to waivers that courts have upheld, if challenged, only a court of competent jurisdiction may make that determination based on the facts and circumstances of a case in controversy.
 
Tribal sovereignty also means that in some cases a tribal court is the only court that has jurisdiction to adjudicate a dispute involving a tribe, tribal lands or resources or business conducted on tribal lands or with tribes. Although language similar to that used in Resolute’s agreements with NNOG that provide for alternative dispute resolution and federal or state court jurisdiction has been upheld in other cases, there is no guarantee that a court would enforce these dispute resolution provisions in a future case.
 
Federal Approvals of Certain Transactions Regarding Tribal Lands. Under current federal law, the Interior Secretary (or the Interior Secretary’s appropriate designee) must approve any contract with an Indian tribe that encumbers, or could encumber, for a period of seven years or more, (1) lands owned in trust by the United States for the benefit of an Indian tribe or (2) tribal lands that are subject to a federal restriction against alienation, or collectively Tribal Lands. Failure to obtain such approval, when required, renders the contract void.
 
Except for Resolute’s oil and gas leases, rights-of-way and operating agreements with the Navajo Nation, Resolute’s agreements do not by their terms specifically encumber Tribal Lands, and it believes that no Interior Secretarial approval was required to enter into those agreements. With respect to its oil and gas leases and unit operating agreements, these and all assignments to Resolute have been approved by the Interior Secretary. In the case of rights-of-way and assignments of these to Resolute, some of these have been approved by the Interior Secretary and others are in various stages of applications for renewal and approval. It is common for these approvals to take an extended period of time, but such approvals are routine and Resolute believes that all required approvals will be obtained in due course.
 
Federal Management and Oversight. Reflecting the federal trust relationship with tribes, the Bureau of Indian Affairs, or the BIA, exercises oversight of matters on the Navajo Nation reservation pertaining to health, welfare and trust assets of the Navajo Nation. Of relevance to Resolute, the BIA must approve all leases, rights-of-way, applications for permits to drill, seismic permits, CO2 pipeline permits and other permits and agreements relating to development of oil and gas resources held in trust for the Navajo Nation. While NNOG has been successful in facilitating timely approvals from the BIA, such timeliness is not guaranteed and obtaining such approvals may cause delays in developing the Aneth Field Properties.
 
Resources Committee of the Navajo Nation Council. The Resources Committee is a standing committee of the Navajo Nation Tribal Council, and has oversight and regulatory authority over all lands and resources of the Navajo Nation. The Resources Committee reviews, negotiates and recommends to the Navajo Nation Tribal Council actions involving the approval of energy development agreements and mineral agreements; gives final approvals of rights of way, surface easements, geophysical permits, geological prospecting permits, and other surface rights for infrastructure; oversees and regulates all activities within the Navajo Nation involving natural resources and surface disturbance; sets policy for natural resource development and oversees the enforcement of federal and Navajo law in the development and utilization of resources, including issuing cease and desist orders and assessing fines for violation of its regulations and orders. The Resources Committee also has oversight authority over, among other agencies and matters, the Navajo Nation Environmental Protection Agency and Navajo Nation environmental laws, the Navajo Nation Minerals Department and Navajo Nation oil and gas


23


Table of Contents

laws and the Navajo Nation Land Department and Navajo Nation land use laws. While NNOG has been successful thus far in facilitating timely approvals from the Resources Committee for Resolute’s operations, such timeliness is not guaranteed and obtaining future approvals may cause delays in developing the Aneth Field Properties. Furthermore, the Navajo Nation Tribal Council was recently reorganized and reduced in size from 88 members to 24 members. The Company does not yet know what effect this will have on the operation of the Tribal Council or the Resources Committee and their impact on Resolute’s operations.
 
Navajo Nation Minerals Department of the Division of Natural Resources. The day-to-day operation of the Navajo Nation minerals program, including the initial negotiation of agreements, applications for approval of assignments, exercise of tribal preferential rights and most other permits and licenses relating to oil and gas development, is managed by the professional staff of the Navajo Nation Minerals Department, located within the Division of Natural Resources and subject to the oversight of the Resources Committee. The Resources Committee and the Navajo Nation Council typically defer to the Minerals Department in decisions to approve all leases and other agreements relating to oil and gas resources held in trust for the Navajo Nation. While NNOG has been successful thus far in facilitating timely action and favorable recommendations from the Minerals Department for Resolute’s operations, such timeliness is not guaranteed and obtaining future approvals may cause delays in developing the Aneth Field Properties.
 
Taxation Within the Navajo Nation. In certain instances, federal, state and tribal taxes may be applicable to the same event or transaction, such as severance taxes. State taxes are rarely applicable within the Navajo Nation Reservation except as authorized by Congress or when the application of such taxes does not adversely affect the interests of the Navajo Nation. Federal taxes of general application are applicable within the Navajo Nation, unless specifically exempted by federal law. Resolute currently pays the following taxes to the Navajo Nation:
 
  •  Oil and Gas Severance Tax. Resolute pays severance tax to the Navajo Nation. The severance tax is payable monthly and is 4% of its 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. Resolute pays 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.
 
  •  Sales Tax. Resolute pays the Navajo Nation a 4% sales tax in lieu of the Navajo Business Activity Tax. All goods and services purchased for use on the Navajo Nation reservation are subject to the sales tax. The sale of oil and gas is exempt from the sales tax.
 
Royalties from Production on Navajo Nation Lands. Under Resolute’s agreements and leases with the Navajo Nation, it pays royalties to the Navajo Nation. The Navajo Nation is entitled to take its royalties in kind, which it currently does for its oil royalties but not its gas royalties. The Minerals Management Service of the United States Department of the Interior has the responsibility for managing and overseeing royalty payments to the Navajo Nation as well as the right to audit royalty payments.
 
Navajo Preference in Employment Act. The Navajo Nation has enacted the Navajo Preference in Employment Act, or the Employment Act, requiring preferential hiring of Navajos by non-governmental employers operating within the boundaries of the Navajo Nation. The Employment Act requires that any Navajo candidate meeting job description requirements receives a preference in hiring. The Employment Act also provides that Navajo employees can only be terminated, penalized, or disciplined for “just cause,” requires a written affirmative action plan that must be filed with the Navajo Nation, establishes the Navajo Labor Commission as a forum to resolve employment disputes and provides authority for the Navajo Labor Commission to establish wage rates on construction projects. The restrictions imposed by the Employment Act and its recent broad interpretations by the Navajo Supreme Court may limit Resolute’s pool of qualified candidates for employment.
 
Navajo Business Opportunity Act. Navajo Nation law requires companies doing business in the Navajo Nation to provide preference priorities to certified Navajo-owned businesses by giving them a first opportunity and


24


Table of Contents

contracting preference for all contracts within the Navajo Nation. While this law does not apply to the granting of mineral leases, subleases, permits, licenses and transactions governed by other applicable Navajo and federal law, Resolute treats this law as applicable to its material non-mineral contracts and procurement relating to its general business activities within the Navajo Nation.
 
Navajo Environmental Laws. The Navajo Nation has enacted various environmental laws that may be applicable to Resolute’s Aneth Field Properties. As a practical matter, these laws are patterned after similar federal laws, and the EPA currently enforces these laws in conjunction with the Navajo EPA. The current practice does not preclude the Navajo Nation from taking a more active role in enforcement or from changing direction in the future. Some of the Navajo Nation environmental laws not only provide for civil, criminal and administrative penalties, but also provide for third-party suits brought by Navajo Nation tribal members directly against an alleged violator, with specified jurisdiction in the Navajo Nation District Court in Window Rock. A recent example of this relates to the March 2008 adoption by the Navajo Nation of the Navajo Comprehensive Environmental Response, Compensation, and Liability Act (“Navajo CERCLA”), which gives the Navajo EPA broad authority over environmental assessment and remediation of facilities contaminated with hazardous substances. Navajo CERCLA is patterned after federal CERCLA with the important exception that, unlike federal CERCLA, Navajo CERCLA considers crude oil and other hydrocarbons to be hazardous substances subject to CERCLA response actions and damages. Navajo CERCLA also imposes a tariff on the transportation of hazardous substances, including petroleum and petroleum products, across Navajo lands. Resolute is negotiating with representatives of the Navajo Nation Council, Navajo Department of Justice, Navajo Environmental Protection Agency, NNOG, an industry group headed by the New Mexico Oil and Gas Association and Colorado Oil and Gas Association, (“the NMOGA Group”), and others, to mitigate Navajo CERCLA’s potential impact on oilfield operations on Navajo lands. The NMOGA Group in particular has challenged the validity of the law and has entered into a tolling agreement with Navajo EPA that should forestall material implementation of Navajo CERCLA at oil and gas facilities while appropriate rules and guidelines are developed with input from the oil and gas sector. The tolling agreement was renewed in June 2010 and expires in August 2011. Negotiations among Navajo EPA, Resolute and the NMOGA Group remain ongoing.
 
Thirty-Two Point Agreement. An explosion at an ExxonMobil facility in Aneth Field in December 1997 prompted protests by local tribal members and temporary shutdown of the field. The protesters asserted concerns about environmental degradation, health problems, employment opportunities and renegotiating leases. The protest was settled among the local residents, ExxonMobil and the Navajo Nation by the Thirty-Two Point Agreement that provided, among other things, for ExxonMobil to pay partial salaries for two Navajo public liaison specialists, follow Navajo hiring practices, and settle further issues addressed in the Thirty-Two Point Agreement in the Navajo Nation’s “peacemaker” courts, which follow a community-level conflict resolution format. After the Thirty-Two Point Agreement was executed, Aneth Field resumed normal operations. While Resolute did not formally assume the obligations of ExxonMobil under the Thirty-Two Point Agreement when it acquired the ExxonMobil Properties in 2006, it has been Resolute’s policy to voluntarily comply with this agreement. While we believe that our relations with the Navajo Nation are satisfactory, it is possible that employee relations or community relations degrade to a point where protests and shutdown occur in the future.
 
Moratorium on Future Oil and Gas Development Agreements and Exploration. In February 1994, the Navajo Nation issued a moratorium on future oil and gas development agreements and exploration on lands situated within the Aneth Chapter on the Navajo Reservation. All of the Aneth Unit and a significant portion of the McElmo Creek Unit are located within the Aneth Chapter. The Navajo Nation has recently taken the position that the term of the moratorium is indefinite. Given that Resolute’s operations within the Aneth Chapter are based on existing agreements and that Resolute currently does not contemplate new exploration in this mature field, the moratorium has had and is expected to continue to have minor impact to Resolute operations.
 
Other Regulation of the Oil and Gas Industry
 
The oil and gas industry is extensively regulated by numerous federal, state and local authorities, including Native American tribes. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state and Native American tribes, are authorized by statute to issue rules and regulations binding on the oil


25


Table of Contents

and gas industry and individual companies, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases Resolute’s cost of doing business and, consequently, affects profitability, these burdens generally do not affect Resolute any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
 
Drilling and Production. Resolute’s operations are subject to various types of regulation at federal, state, local and Navajo Nation levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities, the Navajo Nation and other Native American tribes also regulate one or more of the following:
 
  •  the location of wells;
 
  •  the method of drilling and casing wells;
 
  •  the rates of production or “allowables”;
 
  •  the surface use and restoration of properties upon which wells are drilled;
 
  •  the plugging and abandoning of wells; and
 
  •  notice to surface owners and other third-parties.
 
On state, federal and Indian lands, the Bureau of Land Management laws and regulations regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third-parties and may reduce Resolute’s interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit or limit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas that Resolute can produce from its wells or limit the number of wells or the locations where it can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil and gas within its jurisdiction.
 
Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of gas and the manner in which Resolute’s production is marketed. Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of gas in interstate commerce by gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic gas sold in “first sales,” which include all of Resolute sales of its own production.
 
FERC also regulates interstate gas transportation rates and service conditions, which affects the marketing of gas that Resolute produces, as well as the revenue Resolute receives for sales of its gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the gas industry historically has been very heavily regulated; therefore, Resolute cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future nor can it determine what effect, if any, future regulatory changes might have on gas related activities.
 
Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on-shore and instate waters. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase Resolute’s costs of getting gas to point-of-sale locations.


26


Table of Contents

Employees
 
As of December 31, 2010, Resolute had 160 full-time employees and two part-time employees, including 38 geologists, geophysicists, petroleum engineers and land and regulatory professionals. Approximately 39 of Resolute’s field level employees are represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, or USW labor union, and are covered by a collective bargaining agreement. Resolute believes that it has a satisfactory relationship with its employees.
 
Offices
 
Resolute currently leases approximately 29,000 square feet of office space in Denver, Colorado at 1675 Broadway, Suite 1950, Denver, Colorado 80202, where its principal offices are located. In addition, Resolute owns and maintains field offices in Cortez, Colorado, Montezuma Creek, Utah, and Gillette, Wyoming and leases other, less significant, office space in locations where staff are located. Resolute believes that its office facilities are adequate for its current needs and that additional office space can be obtained if necessary.
 
Available Information
 
The Company maintains a link to investor relations information on its website, www.resoluteenergy.com, where it makes available, free of charge, the Company’s filings with the SEC, including its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, (“Exchange Act”), as soon as reasonably practicable after the Company electronically files such material with, or furnishes it to, the SEC. The Company also makes available on its website copies of the charters of the audit, compensation and corporate governance/nominating committees of the Company’s Board of Directors, its code of business conduct and ethics, audit committee whistleblower policy, stockholder and interested parties communication policy and corporate governance guidelines. Stockholders may request a printed copy of these governance materials or any exhibit to this report by writing to the Secretary, Resolute Energy Corporation, 1675 Broadway, Suite 1950, Denver, Colorado 80202. You may also read and copy any materials the Company files with the SEC at the SEC’s Public Reference Room, which is located at 100 F Street, NE, Room 1580, Washington, D.C. 20549. Information regarding the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website at www.sec.gov that contains the documents the Company files with the SEC. The Company’s website and the information contained on or connected to its website is not incorporated by reference herein and its web address is included as an inactive textual reference only.


27


Table of Contents

ITEM 1A.    RISK FACTORS
 
You should consider carefully the following risk factors, as well as the other information set forth in this Form 10-K.
 
Risks Related to Resolute’s Business, Operations and Industry
 
The risk factors set forth below are not the only risks that may affect Resolute’s business. Resolute’s business could also be affected by additional risks not currently known to it or that it currently deems to be immaterial. If any of the following risks were actually to occur, Resolute’s business, financial condition or results of operations could be materially adversely affected.
 
Resolute’s oil production from its Aneth Field Properties is presently connected by pipeline to only one customer, and such sales are dependent on gathering systems and transportation facilities that Resolute does not control. With only one pipeline connected customer, when these facilities or systems are unavailable, Resolute’s operations can be interrupted and its revenue reduced.
 
The marketability of Resolute’s oil and gas production depends in part upon the availability, proximity and capacity of pipelines, gas gathering systems, and processing facilities owned by third parties. In general, Resolute does not control these facilities and its access to them may be limited or denied due to circumstances beyond its control. A significant disruption in the availability of these facilities could adversely impact Resolute’s ability to deliver to market the oil and gas Resolute produces, and thereby cause a significant interruption in its operations. In some cases, Resolute’s ability to deliver to market its oil and gas is dependent upon coordination among third parties who own pipelines, transportation and processing facilities that Resolute uses, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt Resolute’s operations. These are risks for which Resolute generally does not maintain insurance.
 
With respect to oil produced at its Aneth Field Properties, Resolute operates in a remote part of southeastern Utah, and currently Resolute sells all of its crude oil production to a single customer, Western. Resolute and Western, with the consent of NNOG, entered into a contract covering the joint crude oil volumes of Resolute and NNOG from Aneth Field with a primary term that ended on August 31, 2010, and continues month-to-month thereafter, with either party having the right to terminate upon ninety days’ notice. The contract may also be terminated by Western upon sixty days notice, if Western’s right-of-way agreements with the Navajo Nation are declared invalid and either Western is prevented from using such rights-of way or the Navajo Nation declares Western to be in trespass with respect to such rights-of-way. Resolute is currently negotiating a long term contract with Western, but we cannot give any assurance that we will be able to reach an agreement with Western that incorporates favorable terms or at all on such a contract. Western refines Resolute’s crude oil at Western’s 26,000 barrel per day Gallup refinery in Gallup, New Mexico. Resolute’s production is transported to the refinery via the Running Horse crude oil pipeline owned by NNOG to a terminal known as Bisti, approximately 20 miles south of Farmington, New Mexico, that serves the refinery. The Resolute and NNOG oil has been jointly marketed to Western. The combined Resolute and NNOG volumes are approximately 8,000 barrels of oil per day. See Business and Properties — Marketing and Customers — Aneth Field. There are presently no pipelines in service that run the entire distance from Resolute’s Aneth Field Properties to any alternative markets. If Western did not purchase Resolute’s crude oil, Resolute would have to transport its crude oil to other markets by a combination of the NNOG pipeline, truck and rail, which would result, in the short term, in a lower price relative to the NYMEX price than it currently receives. Resolute may in the future receive prices with a greater differential to NYMEX than it currently receives, which if not offset by increases in the NYMEX price for crude oil could result in a material adverse effect on Resolute’s financial results.
 
Resolute would also have to find alternative markets if Western’s refining capacity in the region is temporarily or permanently shut down for any reason or if NNOG’s pipeline to Western’s refineries is temporarily or permanently shut-in for any reason. Resolute does not have any control over Western’s decisions with respect to its refineries. Resolute would also not have control over similar decisions by any replacement customers.
 
Resolute customarily ships crude oil to Western daily and receives payment on the twentieth day of the month following the month of production. As a result, at any given time, Western owes Resolute between 20 and


28


Table of Contents

50 days of production revenue. Based upon average production from Aneth Field during the twelve months ended December 31, 2010, and a NYMEX oil price of $97.30 per barrel, Western could owe Resolute between $14.5 million and $36.2 million. If Western defaults on its obligation to pay Resolute for the crude oil it has delivered, Resolute’s income would be materially and negatively affected. Both Moody’s Investor Services and Standard & Poor’s have assigned credit ratings to Western’s long-term debt that are below investment grade and Moody’s Investor Services has assigned Western a negative outlook.
 
With respect to its Wyoming operations, Resolute does not have any long-term supply or similar agreements with entities for which it acts as a producer and currently sells most of its Wyoming oil production under a purchase agreement with a single purchaser. Resolute is therefore dependent upon its ability to sell oil and gas at the prevailing wellhead market price. There can be no assurance that purchasers will be available or that the prices they are willing to pay will remain stable and not decline.
 
Financial conditions may have effects on Resolute’s business and financial condition that Resolute cannot predict.
 
Turmoil in the global financial system may have an impact on Resolute’s business and financial condition. Resolute’s ability to access the capital markets due to financial turmoil may be restricted in the future when Resolute would like, or need, to raise capital. Financial turmoil may also limit the number of prospects for Resolute’s development and acquisition, or make such transactions uneconomic or difficult to consummate, and make it more difficult for Resolute to develop its reserves. Financial turmoil could also adversely affect the collectability of Resolute’s trade receivables and cause Resolute’s commodity derivative arrangements, if any, to be ineffective if Resolute’s counterparties are unable to perform their obligations or seek bankruptcy protection. It may also adversely affect any of Resolute’s partners’ ability to fulfill their obligations under operating agreements and Resolute may be required to fund these expenditures from other sources or reduce Resolute’s planned activities. Additionally, turmoil could lead to reduced demand for oil and gas, lower product prices or product price volatility which may a negative effect on Resolute’s revenue.
 
Inadequate liquidity could materially and adversely affect Resolute’s business operations in the future.
 
Resolute’s ability to generate cash flow depends upon numerous factors related to its business that may be beyond its control, including:
 
  •  the amount of oil and gas it produces;
 
  •  the price at which it sells its oil and gas production and the costs it incurs to market its production;
 
  •  the effectiveness of its commodity price derivative strategy;
 
  •  the development of proved undeveloped properties and the success of its enhanced oil recovery activities;
 
  •  the level of its operating and general and administrative costs;
 
  •  its ability to replace produced reserves;
 
  •  prevailing economic conditions;
 
  •  government regulation and taxation;
 
  •  the level of its capital expenditures required to implement its development projects and make acquisitions of additional reserves;
 
  •  its ability to borrow under its revolving credit facility or future debt agreements;
 
  •  its debt service requirements contained in its revolving credit facility or future debt agreements;
 
  •  fluctuations in its working capital needs; and
 
  •  timing and collectability of receivables.


29


Table of Contents

 
Resolute’s planned operations, as well as replacement of its production and reserves, will require additional capital that may not be available.
 
Resolute’s business is capital intensive, and requires substantial expenditures to maintain currently producing wells, to make the acquisitions of additional reserves and/or conduct its exploration, exploitation and development program necessary to replace its reserves, to pay expenses and to satisfy its other obligations, which will require cash flow from operations, additional borrowings or proceeds from the issuance of additional equity, or some combination thereof, which may not be available to Resolute.
 
For example, Resolute expects to spend an additional $446.7 million of capital expenditures (including CO2 purchases) over the next 29 years to implement and complete its proved developed non-producing and proved undeveloped CO2 flood projects. Resolute expects to incur approximately $198.4 million of these future capital expenditures between 2011 and 2013 based on its year-end 2010 SEC case reserve report. To the extent Resolute’s production and reserves decline faster than it anticipates, Resolute will require a greater amount of capital to maintain its production. Resolute’s ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by its financial condition at the time of any such financing or offering, the covenants in its revolving credit facility or future debt agreements, adverse market conditions or other contingencies and uncertainties that are beyond its control. Resolute’s failure to obtain the funds necessary for future activities could materially affect its business, results of operations and financial condition. Even if Resolute is successful in obtaining the necessary funds, the terms of such financings could limit Resolute’s activities and its ability to pay dividends. In addition, incurring additional debt may significantly increase Resolute’s interest expense and financial leverage, and issuing additional equity may result in significant equity holder dilution.
 
A significant part of Resolute’s development plan involves the implementation of its CO2 projects. The supply of CO2 and efficacy of the planned projects is uncertain, and other resources may not be available or may be more expensive than expected, which could adversely impact production, revenue and earnings, and may require a write-down of reserves.
 
Producing oil and gas reservoirs are depleting assets generally characterized by declining production rates that vary depending upon factors such as reservoir characteristics. A significant part of Resolute’s business strategy depends on its ability to successfully implement CO2 floods and other development projects it has planned for its Aneth Field Properties in order to counter the natural decline in production from the field. As of December 31, 2010, approximately 61% of Resolute’s estimated net proved reserves were classified as proved developed non-producing and proved undeveloped, meaning Resolute must undertake additional development activities before it can produce those reserves. These development activities involve numerous risks, including insufficient quantities of CO2, project execution risks and cost overruns, insufficient capital to allocate to these projects, and inability to obtain equipment and materials that are necessary to successfully implement these projects.
 
A critical part of Resolute’s development strategy depends upon its ability to purchase CO2. Resolute has entered into a contract to purchase CO2 from Kinder Morgan. The contract with Kinder Morgan expires in 2020. All of the CO2 Resolute has under contract comes from McElmo Dome Field. If Resolute is unable to purchase sufficient CO2 under this contract, either because Kinder Morgan is unable or is unwilling to supply the contracted volumes, Resolute would have to purchase CO2 from other owners of CO2 in McElmo Dome Field or elsewhere. In such an event, Resolute may not be able to locate substitute supplies of CO2 at acceptable prices or at all. In addition, certain suppliers of CO2, such as Kinder Morgan, use CO2 in their own tertiary recovery projects. As a result, if Resolute needs to purchase additional volumes of CO2, these suppliers may not be willing to sell a portion of their supply of CO2 to Resolute if their own demand for CO2 exceeds their supply. Additionally, even if adequate supplies are available for delivery from the McElmo Dome field, Resolute could experience temporary or permanent shut-ins of Resolute’s pipeline that delivers CO2 from that field to its Aneth Field Properties. If Resolute is unable to obtain the CO2 it requires and is unable to undertake its development projects or if Resolute’s development projects are significantly delayed, Resolute’s recoverable reserves may not be as much as it currently anticipates, it will not realize its expected incremental production, and its expected decline in the rate of production from its Aneth Field Properties will be accelerated. If Resolute’s requirements for CO2 were to decrease, it could be required to incur costs for CO2 that it has not purchased or to purchase more CO2 than it could use effectively. For more information about Resolute’s CO2 development program and minimum financial


30


Table of Contents

obligations under the Kinder Morgan contract, please read “Resolute’s Business — Planned Operating and Development Activities.”
 
In addition, Resolute’s estimate of future development costs, including with respect to its planned CO2 development projects, is based on Resolute’s current expectation of prices and other costs of CO2, equipment and personnel Resolute will need in the future to implement such projects. Resolute’s actual future development costs may be significantly higher than Resolute currently estimates, and delays in executing its development projects could result in higher labor and other costs associated with these projects. If costs become too high, Resolute’s future development projects may not provide economic results and Resolute may be forced to abandon its development projects.
 
Furthermore, the results Resolute obtains from its CO2 flood projects may not be the same as it expected when preparing its estimate of net proved reserves. Lower than expected production results or delays in when Resolute first realizes additional production as a result of its CO2 flood projects will reduce the value of its reserves, which could reduce its ability to incur indebtedness, require Resolute to use cash to repay indebtedness or to satisfy its derivative obligations, and require Resolute to write-down the value of its reserves. Therefore, Resolute’s future reserves, production and future cash flow are highly dependent on Resolute’s success in efficiently developing and exploiting its current estimated net proved undeveloped reserves.
 
Resolute is a party to a contract that requires it to pay for a minimum quantity of CO2. This contract limits Resolute’s ability to curtail costs if its requirements for CO2 decrease.
 
Resolute’s contract with Kinder Morgan requires Resolute to take, or pay for if not taken, a minimum volume of CO2 on a monthly basis. The take-or-pay obligations result in minimum financial obligations through 2020. The take-or-pay provisions in this contract allow Resolute to subsequently apply take-or-pay payments made to volumes subsequently taken, but these provisions have limitations and Resolute may not be able to utilize all such amounts paid if the limitations apply or if Resolute does not subsequently take sufficient volumes to utilize the amounts previously paid.
 
Oil and gas prices are volatile and change for reasons that are beyond Resolute’s control. Decreases in the price Resolute receives for its oil and gas production can adversely affect its business, financial condition, results of operations and liquidity and impede its growth.
 
The oil and gas markets are highly volatile, and Resolute cannot predict future prices. Resolute’s revenue, profitability and cash flow depend upon the prices and demand for oil, natural gas and NGL . The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect Resolute’s financial results and impede its growth. Prices for oil, gas and NGL may fluctuate widely in response to relatively minor changes in the supply of and demand for the commodities, market uncertainty and a variety of additional factors that are beyond Resolute’s control, such as:
 
  •  domestic and foreign supply of and demand for oil and gas, 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;
 
  •  the price of foreign imports;
 
  •  political and economic conditions in oil producing countries, including the Middle East and South America;
 
  •  technological advances affecting energy consumption;
 
  •  variations between product prices at sales points and applicable index prices;
 
  •  domestic, tribal and foreign governmental regulations and taxation;


31


Table of Contents

 
  •  the impact of energy conservation efforts;
 
  •  the capacity, cost and availability of oil and gas pipelines and other transportation and gathering facilities, and the proximity of these facilities to its wells;
 
  •  the availability of refining and processing capability;
 
  •  factors specific to the local and regional markets where Resolute’s production occurs; and
 
  •  the price and availability of alternative fuels.
 
In the past, the price of crude oil has been extremely volatile, and Resolute expects this volatility to continue. For example, during the twelve months ended December 31, 2010, the NYMEX price for light sweet crude oil ranged from a high of $91.49 per Bbl to a low of $65.96 per Bbl. For calendar year 2009, the range was from a high of $81.04 per Bbl to a low of $33.98 per Bbl, and for the five years ended December 31, 2010, the price ranged from a high of $145.28 per Bbl to a low of $31.41 per Bbl.
 
A decline in oil and gas prices can significantly affect many aspects of Resolute’s business, including financial condition, revenue, results of operations, liquidity, rate of growth and the carrying value of Resolute’s oil and gas properties, all of which depend primarily or in part upon those prices. For example, declines in the prices Resolute receives for its oil and gas adversely affect its ability to finance capital expenditures, make acquisitions, raise capital and satisfy its financial obligations. In addition, declines in prices reduce the amount of oil and gas that Resolute can produce economically and, as a result, adversely affect its quantities of proved reserves. Among other things, a reduction in its reserves can limit the capital available to Resolute, as the maximum amount of available borrowing under its revolving credit facility is, and the availability of other sources of capital likely will be, based to a significant degree on the estimated quantities of those reserves.
 
Resolute’s estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities of Resolute’s proved reserves.
 
Resolute’s estimate of proved reserves for the period ended December 31, 2010, is based on the quantities of oil and gas that engineering and geological analyses demonstrate with reasonable certainty to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell & Associates, Inc., independent petroleum engineers, audited reserve and economic evaluations of all properties that were prepared by Resolute on a well-by-well basis. Oil and gas reserve engineering is not exact; it relies on subjective interpretations of data that may be inaccurate or incomplete and requires predictions and assumptions of future reservoir behavior and economic conditions. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including:
 
  •  the assumed accuracy of field measurements and other reservoir data;
 
  •  assumptions regarding expected reservoir performance relative to historical analog reservoir performance;
 
  •  the assumed effects of regulations by governmental agencies;
 
  •  assumptions concerning future oil and gas prices; and
 
  •  assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.
 
Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves:
 
  •  the quantities of oil and gas that are ultimately recovered;
 
  •  the timing of the recovery of oil and gas reserves;
 
  •  the production and operating costs incurred; and
 
  •  the amount and timing of future development expenditures.


32


Table of Contents

 
Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. As a result of all these factors, Resolute may make material changes to reserves estimates to take into account changes in its assumptions and the results of its development activities and actual drilling and production.
 
If these assumptions prove to be incorrect, Resolute’s estimates of reserves, the economically recoverable quantities of oil and gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and Resolute’s estimates of the future net cash flows from its reserves could change significantly. In addition, if declines in oil and gas prices result in its having to make substantial downward adjustments to its estimated proved reserves, or if its estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require Resolute to make downward adjustments, as a non-cash impairment charge to earnings, to the carrying value of Resolute’s oil and gas properties. If Resolute incurs impairment charges in the future, Resolute could have a material adverse effect on its results of operations in the period incurred and on its ability to borrow funds under its credit facility.
 
The standardized measure of future net cash flows from Resolute’s net proved reserves is based on many assumptions that may prove to be inaccurate. Any material inaccuracies in Resolute’s reserve estimates or underlying assumptions will materially affect the quantities and present value of its proved reserves.
 
Actual future net cash flows from Resolute’s oil and gas properties will be determined by the actual prices Resolute receives for oil and gas, its actual operating costs in producing oil and gas, the amount and timing of actual production, the amount and timing of Resolute’s capital expenditures, supply of and demand for oil and gas and changes in governmental regulations or taxation, which may differ from the assumptions used in creating estimates of future cash flows.
 
The timing of both Resolute’s production and its incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor Resolute uses when calculating discounted future net cash flows in compliance with guidance from the FASB may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with Resolute or the oil and gas industry in general.
 
Currently, substantially all of Resolute’s oil producing properties are located on the Navajo Reservation, making Resolute vulnerable to risks associated with laws and regulations pertaining to the operation of oil and gas properties on Native American tribal lands.
 
Substantially all of Resolute’s Aneth Field Properties, which represent approximately 92% of Resolute’s total proved reserves and approximately 76% of Resolute’s production (on an equivalent barrel basis) at December 31, 2010, are located on the Navajo Reservation in southeastern Utah. Operation of oil and gas interests on Indian lands presents unique considerations and complexities. These arise from the fact that Indian tribes are dependent sovereign nations located within states, but are subject only to tribal laws and treaties with, and the laws and Constitution of, the United States. This creates a potential overlay of three jurisdictional regimes — Indian, federal and state. These considerations and complexities could affect various aspects of Resolute’s operations, including real property considerations, employment practices, environmental matters and taxes.
 
For example, Resolute is subject to the Navajo Preference in Employment Act. This law requires that it give preference in hiring to members of the Navajo Nation, or in some cases other Native American tribes, if such a person is qualified for the position, rather than hiring the most qualified person. A further regulatory requirement is imposed by the Navajo Nation Business Opportunity Act which requires Resolute to give preference to businesses owned by Navajo persons when it is hiring contractors. These regulatory restrictions can negatively affect Resolute’s ability to recruit and retain the most highly qualified personnel or to utilize the most experienced and economical contractors for its projects.
 
Furthermore, because tribal property is considered to be held in trust by the federal government, before Resolute can take actions such as drilling, pipeline installation or similar actions, it is required to obtain approvals


33


Table of Contents

from various federal agencies that are in addition to customary regulatory approvals required of oil and gas producers operating on non-Indian property. Resolute also is required to obtain approvals from the Resources Committee, which is a standing committee of the Navajo Nation Tribal Council, before Resolute can take similar actions with respect to its Aneth Field Properties. These approvals could result in delays in its implementation of, or otherwise prevent it from implementing, its development program. These approvals, even if ultimately obtained, could result in delays in Resolute’s ability to implement its development program.
 
In addition, under the Native American laws and regulations, Resolute could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of Resolute’s operations and subject it to administrative, civil and criminal penalties, including the assessment of natural resource damages.
 
Thirty-Two Point Agreement. An explosion at an ExxonMobil facility in Aneth Field in December 1997 prompted protests by local tribal members and temporary shutdown of the field. The protesters asserted concerns about environmental degradation, health problems, employment opportunities and renegotiating leases. The protest was settled among the local residents, ExxonMobil and the Navajo Nation by the Thirty-Two Point Agreement that provided, among other things, for ExxonMobil to pay partial salaries for two Navajo public liaison specialists, follow Navajo hiring practices, and settle further issues addressed in the Thirty-Two Point Agreement in the Navajo Nation’s “peacemaker” courts, which follow a community-level conflict resolution format. After the Thirty-Two Point Agreement was executed, Aneth Field resumed normal operations. While Resolute did not formally assume the obligations of ExxonMobil under the Thirty-Two Point Agreement when it acquired the ExxonMobil Properties in 2006, it has been Resolute’s policy to voluntarily comply with this agreement. While the Company believes that its relations with the Navajo Nation are satisfactory, it is possible that employee relations or community relations degrade to a point where protests and shutdown occur in the future.
 
For additional information about the legal complexities and considerations associated with operating on the Navajo Reservation, please read “Resolute’s Business — Laws and Regulations Pertaining to Oil and Gas Operations on Navajo Nation Lands.”
 
NNOG has options to purchase a portion of Resolute’s Aneth Field Properties.
 
NNOG has a total of six options to purchase for cash at fair market value, in the aggregate, up to 30.0% of Resolute’s interest in the Chevron Properties and 30.0% of its interest in the ExxonMobil Properties. These options become exercisable over a period of time if financial hurdles related to recovery by Resolute of its investments are met. If NNOG exercises its purchase options in full, it could acquire from Resolute undivided working interests representing an 18.15% working interest in the Aneth Unit, a 22.5% working interest in the McElmo Creek Unit and a 17.7% working interest in the Ratherford Unit. If NNOG were to exercise any of these options, Resolute might not be able to effectively redeploy the cash received from NNOG. For additional information about NNOG’s purchase right, please read “Resolute’s Business — Relationship with the Navajo Nation.”
 
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 negotiation could diminish the value Resolute may be able to receive in a sale of its properties.
 
Nearly all of Resolute’s Aneth Field Properties are located on the Navajo Reservation. The Navajo Nation has a statutory preferential right to purchase at the offered price any Navajo Nation oil and gas lease or working interest in such a lease at the time a proposal is made to transfer the lease or interest. The existence of this right can make it more difficult to sell a Navajo Nation oil and gas lease because this right may discourage third parties from purchasing such a lease and, therefore, could reduce the value of Resolute’s leases if it were to attempt to sell them. In addition, under the terms of Resolute’s Cooperative Agreement with NNOG, Resolute is obligated to first negotiate with NNOG to sell its Aneth Field Properties before it may offer to sell such properties to any other third party. This contractual right could make it more difficult for Resolute to sell its Aneth Field Properties. For additional information about the right of first negotiation for the benefit of NNOG, please read “Resolute’s Business — Relationship with the Navajo Nation.”


34


Table of Contents

Resolute’s producing properties are primarily located in two geographic areas, making it vulnerable to risks associated with lack of geographic diversification.
 
A substantial amount of Resolute’s sales of oil and gas and 92% of its total proved reserves at December 31, 2010, are currently located in its Aneth Field Properties in the southeast Utah portion of the Paradox Basin in the Four Corners area of the southwestern United States. Essentially all of the remainder of Resolute’s sales of oil and gas and 7% of its total proved reserves are predominantly located in Hilight Field in the Powder River Basin in northeastern Wyoming and southeastern Montana. As a result of Resolute’s lack of diversification in asset type and location, any delays or interruptions of production from these wells caused by such factors as governmental regulation, transportation capacity constraints, curtailment of production or interruption of transportation of oil produced from the wells in these fields, price fluctuations, natural disasters or shutdowns of the pipelines connecting its Aneth Field production to refineries would have a significantly greater impact on Resolute’s results of operations than if Resolute possessed more diverse assets and locations.
 
Lack of geographic diversification also affects the prices to be received for Resolute’s oil and gas production from its properties, since prices are determined to a significant extent by factors affecting the regional supply of and demand for oil and gas, including the adequacy of the pipeline and processing infrastructure in the region to transport or process Resolute’s production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional oil and gas production and the actual (frequently lower) price Resolute may receive for its production.
 
Developing and producing oil and gas are costly and high-risk activities with many uncertainties that could adversely affect Resolute’s financial condition or results of operations, and insurance may not be available or may not fully cover losses.
 
There are numerous risks associated with developing, completing and operating a well, and cost factors can adversely affect the economics of a well. Resolute’s development and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
 
  •  high costs, shortages or delivery delays of rigs, equipment, labor or other services;
 
  •  unexpected operational events and/or conditions;
 
  •  reductions in oil or gas prices or increases in the differential between index oil or gas prices and prices received by Resolute;
 
  •  increases in severance taxes;
 
  •  limitations on Resolute’s ability to sell its crude oil or gas 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;
 
  •  shortages or delivery delays of equipment and services;
 
  •  title problems;
 
  •  objections from surface owners and nearby surface owners in the areas where Resolute operates; and
 
  •  uncontrollable flows of oil, gas or well fluids.


35


Table of Contents

 
Any of these or other similar occurrences could reduce Resolute’s cash from operations or result in the disruption of Resolute’s operations, substantial repair costs, significant damage to property, environmental pollution and impairment of its operations. The occurrence of these events could also affect third parties, including persons living near Resolute’s operations, Resolute’s employees and employees of Resolute’s contractors, leading to injuries or death.
 
Insurance against all operational risk is not available to Resolute, and pollution and environmental risks generally are not fully insurable. Additionally, Resolute may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. Resolute does not maintain business interruption insurance. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001, have made it more difficult for Resolute to obtain coverage for terrorist attacks and related risks. Resolute may not be able to obtain the levels or types of insurance it would otherwise have obtained prior to these market changes, and any insurance coverage Resolute does obtain may contain large deductibles or it may not cover all hazards or potential losses. Losses and liabilities from uninsured and underinsured events or a delay in the payment of insurance proceeds could adversely affect Resolute’s business, financial condition and results of operations.
 
Exploration and development drilling may not result in commercially productive reserves.
 
Resolute may not encounter commercially productive reservoirs through its drilling operations. In 2011, Resolute expects to incur approximately $42 million of capital expenditures for acreage acquisition, exploration and development drilling in the Williston Basin properties in North Dakota. Additionally, the Company has allocated $15 million for exploration and development projects in its Wyoming Properties and Big Horn Basin acreage. The new wells Resolute drills or participates in may not be productive and the Company may not recover all or any portion of its investment in such wells. The seismic data and other technologies Resolute uses do not allow it to know conclusively prior to drilling whether it will find oil or gas or, if found, that the hydrocarbons will be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Resolute’s efforts will be unprofitable if it drills dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, Resolute’s drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
 
  •  increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment;
 
  •  unexpected drilling conditions;
 
  •  title problems;
 
  •  pressure or irregularities in formations;
 
  •  equipment failures or accidents;
 
  •  adverse weather conditions; and
 
  •  compliance with environmental and other governmental requirements.
 
If Resolute does not make acquisitions of reserves on economically acceptable terms, Resolute’s future growth and ability to maintain production will be limited to only the growth it intends to achieve through the development of its proved developed non-producing and proved undeveloped reserves.
 
Producing oil and gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from Resolute’s existing wells declines in a different manner than Resolute has estimated and can change under other circumstances. Resolute’s future oil and gas reserves and production and, therefore, Resolute’s cash flow and income are highly dependent upon its success in efficiently developing and exploiting its current reserves and economically finding or acquiring additional recoverable reserves.


36


Table of Contents

Resolute intends to grow by bringing its proved developed non-producing reserves into production, developing its proved undeveloped reserves and exploring for and finding additional reserves on its non-proved properties. Resolute’s ability to further grow depends in part on its ability to make acquisitions, particularly in the event NNOG exercises its options to increase its working interest in the Aneth Field Properties. Resolute may be unable to make such acquisitions because it is:
 
  •  unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with the seller;
 
  •  unable to obtain financing for these acquisitions on economically acceptable terms; or
 
  •  outbid by competitors.
 
If Resolute is unable to acquire properties containing proved reserves at acceptable costs, Resolute’s total level of proved reserves and associated future production will decline as a result of its ongoing production of its reserves.
 
Any acquisitions Resolute completes are subject to substantial risks that could negatively affect its financial condition and results of operations.
 
Even if Resolute does make acquisitions that it believes will enhance its growth, financial condition or results of operations, any acquisition involves potential risks, including, among other things:
 
  •  the validity of Resolute’s assumptions about the acquired properties or company’s reserves, future production, the future prices of oil and gas, infrastructure requirements, environmental and other liabilities, revenue and costs;
 
  •  an inability to integrate successfully the properties and businesses Resolute acquires;
 
  •  a decrease in Resolute’s liquidity to the extent it uses a significant portion of its available cash or borrowing capacity to finance acquisitions or operations of the acquired properties;
 
  •  a significant increase in its interest expense or financial leverage if Resolute incurs debt to finance acquisitions or operations of the acquired properties;
 
  •  the assumption of unknown liabilities, losses or costs for which Resolute is not indemnified or for which Resolute’s 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 Resolute’s growing business and assets;
 
  •  unforeseen difficulties encountered in operating in new geographic areas; and
 
  •  customer or key employee losses at the acquired businesses.
 
Resolute’s decision to acquire a property or business will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.
 
Also, Resolute’s reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential problems. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. The potential risks in making acquisitions could adversely affect Resolute’s ability to achieve anticipated levels of cash flows from the acquired businesses or realize other anticipated benefits of those acquisitions.


37


Table of Contents

Resolute’s future debt levels may limit its flexibility to obtain additional financing and pursue other business opportunities.
 
Resolute expects to have the ability to incur additional debt under its revolving credit facility, subject to borrowing base limitations. Resolute’s increased level of indebtedness could have important consequences to Resolute, including:
 
  •  Resolute’s 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 Resolute’s existing and future credit and debt arrangements will require it to meet financial tests that may affect its flexibility in planning for and reacting to changes in its business, including possible acquisition opportunities;
 
  •  Resolute will need a substantial portion of its cash flow to make principal and interest payments on its indebtedness, reducing the funds that would otherwise be available for operations and future business opportunities; and
 
  •  Resolute’s debt level will make it more vulnerable than its competitors with less debt to competitive pressures or a downturn in its business or the economy generally.
 
Resolute’s ability to service its indebtedness will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond Resolute’s control. If Resolute’s operating results are not sufficient to service its current or future indebtedness, it will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing Resolute’s indebtedness, or seeking additional equity capital or bankruptcy protection. Resolute may not be able to effect any of these remedies on satisfactory terms or at all.
 
Resolute’s revolving credit facility has substantial financial and operating covenants that restrict Resolute’s business and financing activities and prohibit Resolute from paying dividends. Future borrowing agreements would likely include similar restrictions.
 
The operating and financial covenants in Resolute’s senior secured revolving credit facility restrict Resolute’s ability to finance future operations or capital needs or to engage, expand or pursue its business activities. Resolute’s revolving credit facility currently restricts, and it anticipates that any amendment to such facility would restrict, its ability to:
 
  •  incur indebtedness;
 
  •  grant liens;
 
  •  make acquisitions and investments;
 
  •  lease equipment;
 
  •  redeem or prepay other debt;
 
  •  pay dividends to shareholders or repurchase shares;
 
  •  enter into transactions with affiliates; and
 
  •  enter into a merger, consolidation or sale of assets.
 
The revolving credit agreement matures in March 2014, unless extended, and is secured by all of Resolute’s oil and gas properties as well as a pledge of all ownership interests in operating subsidiaries. The revolving credit agreement has a borrowing base (currently $260 million) determined by the lenders based on their evaluation of the value of the collateral. Resolute is required to maintain a consolidated current ratio of at least 1.0 to 1.0 at the end of any fiscal quarter; and may not permit its Maximum Leverage Ratio (consolidated indebtedness to


38


Table of Contents

consolidated EBITDA as defined in the credit agreement) to exceed 4.0 to 1.0 at the end of each fiscal quarter. Resolute’s revolving credit facility does not permit it to pay dividends to shareholders.
 
Resolute may enter into additional borrowing agreements which would likely include additional operating and financial covenants.
 
Shortages of qualified personnel or field equipment and services could affect Resolute’s ability to execute its plans on a timely basis, reduce its cash flow and adversely affect its results of operations.
 
The demand for qualified and experienced geologists, geophysicists, engineers, field operations specialists, landmen, financial experts and other personnel in the oil and gas industry can fluctuate significantly, often in correlation with oil and gas prices, causing periodic shortages. From time to time, there also have been shortages of drilling rigs and other field equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors can also result in significant increases in costs for equipment, services and personnel. Higher oil and gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Historically, increased demand resulting from high commodity prices have at times significantly increased costs and resulted in some difficulty in obtaining drilling rigs, experienced crews and related services. Resolute may continue to experience such difficulties in the future. If shortages persist or prices continue to increase, Resolute’s profit margin, cash flow and operating results could be adversely affected and Resolute’s ability to conduct its operations in accordance with current plans and budgets could be restricted.
 
Resolute’s derivative activities could reduce its net income, which could reduce the price at which the Company’s stock may trade.
 
To achieve more predictable cash flow and to reduce Resolute’s exposure to adverse changes in the price of oil and gas, Resolute has entered into, and plans to enter into in the future, derivative arrangements covering a significant portion of its oil and gas production. These derivative arrangements could result in both realized and unrealized derivative losses. Resolute’s derivative instruments are subject to mark-to-market accounting treatment, and the change in fair market value of the instrument is reported in Resolute’s statement of operations each quarter, which has resulted in, and will in the future likely result in, significant unrealized net gains or losses.
 
As of December 31, 2010, Resolute had in place oil swaps covering approximately 60% of its anticipated 2011 oil production at a weighted average price of $68.26 per Bbl, oil collars covering approximately 5% of its anticipated 2011 oil production with a floor of $80.00 per Bbl and a ceiling of $90.00 per Bbl, gas swaps covering approximately 47% of its anticipated 2011 gas production at a weighted average price of $9.32 per MMBtu, and gas basis derivatives at a weighted average price of $1.40 per MMBtu covering approximately 57% of its anticipated 2010 gas production. Additional instruments are also in place for future years. Resolute expects to continue to use derivative arrangements to reduce commodity price risk with respect to its estimated production from producing properties. Please read — “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Resolute — How Resolute Evaluates Its Operations — Production Levels, Trends and Prices” and “Management’s Discussion and Analysis of Financial Condition and Results of Resolute — Quantitative and Qualitative Disclosures About Market Risk.”
 
Resolute’s actual future production during a period may be significantly higher or lower than it estimates at the time it enters into derivative transactions for such period. If the actual amount is higher than it estimates, it will have more unhedged production and therefore greater commodity price exposure than it intended. If the actual amount is lower than the nominal amount that is subject to Resolute’s derivative financial instruments, whether due to issues with our sales to Western, natural declines in production and the failure to develop new reserves, the efficacy of our CO2 project or other factors, Resolute might be forced to satisfy all or a portion of its derivative transactions in cash without the benefit of the cash flow from its sale of the underlying physical commodity, resulting in a substantial diminution of its liquidity. As a result of these factors, Resolute’s derivative activities may not be as effective as it intends in reducing the volatility of its cash flows, and in certain circumstances may actually increase the volatility of its cash flows.


39


Table of Contents

In addition, Resolute’s derivative activities are subject to the risk that a counterparty may not perform its obligation under the applicable derivative instrument. If derivative counterparties, some of which have received governmental support in connection with the ongoing credit crisis, are unable to make payments to Resolute under its derivative arrangements, Resolute’s results of operations, financial condition and liquidity would be adversely affected.
 
The effectiveness of derivative transactions to protect Resolute from future oil price declines will be dependent upon oil prices at the time it enters into future derivative transactions as well as its future levels of hedging, and as a result its future net cash flow may be more sensitive to commodity price changes.
 
As Resolute’s derivatives expire, more of its future production will be sold at market prices unless it enters into additional derivative transactions. Resolute’s revolving credit facility prohibits it from entering into derivative arrangements for more than 85% of its production from projected proved developed producing reserves using economic parameters specified in its credit agreements. The prices at which Resolute hedges its production in the future will be dependent upon commodity prices at the time it enters into these transactions, which may be substantially lower than current prices. Accordingly, Resolute’s commodity price hedging strategy will not protect it from significant and sustained declines in oil and gas prices received for its future production. Conversely, Resolute’s commodity price hedging strategy may limit its ability to realize cash flow from commodity price increases. It is also possible that a larger percentage of Resolute’s future production will not be hedged as the Company’s derivative policies may change, which would result in its oil revenue becoming more sensitive to commodity price changes.
 
The nature of Resolute’s assets exposes it to significant costs and liabilities with respect to environmental and operational safety matters. Resolute is also responsible for costs associated with the removal and remediation of the decommissioned Aneth Gas Processing Plant.
 
Resolute may incur significant costs and liabilities as a result of environmental, health and safety requirements applicable to its oil and gas exploitation, production and other activities. These costs and liabilities could arise under a wide range of environmental, health and safety laws and regulations, including agency interpretations thereof and governmental enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, cleanup and site restoration costs and liens, the denial or revocation of permits or other authorizations and the issuance of injunctions to limit or cease operations. Compliance with these laws and regulations also increases the cost of Resolute’s operations and may prevent or delay the commencement or continuance of a given operation. In addition, claims for damages to persons or property may result from environmental and other impacts of its operations.
 
Resolute has an interest in the Aneth Gas Processing Plant, which is currently being decommissioned. Under Resolute’s purchase agreement with Chevron, Chevron is responsible for indemnifying Resolute against the decommissioning and clean-up or remediation costs allocable to the 39% interest Resolute purchased from it. Under Resolute’s purchase agreement with ExxonMobil, however, Resolute is responsible for the decommissioning and clean-up or remediation cost allocable to the interests it purchased from ExxonMobil, which is 25% of the total cost of the project. If Chevron fails to pay its share of the decommissioning costs in accordance with the purchase agreement, Resolute could be held responsible for 64% of the total costs to decommission and remediate the Aneth Gas Processing Plant. Chevron is managing the decommissioning process and, based on Resolute’s current estimate, the total cost of the decommissioning is $24.4 million. $20.9 million has already been incurred and paid for as of December 31, 2010. This estimate does not include any costs for any possible subsurface clean-up or remediation of the site.
 
The Aneth Gas Processing Plant site was previously evaluated by the U.S. EPA for possible listing on the NPL of sites contaminated with hazardous substances with the highest priority for clean-up under the CERCLA. Based on its investigation, the EPA concluded no further investigation was warranted and that the site was not required to be listed on the NPL. The Navajo Environmental Protection Agency now has primary jurisdiction over the Aneth Gas Processing Plant site, however, and Resolute cannot predict whether it will require further


40


Table of Contents

investigation and possible clean-up, and the ultimate cleanup liability may be affected by the recent enactment by the Navajo Nation of the Navajo CERCLA. In some matters, the Navajo CERCLA imposes broader obligations and liabilities than the federal CERCLA. Resolute has been advised by Chevron that a significant portion of the subsurface clean-up or remediation costs, if any, would be covered by an indemnity from the prior owner of the plant, and Chevron has provided Resolute with a copy of the pertinent purchase agreement that appears to support its position. Resolute cannot predict whether any subsurface remediation will be required or what the costs of the subsurface clean-up or remediation could be. Additionally, it cannot be certain whether any of such costs will be reimbursable to it pursuant to the indemnity of the prior owner. To the extent any such costs are incurred and not reimbursed pursuant to the indemnity from the prior owner, Resolute would be liable for 25% of such costs as a result of its acquisition of the ExxonMobil Properties. Please read “Resolute’s Business — Aneth Gas Processing Plant” for additional information about this liability.
 
Strict or joint and several liability to remediate contamination may be imposed under environmental laws, which could cause Resolute to become liable for the conduct of others or for consequences of its own actions that were in compliance with all applicable laws at the time those actions were taken. New or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. Please read “Resolute’s Business — Environmental, Health and Safety Matters and Regulation” for more information.
 
Resolute may be unable to compete effectively with larger companies, which may adversely affect its operations and ability to generate and maintain sufficient revenue.
 
The oil and gas industry is intensely competitive, and Resolute competes with companies that have greater resources. Many of these companies not only explore for and produce oil and gas, but also refine and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and gas properties and exploratory prospects or identify, evaluate, bid for and purchase a greater number of properties and prospects than Resolute’s financial or human resources permit. In addition, these companies may have a greater ability to continue exploration or exploitation activities during periods of low oil and gas market prices. Resolute’s larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than Resolute can, which would adversely affect Resolute’s competitive position. Resolute’s ability to acquire additional properties and to discover reserves in the future will depend upon its ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.
 
Resolute is subject to complex federal, state, tribal, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
 
Exploration, exploitation, development, production and marketing operations in the oil and gas industry are regulated extensively at the federal, state and local levels. In addition, substantially all of Resolute’s current leases in the Aneth Field are regulated by the Navajo Nation. Some of its future leases may be regulated by Native American tribes. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and properly abandon oil and gas wells and other recovery operations. Under these laws and regulations, Resolute could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of Resolute’s operations or denial or revocation of permits and subject Resolute to administrative, civil and criminal penalties. In addition, the President’s budget and other legislative proposals would terminate various tax deductions currently available to companies engaged in oil and gas development and production. Tax deductions that are proposed to be terminated include the deduction for intangible drilling and development costs, the deduction for qualified tertiary injectant expenses, and the domestic manufacturing deduction. If enacted, the elimination of these deductions will adversely affect our business.
 
Part of the regulatory environment in which Resolute operates includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production activities. In addition, Resolute’s activities are subject to regulation by oil and gas producing states and the Navajo Nation regarding conservation practices, protection of correlative rights


41


Table of Contents

and other concerns. These regulations affect Resolute’s operations and could limit the quantity of oil and gas it may produce and sell. A risk inherent in Resolute’s CO2 flood project is the need to obtain permits from federal, state, local and Navajo Nation tribal authorities. Delays or failures in obtaining regulatory approvals or permits or the receipt of an approval or permit with unreasonable conditions or costs could have a material adverse effect on Resolute’s ability to exploit its properties. Additionally, the oil and gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect Resolute’s profitability. Proposed GHG reporting rules and proposed GHG cap and trade legislation are two examples of proposed changes in the regulatory climate that would affect Resolute. Furthermore, Resolute may be placed at a competitive disadvantage to larger companies in the industry, which can spread these additional costs over a greater number of wells and larger operating staff. Please read “Resolute’s Business — Environmental, Health and Safety Matters and Regulation” and “Resolute’s Business — Other Regulation of the Oil and Gas Industry” for a description of the laws and regulations that affect Resolute.
 
Possible regulation related to global warming and climate change could have an adverse effect on Resolute’s operations and demand for oil and gas.
 
Recent scientific studies have suggested that emissions of GHG, including CO2 and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is considering legislation to reduce emissions of GHG. In addition, several states have already taken legal measures to reduce emissions of GHG. As a result of the U.S. Supreme Court’s decision on April 2, 2007, in Massachusetts, et al. v. EPA, the EPA also may be required to regulate GHG emissions from mobile sources (e.g. cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of GHG. Other nations have already agreed to regulate emissions of GHG, pursuant to the United Nations Framework Convention on Climate Change, and the subsequent “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of GHG to below 1990 levels by 2012. Passage of state or federal climate control legislation or other regulatory initiatives or the adoption of regulations by the EPA and state agencies that restrict emissions of GHG in areas in which Resolute conducts business could have an adverse effect on Resolute’s operations and demand for oil and gas.
 
Resolute depends on a limited number of key personnel who would be difficult to replace.
 
Resolute depends substantially on the performance of its executive officers and other key employees. Resolute has not entered into any employment agreements with any of these employees, and Resolute does not maintain key person life insurance policies on any of these employees. The loss of any member of the senior management team or other key employees could negatively affect Resolute’s ability to execute its business strategy.
 
Terrorist attacks aimed at Resolute’s facilities or operations could adversely affect its business.
 
The United States has been the target of terrorist attacks of unprecedented scale. The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments have subjected Resolute’s operations to increased risks. Any terrorist attack at Resolute’s facilities, or those of its customers or suppliers, could have a material adverse effect on Resolute’s business.
 
Work stoppages or other labor issues at Resolute’s facilities could adversely affect its business, financial position, results of operations, or cash flows.
 
As of December 31, 2010, approximately 39 of Resolute’s field level employees were represented by the USW, and covered by a collective bargaining agreement. Although Resolute believes that its relations with its employees are generally satisfactory, if Resolute is unable to reach agreement with any of its unionized work groups on future negotiations regarding the terms of their collective bargaining agreements, or if additional segments of Resolute’s workforce become unionized, Resolute may be subject to work interruptions or stoppages. In addition, work stoppages have occurred in the past as a result of protests by local tribal members. Work stoppages at the facilities of Resolute’s customers or suppliers may also negatively affect Resolute’s business. If any of Resolute’s customers experience a material work stoppage, the customer may halt or limit the


42


Table of Contents

purchase of Resolute’s products. Moreover, if any of Resolute’s suppliers experience a work stoppage, its operations could be adversely affected if an alternative source of supply is not readily available. Any of these events could be disruptive to Resolute’s operations and could adversely affect its business, financial position, results of operations, or cash flows.
 
Resolute may be required to write down the carrying value of its properties in the future.
 
Resolute uses the full cost accounting method for oil and gas exploitation, development and exploration activities. Under the full cost method rules, Resolute performs a ceiling test and if the net capitalized costs for a cost center exceed the ceiling for the relevant properties, it writes down the book value of the properties. Accordingly, Resolute could recognize impairments in the future if oil and gas prices are low, if Resolute has substantial downward adjustments to its estimated proved reserves, if Resolute experiences increases in its estimates of development costs or deterioration in its exploration and development results.
 
At December 31, 2009, using its year-end reserve estimates prepared in accordance with the then recently promulgated SEC rules, total capitalized costs exceeded the full cost ceiling by approximately $150 million. No impairment expense was recorded at December 31, 2009, as the Company requested and received an exemption from the SEC to exclude the Resolute Transaction from the full cost ceiling assessment for a period of twelve months following the acquisition, provided the Company was able to demonstrate that the fair value of the acquired properties exceeded the carrying value in the interim periods through June 30, 2010, which was the case. No ceiling test impairment expense was recorded during 2010.
 
Compliance with the Sarbanes-Oxley Act of 2002 and other obligations of being a public company will require substantial financial and management resources.
 
Section 404 of the Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act, requires that the Company evaluate and report on its system of internal controls. If the Company fails to maintain the adequacy of its internal controls, it could be subject to regulatory scrutiny, civil or criminal penalties and/or stockholder litigation. Any inability to provide reliable financial reports could harm the Company’s business. Section 404 of the Sarbanes-Oxley Act also requires that the Company’s independent registered public accounting firm report on management’s evaluation of the Company’s system of internal controls. Any failure to maintain the adequacy of its internal controls could harm the Company’s operating results or cause the Company to fail to meet its reporting obligations. Inferior internal controls could also cause investors to lose confidence in the Company’s reported financial information, which could have a negative effect on the trading price of the shares of Company common stock.
 
Delaware law and our amended and restated charter documents may impede or discourage a takeover that our stockholders may consider favorable.
 
Our amended and restated charter and bylaws have provisions that may deter, delay or prevent a third party from acquiring us. These provisions include:
 
  •  limitations on the ability of stockholders to amend our charter documents, including stockholder supermajority voting requirements
 
  •  the inability of stockholders to act by written consent or to call special meetings.
 
  •  a classified board of directors with staggered three-year terms;
 
  •  the authority of our board of directors to issue, without stockholder approval, up to 1,000,000 shares of preferred stock with such terms as the board of directors may determine and to issue additional shares of our common stock; and
 
  •  advance notice procedures with respect to stockholder proposals and the nomination of candidates for election as directors.


43


Table of Contents

 
Offers or availability for resale of a substantial number of shares of our common stock may cause the price of our common stock to decline.
 
If our warrant holders exercise outstanding Warrants and sell substantial amounts of our common stock in the public market, or if our stockholders resell substantial amounts of our common stock pursuant to a registration statement or upon the expiration of any statutory holding period under Rule 144 or Rule 145 under the Securities Act of 1933, as amended (the “Securities Act”), such resales could create a circumstance commonly referred to as an “overhang” and in anticipation of which the market price of our common stock could fall. The existence of an overhang, whether or not sales have occurred or are occurring, also could exert downward pressure on our stock price and make it more difficult for us to raise additional financing through the sale of equity or equity-related securities in the future at a time and price that we deem reasonable or appropriate. At December 31, 2010, the Company had outstanding warrants to purchase 48,400,000 shares of common stock at an exercise price of $13.00 per share, representing approximately 88% of the Company’s outstanding common stock at such date. Exercise of these warrants will result in dilution to our stockholders, which could cause the market price of our common stock to decline.
 
Registration rights held by certain of our stockholders may have an adverse effect on the market price of our common stock.
 
The Company’s Registration Statement on Form S-1 (File No. 333-167894) (the “Registration Statement”), declared effective in June 2010, registered for resale 12,859,193 shares of Company common stock by certain selling stockholders identified therein (the “Resale Shares”). The sale of the Resale Shares in the public market pursuant to the Registration Statement could adversely affect the market price of our common stock or impact our ability to raise additional equity capital.
 
In addition under a Registration Rights Agreement entered into in connection with the Resolute Transaction, holders of registrable securities have the right to demand registration under the Securities Act of all or a portion of their registrable securities subject to amount and time limitations. Holders of the registrable securities may demand four registrations. Additionally, whenever (i) we propose to register any of our securities under the Securities Act and (ii) the method we select would permit the registration of registrable securities, holder of registrable securities have the right to request the inclusion of their registrable securities in such registration. The resale of these shares in the public market upon exercise of the registration rights described above may also adversely affect the market price of our common stock or impact our ability to raise additional equity capital. Parties to the Registration Rights Agreement have right to request registration of (i) shares representing 8% of our outstanding common stock at December 31, 2010, and (ii) an additional 20,800,000 shares purchasable on exercise of outstanding warrants.
 
ITEM 3.     LEGAL PROCEEDINGS
 
Legal Proceedings
 
Resolute is not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to its business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, Resolute’s management believes that the resolution of any of its pending proceedings will not have a material adverse effect on its financial condition or results of operations.
 
ITEM 4.     RESERVED


44


Table of Contents

PART II
 
ITEM 5.     MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
Price Range of Common Stock and Number of Holders
 
Resolute’s common stock is listed on the New York Stock Exchange under the symbol “REN”. The following table sets forth the high and the low sale prices per share of Resolute’s common stock for the twelve months ended December 31, 2010 and 2009. The closing price of the common stock on March 11, 2011 was $17.45.
 
                                 
    2010     2009  
Period   High     Low     High     Low  
 
1st Quarter
  $ 12.66     $ 10.46     $     $  
2nd Quarter
  $ 13.87     $ 11.59     $     $  
3rd Quarter
  $ 12.82     $ 10.48     $ 10.60     $ 9.72  
4th Quarter
  $  14.83     $  10.91     $  11.79     $  10.12  
 
As of March 10, 2011, there were approximately 92 record holders of Resolute’s common stock.
 
Resolute’s warrants are listed on the New York Stock Exchange under the symbol “RENWS”. The following table sets forth the high and the low sale prices per share of Resolute’s warrants for the twelve months ended December 31, 2010 and 2009. The closing price of the warrants on March 11, 2011 was $4.58.
 
                                 
    2010     2009  
Period   High     Low     High     Low  
 
1st Quarter
  $ 2.61     $ 1.77     $     $  
2nd Quarter
  $ 3.20     $ 1.96     $     $  
3rd Quarter
  $ 2.59     $ 1.38     $ 1.65     $ 1.00  
4th Quarter
  $  3.33     $  1.70     $  2.38     $  1.40  
 
Issuer Purchases of Equity Securities
 
In connection with the vesting of Resolute Energy Corporation restricted common stock under the 2009 Long Term Performance Incentive Plan (“LTIP”) on December 31, 2010, the Company retained 142,468 shares of common stock at the election of the recipients of such awards in satisfaction of withholding tax obligations. Such shares were valued at $14.76 per share, the closing price of the Company’s common stock on the NYSE on December 31, 2010. These shares were retired by the Company.
 
Dividend Policy
 
Resolute has not declared any cash dividends on its common stock since inception and has no plans to do so in the foreseeable future. The ability of Resolute’s Board of Directors to declare any dividend is subject to limits imposed by the terms of its credit agreement, which currently prohibit Resolute from paying dividends on its common stock. Resolute’s ability to pay dividends is also subject to limits imposed by Delaware law. In determining whether to declare dividends, the Board of Directors will consider the limits imposed by the credit agreement, financial condition, results of operations, working capital requirements, future prospects and other factors it considers relevant.


45


Table of Contents

Comparison of Cumulative Return
 
The following graph compares the cumulative return on a $100 investment in Resolute common stock from September 28, 2009, the date the common stock began trading on the New York Stock Exchange, through December 31, 2010, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the S&P 500 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. The indices are included for comparative purpose only. This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing.
 
COMPARISON OF CUMULATIVE TOTAL RETURN
AMONG RESOLUTE ENERGY CORPORATION, THE RUSSELL 2000 INDEX,
AND THE S&P 500 ENERGY INDEX
 
(PERFORMANCE GRAPH)


46


Table of Contents

ITEM 6.     SELECTED FINANCIAL DATA
 
The following table presents Resolute’s selected historical financial data for the years ended December 31, 2010, 2009, 2008 and 2007. The consolidated balance sheet and income statement information are derived from Resolute’s audited financial statements. HACI was the accounting acquirer and, accordingly, the historical financial data below reflects HACI through the date of the Resolute Transaction. Results of oil and gas operations are reflected from the date of the Resolute Transaction in September 2009. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines and other factors. This information should be read in conjunction with the consolidated financial statements and notes thereto and “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations” presented elsewhere in this report. The discussion in Item 7 regarding the Resolute Transaction affects the comparability of the information provided in this Selected Financial Data.
 
                                 
    Year Ended December 31,  
    2010     2009     2008     2007  
    (in thousands, except per share data)  
 
Statement of Operation Data:
                               
Revenue
  $ 173,395     $ 42,416     $     $  
Operating expenses
    (142,225 )     (57,361 )     (1,560 )     (1,036 )
Income (loss) from operations
    31,170       (14,945 )     (1,560 )     (1,036 )
Other income (expense)
    (22,597 )     (50,185 )     7,601       5,154  
Income (loss) before income taxes
    8,573       (65,130 )     6,041       4,118  
Income tax benefit (expense)
    (2,388 )     19,887       (2,054 )     (1,401 )
Net income (loss)
    6,185       (45,243 )     3,987       2,717  
                                 
Earnings (loss) per share:
                               
Common stock, subject to redemption
  $     $ (0.16 )   $ 0.09     $ 0.06  
Common stock, basic and diluted
  $ 0.12     $ (0.93 )   $ 0.06     $ $0.09  
Weighted average shares outstanding:
                               
Common stock, subject to redemption
          12,114       16,560       16,560  
Common stock, basic
    49,900       46,394       45,105       18,587  
Common stock, diluted
    50,475       46,394       45,105       18,587  
                                 
Selected Cash Flow Data:
                               
Net cash provided by (used in) operating activities
  $ 58,495     $ (12,164 )   $ 3,031     $ 5,164  
Net cash provided by (used in) investing activities
    (69,123 )     209,987       (2,264 )     (541,302 )
Net cash provided by (used in) financing activities
    12,017       (198,197 )           536,190  
 
                                 
    As of December 31,  
    2010     2009     2008     2007  
    (In thousands)  
 
Balance Sheet Data:
                               
Total assets
  $ 760,523     $ 693,440     $ 544,797     $ 541,842  
Long term debt
    127,900       109,575              
Total liabilities
    356,657       299,903       19,291       20,322  
Stockholders’ equity
    403,866       393,537       362,199       359,702  


47


Table of Contents

ITEM 7.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
The following discussion and analysis should be read in conjunction with the consolidated financial statements and the notes thereto contained elsewhere in this report. Due to the nature of the Resolute Transaction, two sets of financial statements are presented in this report. The first set covers the reporting company, Resolute. The second set covers the predecessor company, Predecessor Resolute, through September 24, 2009.
 
The following discussion relating to the business of Resolute is presented in one combined section with the results for the twelve months ended December 31, 2010 compared to the combined results of Resolute for the 98 days ended December 31, 2009 and Predecessor Resolute for the 267 day period ended September 24, 2009 and the twelve months ended December 31, 2008.
 
Overview
 
Resolute is an independent oil and gas company engaged in the acquisition, exploration, development and production of oil, gas and hydrocarbon liquids. Resolute’s strategy is to grow through exploration, exploitation and industry standard enhanced oil recovery projects.
 
As of December 31, 2010, Resolute’s estimated net proved reserves were approximately 64.7 MMBoe, of which approximately 53% were proved developed reserves and approximately 78% were oil. The standardized measure of Resolute’s estimated net proved reserves as of December 31, 2010, was $587 million. See Note 15 to the Consolidated Financial Statements.
 
Resolute focuses its efforts on increasing reserves and production while controlling costs at a level that is appropriate for long-term operations. Resolute’s future earnings and cash flow from existing operations are dependent on a variety of factors including commodity prices, exploitation and recovery activities and its ability to manage its overall cost structure at a level that allows for profitable production.
 
How Resolute Evaluates Its Operations
 
Resolute’s management uses a variety of financial and operational measurements to analyze its operating performance, including but not limited to, production levels, trends and prices, reserve and production volumes and trends, operating and general and administrative expenses, operating cash flow, and Adjusted EBITDA (defined below).
 
Production Levels, Trends and Prices. Oil and gas revenue is the product of Resolute’s production multiplied by the price that it receives for that production. Because the price that Resolute receives is highly dependent on many factors outside of its control, except to the extent that it has entered into derivative arrangements that can influence its net price either positively or negatively, production is the primary revenue driver over which it has some influence. Although Resolute cannot greatly alter reservoir performance, it can aggressively implement exploitation activities that can increase production or diminish production declines relative to what would have been the case without intervention. Examples of activities that can positively influence production include minimizing production downtime due to equipment malfunction, well workovers and cleanouts, recompletions of existing wells in new parts of the reservoir, and expanded secondary and tertiary recovery programs. Total production for 2011 is expected to be between 2.95 and 3.05 MMBoe, or an average of 8,000 to 8,400 Boe per day.
 
The price of crude oil has been extremely volatile, and Resolute expects that this volatility will continue. Given the inherent volatility of crude oil prices, Resolute plans its activities and budget based on sales price assumptions that it believes to be reasonable. Resolute uses derivative arrangements to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices. These instruments limit its exposure to declines in prices, but also limit its expected benefits if prices increase. Changes in the price of oil or gas will result in the recognition of a non-cash gain or loss recorded in other income or expense due to changes in the fair value of the derivative arrangements. Recognized gains or losses only arise from payments made or received on monthly settlements of contracts or if a contract is terminated prior to its expiration. Resolute typically enters into derivative arrangements that cover a significant portion of its estimated future oil and gas production.


48


Table of Contents

Resolute currently has such derivative arrangements in place through 2014. As of December 31, 2010, Resolute has oil swaps in place for 2011 covering the aggregate average daily oil volumes of 3,250 barrels of oil at a NYMEX weighted average price of $68.26 per Bbl, oil collars covering daily oil volumes of 250 barrels of oil with a floor of $80.00 per Bbl and a ceiling of $90.00 per Bbl, gas swaps covering daily gas volumes of 2,750 MMBtu at a NYMEX price of $9.32 per MMBtu and gas basis derivatives covering the aggregate average daily volumes of 3,300 MMBtu at a NYMEX weighted average price of $1.40 per MMBtu. These derivatives provide price protection (and potentially limit price received) on an estimated 58% at the midpoint of previously announced guidance relating to 2011 oil production and 56% at the midpoint of previously announced guidance relating to 2011 gas production.
 
Reserve and Production Volumes and Trends. From inception, Predecessor Resolute grew its reserve base through a focused acquisition strategy, completing three significant acquisitions. These included the acquisition of the majority of its Aneth Field Properties through two significant purchases: the acquisition of the Chevron Properties was completed in November 2004 followed by the acquisition of the ExxonMobil Properties in April 2006. Predecessor Resolute acquired all of its Wyoming Properties through the purchase of Primary Natural Resources, Inc. now known as RWI in July 2008. Resolute will continue to seek opportunities to acquire similar producing properties that have upside potential through low-risk development drilling and exploitation projects. Resolute believes that its knowledge of various domestic, on-shore operating areas, strong management and staff and solid industry relationships will allow it to locate, capitalize on and integrate strategic acquisition opportunities.
 
At December 31, 2010, Resolute had estimated net proved reserves of approximately 39.7 MMBoe that were classified as proved developed non-producing and proved undeveloped. An estimated 37.4 MMBoe, or 94%, of those reserves are attributable to recoveries associated with expansions, extensions and processing of the tertiary recovery CO2 floods that are currently in operation on Resolute’s Aneth Field Properties. Resolute expects to incur approximately $446.7 million of capital expenditures over the next 29 years (including purchases of CO2 under existing contracts), in connection with bringing those incremental reserves attributable to Resolute’s CO2 flood projects into production. Resolute believes that these expenditures will result in significant increases in its oil and gas production.
 
Operating Expenses. Operating expenses are costs associated with the operation of oil and gas properties and are classified as lease operating expenses and production and ad valorem taxes. Direct labor, repair and maintenance, workovers, utilities and contract services comprise the most significant portion of lease operating expenses. Resolute monitors its operating expenses in relation to the amount of production and the number of wells operated. Some of these expenses are relatively independent of the volume of hydrocarbons produced, but may fluctuate depending on the activities performed during a specific period. Other expenses, such as taxes and utility costs, are more directly related to production volumes or reserves. Severance taxes, for example, are charged based on production revenue and therefore are based on the product of the volumes that are sold and the related price received. Ad valorem taxes are based on the value of reserves. Because Resolute operates on the Navajo Reservation, it also pays a possessory interest tax, which is effectively an ad valorem tax assessed by the Navajo Nation. Resolute’s largest utility expense is for electricity that is used primarily to power the pumps in producing wells and the compressors behind the injection wells. The more fluid that is moved, the greater the amount of electricity that is consumed. In the recent past, higher oil prices led to higher demand for drilling rigs, workover rigs, operating personnel and field supplies and services, which in turn caused increases in the costs of those goods and services. Resolute projects 2011 cash lease operating expenses of $54 million to $58 million. Production taxes for 2011 are expected to be 14.25% to 14.75% of 2011 production revenue.
 
General and Administrative Expenses. Resolute monitors its general and administrative expenses carefully, attempting to balance the cash effect of incurring general and administrative costs against the benefits of, among other things, hiring and retaining highly qualified staff who can add value to the Company’s asset base. General and administrative expenses include, among other things, salaries and benefits, share-based compensation, general corporate overhead, fees paid to independent auditors, lawyers, petroleum engineers and other professional advisors, costs associated with shareholder reports, investor relations activities, registrar and transfer agent fees, director and officer liability insurance costs and director compensation. Resolute expects G&A expense will be $13 million to $15 million, excluding non-cash share-based compensation expense.


49


Table of Contents

Operating Cash Flow. Operating cash flow is the cash directly derived from Resolute’s oil and gas properties, before considering such things as administrative expenses and interest costs. Operating cash flow on a per unit of production basis is a measure of field efficiency, and can be compared to results obtained by operators of oil and gas properties with characteristics similar to Resolute’s in order to evaluate relative performance. Aggregate operating cash flow is a measure of Resolute’s ability to sustain overhead expenses and costs related to capital structure, including interest expenses.
 
Adjusted EBITDA. Adjusted EBITDA (a non-GAAP measure) is defined by the Company as consolidated net income adjusted to exclude interest expense, interest income, income taxes, depletion, depreciation and amortization, impairment expense, accretion of asset retirement obligation, change in fair value of derivative instruments, expiration of puts, non-cash equity-based compensation expense and noncontrolling interest amounts. This definition is consistent with the definition of Adjusted EBITDA in Resolute’s existing credit agreement. Adjusted EBITDA is also a financial measure that Resolute expects will be reported to its lenders and used as a gauge for compliance with some of the financial covenants under its revolving credit facility.
 
Adjusted EBITDA is used as a supplemental liquidity or performance measure by Resolute’s management and by external users of its financial statements such as investors, commercial banks, research analysts and others, to assess:
 
  •  the ability of Resolute’s assets to generate cash sufficient to pay interest costs;
 
  •  the financial metrics that support Resolute’s indebtedness;
 
  •  Resolute’s ability to finance capital expenditures;
 
  •  financial performance of the assets without regard to financing methods, capital structure or historical cost basis;
 
  •  Resolute’s operating performance and return on capital as compared to those of other companies in the exploration and production industry, without regard to financing methods or capital structure; and
 
  •  the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
 
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. Because Resolute has borrowed money to finance its operations, interest expense is a necessary element of its costs and its ability to generate gross margins. Because Resolute uses capital assets, depletion, depreciation and amortization are also necessary elements of its costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, Resolute believes that it is important to consider both net income and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate its financial performance and liquidity. Adjusted EBITDA excludes some, but not all, items that affect net income, operating income and net cash provided by operating activities and these measures may vary among companies. Resolute’s Adjusted EBITDA may not be comparable to Adjusted EBITDA or Adjusted EBITDA of any other company because other entities may not calculate these measures in the same manner.
 
Factors That Significantly Affect Resolute’s Financial Results
 
Revenue, cash flow from operations and future growth depend substantially on factors beyond Resolute’s control, such as economic, political and regulatory developments and competition from other sources of energy. Crude oil prices have historically been volatile and may be expected to fluctuate widely in the future. Sustained periods of low prices for crude oil could materially and adversely affect Resolute’s financial position, its results of operations, the quantities of oil and gas that it can economically produce, and its ability to obtain capital.
 
Like all businesses engaged in the exploration for and production of oil and gas, Resolute faces the challenge of natural production declines. As initial reservoir pressures are depleted, oil and gas production from a given well decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or gas it produces. Resolute attempts to overcome this natural decline by implementing secondary and


50


Table of Contents

tertiary recovery techniques and by acquiring more reserves than it produces. Resolute’s future growth will depend on its ability to enhance production levels from existing reserves and to continue to add reserves in excess of production through exploration, development and acquisition. Resolute will maintain its focus on costs necessary to produce its reserves as well as the costs necessary to add reserves through production enhancement, drilling and acquisitions. Resolute’s ability to make capital expenditures to increase production from existing reserves and to acquire more reserves is dependent on availability of capital resources, and can be limited by many factors, including the ability to obtain capital in a cost-effective manner and to timely obtain permits and regulatory approvals.
 
Results of Operations
 
Through September 24, 2009, HACI’s efforts had been primarily limited to organizational activities, activities relating to its initial public offering, activities relating to identifying and evaluating prospective acquisition candidates, and activities relating to general corporate matters. HACI had not generated any revenue, other than interest income earned on the proceeds of its initial public offering.
 
For the purposes of management’s discussion and analysis of the results of operations of Resolute, management has analyzed the operational results for the twelve months ended December 31, 2010, in comparison to the combined results of Resolute for the unaudited 98 day period ended December 31, 2009 and Predecessor Resolute for the audited 267 day period ended September 24, 2009 and the audited twelve months ended December 31, 2008, except where indicated.
 
The following table reflects the components of the Company’s sales volumes, revenues, operating expenses, and sets forth its sales prices, costs and expenses on an equivalent barrel of oil (“Boe”) basis for the periods indicated for Resolute and Predecessor Resolute.
 
                                             
                                Predecessor
 
                  Predecessor
    Combined
      Resolute
 
    Resolute
      Resolute
    Resolute
    Twelve
      Twelve
 
    Twelve Months
      98 Day Period
    267 Day
    Months
      Months
 
    Ended
      Ended
    Period Ended
    Ended
      Ended
 
    December 31,
      December 31,
    September 24,
    December 31,
      December 31,
 
    2010       2009     2009     2009       2008  
            (In thousands except where indicated)          
Net Sales:
                                           
Total sales (MBoe)
    2,730         703       2,011       2,714         2,823  
Average daily sales (Boe/d)
    7,478         7,172       7,530       7,434         7,712  
Revenue:
                                           
Revenue from oil and gas activities
  $ 173,395       $ 42,416     $ 85,345     $ 127,761       $ 229,172  
Operating Expenses:
                                           
Lease operating
  $ 51,618       $ 16,185     $ 33,750     $ 49,935       $ 56,570  
Production and ad valorem taxes
    24,151         5,807       13,021       18,828         29,420  
General and administrative
    19,440         23,828       8,077       31,905         20,211  
General and administrative — (excluding non-cash compensation expense)
    13,499         22,909       5,259       28,168         12,333  
Depletion, depreciation, amortization and accretion
    47,016         11,541       21,925       33,466         50,335  
Other Income (Expense):
                                           
Interest expense
  $ (4,854 )     $ (1,538 )   $ (18,416 )   $ (19,954 )     $ (33,139 )
Realized and unrealized gain (loss) on derivative instruments
    (17,842 )       (49,514 )     (23,519 )     (73,033 )       96,032  
Income tax benefit (expense)
    (2,388 )       19,887       5,019       24,906         18,247  
Average Sales Prices ($/Boe):
                                           
Average sales price (excluding derivative settlements)
  $ 63.52       $ 60.35     $ 42.45     $ 47.08       $ 81.19  
Operating Expenses ($/Boe):
                                           
Lease operating
  $ 18.91       $ 23.03     $ 16.79     $ 18.40       $ 20.04  
Production and ad valorem taxes
    8.85         8.26       6.48       6.94         10.42  
      7.12         33.90       4.02       11.76         7.16  
General and administrative — (excluding non-cash compensation expense)
    4.95         32.59       2.62       10.38         4.37  
Depletion, depreciation, amortization and accretion
    17.22         16.42       10.90       12.33         17.83  


51


Table of Contents

Year Ended December 31, 2010, Compared to the Year Ended December 31, 2009
 
Revenue. Revenue from oil and gas activities increased to $173.4 million during 2010, from $127.8 million during 2009. Total production increased 0.6% during 2010 as compared to 2009, from 2,714 MBoe to 2,730 MBoe. The increase in production was largely attributed to an increased response from the Company’s CO2 flood and recompletion projects in its Aneth Field Properties. In addition to natural production declines, the overall increase in production was offset by limited compression capability at the Western Gas Resources Hilight Plant for the majority of 2010. Full compression capability was restored in September 2010, and management estimates that these constraints resulted in a reduction in production volumes of approximately 29.5 MBoe during the year, as compared to what the field was capable of producing if unconstrained. In addition, the Company voluntarily shutdown a portion of its coalbed methane production in Wyoming during 2009 due to uneconomic product prices for natural gas in that area. This led to a reduction of production volumes in 2010 of approximately 28.9 MBoe. Further, in 2009 the Company deferred its anticipated capital projects due to low product prices and limited financial liquidity. Had these anticipated capital projects been completed, the resulting additional production in 2010 may have partially offset the natural production declines.
 
In addition to increased production versus 2009, the Company experienced an increase in average sales price, excluding derivatives settlements, from $47.08 per Boe in 2009 to $63.52 per Boe in 2010, as a result of increased commodity pricing.
 
Operating Expenses. Lease operating expenses increased to $51.6 million during 2010, from $49.9 million during 2009. The $1.7 million, or 3.4%, increase was primarily attributable to a $1.0 million increase in equipment maintenance and supplies, $0.9 million increase in utilities and fuel and a $0.4 million increase in labor costs. The overall increase was offset by decreases in workover and compression and gathering expenses.
 
Production and ad valorem taxes increased to $24.2 million during 2010 from $18.8 million during 2009. The $5.4 million, or 28.7% increase was mainly due to the 35.7% increase in revenue. The increase in production and ad valorem taxes was offset by a decrease in the ad valorem tax rate from 14.7% of total revenue in 2009 to 13.9% of total revenue in 2010.
 
Depletion, depreciation, amortization and accretion expenses increased to $47.0 million during 2010, as compared to $33.5 million during 2009. The $13.5 million, or 40.3%, increase is mainly due to an increase in the per Boe depletion, depreciation and amortization rate from $12.33 per Boe in 2009 to $17.22 per Boe in 2010, due to increased capital spending versus 2009 and the increased depletable base that resulted from the acquisition accounting on the date of the Resolute Transaction.
 
Pursuant to full cost accounting rules, Resolute performs a ceiling test each quarter on its proved oil and gas assets. As a result of this limitation on capitalized costs, Predecessor Resolute included a provision for an impairment of oil and gas property costs of $13.3 million during the 267 day period ended September 24, 2009. No provision for impairment was recorded in 2010.
 
General and administrative expenses decreased to $19.4 million during 2010, as compared to $31.9 million during 2009. The $12.5 million, or 39.2%, decrease in the absolute level of general and administrative expenses principally resulted from a decrease of $19.1 million in acquisition and transaction costs incurred in 2009 in connection with the Resolute Transaction, the like of which were not incurred during 2010. Outside of these costs, the Company incurred a $0.8 million increase in corporate overhead, a $0.8 million increase in professional services and consulting fees, a $4.2 million increase in personnel costs due to additional employees versus 2009 and accrual of the Company’s Short Term Incentive Plan and an increase of $2.2 million in stock based compensation awarded under the Company’s 2009 Performance Incentive Plan.
 
Other Income (Expense). All oil and gas derivative instruments are accounted for under mark-to-market accounting rules, which provide for the fair value of the contracts to be reflected as either an asset or a liability on the balance sheet. The change in the fair value during an accounting period is reflected in the income statement for that period. During 2010, the realized and unrealized losses on of oil and gas derivatives totaled $17.8 million. This amount included approximately $8.2 million of realized losses on oil and gas derivatives and $9.6 million of decreases in the unrealized fair value of oil and gas derivatives. During 2009, the realized and unrealized losses


52


Table of Contents

on oil and gas derivatives totaled $73.0 million and included approximately $71.8 million of unrealized losses in the fair value of oil and gas derivatives and $1.2 million of realized losses from monthly settlements.
 
Interest expense was $4.9 million during 2010, as compared to $20.0 million during 2009. The $15.1 million, or 75.5%, decrease is attributable to lower interest rates and a lower average debt balance during 2010 as the Company utilized funds received in the Resolute Transaction in 2009 to pay off a significant amount of debt on the Acquisition Date.
 
Income Tax Benefit (Expense). Income tax expense recognized during 2010 was $2.4 million, or 27.9% of income before income taxes, as compared to an income tax benefit of $24.9 million, or 22.3% of loss before income taxes, for Resolute in 2009. The change in the effective rate reflects the differing tax jurisdictions in which Resolute operates following the Resolute Transaction, permanent differences relating to transaction costs in 2009 and the differing entities subject to federal and state income tax prior to the Resolute Transaction. Income tax expense differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% due to state income taxes, estimated permanent differences and revisions to prior year estimates as a result of final income tax return filings. Resolute carried a $12.0 million current deferred tax asset at December 31, 2010, for which no valuation allowance was recorded as it is more likely than not that the asset will be realized due to projected future taxable income. The Company expects income tax benefit (expense) to more closely reflect the U.S. federal income tax rate of 35% in future years.
 
Year Ended December 31, 2009, Compared to the year Ended December 31, 2008
 
Revenue. Revenue from oil and gas activities decreased to $127.8 million during 2009, from $229.2 million during 2008. Total production decreased 3.9% during 2009 as compared to 2008, and decreased only 3.6% during 2009 on a daily basis as compared to 2008. The overall production decrease was primarily due to the previously discussed shutdown of CBM wells in 2009 that were producing in 2008. This decrease was mitigated on a daily basis by an increased CO2 production response in Aneth versus 2008. The average sales price per Boe, excluding derivative settlements, decreased by $34.11 per Boe or 42.0% in 2009 as compared to 2008 due to lower commodity pricing in 2009.
 
Operating Expenses. Lease operating expenses decreased to $49.9 million during 2009, from $56.6 million during 2008. The $6.7 million, or 11.8%, decrease was mainly attributable to a $2.4 million decrease in workover expenses, $2.4 million decrease in labor costs and a $1.2 million decrease in compression and gathering.
 
Production and ad valorem taxes decreased to $18.8 million during 2009 from $29.4 million during 2008. The $10.6 million, or 36.1% decrease was mainly due to the 44.2% decrease in revenue. The decrease was offset by an increase in the production and ad valorem tax rate to 14.7% in 2009, compared to 12.8% in 2008.
 
Depletion, depreciation, amortization and accretion expenses decreased to $33.5 million during 2009, as compared to $50.3 million during 2008. The $16.8 million, or 33.4%, decrease is primarily due to a decrease in the per Boe depletion, depreciation and amortization rate from $17.83 per Boe in 2008 to $12.33 per Boe in 2009, due to the reduction in the carrying value of proved oil and gas properties in 2009 following the impairment of proved properties at December 31, 2008 and March 31, 2009.
 
Resolute recorded a ceiling test impairment of oil and gas property costs during 2009 and 2008 of $13.3 million and $245.0 million, respectively.
 
General and administrative expenses increased to $31.9 million during 2009, as compared to $20.2 million during 2008. The $11.7 million, or 57.9%, increase in the absolute level of general and administrative expenses principally resulted from an increase of $14.0 million of acquisition and transaction costs associated with the Resolute Transaction (including $3.5 million in deferred acquisition costs) to $19.1 million versus $5.1 million of similar costs in 2008 and increases in salaries and wages of $2.9 million. These costs were offset by decreases of $4.3 million in non-cash charges to compensation expense and $1.1 million in professional services.
 
Other Income (Expense). During 2009, the fair value of oil and gas derivatives decreased by $73.0 million. This amount included approximately $1.2 million of realized losses on oil and gas derivatives, including a realized loss of $12.5 million that was incurred in 2009 to cash settle a 2010 derivative position as required under the terms of the Resolute Transaction, and $71.8 million of decreases in the unrealized fair value of oil and gas


53


Table of Contents

derivatives. During 2008, the fair value of oil and gas derivatives increased by $96.0 million. This amount included approximately $120.6 million of unrealized gains in the fair value of oil and gas derivatives and $24.6 million of realized losses from monthly settlements.
 
Interest expense was $20.0 million during 2009, as compared to $33.1 million during 2008. The $13.1 million, or 39.6%, decrease is attributable to lower interest rates and a lower average debt balance during 2009.
 
Income Tax Benefit (Expense). Income tax benefit recognized during 2009 was $24.9 million, or 22.3% of the loss before income taxes, as compared to an income tax benefit of $18.2 million, or 16.8% of loss before income taxes in 2008. The change in the effective rate reflects the differing tax jurisdictions in which Resolute operates following the Resolute Transaction which occurred in 2009. Income tax expense differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% due to state income taxes, estimated permanent differences and inclusion of nontaxable entities prior to the Resolute Transaction.
 
Liquidity and Capital Resources
 
Resolute’s primary sources of liquidity have been cash generated from operations and amounts available under its revolving Credit Facility (as defined below). During 2011, another significant source of liquidity is expected to be proceeds from the exercise of warrants for shares of Resolute common stock. Subsequent to December 31, 2010, and through March 11, 2011, the Company has received $41.6 million upon the exercise of 3,196,000 warrants.
 
Net cash provided by operating activities during 2010 was $58.5 million, which represents a $70.7 million increase from the $12.2 million used in operating activities during 2009. The increase was primarily due to a full year of oil and gas operations during 2010. Resolute plans to reinvest a sufficient amount of its cash flow in its development operations in order to maintain its production over the long term, and plans to use external financing sources as well as cash flow from operations and cash reserves to increase its production.
 
Net cash used in investing activities was $69.1 million in 2010 versus cash provided by investing activities of $210.0 million during 2009. The cash provided in 2009 was the result of activities related to the Resolute Transaction. The primary investing activities during 2010 were capital expenditures of $65.3 million. The 2010 capital expenditures were comprised of $30.8 million in leasehold and exploratory costs as a result of the acquisition and drilling of undeveloped leasehold acreage in Williams County, North Dakota, $12.9 million in CO2 acquisition and $21.6 million in facility reconfiguration and other capital expenditures.
 
Net cash provided by financing activities was $12.0 million in 2010 and consisted primarily of $18.3 million in net bank borrowings less $4.0 million in deferred financing costs related to the amended credit agreement entered into by the Company on March 30, 2010. Net cash used in financing activities during 2009 related primarily to redemption and purchase of common stock and warrants as a result of the Resolute Transaction.
 
If cash flow from operating activities does not meet expectations, Resolute may reduce its expected level of capital expenditures and/or fund a portion of its capital expenditures using borrowings under its Credit Facility, issuances of debt and equity securities or from other sources, such as asset sales. There can be no assurance that needed capital will be available on acceptable terms or at all. Resolute’s ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in its Credit Facility. If Resolute is unable to obtain funds when needed or on acceptable terms, it may not be able to complete acquisitions that may be favorable to it or finance the capital expenditures necessary to maintain production or proved reserves.
 
Resolute plans to continue its practice of hedging a significant portion of its production through the use of various derivative transactions. Resolute’s existing derivative transactions do not qualify as cash flow hedges, and the Company anticipates that future transactions will receive similar accounting treatment. Derivative arrangements are generally settled within five days of the end of the month. As is typical in the oil and gas industry, however, Resolute does not generally receive the proceeds from the sale of its crude oil production until the 20th day of the month following the month of production. As a result, when commodity prices increase above the fixed price in the derivative contacts, Resolute will be required to pay the derivative counterparty the difference between the fixed price in the derivative contract and the market price before receiving the proceeds


54


Table of Contents

from the sale of the hedged production. If this occurs, Resolute may use working capital or borrowings under the Credit Facility to fund its operations.
 
Revolving Credit Facility
 
Resolute’s credit facility is with a syndicate of banks led by Wells Fargo Bank, National Association (the “Credit Facility”) with Resolute as the borrower. The Credit Facility specifies a maximum borrowing base as determined by the lenders. The determination of the borrowing base takes into consideration the estimated value of Resolute’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. On March 30, 2010, the Company entered into an amended and restated credit facility agreement. Under the terms of the restated agreement, the borrowing base was increased from $240.0 million to $260.0 million and the maturity date was extended to March 2014. At Resolute’s option, the outstanding balance under the Credit Facility accrues interest at either (a) the London Interbank Offered Rate, plus a margin which varies from 2.25% to 3.0% or (b) the Alternative Base Rate defined as the greater of (i) the Administrative Agent’s Prime Rate, (ii) the Federal Funds Effective Rate plus 0.5%, or (iii) an adjusted London Interbank Offered Rate plus 1%, plus a margin which ranges from 1.25% to 2.0%. Each such margin is based on the level of utilization under the borrowing base. As of December 31, 2010, the weighted average interest rate on the outstanding balance under the Credit Facility was 3.15%.
 
The borrowing base is redetermined semi-annually, and the amount available for borrowing could be increased or decreased as a result of such redeterminations. Under certain circumstances, either Resolute or the lenders may request an interim redetermination. As of December 31, 2010, outstanding borrowings were $127.9 million and unused availability under the borrowing base was $128.8 million. The borrowing base availability has been reduced by $3.3 million in conjunction with letters of credit issued to vendors at December 31, 2010. To the extent that the borrowing base, as adjusted from time to time, exceeds the outstanding balance, no repayments of principal are required prior to maturity. The Credit Facility is collateralized by substantially all of the proved oil and gas assets of Aneth and RWI, and is guaranteed by Resolute’s subsidiaries.
 
The Credit Facility includes terms and covenants that place limitations on certain types of activities, the payment of dividends, and require satisfaction of certain financial tests. Resolute was in compliance with all terms and covenants of the Credit Facility at December 31, 2010.
 
As of March 11, 2011, Resolute had borrowings of $96.6 million under the Credit Facility, resulting in an unused availability of $160.1 million under the borrowing base.
 
Off Balance Sheet Arrangements
 
Resolute does not have any off-balance sheet financing arrangements other than operating leases. Resolute has not guaranteed any debt or commitments of other entities or entered into any options on non-financial assets.
 
Contractual Obligations
 
Resolute has the following contractual obligations and commitments as of December 31, 2010:
 
                                                         
    Payments Due By Year
 
    (in thousands)
 
                                  After
       
    2011     2012     2013     2014     2015     2015     Total (6)  
 
Long-term debt (1)
  $     $     $     $ 127,900     $     $     $ 127,900  
Office and equipment leases
    553       501       537       27       36       9       1,663  
Operating equipment leases(2)
    2,747       2,747       2,747       2,747       2,332       3,455       16,775  
Vehicle leases
    543       507       307       127                   1,484  
ExxonMobil escrow agreement (3)
    1,800       1,800       1,800       1,800       1,800       16,100       25,100  
Construction purchase obligations (4)
    11,638                                     11,638  
CO2 purchases (5)
    23,032       23,893       23,033       19,062       14,694       35,586       139,300  
                                                         
Total
  $ 40,313     $ $29,448     $ 28,424     $ 151,663     $ 18,862     $ 55,150     $ 323,860  
                                                         


55


Table of Contents

 
     
                             
1) Long-term debt represents the outstanding principal amount under Resolute’s Credit Facility. This table does not include future commitment fees, interest expense or other fees because the Credit Facility is a floating rate instrument, and the Company cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.
 
2) Operating equipment leases consist of compressors and other oil and gas field equipment used in the CO2 project.
 
3) Under the terms of Resolute’s purchase agreement with ExxonMobil, Resolute is obligated to make annual deposits into an escrow account that will be used to fund plugging and abandonment liabilities associated with the ExxonMobil Properties.
 
4) Represents purchase commitments in effect at December 31, 2010 related to construction projects in the Aneth Field Properties.
 
5) Represents the minimum take-or-pay quantities associated with Resolute’s existing CO2 purchase contracts. For purposes of calculating the future purchase obligation under these contracts, Resolute has assumed the purchase price over the term of the contract was the price in effect as of December 31, 2010.
 
6) Total contractually obligated payment commitments do not include the anticipated settlement of derivative contracts, obligations to taxing authorities or amounts relating to our asset retirement obligations, which include plugging and abandonment obligations, due to the uncertainty surrounding the ultimate settlement amounts and timing of these obligations.
 
Critical Accounting Policies
 
The discussion and analysis of Resolute’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires Resolute to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. The application of accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Resolute evaluates estimates and assumptions on a regular basis. Resolute bases estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ, perhaps materially, from these estimates and assumptions used in preparation of Resolute’s financial statements. Provided below is an expanded discussion of Resolute’s most significant accounting policies, estimates and judgments used in the preparation of the financial statements.
 
Oil and Gas Properties. Resolute uses the full cost method of accounting for oil and gas producing activities. All costs incurred in the acquisition, exploration and development of properties, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities, improved recovery systems and a portion of general and administrative and operating expenses are capitalized within the cost center.
 
Resolute conducts tertiary recovery projects on a portion of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Under the full cost method, all development costs are capitalized at the time incurred. Development costs include charges associated with access to and preparation of well locations, drilling and equipping development wells, test wells, and service wells including injection wells; acquiring, constructing, and installing production facilities and providing for improved recovery systems. Improved recovery systems include all related facility development costs and the cost of the acquisition of tertiary injectants, primarily purchased CO2. The development cost related to CO2 purchases are incurred solely for the purpose of gaining access to incremental reserves not otherwise recoverable. The accumulation of injected CO2, in combination with additional purchased and recycled CO2, provide future economic value over the life of the project.


56


Table of Contents

In contrast, other costs related to the daily operation of the improved recovery systems are considered production costs and are expensed as incurred. These costs include, but are not limited to, costs incurred to maintain reservoir pressure, compression, electricity, separation, and re-injection of recovered CO2 and water.
 
Capitalized general and administrative and operating costs include salaries, employee benefits, costs of consulting services and other specifically identifiable capital costs and do not include costs related to production operations, general corporate overhead or similar activities.
 
Investments in unproved properties are not depleted, pending determination of the existence of proved reserves. Unproved properties are periodically evaluated for impairment. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Properties are grouped for purposes of assessing impairment when it is not practicable to assess the amount of impairment of properties on an individual basis. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense as appropriate.
 
Pursuant to full cost accounting rules, Resolute must perform a ceiling test each quarter on its proved oil and gas assets. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, and a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, an impairment charge would be recognized to the extent of the excess capitalized costs.
 
No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil and gas properties and the gain significantly alters the relationship between capitalized costs and proved oil reserves of the cost center.
 
Depletion and amortization of oil and gas properties is computed on the unit-of-production method based on proved reserves. Amortizable costs include estimates of asset retirement obligations and future development costs of proved reserves, including, but not limited to, costs to drill and equip development wells, constructing and installing production and processing facilities, and improved recovery systems including the cost of required future CO2 purchases.
 
Oil and Gas Reserve Quantities. Resolute’s estimate of proved reserves is based on the quantities of oil and gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Reserves and their relation to estimated future net cash flows affect Resolute’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserves estimates. Resolute prepares reserves estimates, and the projected cash flows derived from these reserves estimates, in accordance with SEC and FASB guidelines. The accuracy of Resolute’s reserves estimates is a function of many factors including but not limited to the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. Resolute’s proved reserves estimates are a function of many assumptions, any or all of which could deviate significantly from actual results. As such, reserves estimates may vary materially from the ultimate quantities of oil, gas and natural gas liquids eventually recovered.
 
Derivative Instruments and Hedging Activities. Resolute enters into derivative contracts to manage its exposure to oil and gas price volatility. Derivative contracts may take the form of futures contracts, swaps or options. Realized and unrealized gains and losses related to commodity derivatives are recognized in other income (expense). Realized gains and losses are recognized in the period in which the related contract is settled. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as financing activities in the consolidated statement of cash flows.


57


Table of Contents

FASB Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging, requires recognition of all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of a derivative are recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses on derivative hedging instruments must be recorded in either other comprehensive income or current earnings, depending on the nature and designation of the instrument. Presently, Resolute’s management has determined that the benefit of the financial statement presentation available under the provisions of FASB ASC Topic 815, which may allow for its derivative instruments to be reflected as cash flow hedges, is not commensurate with the administrative burden required to support that treatment. As a result, Resolute marked its derivative instruments to fair value in accordance with the provisions of FASB ASC Topic 815 and recognized the changes in fair market value in earnings. Gains and losses on derivative instruments reflected in the consolidated statement of operations incorporate both realized and unrealized values.
 
FASB ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes market or observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The guidance establishes a hierarchy for determining the fair values of assets and liabilities, based on the significance level of the following inputs:
 
  •  Level 1 — Quoted prices in active markets for identical assets or liabilities.
 
  •  Level 2 — Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.
 
  •  Level 3 — Significant inputs to the valuation model are unobservable.
 
An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Resolute’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Following is a description of the valuation methodologies used by Resolute as well as the general classification of such instruments pursuant to the hierarchy.
 
As of December 31, 2010, Resolute’s commodity derivative instruments were required to be measured at fair value on a recurring basis. Resolute used the income approach in determining the fair value of its derivative instruments, utilizing present value techniques for valuing its swaps and basis swaps and option-pricing models for valuing its collars. Inputs to these valuation techniques include published forward index prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. Substantially all of these inputs are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the valuation hierarchy.
 
Asset Retirement Obligations. Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability.
 
Resolute’s estimated asset retirement obligation liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells.


58


Table of Contents

Share-Based Compensation. Resolute accounts for share-based compensation in accordance with FASB ASC Topic 718, which requires it to measure the grant date fair value of equity awards given to employees in exchange for services, and to recognize that cost, less estimated forfeitures, over the period that such services are performed.
 
Income taxes. Deferred tax assets and liabilities are recorded to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The ability to realize the deferred tax assets is routinely assessed. If the conclusion is that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the tax asset would be reduced by a valuation allowance. The future taxable income is considered when making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices). Income tax positions are also required to meet a more-likely-than-not recognition threshold to be recognized in the financial statements. Tax positions that previously failed to meet the more-likely-than-not threshold are recognized in the first subsequent financial reporting period in which that threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not threshold are derecognized in the first subsequent financial reporting period in which that threshold is no longer met.


59


Table of Contents

ITEM 7A. QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Commodity Price Risk and Derivative Arrangements
 
Resolute’s major market risk exposure is in the pricing applicable to oil and gas production. Realized pricing on Resolute’s unhedged volumes of production is primarily driven by the spot market prices applicable to oil production and the prevailing price for gas. Pricing for oil production has been volatile and unpredictable for several years, and Resolute expects this volatility to continue in the future. The prices Resolute receives for unhedged production depend on many factors outside of Resolute’s control.
 
Resolute periodically hedges a portion of its oil and gas production through swaps, puts, calls, collars and other such agreements. The purpose of the hedges is to provide a measure of stability to Resolute’s cash flows in an environment of volatile oil and gas prices and to manage Resolute’s exposure to commodity price risk.
 
Under the terms of its Credit Agreement the form of derivative instruments to be entered into is at Resolute’s discretion, not to exceed 85% of its anticipated production from proved developed producing properties utilizing economic parameters specified in its Credit Agreement, including escalated prices and costs.
 
By removing the price volatility from a significant portion of Resolute’s oil and gas production, Resolute has mitigated, but not eliminated, the potential effects of changing prices on the cash flow from operations for periods hedged. While mitigating negative effects of falling commodity prices, certain of these derivative contracts also limit the benefits Resolute would receive from increases in commodity prices. It is Resolute’s policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers.
 
As of December 31, 2010, Resolute had entered into certain derivative instruments that are summarized in the tables below.
 
                                         
    Oil Swap
    Oil (NYMEX WTI)
    Oil Collar
    (NYMEXWTI)  
    Volumes
    Weighted Average
    Volumes
    Floor
    Ceiling
 
Year
  Bbl per Day     Hedge Price per Bbl     Bbl per Day     Price     Price  
 
2011
    3,250     $      68.26       250     $   80.00     $   90.00  
2012
    3,250     $ 68.26       250     $ 80.00     $ 93.50  
2013
    2,000     $ 60.47           $     $  
 
                 
    Gas Swap
    Gas (NYMEX HH)
 
    Volumes
    Weighted Average
 
Year
  MMBtu per Day     Hedge Price per MMBtu  
 
2011
    2,750     $ 9.32  
2012
    2,100     $ 7.42  
2013
    1,900     $      7.40  
 
                     
    Basis Hedges  
              Hedged Price
 
              Differential per
 
Year
  Index   MMBtu per Day     MMBtu  
 
2011 – 2013
  Rocky Mountain NWPL     1,800     $ 2.10  
2011
  Rocky Mountain CIG     1,500     $ 0.57  
2012
  Rocky Mountain CIG     1,000     $   0.575  
2013
  Rocky Mountain CIG     500     $ 0.59  
2014
  Rocky Mountain CIG     1,000     $ 0.59  


60


Table of Contents

Subsequent to December 31, 2010 and effective March 1, 2011, Resolute had modified its oil derivative instrument position as summarized in the table below. The Company will incur premium payments associated with the oil collars of $4.8 million, $1.0 million, $1.2 million and $2.7 million in 2011, 2012, 2013 and 2014, respectively.
 
                                         
    Oil Swap
    Oil (NYMEX WTI)
    Oil Collar
    (NYMEXWTI)  
    Volumes
    Weighted Average
    Volumes
    Floor
    Ceiling
 
Year
  Bbl per Day     Hedge Price per Bbl     Bbl per Day     Price     Price  
 
2011
    750     $ 70.58       3,750     $ 66.67     $ 94.67  
2012
    3,250     $ 68.26       875     $ 69.71     $ 98.14  
2013
    2,000     $      60.47       775     $ 80.00     $ 105.00  
2014
                1,500     $   65.00     $   110.00  
 
As of December 31, 2010, the Company’s weighted average derivative instrument position incorporating both the derivative instrument position in place at December 31, 2010 and the modification effective March 1, 2011 is summarized in the table below.
 
                                         
    Oil Swap
    Oil (NYMEX WTI)
    Oil Collar
    (NYMEXWTI)  
    Volumes
    Weighted Average
    Volumes
    Floor
    Ceiling
 
Year
  Bbl per Day     Hedge Price per Bbl     Bbl per Day     Price     Price  
 
2011
    1,154     $ 69.53       3,184     $ 66.84     $ 94.61  
2012
    3,250     $ 68.26       875     $ 69.71     $ 98.14  
2013
    2,000     $      60.47       775     $ 80.00     $ 105.00  
2014
                1,500     $   65.00     $   110.00  
 
Interest Rate Risk
 
At December 31, 2010, Resolute has $127.9 million of outstanding debt under the Credit Facility. Interest is calculated under the terms of the agreement based on a LIBOR spread. A 10% increase in LIBOR would result in an estimated $0.1 million increase in annual interest expense. Resolute does not currently intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to its outstanding indebtedness.
 
Credit Risk and Contingent Features in Derivative Instruments
 
Resolute is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above. All counterparties are also lenders under Resolute’s Credit Facility. For these contracts, Resolute is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Credit Facility. Resolute’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events, and set-off provisions. Resolute has set-off provisions with its lenders that, in the event of counterparty default, allow Resolute to set-off amounts owed under the Credit Facility or other general obligations against amounts owed for derivative contract liabilities.
 
ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
The information required by this item is included in “Item 15. Exhibits, Financial Statements Schedules”.
 
ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
None.
 
ITEM 9A.     CONTROLS AND PROCEDURES
 
Attached as exhibits to this reports are certifications of our CEO and CFO required pursuant to Rule 13a-14 under the Exchange Act. This section includes information concerning the controls and procedures evaluation referred to in the certifications. Included in this report is the report of KPMG LLP, our independent registered public accounting firm,


61


Table of Contents

regarding its audit of our internal control over financial reporting. This section should be read in conjunction with the certifications and the KPMG LLP report for a more complete understanding of the topics presented.
 
Evaluation of Disclosure Controls and Procedures. We conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of December 31, 2010. This evaluation was conducted under the supervision and with the participation of management, including our CEO and CFO. Based on this evaluation, our CEO and CFO have concluded that, subject to the limitations noted in this section, as of December 31, 2010, our disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed by us in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified by the rules and forms of the SEC. We also concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our CEO and CFO, to allow timely decisions regarding disclosure.
 
Management’s Annual Report on Internal Control over Financial Reporting. Management is responsible for establishing and maintaining adequate internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). Management assessed our internal control over financial reporting as of December 31, 2010, and has concluded that the Company maintained effective internal control over financial reporting as of December 31, 2010. This assessment was based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
Changes in Internal Control over Financial Reporting. There have been no significant changes in our internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
ITEM 9B.     OTHER INFORMATION
 
None.
 
PART III
 
ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERANCE
 
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2011 annual stockholders’ meeting and is incorporated by reference in this report.
 
ITEM 11.     EXECUTIVE COMPENSATION
 
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2011 annual stockholders’ meeting and is incorporated by reference in this report.
 
ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
 
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2011 annual stockholders’ meeting and is incorporated by reference in this report.
 
ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
 
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2011 annual stockholders’ meeting and is incorporated by reference in this report.
 
ITEM 14.     PRINCIPAL ACCOUNTING FEE AND SERVICES
 
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2011 annual stockholders’ meeting and is incorporated by reference in this report.


62


Table of Contents

 
PART IV
 
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
 
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
 
See “Item 8 Financial Statements and Supplementary Data”.
 
(a)(3) Exhibits
 
         
  Exhibit
   
  Number   Description of Exhibits
 
  2 .1†   Purchase and IPO Reorganization Agreement, dated as of August 2, 2009, among Hicks Acquisition Company I, Inc., Resolute Energy Corporation, Resolute Subsidiary Corporation., Resolute Holdings, LLC, Resolute Holdings Sub, LLC, Resolute Aneth, LLC and HH-HACI, L.P., (incorporated by reference to Annex A to the Registration Statement on Form S-4 filed with the SEC on August 6, 2009 (File. No 33-161076)(“Initial S-4”).
  2 .2   Letter Agreement amending Purchase and IPO Reorganization Agreement, dated as of September 9, 2009, among Hicks Acquisition Company I, Inc., Resolute Energy Corporation, Resolute Subsidiary Corporation., Resolute Holdings, LLC, Resolute Holdings Sub, LLC, Resolute Aneth, LLC and HH-HACI, L.P., (incorporated by reference to Annex A to the Initial S-4.
  2 .3†   Purchase and Sale Agreement between Exxon Mobil Corporation, ExxonMobil Oil Corporation, Mobil Exploration and Producing North America Inc., Mobil Producing Texas & New Mexico Inc. and Mobil Exploration & Producing U.S. Inc. and Resolute Aneth, LLC — 75% and Navajo Nation Oil and Gas Company — 25% dated January 1, 2005. (incorporated by reference to Exhibit 2.2 to the Initial S-4)
  2 .4†   Asset Sale Agreement Aneth Unit, Rutherford Unit and McElmo Creek Unit, San Juan County, Utah between Chevron U.S.A. Inc. (as seller) and Resolute Natural Resources Company and Navajo Nation Oil and Gas Company, Inc. (as buyer) dated October 22, 2004. (incorporated by reference to Exhibit 2.3 to the Initial S-4)
  2 .5†   Stock Purchase Agreement dated June 24, 2008, between Primary Natural Resources, Inc. (as seller) and Resolute Acquisition Company, LLC (as buyer). (incorporated by reference to Exhibit 2.4 to the Initial S-4)
  3 .1   Amended and Restated Certificate of Incorporation of Resolute Energy Corporation, filed September 25, 2009 (incorporated by reference to Exhibit 3.1 to the Annual Report on Form 10-K of Resolute Energy Corporation filed on March 30, 2010)
  3 .2   Amended and Restated Bylaws of Resolute Energy Corporation (incorporated by reference to Exhibit 3.2 to the Annual Report on Form 10-K of Resolute Energy Corporation filed on March 30, 2010)
  4 .1   Warrant Agreement between Resolute Energy Corporation and Continental Stock Transfer and Trust Company dated September 25, 2009 (incorporated by reference as Annex D to the Initial S-4)
  4 .2   Registration Rights Agreement dated September 25, 2009, among Resolute Energy Corporation and certain holders. (incorporated by reference as Exhibit 4.4 to Amendment No. 2 to the Initial S-4 filed on September 8, 2009)
  10 .1   Second Amended and Restated Credit Agreement dated March 30, 2010, between Resolute Energy Corporation as Borrower and certain of its Subsidiaries as Guarantors, Wells Fargo Bank, National Association, as Administrative Agent, Bank of Montreal as Syndication Agent, Deutsche Bank Securities Inc., UBS Securities LLC and Union Bank, N.A. as Co-Documentation Agents, and The Lenders Party Hereto, Wells Fargo Securities, LLC and BMO Capital Markets as Joint Bookrunners and Joint Lead Arrangers (incorporated by reference to Exhibit 10.1 to the Annual Report on Form 10-K of Resolute Energy Corporation filed on March 30, 2010)
  10 .2#   2009 Performance Incentive Plan. (incorporated by reference as Exhibit 10.7 to Amendment No. 1 to the Initial S-4 filed on August 31, 2009)


63


Table of Contents

         
  Exhibit
   
  Number   Description of Exhibits
 
  10 .3#   Form of Indemnification Agreement between Resolute Energy Corporation and each executive officer and independent director of the Company. (incorporated by reference as Exhibit 10.8 to Amendment No. 1 to the initial S-4 filed on August 31, 2009)
  10 .4††   Cooperative Agreement between Resolute Natural Resources Company and Navajo Nation Oil and Gas Company dated October 22, 2004. (incorporated by reference by Exhibit 10.9 to the Initial S-4)
  10 .5††   First Amendment of Cooperative Agreement between Resolute Aneth, LLC and Navajo Nation Oil and Gas Company, Inc. dated October 21, 2005. (incorporated by reference as Exhibit 10.10 to the Initial S-4)
  10 .6††   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 July 21, 2006. (incorporated by reference as Exhibit 10.11 to Amendment No. 1 to the Initial S-4 filed on August 31, 2009)
  10 .7††   Product Sale and Purchase Contract by and between Resolute Natural Resources Company (Buyer) and Kinder Morgan CO 2 Company, L.P. (Seller) dated July 1, 2007, as amended October 1, 2007, January 1, 2009 and October 5, 2010. (incorporated by reference as Exhibit 10.12 to Amendment No. 1 to the Initial S-4 filed on August 31, 2009 and Exhibit 99.1 to the Current Report on Form 8-K filed on October 7, 2010.)
  10 .8   Gas Sales and Purchase Contract — Conventional & Residue Gas dated April 12, 1995, between Rim Offshore, Inc., as producer, and Western Gas Resources, Inc., as processor (Contract #6690), as amended July 27, 2006 and March 6, 2009. (incorporated by reference as Exhibit 10.13 to Amendment No. 1 to the Initial S-4 filed on August 31, 2009 )
  10 .9   Consent Decree, entered into June 2005, relating to alleged violations of the federal Clean Air Act. (incorporated by reference as Exhibit 10.16 to the Initial S-4)
  10 .10   Consent Decree, entered into August 2004, relating to alleged violations of the federal Clean Water Act. (incorporated by reference as Exhibit 10.17 to the Initial S-4)
  10 .11   Crude Oil Purchase Agreement dated August 27, 2009 between Western Refining Southwest, Inc., as purchaser, and Resolute Natural Resources Company, as seller. (incorporated by reference as Exhibit 10.18 to Amendment No. 1 to the Initial S-4 filed on August 31, 2009)
  10 .12   Form of Retention Award Agreement between Resolute Energy Corporation and certain award recipients. (incorporated by reference as Exhibit 10.19 to Amendment No. 2 to the Initial S-4 filed on September 8, 2009)
  10 .13   Form of Restricted Stock Award Agreement for Non-employee Directors (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K of Resolute Energy Corporation filed on March 30, 2010)
  10 .14#   Form of Confidentiality and Non Compete Agreement among Resolute Holdings, LLC and certain employees dated as of January 23, 2004 (incorporated by reference to Exhibit 10.14# to the Annual Report on Form 10-K of Resolute Energy Corporation filed on March 30, 2010)
  10 .15#   Form of Restricted Stock Agreement for Employees (incorporated by referenced as Exhibit 10.1 to the 10-Q filed on May 11, 2010)
  10 .16#   Form of Stock Appreciation Right Agreement for Non-employee Directors (incorporated by reference as Exhibit 10.2 to the 10-Q filed on May 11, 2010)
  10 .17#   Letter Agreement between Resolute Energy Corporation and Dale E. Cantwell, effective as of June 1, 2010 (incorporated by reference as Exhibit 10.1 to the 10-Q filed on August 12, 2010)
  10 .18#   Letter Agreement between Resolute Energy Corporation and Janet W. Pasque, effective as of June 1, 2010 (incorporated by reference as Exhibit 10.1 to the 10-Q filed on August 12, 2010)
  12 .1   Statement of Ratio of Earnings to Fixed Charges
  21     List of Subsidiaries of Resolute Energy Corporation
  23 .1   Consent of Deloitte & Touche LLP.
  23 .2   Consent of KPMG LLP.
  23 .3   Consent of Netherland, Sewell & Associates, Inc.
  31 .1   Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
  31 .2   Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
  32     Certification of the Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

64


Table of Contents

         
  Exhibit
   
  Number   Description of Exhibits
 
  99 .1   Report of Netherland, Sewell & Associates, Inc. regarding the registrant’s reserves as of December 31, 2010
         
      The Purchase and IPO Reorganization Agreement filed as Exhibit 2.1, the Purchase and Sale Agreement filed as Exhibit 2.3, the Asset Sale Agreement filed as Exhibit 2.4, the Purchase and Sale Agreement filed as Exhibit 2.5 and the Cooperative Agreement file as Exhibit 10.4 omit certain of the schedule and exhibits to each of the Purchase and IPO Reorganization Agreement, Purchase and Sale Agreements, the Asset Sale Agreement and the Cooperative 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, the Asset Sale Agreement and the Cooperative Agreement filed as Exhibit 2.1, 2.3, 2.4, 2.5 and 10.4, respectively. Resolute agrees to furnish supplementally a copy of any omitted schedule or exhibit to the Securities and Exchange Commission upon request.
  ††     Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
  #     Management Contract, Compensation Plan or Agreement

65


Table of Contents

SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
     
RESOLUTE ENERGY CORPORATION
  Dated: March 14, 2011
 
By:         
/s/  Nicholas J. Sutton
Nicholas J. Sutton, Chief Executive Officer and Director
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
             
Signature   Title   Date
 
         
/s/  Nicholas J. Sutton

Nicholas J. Sutton
  Chief Executive Officer and Director (Principal Executive Officer)   March 14, 2011
         
/s/  James M. Piccone

James M. Piccone
  President and Director   March 14, 2011
         
/s/  Theodore Gazulis

Theodore Gazulis
  Senior Vice President and Chief Financial Officer (Principal Financial Officer)   March 14, 2011
         
/s/  James A. Tuell

James A. Tuell
  Vice President and Chief Accounting Officer (Principal Accounting Officer)   March 14, 2011
         
/s/  Richard L. Covington

Richard L. Covington
  Director   March 14, 2011
         
/s/  William H. Cunningham

William H. Cunningham
  Director   March 14, 2011
         
/s/  James E. Duffy

James E. Duffy
  Director   March 14, 2011
         
/s/  Kenneth A. Hersh

Kenneth A. Hersh
  Director   March 14, 2011
         
/s/  Thomas O. Hicks, Jr.

Thomas O. Hicks, Jr.
  Director   March 14, 2011
         
/s/  William J. Quinn

William J. Quinn
  Director   March 14, 2011
         
/s/  Robert M. Swartz

Robert M. Swartz
  Director   March 14, 2011


66


Table of Contents

FINANCIAL STATEMENTS
 
INDEX TO FINANCIAL STATEMENTS
 
 
 
     
RESOLUTE ENERGY CORPORATION
   
     
  F-2
  F-4
  F-5
  F-6
  F-7
  F-8
     
PREDECESSOR RESOLUTE
   
     
  F-30
  F-31
  F-32
  F-33
  F-34


F-1


Table of Contents

 
Report of Independent Registered Public Accounting Firm
 
To the Board of Directors and Stockholders of
Resolute Energy Corporation:
 
 
We have audited the accompanying consolidated balance sheets of Resolute Energy Corporation and subsidiaries (successor by merger to Hicks Acquisition Company I, Inc.) (the Company) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2010. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financials statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Resolute Energy Corporation and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Resolute Energy Corporation’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 14, 2011 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
 
/s/  KPMG LLP
 
Denver, Colorado
 
March 14, 2011


F-2


Table of Contents

Report of Independent Registered Public Accounting Firm
 
To the Board of Directors and Stockholders of
Resolute Energy Corporation:
 
 
We have audited Resolute Energy Corporation and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of the inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, Resolute Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by COSO.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Resolute Energy Corporation as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2010, and our report dated March 14, 2011 expressed an unqualified opinion on these consolidated financial statements.
 
/s/  KPMG LLP
 
Denver, Colorado
 
March 14, 2011


F-3


Table of Contents

 
RESOLUTE ENERGY CORPORATION
 
(in thousands, except share amounts)
 
 
                 
    December 31,  
    2010     2009  
 
Assets
               
Current assets:
               
Cash and cash equivalents
  $ 1,844     $ 455  
Accounts receivable
    45,154       27,047  
Deferred income taxes
    11,954       7,050  
Derivative instruments
    4,745       6,958  
Prepaid expenses and other current assets
    1,596       1,930  
                 
Total current assets
    65,293       43,440  
                 
Property and equipment, at cost:
               
Oil and gas properties, full cost method of accounting
               
Unproved
    37,235       7,306  
Proved
    689,021       634,383  
Other property and equipment
    2,869       2,413  
Accumulated depletion, depreciation and amortization
    (57,564 )     (11,323 )
                 
Net property and equipment
    671,561       632,779  
                 
Other assets:
               
Restricted cash
    14,781       12,965  
Derivative instruments
    3,098       3,600  
Deferred financing costs
    3,281        
Other assets
    2,509       656  
                 
Total assets
  $ 760,523     $ 693,440  
                 
                 
Liabilities and Stockholders’ Equity
               
Current liabilities:
               
Accounts payable and accrued expenses
  $ 58,144     $ 41,287  
Asset retirement obligations
    3,072       1,221  
Derivative instruments
    31,193       20,360  
                 
Total current liabilities
    92,409       62,868  
                 
Long term liabilities:
               
Long term debt
    127,900       109,575  
Asset retirement obligations
    11,693       9,217  
Derivative instruments
    51,279       55,260  
Deferred income taxes
    73,376       62,467  
Other noncurrent liabilities
          516  
                 
Total liabilities
    356,657       299,903  
                 
                 
Commitments and contingencies
               
Stockholders’ equity: