Edgar Filing: Resolute Energy Corp

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Smaller reporting company

10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

¨	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 ¨ No x

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 ¨ No x

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 x No ¨

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 x No ¨

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. x

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.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No x

The aggregate market value of registrant’s common stock held by non-affiliates on June 30, 2011, computed by reference to the price at which the common stock was last sold as posted on the New York Stock Exchange, was $580.4 million.

As of February 29, 2012, 60,940,208 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 2012 annual meeting of stockholders (“Proxy Statement”) are incorporated by reference into Part III of this Form 10-K.

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 2012 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; discovery, estimation 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;

•

a lack of available capital and financing on acceptable terms;

•

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 our Aneth Field Properties;

•

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

•

the completion, timing and success of exploratory drilling;

•

availability of, or delays related to, drilling, completion and production, personnel, supplies and equipment;

•

the effect of third party activities on our oil and gas operations, including our dependence on gas gathering and processing systems;

•

inaccuracy in reserve estimates and expected production rates;

•

our operating costs and other expenses;

•

our success in marketing oil and gas;

•

competition in the oil and gas industry;

•

operational problems, or uninsured or underinsured losses affecting our operations or financial results;

•

the impact and costs related to compliance with, or changes in, laws or regulations governing our oil and gas operations, including the potential for increased regulation of underground injection operations;

•

our relationship with the Navajo Nation, the local 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, explosions, floods and other events and natural disasters;

•

environmental liabilities;

•

anticipated CO₂supply which is currently sourced exclusively from Kinder Morgan CO₂ Company, L.P.;

•

risks related to our level of indebtedness;

•

developments in oil and gas-producing countries;

•

loss of senior management or technical personnel;

•

timing of issuance of permits and rights of way;

•

timing of installation of gathering infrastructure in areas of new exploration and development;

•

potential breakdown of equipment and machinery relating to Aneth compression facility;

•

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	26

Item 1B.	Unresolved Staff Comments	42

Item 3.	Legal Proceedings	42

Item 4.	Mine Safety Disclosures	42

PART II —

Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	43

Item 6.	Selected Financial Data	45

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	46

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	57

Item 8.	Financial Statements and Supplementary Data	58

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	58

Item 9A.	Controls and Procedures	58

Item 9B.	Other Information	58

PART III —

Item 10.	Directors, Executive Officers and Corporate Governance	58

Item 11.	Executive Compensation	59

Item 12.	Security Ownership of Certain Beneficial Owners and Mangement and Related Stockholder Matters	59

Item 13.	Certain Relationships and Related Transactions and Director Independence	59

Item 14.	Principal Accounting Fees and Services	59

PART IV —

Item 15.	Exhibits and Financial Statement Schedules	60

Signatures		63

PART I

ITEMS 1. and 2.

BUSINESS AND PROPERTIES

In Items 1 and 2 of this Annual Report on Form 10-K, unless the context indicates otherwise, references to “Resolute” or the “Company” refer to Predecessor Resolute (as defined in Business and Properties—Company History) for all periods prior to September 25, 2009 and Resolute Energy Corporation and its subsidiaries for all periods thereafter.

Business Overview

Resolute is an independent oil and gas company engaged in the exploration, exploitation and development of its oil and gas properties located in Utah (its “Aneth Field Properties”), Wyoming (its “Wyoming Properties”), North Dakota (its “North Dakota Properties”) and Texas (its “Texas Properties”). The Company’s primary operational focus is on increasing reserves and production from these properties while improving efficiency and controlling operational costs. Resolute plans to further expand its reserve base through an organic growth strategy focused on exploration and exploitation of oil-prone acreage, particularly among its North Dakota and Permian Basin properties, that it believes contain relatively low risk and repeatable drilling opportunities, and through carefully targeted exploration activities, particularly on its Wyoming Properties. Resolute also expects to engage in opportunistic acquisitions in and around its core areas, which may provide economies of scale and take advantage of operational expertise.

Oil sales comprised approximately 90% of revenue during 2011. As of December 31, 2011, Resolute’s estimated net proved reserves were approximately 64.8 million equivalent barrels of oil (“MMBoe”), of which approximately 57% and 44% were proved developed reserves and proved developed producing reserves, respectively. Additionally, approximately 82% of the Company’s estimated net proved reserves were oil and approximately 91% were oil and natural gas liquids (“NGL”). The pre-tax present value discounted at 10% (“PV-10”) of Resolute’s net proved reserves at December 31, 2011, was $1,143.0 million and the standardized measure of its estimated net proved reserves was $816.0 million. For additional information about the calculation of Resolute’s PV-10 and its standardized measure, please read “Business and Properties — Estimated Net Proved Reserves.”

Business Strategies

Bring Non-Producing Properties in Aneth Field into Production. A primary business strategy of Resolute is to continue the development of the Aneth Field Properties to generate production from our relatively low risk proved developed non-producing and proved undeveloped reserves into production. At December 31, 2011, Resolute had estimated net proved reserves of approximately 36.5 MMBoe that were classified as proved developed non-producing and proved undeveloped. An estimated 32.0 MMBoe, or 88% 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.

Focus on Exploitation and Development of Oil and Liquid-Prone Formations on Existing Properties. In addition to its properties in Aneth Field, Resolute has assembled a portfolio of low-risk properties with acreage in three of the most active oil-focused resource plays in the United States. The Company has active drilling programs in the Bakken trend in the Williston Basin of North Dakota and in the Wolfbone and Wolfberry plays in the Permian Basin of Texas. In the Bakken, Resolute controls approximately 33,000 net acres, has participated in the drilling of 24 gross wells and currently has two active drilling rigs. In the Permian Basin, Resolute controls approximately 9,000 net acres, has interests in 12 gross wells and is currently operating a two-rig drilling program. All of these areas are characterized by relatively low risk drilling, with production heavily weighted toward oil and NGL. Resolute is focused on maximizing returns from these projects by optimizing completion techniques to enhance well performance and ultimate recoveries and accelerating development activity to increase production and reserves.

Pursue Acquisitions of Properties with Development Potential in Core Areas. From inception, the Company’s goal has been to grow its reserve base and production through a focused acquisition strategy of domestic onshore properties. It completed the acquisitions of its Aneth Field Properties in 2004 and 2006, its Wyoming Properties in 2008, its North Dakota Properties in 2010 and 2011 and its Texas Properties in 2011. While a primary business strategy is the continued development of these properties, Resolute also will continue to pursue opportunities to acquire, explore and develop properties that are prospective for production of oil or NGL, particularly in the Permian Basin and Rocky Mountain regions, with the objective of adding scale to its existing operations. 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.

Increase Production and Improve Efficiency of Operations on Resolute’s Properties. Resolute intends to continue its long-term focus on maximizing economic returns on all of its properties through improvements in operational efficiency and cost control. Resolute’s management team has experience in managing operationally intensive oil and gas properties.

Furthermore, as the operator of its Aneth Field Properties, its Wyoming Properties and its Texas Properties, Resolute has

the ability to directly manage its costs, control the timing of its exploitation, drilling and producing activities and effectively implement programs to increase production and improve the efficiency of its operations. Operational control over its properties also allows Resolute to focus on cost control to optimize long-term cash margins.

Identify Future Core Areas Through Focused Exploration Efforts. In addition to its large producing asset in Aneth Field and development drilling activity in the Williston and Permian Basins, Resolute controls acreage in two emerging exploration plays in Wyoming. Resolute has approximately 45,000 net acres in the Powder River Basin in an area that has seen increasing levels of activity by industry participants with targets including the Turner, Niobrara and Mowry formations. All of Resolute’s acreage in this area is held by production from the deeper Muddy formation. The Company is conducting geologic studies of the area including shooting a 3-D seismic program over a large portion of the acreage, integrating well log and core data and mapping the target formations. In the Big Horn Basin of Wyoming, Resolute controls approximately 73,000 acres, almost exclusively on ten year federal leases, most with four or more years remaining. The Company’s primary target in the Big Horn Basin is the Mowry oil shale. Resolute has re-completed one well and drilled a new well to test the productivity of the Mowry. Resolute’s exploration activity is focused on establishing production from these two assets through drilling of additional wells. Resolute will seek to attract industry and financial participants to these activities in order to leverage the Company’s capital and to share risk.

Competitive Strengths

A High Quality Base of Long-Lived Oil Producing Properties. As of December 31, 2011, Resolute had estimated net proved reserves of approximately 64.8 million MMBoe, with a proved developed producing reserves-to-production ratio of 10 years and a proved developed reserves-to-production ratio of 22 years.

The Aneth Field Properties in particular have characteristics that Resolute believes will provide a stable production platform and yield positive free cash flow to fund Resolute’s development and growth activities:

•

The properties are expected to have a long productive life. As of December 31, 2011, the proved developed producing reserves had a reserves-to-production ratio of approximately 11 years and total proved reserves had a reserves-to-production ratio of 26 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.

Additionally, although Resolute’s Texas and North Dakota Properties are in the early stages of development, they are located in oil-prone areas where the industry has achieved economic returns.

Portfolio of Significant Organic Development Opportunities. Resolute controls significant quantities of proved developed non-producing and proved undeveloped reserves as well as development potential which is not currently reflected in the Company’s proved reserves. Within Aneth Field Resolute has estimated net proved reserves of 32.0 MMBoe that are classified as proved developed non-producing or proved undeveloped. These proved reserves are attributable to recoveries associated with expansions, extensions and processing of the tertiary recovery CO₂ floods that are currently in operation. In addition, Resolute’s Texas and North Dakota Properties provide a significant multi-year inventory of low risk drilling opportunities that are expected to contribute significantly to growth in production and proved reserves over the next several years.

Operating Control Over Our Properties. Resolute has the ability to control the timing, scope and costs of development projects undertaken on its various properties. The Company operates its Aneth Field, Wyoming and Texas Properties which constitute approximately 95% of its proved reserves and production. Further, operatorship of its Aneth Field and Wyoming Properties is secured for the foreseeable future as the acreage is held by production. In North Dakota, the Company has assumed operatorship of a portion of its acreage beginning in 2012. With respect to its non-operated North Dakota Properties, Resolute works very closely with its operating partner GeoResources, Inc. (“GeoResources”) in developing drilling and operating plans, ensuring that operating efficiencies and cost controls can also be maintained in that area of operations.

Strong Balance Sheet. Resolute practices a disciplined approach to liquidity and management of leverage and has a capital structure that provides it with the ability to execute its business plan. As of December 31, 2011, outstanding borrowings under Resolute’s credit facility were $170.0 million and unused availability under the borrowing base was $156.9 million. Resolute plans to maintain a capital structure that provides financial flexibility through the prudent use of leverage, aligning capital expenditures to cash flows, and maintaining a strategic hedging program.

Experienced Management and Technical Teams with Extensive Operational, Transactional and Financial Experience in the Energy Industry. With average industry work experience of almost 30 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 executive management 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 was acquired by Kerr-McGee Corporation in 2001. Resolute also employs more than 27 oil and gas technical professionals, including geophysicists, geologists, petroleum engineers and production and reservoir engineers, who have an average of approximately 16 years of experience in their respective technical fields. Resolute continually applies the extensive experience of its senior management and technical staff to benefit all aspects of its operations.

Summary Reserve Information

The following table sets forth summary information attributable to Resolute’s estimated net proved reserves that are derived from its December 31, 2011 reserve report which was developed by Resolute and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers.

		September 30,		September 30,		September 30,		September 30,		September 30,
	Estimated Net Proved Reserves as of December 31, 2011
	Proved Developed		Proved Developed		Proved		Total		Net Daily Production
	Producing		Non-Producing		Undeveloped		Proved		(Boe per day)⁽¹⁾
Aneth Field Properties (MMBoe)		23.4		7.6		25.0		56.0		6,010
Wyoming Properties (MMBoe)		3.1		0.9		—		4.0		1,515
Texas Properties (MMBoe)		1.1		0.1		2.3		3.5		328
North Dakota Properties (MMBoe)		0.7		—		0.6		1.3		399

Total (MMBoe)		28.3		8.6		27.9		64.8		8,252

Future operating costs (millions)							$	1,357.2
Future production taxes (millions)								711.4
Future capital costs (millions)								648.1

Future operating costs ($/Boe)							$	20.95
Future production taxes ($/Boe)								10.98
Future capital costs ($/Boe)								10.00

1)	For the quarter ended December 31, 2011.

Description of Properties

Aneth Field Properties

Resolute’s largest asset, constituting 86% of its net proved reserves, is its ownership of working interests in Greater Aneth Field (“Aneth Field”), a mature, long-lived oil producing field, most of which is located 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 which constitute the Aneth Field Properties. These are the Aneth Unit, the McElmo Creek Unit and the Ratherford Unit in which Resolute owns working interests of 62%, 75% and 59%, respectively. 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. Resolute believes that significantly more oil can be recovered from its Aneth Field Properties through industry standard secondary and tertiary recovery techniques.

During the twelve months ended December 31, 2011, gross oil production from the Aneth Field Properties averaged 10,230 barrels of oil per day. As of December 31, 2011, Resolute had interests in and operated 391 gross (257 net) producing wells and 330 gross (215 net) active water and CO₂ injection wells.

The primary producing horizon in Aneth Field is the Pennsylvanian-age Desert Creek formation, which is a carbonate algal-mound found at 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.

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 from Chevron (“Chevron Properties”). In April 2006, it acquired an additional 7.5% 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 from ExxonMobil (“ExxonMobil Properties”).

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 working 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.”

Upon completion of the acquisition of the Chevron Properties in 2004 and the ExxonMobil Properties in 2006, Resolute initially focused on a program of field rejuvenation directed at improving field reliability and returning shut in wells to production. This activity had the effect of reversing the long term decline the Aneth Field had been exhibiting prior to the Resolute Acquisition. While production between 2003 and 2004 declined by 13%, production between 2006 and 2007 increased by 5%.

After stabilizing production, Resolute set about identifying strategies to grow reserves and production in Aneth Field. These initiatives focused on expanding a successful CO₂ flood initiated by Mobil in 1985 in the McElmo Creek Unit to the remainder of the field. Other initiatives included re-activating a shut in of the McElmo Creek IIC subzone of the Desert Creek formation, the (“DC IIC”), and infill drilling in previously bypassed sections of the field. 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. Resolute estimates that the rate of oil production will increase faster at the Aneth Unit than that experienced at the McElmo Creek Unit because of Resolute’s practice of injecting CO₂ at higher rates at the Aneth Unit than was the case in the McElmo Creek Unit.

The expansion of the CO₂ flood commenced in 2006 with the start of CO₂ flooding in the Aneth Unit. This project was divided into four discrete phases which in total would cover substantially all of the Aneth Unit. As of 2008 Phases 1 through 3 of this project had been completed and CO₂ injection had commenced over the western half of the Aneth Unit. Phase 4, which covers the eastern half of the Unit, was delayed based on economic conditions in 2008 and 2009. Installation of the infrastructure for Phase 4 was commenced in 2010 and CO₂ injection began in the fourth quarter of 2011. Additional work will be required in 2012 to expand the infrastructure and spread CO₂ injection throughout the remainder of the Phase 4 area.

Typically in a tertiary recovery project employing CO₂ injection, twelve to eighteen months elapse between the commencement of injection and a demonstrated production response from the field. After beginning injection in Phases 1 through 3 of the Aneth Unit in late 2007, Resolute began to see response from the wells in this area in late 2008. As of year-end 2011, production from this area had increased 124% from 2007. Of the 86 producing wells in this area, 69 had demonstrated CO₂ response by year end 2011. Resolute anticipates a similar response from injection of CO₂ in the Phase 4 area.

Beginning in early 2010, Resolute began recompleting the DC IIC in the McElmo Creek Unit, with notable increases in production. This subzone was waterflooded by a previous operator. However, due to high water cuts and low oil prices prevalent at the time, the zone was shut in by the early 1980s. Because the CO₂ flood was not started in McElmo Creek Unit until 1985, this zone has never been CO₂ flooded. As part of its work in the field, Resolute has determined that the DC IIC can be reactivated as a water flood with highly economic results given today’s commodity prices. Plans to implement a CO₂ flood in this zone are progressing as reservoir properties collected from the recompletions, such as deliverability, oil cut and reservoir pressure are analyzed. Meanwhile, Resolute has begun the process of repressurizing this zone with water in preparation for CO₂ flooding. This recompletion and CO₂ flood project is expected to continue for several years, with further production increases expected. The project will also require construction and rebuilding of infrastructure to accommodate the incremental injection and production.

The following table sets forth, as of December 31, 2011, 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 2042. The table also sets forth the estimated net proved developed non-producing and proved undeveloped reserves that Resolute anticipates will be produced as a result of these projects, as included in Resolute’s reserve report as of December 31, 2011. Resolute incurred $61.0 million of capital expenditures related to the Aneth Field Properties during 2011.

		September 30,		September 30,		September 30,		September 30,		September 30,
	Estimated Future Capital Expenditures		Estimated Future CO₂ Purchases		Estimated Future Total Capital Expenditures		Estimated Reserves (MMBoe)		Estimated Future Development Cost ($/Boe)
	(in millions, except as otherwise indicated)
Aneth Unit — Phase 1, 2 and 3	$	4.7	$	50.0	$	54.7		7.4	$	7.41
Aneth Unit — Phase 4 and Plant		66.7		158.6		225.3		14.1		15.92
McElmo Creek Unit – DC IIC and Plant		131.1		82.0		213.1		10.5		20.28

Total	$	202.5	$	290.6	$	493.1		32.0	$	15.39

The success of Resolute’s CO₂ projects depends on acquiring adequate amounts of CO₂. Resolute is party to 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. The contract is intended to provide substantially all of the anticipated CO₂required through 2020 to pursue our existing CO₂ projects. 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 52,000 Mcf of CO₂ per day in 2013, 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, 2011, Resolute had made payments under this contract for minimal CO₂ volumes for which it had not yet taken delivery, but anticipates utilizing during 2012.

The CO₂ that Resolute purchases for its flood operations is delivered through the McElmo Creek Pipeline, which is approximately 25 miles in length and runs directly from McElmo Dome Field to Resolute’s McElmo Creek Unit. Other 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 approximately 70,000 Mcf per day.

Aneth Field — Gas Compression. Currently there are two types of gas production in Aneth Field, saleable gas and gas that is contaminated by CO₂. The saleable gas stream has low levels of CO₂ while the contaminated gas stream has high levels of CO₂, which makes it unacceptable to gas purchasers. This contaminated gas stream, which is rich in valuable NGL and natural gas, is currently compressed and re-injected into the reservoir. As Resolute continues its CO₂ injection and expansion plans, the volume of contaminated gas will significantly increase. During the third quarter of 2011, the Company completed rebuilding of the gas compression plant at Aneth, which processes all contaminated gas from the expansion project. This plant dehydrates and recovers condensate from the recycled gas stream and Resolute plans to eventually expand the plant to strip CO₂ and hydrocarbon gas as well. The hydrocarbon gas will be sold, adding income streams to the field economics while the separated CO₂ stream will be reinjected into the producing zone

Wyoming Producing Properties

Resolute’s producing Wyoming Properties, which are operated by the Company, are located in the Powder River Basin and constitute approximately 6% of Resolute’s net proved reserves. Hilight Field, anchoring our Wyoming production and reserves, produces oil and gas from the Muddy sandstone and Mowry shale formations. As of December 31, 2011, the Wyoming Properties consisted of 157 gross (149 net) producing wells, excluding shut-in coalbed methane (“CBM”) wells, and 2 gross (2 net) active water injection wells.

Hilight Field in Campbell County consists of the Jayson Unit, the Grady Unit and the Central 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 gross acres. Hilight Field was discovered by Inexco Oil Company in 1969, unitized in 1971 and 1972 and underwent waterflood between 1972 and the mid-1990s. As of December 31, 2011, there were 139 gross (132 net) producing wells, and cumulative production through December 31, 2011 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, 2011 was 243 Bbl of oil and 9,202 Mcf of gas per day. Resolute also has non-unitized production in the Hilight area which consists of 15 gross (14 net) wells. Muddy formation sandstones form the main reservoir in the field at an average depth of approximately 9,100 feet. Resolute also operates production from the Mowry and Niobrara formations. Resolute has prepared a multi-year development plan for the Wyoming Properties based on stimulating the Muddy formation. Resolute has continued this program with seven refracs completed during 2010 and four completed during 2011 and has initiated the Mowry shale exploration program with re-completions of two wells performed in 2010 and seven performed in 2011.

All of Resolute’s CBM production was shut-in as of December 31, 2011. Prior to shut-in, Resolute CBM production came from 260 gross (239 net) producing wells. Average daily gross production for the twelve months ending December 31, 2011, was 1,379 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 the CBM wells as of December 31, 2011. Due to field economics, the Company anticipates plugging and abandoning the CBM properties over a three year period beginning in 2012.

North Dakota Properties

As of December 31, 2011, Resolute had interests in approximately 94,000 gross (33,000 net) acres within the Bakken shale trend of the Williston Basin in North Dakota. The Company’s position is divided between two principal project areas; the New Home project area located in Williams County, comprising approximately 23,000 net acres and the Paris project area located in McKenzie County, comprising approximately 9,000 net acres. The Company also has interests in various smaller project areas, which in total comprise approximately 1,000 net acres, primarily in McKenzie County.

New Home Project. Resolute acquired its interest in the New Home project area in 2010 through a joint venture with GeoResources. In total, the New Home project area includes 70,000 gross acres, in which Resolute and GeoResources each have an average 33% working interest. During 2011, Resolute participated in drilling and completing nine wells and had an additional eight wells waiting on completion at year-end. Based on drilling activity to date, approximately 15% of the acreage is considered developed and 29% is held by production. In 2012, the companies plan to employ two drilling rigs in this area with the objective of drilling and completing 24 to 26 gross (5 to 6 net) wells.

The primary objective of the New Home development plan is the middle member of the Bakken shale formation. A secondary objective is the Three Forks formation which lies below the lower Bakken shale. All of the Company’s producing wells are producing from the Middle Bakken. While Resolute has not tested the Three Forks formation, it is productive in other portions of Williams and McKenzie counties. To date, the Company has a 100% success rate on wells drilled and completed within the project area, with all wells drilled being completed as producers. The wells in this area are drilled to a target depth, at which point the drill bit is steered to result in drilling horizontally through the target formation. A typical well in this area has a horizontal length of 10,000 feet and is completed using hydraulic fracturing with between 24 and 34 frac stages.

During the fourth quarter of 2011, average daily production from the New Home project was approximately 300 Boe per day net to Resolute. Production from New Home is approximately 95% oil. See “Marketing and Customers” for more information on how production from this area is sold.

In 2012, Resolute and GeoResources are focused on improving the economics of new development in this area primarily through lowering drilling and completion costs. The most recent Authorization for Expenditures (“AFE”) in this area have been less than $8 million per well. Some techniques currently employed to reduce costs include pad drilling where multiple wells are drilled and completed from the same surface location, changes in completion design that seek to optimize the number of fracture stages and the proppant design relative to well performance and through reducing cycle times which reduce the number of days required to drill a well to total depth and directly affects the related rig charges.

Paris Project. Resolute acquired its interest in the Paris project area through a farmout from Marathon Oil Company. The Paris project area covers approximately 19,000 gross acres, and Resolute has approximately a 46% interest in the acreage. Resolute is the operator of the Paris project and earned its ownership by drilling and completing two wells. The first well, the Watson USA 14 32H, was completed in the first quarter of 2011 and is currently producing. The second well, the Forest USA 14 2H, was drilled in the first quarter of 2011, but experienced weather induced delays and mechanical difficulties in completing the well. While the Forest well has produced commercial quantities of oil at times during the completion process, it is currently shut in pending a work over and finalization of the planned completion. We expect that this well will be completed and placed on production in the second quarter of 2012.

Resolute does not currently anticipate drilling any additional wells in the Paris area during 2012. While activities by other operators in close proximity to the Paris area lead us to believe this area will be economic, we do not face pending material lease expirations with the nearest expirations occurring in the third quarter of 2014. The land situation in the Paris area allows us the time to perform additional analysis pending completion of the Forest well while we focus on our New Home project where we face more near term lease expirations.

When drilling does re-commence in the Paris area we plan to utilize many of the same cost containment measures currently being employed in the New Home project to maximize economic returns from development in Paris.

Texas Properties

As of December 31, 2011, Resolute had interests in 24,000 gross (9,000 net) acres in the Permian Basin of Texas. The Company’s position is divided between two principal project areas. The Wolfbone project area consists of approximately 8,000 net acres located in the Delaware Basin portion of the Permian Basin in Reeves County, and the Wolfberry project area consists of approximately 1,000 net acres located in the Midland Basin portion of the Permian Basin in Howard and Martin counties.

Wolfbone Project. Resolute acquired its interest in the Wolfbone project in the second quarter of 2011. The Wolfbone project area includes approximately 23,000 gross acres in which Resolute holds a 35% interest. Resolute has entered into a partnership with a Dallas-based private company, covering 60% of the acreage. Resolute is the operator for this area. At year-end 2011, Resolute had drilled and completed five wells in the Wolfbone project area. Based on drilling activity to date, approximately 10% of the acreage is considered developed and is held by production. In 2012 Resolute plans to employ two drilling rigs in this area with the objective of drilling and completing 21 gross wells, 10.7 net to Resolute.

The primary objectives of the Wolfbone development plan are the Wolfcamp and Bone Spring formations with the Avalon as a secondary objective. To date Resolute has had a 100% success rate on drilling within the project area with all wells drilled being completed as producers. Resolute’s current development plan calls for vertical well bores with between eight and ten completion stages in the upper Wolfcamp and Third Bone Spring sand.

For the fourth quarter of 2011, average daily production from the Wolfbone project was 11 Boe per day net to Resolute. At year-end 2011, gas gathering infrastructure did not yet exist in this project area and all gas produced from the wells was being flared. Resolute expects to have the wells connected to gathering infrastructure in the second quarter of 2012 and to commence gas and NGL sales at that time. We anticipate that production from the Wolfbone project area will be approximately 70% oil and NGL. See “Marketing and Customers” for more information on how production from this area is sold.

In 2012, Resolute plans to focus on refining its completion design for wells in this area. The most recent wells drilled by Resolute in 2011 have demonstrated significantly improved production resulting from increased concentrations of proppant and the addition of incremental completion stages in the Third Bone Spring formation. Resolute will seek to replicate and then improve on this performance in its 2012 drilling program. Other initiatives intended to improve development economics in this area will include reducing cycle times, or the time from initial spud of a well to the time of first sales of production, and the installation of water disposal facilities to reduce the expense of handling produced water.

Wolfberry Project. Resolute acquired its interest in the Wolfberry project in the third quarter of 2011 from a private company. The Wolfberry project area, which Resolute operates, comprises approximately 750 gross acres in which Resolute has a 99% interest. The initial acquisition was primarily an acquisition of proved reserves with seven producing wells. The property also contained numerous opportunities for incremental development including eleven down spacing opportunities and five up hole recompletion opportunities. In 2012, Resolute plans to drill four gross (four net) wells in this area.

The producing formations in our Wolfberry area extend over a 3,000 foot stratigraphic column and include the Mississipian, Strawn, Canyon, Cisco, Cline, Spraberry and Wolfcamp formations. In 2011, Resolute did not initiate any new development activity in this area. Resolute’s current development plan calls for vertical well bores with five to six completion stages in the Mississipian through Wolfcamp formations.

For the fourth quarter of 2011 average daily production from the Wolfberry project was 321 Boe per day net to Resolute. There is no corresponding production information for the fourth quarter of 2010. Production from the Wolfberry project area is estimated to be 74% oil and NGL. See “Marketing and Customers” for more information on how production from this area is sold.

Exploration Focused Properties

As of December 31, 2011, Resolute had interests in approximately 137,000 gross (122,000 net) acres in two exploratory areas in Wyoming. The Big Horn Basin has unconventional oil objectives in the Cretaceous Mowry shale and conventional oil objectives in the Permian Phosphoria Formation. At year-end, Resolute had drilled but not yet completed a Mowry horizontal well. In late 2011, Resolute also recompleted a vertical well in the Mowry shale, which produced commercial quantities of oil and gas. In addition to exploration activities performed by Resolute, two other operators have drilled a total of four additional wells targeting the Mowry shale.

In the Powder River Basin, where Resolute controls approximately 45,000 acres held by production in its Hilight Field, levels of industry activity have increased significantly with various companies pursuing exploration programs targeting objectives including the Turner, Niobrara and Mowry formations. Some of this activity is on acreage directly adjacent to acreage controlled by Resolute. During 2011 Resolute recompleted seven wells in the Mowry shale, bringing the total number of Hilight Field Mowry recompletions to nine wells. For the fourth quarter of 2011, average daily production from the 9 Mowry wells was 80 Boe per day. This pilot project sets up a potential Mowry horizontal drilling program. Also in 2011, Resolute underwrote a speculative 3D seismic survey covering Hilight Field and adjacent areas. This 3D seismic survey should help to delineate oil drilling prospects in the Mowry, and also in the Turner and Niobrara formations.

Estimated Net Proved Reserves

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, 2011, 2010 and 2009 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.

		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009

Net proved developed reserves
Oil (MBbl)		32,347			30,818			30,895
Gas (MMcf)		17,523			13,968			15,524
NGL (MBbl)		1,603			1,165			1,456

MBoe		36,871			34,312			34,938

Net proved undeveloped reserves
Oil (MBbl)		20,494			19,414			18,964
Gas (MMcf)		17,634			25,130			22,705
NGL (MBbl)		4,494			6,754			6,747

MBoe		27,927			30,357			29,495

Total net proved reserves
Oil (MBbl)		52,841			50,232			49,859
Gas (MMcf)		35,157			39,098			38,229
NGL (MBbl)		6,097			7,919			8,203

MBoe		64,798			64,669			64,433

PV-10 ($ in millions) ⁽¹⁾⁽³⁾	$	1,143		$	848		$	480
Discounted future income taxes ($ in millions)		(327	)		(261	)		(119	)

Standardized measure ($ in millions) ⁽¹⁾⁽²⁾	$	816		$	587		$	361

In accordance with SEC and Financial Accounting Standards Board (“FASB”) requirements, Resolute’s estimated net proved reserves and standardized measure at December 31, 2011, were determined utilizing prices equal to the 2011 twelve-month unweighted arithmetic average of first day of the month prices, resulting in an average NYMEX oil price of $96.19 per Bbl and an average Henry Hub spot market gas price of $4.12 per MMBtu.

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% annual rate 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.”

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.

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 13 — 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.

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. Resolute’s proved undeveloped reserves are primarily associated with large CO₂ flood projects in the Aneth and McElmo Creek Units that require significant capital investments over several years of development. These undeveloped CO₂flood projects comprise approximately 85% of the Company’s proved undeveloped reserves as of December 31, 2011. Facility construction and well development activities began on these projects in 2010 and remain ongoing.

During 2011, the Company developed 1.6 MMBoe of proved undeveloped reserves as a result of the following activities:

•

The addition of a refrigeration plant as part of the project to rebuild the Aneth Unit gas processing facility.

•

Surface facility construction associated with the Aneth Unit Phase 4 CO₂ flood expansion project began, allowing limited CO₂ injection in the fourth quarter and development of a small portion of the Phase 4 reserves as a result of early well response.

•

Additional producing and injecting wells in the McElmo Creek Unit DC IIC CO₂ flood project were recompleted. CO₂ injection in this area has not yet commenced.

As an operator of domestic oil and gas properties, the Company has filed Department of Energy Form EIA-23, “Annual Survey of Oil and Gas Reserves,” as required by Public Law 93-275. There are differences between the reserves as reported on Form EIA-23 and as reported herein. The differences are attributable to the fact that Form EIA-23 requires that an operator report on the total reserves attributable to wells that it operates, without regard to ownership (i.e., reserves are reported on a gross operated basis, rather than on a net interest basis).

Changes in Proved Reserves

Proved reserves reported by Resolute of 64.8 MMBoe at December 31, 2011, was consistent with the 64.7 MMBoe reported at December 31, 2010. Production during 2011 reduced proved reserves by 2.9 MMBoe and net revisions of previous estimates decreased proved reserves by 2.1 MMBoe. Increased commodity pricing in 2011 was the principal factor leading to the upward revision in proved oil reserves. The downward revision in gas and NGL reserves was associated with changes in the gas composition and in the estimated recovery yields associated with the Aneth CO₂ contaminated gas membrane plant. Purchases of reserves in place increased proved reserves by 4.0 MMBoe while sales of reserves decreased proved reserves by 0.3 MMBoe. In accordance with SEC requirements, the reserves at December 31, 2011, utilized prices of $96.19 per barrel of oil and $4.12 per MMBtu of gas, as compared to prices of $79.43 per barrel of oil and $4.38 per MMBtu of gas at December 31, 2010.

Resolute incurred development costs of $77.2 million in 2011 as compared to the $47.6 million incurred in 2010. The increase was primarily due to the Aneth Central Gas Plant rebuild which took place primarily during 2011.

At December 31, 2011, no proved undeveloped reserves have remained undeveloped for more than five years.

Controls Over Reserve Report Preparation, Technical Qualification and Methodologies Used

Reserve estimates as of December 31, 2011, 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, M. David Clouatre, who is a qualified reserve estimator and auditor. His qualifications 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. They 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 29 years of practical petroleum engineering experience in estimating and evaluating reserves information with at least seven of these years being in charge of estimating and evaluating reserves. Subsequent to December 31, 2011, Mr. Clouatre has retired, remaining with the Company in a consulting role. Resolute has appointed Paul J. Taylor to the position of Resolute’s Reservoir Engineering Manager. Mr. Taylor has succeeded Mr. Clouatre with responsibility for direction and supervision of the reserve report preparation process. Mr. Taylor has more than 25 years of experience in the oil and gas industry including engineering, business development and economic analysis. During his career, Mr. Taylor has worked in Alaska, California, Texas, the UK and the Middle East, has experience with nearly all forms of primary, secondary, and tertiary recovery methods and has worked on-shore and on shallow water and deep water projects. Mr. Taylor has a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines, a Master of Science in Energy

Economics from the University of Wisconsin-Madison and is a Professional Petroleum Engineer in Colorado and Alaska. His qualifications also 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.

The reserve report is 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 are reviewed internally by Resolute’s senior management prior to an audit of the reserve estimates by NSAI. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, advance production type curve matching, volumetrics, material balance, petrophysics/log analysis and analogy reservoir simulation. Some combination of these methods is used to determine reserve estimates in substantially all of our areas of operation.

NSAI is a worldwide leader in petroleum property analysis for industry, financial organizations and government agencies. NSAI was founded in 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 30 years of practical experience in petroleum engineering, with more than 14 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, 2011, has been filed as Exhibit 99.1 to this report and is incorporated herein.

Production and Price History

The table below summarizes Resolute and Predecessor Resolute’s operating data for 2011, 2010 and 2009.

		September 30,		September 30,		September 30,		September 30,
	Resolute⁽¹⁾						Predecessor Resolute
	Year Ended December 31,						For the 267 day period ended September 24,
	2011		2010		2009		2009
Sales Data:
Oil (MBbl)		2,298		2,089		543		1,444
Gas and NGL (MMcfe)		3,755		3,843		958		3,400
Combined volumes (MBoe)		2,924		2,730		703		2,011
Daily combined volumes (Boe per day)		8,012		7,478		7,172		7,530

Average Realized Prices (excluding derivative settlements):
Oil ($/Bbl)	$	77.60	$	73.22	$	69.11	$	50.32
Gas and NGL ($/Mcfe)		6.13		5.32		5.10		3.73

Average Production Costs ($/Boe):
Lease operating expense	$	20.35	$	18.91	$	23.03	$	16.84
Production and ad valorem taxes		10.73		8.85		8.26		6.42

(1)

The Aneth Field Properties comprised more than 15% of our total proved reserves as of December 31, 2011. Production from the Aneth Field Properties was 2,103 MBbl and 504 MMcfe in 2011, 1,944 MBbl and 482 MMcfe in 2010 and 485 MBbl and 71 MMcfe in 2009. Average realized oil prices were $88.79 per Bbl, $70.57 per Bbl and $69.78 per Bbl in 2011, 2010 and 2009, respectively. Average realized gas prices were $7.50 per Mcfe, $6.71 per Mcfe and $5.46 per Mcfe in 2011, 2010 and 2009, respectively. Average lease operating expense per Boe was $22.74, $21.18 and $26.88 in 2011, 2010 and 2009, respectively.

Productive Wells

The following table sets forth information as of December 31, 2011, 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 below, Resolute had interests in and operated 332 gross (217 net) active water and CO₂ injection wells as of December 31, 2011.

		September 30,		September 30,
	Productive Wells
	Gross		Net
Oil		574		419
Natural gas		266		245

Total		840		664

Drilling Results

The following table sets forth information with respect to development and exploration wells we completed from 2009 through 2011. The number of gross wells is the total number of wells we participated in, regardless of our ownership interest in the wells. Fluid injection wells for water flood and other enhanced recovery projects are not included as gross or net wells.

		September 30,		September 30,		September 30,
	Year Ended December 31,
	2011		2010		2009
Gross development wells:
Productive ⁽¹⁾		—		—		—
Dry ⁽²⁾		—		—		—

Total development wells		—		—		—

Gross exploratory wells:
Productive ⁽¹⁾		17		1		—
Dry ⁽²⁾		—		—		—

Total exploratory wells		17		1		—

Total wells drilled		17		1		—

		September 30,		September 30,		September 30,
	Year Ended December 31,
	2011		2010		2009
Net development wells:
Productive ⁽¹⁾		—		—		—
Dry ⁽²⁾		—		—		—

Total development wells		—		—		—

Net exploratory wells:
Productive ⁽¹⁾		7		1		—
Dry ⁽²⁾		—		—		—

Total exploratory wells		7		1		—

Total wells drilled		7		1		—

1)	A productive well is a well we have cased. Wells classified as productive do not always result in wells that provide economic production.

2)	A dry well is a well that is incapable of producing oil or gas in sufficient quantities to justify completion.

Acreage

All of Resolute’s leasehold acreage is categorized as developed or undeveloped. The following table sets forth information as of December 31, 2011, relating to the Company’s leasehold acreage:

		September 30,		September 30,
	Developed Acreage (1)
Area	Gross (2)		Net (3)
Aneth Field (UT)		43,218		28,122
Hilight Field (WY)		49,608		45,421
Hilight area non-unit acreage (WY)		3,482		3,308
Big Horn Basin (WY)		120		120
North Dakota		13,695		5,336
Texas		1,546		1,153

Total		111,669		83,460

		September 30,		September 30,
	Undeveloped Acreage (4)
Area	Gross (2)		Net (3)
South Hilight deep rights (WY)		1,640		1,600
Big Horn Basin (WY)		84,096		72,774
Black Warrior Basin (AL)		28,941		21,113
North Dakota		80,721		28,109
Texas		22,724		8,080

Total		218,122		131,676

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)	Undeveloped acreage includes leases either within their primary term or held by production.

Approximately 3,800 net acres of undeveloped acreage expires in 2012 and approximately 29,200 and 9,900 net acres expire in 2013 and 2014, respectively. Approximately 14,000 net acres that expire in 2013 relate to acreage in the Black Warrior Basin in Alabama.

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. 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 after payout is achieved, 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, 2011, the payout balance on the Chevron Properties was approximately $57.7 million and the payout balance on the ExxonMobil Properties was approximately $48.6 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.

		September 30,			September 30,			September 30,
	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	%

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 purchase agreement effective August, 2011, which provides for a fixed differential to the NYMEX price for crude oil of $6.25 per barrel, with future adjustments to reflect any increase in transportation costs from the field to the refinery. The agreement covers up to 8,000 combined barrels per day of Resolute and Navajo Nation Oil and Gas Company volumes (the “Base Volume”) and an additional volume of up to 3,000 barrels per day (the “Additional Volume”). The agreement contains a two year term for the Base Volume and a six month term for the Additional Volume, each commencing on August 1, 2011. Both continue automatically on a month-to-month basis after expiration of the initial term unless terminated by either party with 180 day prior written notice (120 days for the Additional Volume). The agreement 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.

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 its Bisti terminal, 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 as of year-end.

Resolute’s Aneth Field crude oil is a sweet, light crude oil that is 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 has 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 of 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 an affiliate of Anadarko Petroleum Corporation’s (“Anadarko”) Hilight Gas Plant. Resolute receives a percentage of proceeds for the NGL 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 receives the Colorado Interstate Gas Company index price after deducting differentials and transportation costs for all the gas it sells.

North Dakota. Resolute currently sells its working interest share of crude oil produced from the New Home area in Williams County, North Dakota through the project’s operator, G3 Energy, LLC (“G3”), a subsidiary of GeoResources, Inc. G3 markets the crude through a month-to-month crude oil purchase agreement with Plains Marketing, LP (“Plains”). G3 sells its crude oil to Plains in large part due to Plains’ ability to consistently provide trucking to transport our New Home crude oil to one of several Plains’ terminal facilities in the area. Other transporter/marketers have reportedly been less reliable than Plains and producers have been left with crude oil stranded in tanks onsite. Until the region’s pipeline and rail take-away capacity is increased, reliable truck transport is critical to move crude out of the region.

The contract price is calculated from the average daily NYMEX West Texas Intermediate (“WTI”) prompt month settlement price as traded for the calendar month of delivery, minus the Clearbrook, MN sweet crude differential, minus actual transportation costs from the New Home area to Enbridge’s pipeline terminal in Clearbrook, MN. The WTI/Clearbrook differential was a deduction of $2.00 to $3.00 in January 2011 but averaged a premium of approximately $5.00 to $6.00 through late October 2011, when the Clearbrook market weakened. In the latter part of 2011, the differential was approximately $2.50 below WTI.

In 2011, G3 entered into a crude oil gathering agreement with Banner Transportation Company, LLC (“Banner”). G3, Resolute and other working interest owners have agreed to commit all crude oil volumes produced at New Home for a period of ten years to Banner’s planned Market Center Gathering System to be constructed in Eastern Montana and Western North Dakota. Resolute believes that Banner’s gathering system will be in operation late in the first quarter of 2012, at which time crude oil will be taken off-lease by pipeline, and as a result transportation charges will be reduced by 50 to 75 percent compared to current trucking charges.

Due to a lack of gas gathering infrastructure in the New Home area, G3 is currently flaring all natural gas produced. G3 has entered into a gas gathering and purchase agreement with Highland Partners and hopes to have the first New Home wells connected late in the first quarter of 2012.

Texas. In Reeves County, Resolute sells all of its oil to Western Refining. The contract calls for the price paid by Western to Resolute to the sum of the Base Price (average daily NYMEX settlement price plus or minus the roll component), plus or minus the differential between Argus reported Midland WTI and Cushing WTI, and a transportation differential of $3.30 per Bbl.

Resolute is finalizing negotiations with Southern Union Gas Services to connect substantially all of its Reeves County natural gas into Southern Union’s JAL No. 3 Plant Area system. The contract will have a seven year term and is a percent of proceeds agreement that nets Resolute with 87 percent of the value of NGL and residual gas sales, less certain transportation and fractionation fees. The prices paid by Southern Union to Resolute for NGL is based on the monthly average of the daily price for NGL components quoted in the Oil Price Information Service for “Mont Belvieu Spot Gas Liquids Prices,” less a transportation and fractionation fee of $0.055 per gallon. The price paid for residue gas is the index posting for “Midpoint: Permian Basin Area” for El Paso Natural-Permian Basin published in “Platts Gas Daily”. The contract is expected to be finalized during the first quarter of 2012 with the connection to Southern Union’s line planned for early in the second quarter of 2012.

In Martin and Howard counties, Resolute sells all oil to Plains Marketing, LP (“Plains”). The month-to-month agreement calls for the price paid by Plains to Resolute to equal the sum of (a) the Plains West Texas Intermediate crude oil posting for the month, plus or minus (b) the Argus P+ weighted average for the month of delivery, plus or minus (c) the differential between Argus reported Midland WTI and Cushing WTI, less a transportation differential of $2.50 per bbl.

Gas produced in Martin and Howard counties is gathered by and sold to WTG Gas Processing, LP under a percent of proceeds contract that nets Resolute with 88 percent of the NGL and residual gas sales, less certain transportation and fractionation fees. The prices paid by Southern Union to Resolute for NGL is based on the monthly average of the daily midpoint price for NGL components quoted in the Oil Price Information Service for “Mont Belvieu Spot Gas Liquids Prices.” The price paid for residue gas is the index posting for El Paso Natural Gas Company-Permian Basin published in “Inside FERC Gas Market Report”. The contract has a five-year term that expires in early 2014 and then continues on a year-to-year basis thereafter.

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 short-term fluctuations in oil and gas prices. Such third parties must be parties to Resolute’s credit facility. 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, 2011, Resolute estimates the total cost to fully decommission the inactive portion of the Aneth Gas Processing Plant site to be $26.3 million, of which approximately $23.2 million had already been incurred and paid for. Resolute has recorded an asset retirement obligation for the remaining demolition liability net to Resolute’s interest of $0.8 million at December 31, 2011. Demolition activities are scheduled to be concluded in 2012. 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 Nation

Environmental Protection Agency now has primary jurisdiction over the Aneth Gas Processing Plant site. Resolute cannot predict whether Navajo Nation EPA 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 statute. 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, Resolute 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

Producing Property Acquisitions

Resolute believes it has satisfactory title to all of its material proved properties in accordance with standards 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.

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. With regard to the Company’s producing properties in Martin and Howard counties in Texas, Resolute reviewed attorney title opinions and public records covering 100% of the proved reserves.

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.

Non-Producing Leasehold Acquisitions

Resolute participates in the normal industry practice of engaging consulting companies to research public records before making payment to a mineral owner for non-producing leasehold. Prior to drilling a well on these properties, a title attorney is engaged to give an opinion of title.

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. Resolute 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:

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

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require the installation of expensive pollution control equipment;

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

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

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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

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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.

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 tribal 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 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 believes the consent decree may be terminated in 2012 by the EPA, although the EPA has given us no definite confirmation.

On July 1, 2011, EPA promulgated final rules titled “Review of New Sources and Modifications in Indian Country.” (Tribal Minor NSR Rules) 76 Fed. Reg. 38748-808 (July 1, 2011) (to be codified at 40 C.F.R. Parts 49 and 51). The final rules became effective on August 30, 2011, and establish the phased implementation of a program of minor source permitting by EPA in Indian Country over a period of 36 months. Under the Tribal Minor NSR Rules, new wells and associated equipment located in “Indian Country” that will be minor sources even without emission controls need not obtain a permit prior to their construction for up to 36 months from the effective date of the rules, while such sources that exceed major source thresholds without legally and practically enforceable emission control devices in place must obtain a synthetic minor permit prior to their construction. The Tribal Minor NSR Rules specifically provide for a synthetic minor permit to be issued to an otherwise major source that takes a permit restriction, enforceable as a legal and practical matter, so that the source’s potential to emit is less than the threshold applicability amount for major sources, i.e., 250 tons per year of criteria pollutants. Resolute has begun to evaluate its existing and planned new sources in Indian Country for purposes of registering them, and eventually permitting them with EPA, and evaluating the need to apply for any synthetic minor permits for existing facilities that may undergo modifications. Delays in obtaining such new permits from EPA under the Tribal Minor NSR Rules could adversely affect Resolute’s planned activities which previously were not subject to minor source permitting requirements or associated delays and expense.

Actual air emissions reported for these facilities are in material compliance with the terms and emission limits contained in the permit applications 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 November 2001, the EPA issued an administrative order to ExxonMobil for removal and remediation of crude oil and hydrocarbon contaminated ground water released as a result of a shallow casing leak at the McElmo Creek P-20 well that occurred 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 issued to ExxonMobil, 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 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 is 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 agreed to reduce their emissions of GHG to below 1990 levels by 2012. A successor treaty to the Kyoto Protocol has not been developed to date. In response to such studies and international action, the U.S. Congress has considered 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. Furthermore, a number of states have taken legal measures to reduce emissions of GHG, primarily through the planned development of GHG emission inventories and/or regional cap and trade programs. 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” has resulted in the regulation and permitting of GHG emissions from major stationary sources under the Clean Air Act, due to EPA’s “endangerment finding” that links global warming to man-caused emissions of GHG, and the EPA’s subsequent GHG Tailoring Rule, which subjects certain major sources of GHG emissions to Title V operating permit and New Source Review permitting requirements for the first time. The passage or adoption of additional 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 and Process Safety Management (PSM) regulations, 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, tribal, state and local government authorities, and the public. PSM requirements applicable to gas processing activities are an intended focus of OSHA enforcement in recent years, and emphasize the need for process safety information disclosure, including short and long-term off-site consequence analyses. Resolute believes that it is in substantial compliance with these applicable requirements and with other OSHA and comparable health and safety 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 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 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 the longer term implications, if any, 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:

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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.

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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.

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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 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. Since 2008, Resolute has been 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 challenged the validity of the law and entered into a tolling agreement with Navajo EPA (which was subsequently amended several times) that forestalled 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. A partial settlement agreement was entered into in January, 2012 among the NMOGA Group parties and the Navajo Nation. Under the terms of this agreement, enforcement of most of the material provisions of Navajo CERCLA is delayed for at least five years and the NMOGA Group retains its ability to file suit to challenge the law at such five year period. In the interim, Navajo Nation EPA has indicated it will require routine reporting of spills of oil and other hazardous substances to now go directly to the Navajo CERCLA program personnel within Navajo Nation EPA, in addition to that information going to other spill reporting contacts within NNEPA.

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 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:

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the location of wells;

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the method of drilling and casing wells;

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the rates of production or “allowables”;

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

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the plugging and abandoning of wells; and

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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 in-state 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.

Hydraulic Fracturing Disclosure and Possible Regulation or Prohibition. Hydraulic fracturing or “fracing” is a process used by oil and gas producers in the completion or re-working of some oil and gas wells. Water, sand and certain chemical additives are injected under high pressure into subsurface formations to create and prop open fractures and thus enable fluids that would otherwise remain trapped in the formation to flow to the surface. Fracing has been in use for many years in a variety of geologic formations. Combined with advances in drilling technology, recent advances in frac technology have contributed to a large increase in production of gas and oil from shales that would otherwise not be economically productive. Fracing is typically subject to state oil and gas agencies’ regulatory oversight, and has not been regulated at the federal level. However, due to assertions that fracing may adversely affect drinking water supplies, the federal EPA has commenced a study of the potentially adverse impacts that fracing may have on water quality and public health, and a committee of the U.S. House of Representatives has commenced its own investigation into fracing practices. Additionally, legislation has been introduced in Congress to amend the federal Safe Drinking Water Act (“SDWA”) to subject fracing to federal regulation under the SDWA, and to require the disclosure of chemical additives used in fracing fluids. If enacted, such legislation could require fracing to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping requirements, and meet plugging and abandonment requirements, in addition to those already applicable to well site reclamation under various federal, tribal and state laws. We routinely utilize hydraulic fracturing techniques in many of our reservoirs. Adoption of legislation and implementing regulations placing restrictions on fracing could impose operational delays, increased operating costs and additional regulatory burdens on Resolute’s exploration and production activities, which could make it more difficult to perform hydraulic fracturing, resulting in reduced amounts of oil and gas being produced, as well as increased costs of compliance and doing business. Resolute discloses information pertaining to frac fluids, additives, and chemicals to the FracFocus databases in compliance with statewide requirements established by the Texas Railroad Commission and Wyoming Oil and Gas Conservation Commission. Resolute is currently waiting to see what requirements will be promulgated by the Navajo Nation before disclosing similar information for wells fractured on Navajo lands.

Employees

As of December 31, 2011, Resolute had 201 full-time employees, of which 61 were field level employees 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 37,000 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 Colorado, Utah, and 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.

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 sells all of its crude oil production to a single customer, Western. The purchase agreement with Western, effective August, 2011, provides for a fixed differential to the NYMEX price for crude oil of $6.25 per barrel, with future adjustments to reflect any increase in transportation costs from the field to the refinery. The agreement covers up to 8,000 combined barrels per day of Resolute and Navajo Nation Oil and Gas Company Base Volume and an Additional Volume of up to 3,000 barrels per day. The agreement contains a two year term for the Base Volume and a six month term for the Additional Volume, each commencing on August 1, 2011. Both continue automatically on a month-to-month basis after expiration of the initial term unless terminated by either party with 180 day prior written notice (120 days for the Additional Volume). The agreement 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.

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 the Bisti terminal, 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 50 days of production revenue. Based upon average production from Aneth Field during the quarter ended December 31, 2011, and a NYMEX oil price of $100 per barrel, Western could owe Resolute between $11.3 million and $28.2 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.

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:

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the amount of oil and gas it produces;

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the price at which it sells its oil and gas production and the costs it incurs to market its production;

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the effectiveness of its commodity price hedging strategy;

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the development of proved undeveloped properties and the success of its enhanced oil recovery activities;

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the level of its operating and general and administrative costs;

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its ability to replace produced reserves;

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prevailing economic conditions;

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government regulation and taxation;

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the level of its capital expenditures required to implement its development projects and make acquisitions of additional reserves;

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its ability to borrow under its revolving credit facility or future debt agreements;

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debt service requirements contained in its revolving credit facility or future debt agreements;

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fluctuations in its working capital needs; and

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timing and collectability of receivables.

Failure to maintain adequate liquidity could result in an inability to replace reserves and production, to maintain ownership of undeveloped leasehold and adverse borrowing base determinations. Any or all of the foregoing could materially and adversely affect our business and results of operations.

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 $565.8 million of capital expenditures (including CO₂ purchases) over the next 31 years to implement and complete its proved developed non-producing and proved undeveloped projects. Resolute expects to incur approximately $200.0 million of these future capital expenditures between 2012 and 2013 based on the capital plan contemplated by its year-end 2011 SEC 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, 2011, approximately 56% 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, manpower 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 be less than 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 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 monthly. 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, 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:

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

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weather conditions;

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overall domestic and global political and economic conditions;

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

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the price of foreign imports;

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political and economic conditions in oil producing countries, including the Middle East and South America;

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technological advances affecting energy consumption;

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variations between product prices at sales points and applicable index prices;

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domestic, tribal and foreign governmental regulations and taxation;

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the impact of energy conservation efforts;

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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;

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the availability of refining and processing capability;

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factors specific to the local and regional markets where Resolute’s production occurs; and

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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, 2011, the NYMEX price for light sweet crude oil ranged from a high of $113.93 per Bbl to a low of $75.67 per Bbl. For calendar year 2010, the range was from a high of $91.49 per Bbl to a low of $65.96 per Bbl, and for the five years ended December 31, 2011, 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.

U.S. and global economic recession could have a material adverse effect on our business and operations.

Any or all of the following may occur if the recent crisis in the domestic and global financial and securities markets returns or economic conditions worsen:

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We may be unable to obtain additional debt or equity financing, which would require us to limit our capital expenditures and other spending. This would lead to lower growth in our production and reserves than if we were able to spend more than our cash flow. Financing costs may significantly increase as lenders may be reluctant to lend without receiving higher fees and spreads.

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The economic slowdown has led and could continue to lead to lower demand for crude oil and natural gas by individuals and industries, which in turn has resulted and could continue to result in lower prices for the crude oil and natural gas sold by us, lower revenues and possibly losses.

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The lenders under our revolving credit facility may become more restrictive in their lending practices or unable or unwilling to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and possibly losses.

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The losses incurred by financial institutions as well as the bankruptcy of some financial institutions heightens the risk that a counterparty to our derivative instruments could default on its obligations. These losses and the possibility of a counterparty declaring bankruptcy may affect the ability of the counterparties to meet their obligations to us on derivative transactions, which could reduce our revenues from derivatives at a time when we are also receiving a lower price for our natural gas and crude oil sales. As a result, our financial condition could be materially adversely affected.

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Our credit facility bears floating interest rates based on the London Interbank Offer Rate, or LIBOR. As banks were reluctant to lend to each other to avoid risk, LIBOR increased to unprecedented spread levels in 2008. This causes higher interest expense for unhedged levels of LIBOR-based borrowings.

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Our credit facility requires the lenders to redetermine our borrowing base semi-annually. The redeterminations are based on our proved reserves using price assumptions determined by each lender, with effect given to our derivative positions. It is possible that the lenders could reduce their price assumptions used to determine reserves for calculating our borrowing base and our borrowing base could be reduced. This would reduce our funds available to borrow.

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Bankruptcies of purchasers of our crude oil and natural gas could lead to the delay or failure of us to receive the revenues from those sales.

Proposed federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

The U.S. Congress is currently considering legislation that would amend the Safe Drinking Water Act (“SWDA”) to eliminate an existing exemption from federal regulation of hydraulic fracturing activities and require the disclosure of chemical additives used by the crude oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing is a common process in our industry of creating artificial cracks, or fractures, in deep underground rock formations through the pressurized injection of water, sand and other additives to enable fluids (including oil and gas) to move more easily through the rock to a production well. This process is often necessary to produce commercial quantities of oil and gas from many reservoirs, especially shale rock formations. We routinely utilize hydraulic fracturing techniques in many of our reservoirs. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. If adopted, the proposed amendment to the SWDA could result in additional regulations and permitting requirements at the federal level. In addition, various states and localities are also studying or considering various additional regulatory measures related to hydraulic fracturing. Additional regulations and permitting requirements could lead to significant operational delays and increased operating costs, and make it more difficult to perform hydraulic fracturing.

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, 2011, 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 the 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:

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the assumed accuracy of field measurements and other reservoir data;

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assumptions regarding expected reservoir performance relative to historical analog reservoir performance;

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the assumed effects of regulations by governmental agencies;

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assumptions concerning the availability of capital and its costs;

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assumptions concerning future oil and gas prices; and

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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:

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the quantities of oil and gas that are ultimately recovered;

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the timing of the recovery of oil and gas reserves;

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the production and operating costs incurred; and

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the amount and timing of future development expenditures.

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, the majority 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 86% of Resolute’s 2011 oil and gas revenues and total proved reserves at December 31, 2011, 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 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.”

Within the United States, Resolute operates producing properties that are located in a limited number of geographic areas, making it vulnerable to risks associated with lack of geographic diversification.

Currently, approximately 86% of Resolute’s 2011 oil and gas revenues and total proved reserves at December 31, 2011, are 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 14% of its total proved reserves are attributable to the Wyoming, North Dakota and Texas properties. 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:

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

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unexpected operational events and/or conditions;

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reductions in oil or gas prices or increases in the differential between index oil or gas prices and prices received by Resolute;

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increases in severance taxes;

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limitations on Resolute’s ability to sell its crude oil or gas production;

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adverse weather conditions and natural disasters;

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facility or equipment malfunctions, and equipment failures or accidents;

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pipe or cement failures and casing collapses;

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compliance with environmental and other governmental requirements;

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

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lost or damaged oilfield development and service tools;

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

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fires, blowouts, surface craterings and explosions;

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shortages or delivery delays of supplies, equipment and services;

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title problems;

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objections from surface owners and nearby surface owners in the areas where Resolute operates; and

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uncontrollable flows of oil, gas or well fluids.

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 and also may not maintain insurance on all of its equipment. 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. 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:

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increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment;

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unexpected drilling conditions;

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title problems;

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pressure or irregularities in formations;

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equipment failures or accidents;

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adverse weather conditions; and

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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 may achieve through the development of its proved developed non-producing and proved undeveloped reserves and exploration of its non-proved leaseholds.

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.

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:

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

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

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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:

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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;

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an inability to integrate successfully the properties and businesses Resolute acquires;

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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;

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a significant increase in its interest expense or financial leverage if Resolute incurs debt to finance acquisitions or operations of the acquired properties;

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the assumption of unknown liabilities, losses or costs for which Resolute is not indemnified or for which Resolute’s indemnity is inadequate;

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

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an inability to hire, train or retain qualified personnel to manage and operate Resolute’s growing business and assets;

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unforeseen difficulties encountered in operating in new geographic areas; and

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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.

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:

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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;

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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;

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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

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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 in general.

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:

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incur indebtedness;

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grant liens;

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make acquisitions and investments;

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lease equipment;

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redeem or prepay other debt;

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pay dividends to shareholders or repurchase shares;

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enter into transactions with affiliates; and

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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 $330 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 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 or issue debt securities which would likely include additional operating and financial covenants.

Shortages of qualified personnel or field supplies, 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 supplies, equipment and services, 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, supplies 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 consolidated statements of operations each quarter, which has resulted in, and will in the future likely result in, significant unrealized net gains or losses. 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.

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 current credit market, 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.

New derivatives legislation and regulation could adversely affect our ability to hedge natural gas and crude oil prices which may increase our costs and adversely affect our profitability.

In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”). Dodd-Frank imposes restrictions on the use and trading of certain derivatives, including our oil and gas derivative instruments. The nature and scope of those restrictions will be determined in significant part through implementing regulations to be adopted by the SEC, the Commodities Futures Trading Commission and other regulators. We are currently assessing the potential impact of the Dodd-Frank derivatives provisions on our operations and this assessment will be ongoing as the regulatory process contemplated by Dodd-Frank is defined and implemented. The effect of such future regulations on our business is uncertain.

In particular, note the following:

•

Depending on the rules and definitions adopted by regulators, we could be required to post significant amounts of cash collateral with our dealer counterparties for our derivative transactions, which would likely make it impracticable to implement our current hedging strategy.

•

If our ability to enter into derivative transactions is decreased as a result of Dodd-Frank, we would be exposed to additional risks related to commodity price volatility. Commodity price decreases would then have an immediate significant adverse effect on our profitability and revenues. Reduced derivative transactions may also impair our ability to have certainty with respect to a portion of our cash flow, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves.

•

We expect that the cost to enter into derivative transactions will increase as a result of a reduction in the number of counterparties in the market and the pass-through of increased counterparty costs, thereby increasing the costs of derivative instruments. Our derivatives counterparties may be subject to significant new capital, margin and business conduct requirements imposed as a result of the new legislation.

•

Dodd-Frank contemplates that most swaps will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While we may ultimately be eligible for such exceptions, the scope of these exceptions currently is uncertain, pending further definition through rule making proceedings.

•

The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms.

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 exploration, 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 $26.3 million. $23.2 million has already been incurred and paid for as of December 31, 2011. This estimate does not include any costs for any possible subsurface clean-up or remediation of the site, which may be significant.

The Aneth Gas Processing Plant site was previously evaluated by the U.S. 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 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 Nation Environmental Protection Agency now has primary jurisdiction over the Aneth Gas Processing Plant site, however, and Resolute cannot predict whether it will require further 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 Chevron’s 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 certain 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, including and increased ability to attract, compensate and retain quality employees. 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.

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 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

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.

Possible regulation related to global warming and climate change could have an adverse effect on Resolute’s operations and demand for oil and gas.

Certain studies have suggested that emissions of Greenhouse Gases (“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) agreed to reduce their emissions of GHG to below 1990 levels by 2012. A successor treaty to the Kyoto Protocol has not been developed to date. 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 entered into employment agreements with certain of these employees, but 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.

Work stoppages, protests 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, 2011, 61 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 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 2011 or 2010.

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.

Compliance with the Sarbanes-Oxley Act of 2002 and other obligations of being a public company requires 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.

Stock prices of equity securities can be volatile, and there is no assurance that you will be able to resell the common stock you purchase at a price in excess of your purchase price.

Over the past several years, the stock prices of companies on the U.S. securities markets have been volatile, increasing or decreasing not in response to the Company financial or operating results, but the general economic trends or events. In addition, stock prices of companies in the oil and natural gas industry in which Resolute operates are significantly affected by commodity prices for oil and natural gas. In particular, the Company’s stock price was very volatile during 2011, trading between $18.55 and $10.44. All of these factors are beyond the Company’s control, and could have drastic impacts occurring within short periods of time. These factors could cause a decrease in the stock price following your purchase, and you not be able to sell your common stock for price exceeding your purchase price

Offers or availability for resale of a substantial number of shares of our common stock or Exercise of outstanding Warrants would result in dilution to our stockholders and might have an adverse effect on the market price of our common stock.

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 Rule 144 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, 2011, the Company had outstanding warrants to purchase 42.7 million shares of common stock at an exercise price of $13.00 per share, representing approximately 70% 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. In addition, the resale of shares under our existing resale registration statement or pursuant to the exercise of registration rights covering an additional 4.3 million shares of our common stock could further adversely affect the market price of our common stock or impact our ability to raise additional equity capital.

At February 29, 2012, an aggregate of 21.9 million Public Warrants and 20.8 million Sponsor’s Warrants and Founder’s Warrants are exercisable at an exercise price of $13.00 per share. These warrants would likely only be exercised if the market price of our common stock exceeds the $13.00 per share exercise price. Exercise of these warrants at such time will result in dilution to our stockholders, which could cause the market price of our common stock to decline. Outstanding Warrants at such date represented approximately 41% of our total capitalization, assuming full exercise of the warrants. The Company is unable to predict the amount or timing of future exercises.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 3.

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.

MINE SAFETY DISCLOSURES

Not applicable.

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, 2011 and 2010. The closing price of the common stock on February 29, 2012 was $11.16.

		September 30,		September 30,		September 30,		September 30,
	2011				2010
Period	High		Low		High		Low

1st Quarter	$	18.43	$	14.56	$	12.66	$	10.46
2nd Quarter	$	18.55	$	15.15	$	13.87	$	11.59
3rd Quarter	$	17.50	$	11.19	$	12.82	$	10.48
4th Quarter	$	14.24	$	10.44	$	14.83	$	10.91

As of February 29, 2012, there were approximately 215 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, 2011 and 2010. The closing price of the warrants on February 29, 2011 was $1.53.

		September 30,		September 30,		September 30,		September 30,
	2011				2010
Period	High		Low		High		Low

1st Quarter	$	5.50	$	3.17	$	2.61	$	1.77
2nd Quarter	$	5.53	$	2.97	$	3.20	$	1.96
3rd Quarter	$	4.62	$	1.39	$	2.59	$	1.38
4th Quarter	$	3.04	$	1.25	$	3.33	$	1.70

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 (“Incentive Plan”), the Company retains shares of common stock at the election of the recipients of such awards in satisfaction of withholding tax obligations. These shares are retired by the Company.

		September 30,		September 30,		September 30,		September 30,
2011	Total Number of Shares Purchased⁽¹⁾		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publically Announced Plan		Maximum Number of Shares That May Yet Be Purchased Under The Plan⁽²⁾

June		852	$	16.82		—		—
July		932	$	16.52		—		—
August		148	$	16.38		—		—
September		966	$	13.17		—		—
October		311	$	10.78		—		—
November		379	$	13.00		—		—
December		97,990	$	10.80		—		—

1)	All shares purchased in 2011 were to offset tax withholding obligations that occur upon the vesting and delivery of outstanding common shares under the terms of the Incentive Plan.

2)	As of December 31, 2011, the maximum number of shares that may yet be purchased would not exceed the employees’ portion of taxes withheld on unvested shares (1,553,230 common shares) and the shares yet to be granted under the Incentive Plan (6,820,753 common shares).

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.

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, 2011, 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

LOGO

ITEM 6.

SELECTED FINANCIAL DATA

The following table presents Resolute’s selected historical financial data for the years ended December 31, 2011, 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.

		September 30,			September 30,			September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009			2008			2007
	(in thousands, except per share data)
Statement of Operation Data:
Revenue	$	226,908		$	173,395		$	42,416		$	—		$	—
Operating expenses		169,473			142,225			57,361			1,560			1,036
Income (loss) from operations		57,435			31,170			(14,945	)		(1,560	)		(1,036	)
Other income (expense)		(9,080	)		(22,597	)		(50,185	)		7,601			5,154
Income (loss) before income taxes		48,355			8,573			(65,130	)		6,041			4,118
Income tax benefit (expense)		(17,870	)		(2,388	)		19,887			(2,054	)		(1,401	)
Net income (loss)		30,485			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	$	0.53		$	0.12		$	(0.93	)	$	0.06		$	0.09
Common stock, diluted	$	0.47		$	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		57,612			49,900			46,394			45,105			18,587
Common stock, diluted		65,029			50,475			46,394			45,105			18,587

Selected Cash Flow Data:
Net cash provided by (used in) operating activities	$	101,087		$	58,495		$	(12,164	)	$	3,031		$	5,164
Net cash provided by (used in) investing activities		(217,006	)		(69,123	)		209,987			(2,264	)		(541,302	)
Net cash provided by (used in) financing activities		115,210			12,017			(198,197	)		—			536,190

	As of December 31,
	2011			2010			2009			2008			2007
	(in thousands)
Balance Sheet Data:
Total assets	$	947,560		$	760,523		$	693,440		$	544,797		$	541,842
Long term debt		170,000			127,900			109,575			—			—
Total liabilities		431,735			356,657			299,903			19,291			20,322
Stockholders’ equity		515,825			403,866			393,537			362,199			359,702

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 related notes 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, 2011 compared to the results for the twelve months ended December 31, 2010 and 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.

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, 2011, Resolute’s estimated net proved reserves were approximately 64.8 MMBoe, of which approximately 44% were proved developed producing reserves and approximately 82% were oil. The standardized measure of Resolute’s estimated net proved reserves as of December 31, 2011, was $816 million. See Note 13 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 operation.

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 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.

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 contracts to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and currently has such contracts in place through 2014. These instruments limit its exposure to declines in prices, but also limit its 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 future fair value of the derivative contracts. Recognized gains or losses only arise from payments made or received on monthly settlements of derivative contracts or if a derivative contract is terminated prior to its expiration. Resolute typically enters into derivative contracts that cover a significant portion of its estimated future oil and gas production. Resolute currently has such derivative contracts in place through 2014.

Reserve 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. Subsequent to the Resolute Transaction, Resolute acquired its North Dakota Properties in 2010 and 2011 and its Texas Properties in 2011 and plans to 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, 2011, Resolute had estimated net proved reserves of approximately 36.5 MMBoe that were classified as proved developed non-producing and proved undeveloped. An estimated 32.0 MMBoe, or 87%, 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 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 generally 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. Higher oil prices can lead to higher demand for drilling rigs, workover rigs, operating personnel and field supplies and services, which in turn can increase the costs of those goods and services. Resolute projects 2012 cash lease operating expenses of $60.5 million to $65.0 million.

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.

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 derivative premiums, non-cash equity-based compensation expense, early settlement of derivative instruments and noncontrolling interest amounts. Adjusted EBITDA is a financial measure that Resolute reports to its lenders and uses as a gauge for compliance with some of the financial covenants under its revolving credit facility.

Adjusted EBITDA is also 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 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 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.

2012 Guidance

The following table summarizes Resolute’s current financial and operational estimates for the full year 2012.


		Range
Projected 2012 total production (MBoe)		3,250 – 3,450
Boe per day		8,880 – 9,426

Projected 2011 costs
Lease operating expense ($ million)⁽¹⁾		$60 – $65
General & administrative ($ million)⁽¹⁾		$14 – $17
Production and related taxes (% of production revenue)		13.5% – 14.5%
Depletion, depreciation and amortization ($ per Boe)		$20.00 – $21.00
Projected 2012 capital expenditures ($ million)		$180 – $190

Core producing assets		$62 – $66
North Dakota Properties		$54 – $56
Texas Properties		$59 – $62
Other		$5 – $6

(1)	Excludes non-cash items.

As of December 31, 2011, Resolute has oil swaps in place for 2012 covering the aggregate average daily oil volumes of 2,750 barrels of oil at a NYMEX weighted average price of $69.40 per Bbl, oil collars covering daily oil volumes of 1,375 barrels of oil with a weighted average floor of $71.64 per Bbl and a weighted average ceiling of $102.45 per Bbl, gas swaps covering daily gas volumes of 2,100 MMBtu at a NYMEX price of $7.42 per MMBtu and gas basis derivatives covering the aggregate average daily volumes of 2,800 MMBtu at a NYMEX weighted average price of $1.56 per MMBtu.

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, 2011, in comparison to the results for the twelve months ended December 31, 2010 and 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.

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.

		September 30,			September 30,			September 30,			September 30,			September 30,
													Predecessor
	Resolute									Resolute			Resolute
	Twelve Months Ended December 31,			Twelve Months Ended December 31,			Combined Twelve Months Ended December 31,			98 Day Period Ended December 31,			267 Day Period Ended September 24,
	2011			2010			2009			2009			2009
	(in thousands, except where indicated)

Net Sales:
Total sales (MBoe)		2,924			2,730			2,714			703			2,011
Average daily sales (Boe/d)		8,012			7,478			7,434			7,172			7,530
Revenue:
Revenue from oil and gas activities	$	226,908		$	173,395		$	127,761		$	42,416		$	85,345
Operating Expenses:
Lease operating	$	59,516		$	51,618		$	49,935		$	16,185		$	33,750
Production and ad valorem taxes		31,379			24,151			18,828			5,807			13,021
General and administrative		20,914			19,440			31,905			23,828			8,077
General and administrative — (excluding non-cash compensation expense)		13,489			13,499			28,168			22,909			5,259
Depletion, depreciation, amortization and accretion		57,664			47,016			33,466			11,541			21,925
Other Income (Expense):
Interest expense	$	(3,844	)	$	(4,855	)	$	(19,954	)	$	(1,538	)	$	(18,416	)
Realized and unrealized loss on derivative instruments		(5,321	)		(17,842	)		(73,033	)		(49,514	)		(23,519	)
Income tax benefit (expense)		(17,870	)		(2,388	)		24,906			19,887			5,019
Average Sales Prices ($/Boe):
Average sales price (excluding derivative settlements)	$	77.60		$	63.52		$	47.08		$	60.35		$	42.45
Operating Expenses ($/Boe):
Lease operating	$	20.35		$	18.91		$	18.40		$	23.03		$	16.79
Production and ad valorem taxes		10.73			8.85			6.94			8.26			6.48
General and administrative		7.15			7.12			11.76			33.90			4.02
General and administrative — (excluding non-cash compensation expense)		4.61			4.95			10.38			32.59			2.62
Depletion, depreciation, amortization and accretion		19.72			17.22			12.33			16.42			10.90

Year Ended December 31, 2011, Compared to the Year Ended December 31, 2010

Revenue. Revenue from oil and gas activities increased to $226.9 million during 2011, from $173.4 million during 2010. Of the $53.5 million increase in revenue, approximately $41.1 million was attributable to higher commodity prices, while $12.4 million was attributable to increased production. Average sales price, excluding derivative settlements, increased from $63.52 per Boe in 2010 to $77.60 per Boe in 2011, primarily as a function of increased commodity pricing. Sales volumes increased 7% during 2011 as compared to 2010, from 2,730 MBoe to 2,924 MBoe. The 2010 well recompletion program and increased response from the Company’s CO₂ flood projects in the Aneth Field Properties were the primary drivers of the production increase. The additional increase was due to the production related to the North Dakota Properties, although the Company did not begin drilling activities in North Dakota until the end of the third quarter of 2010, and the production attributable to the Texas Properties beginning in August 2011.

Operating Expenses. Lease operating expenses increased to $59.5 million during 2011, from $51.6 million during 2010, a portion of which was due to expanded operations in new areas. The $7.9 million, or 15%, increase was primarily attributable to $4.9 million in increased equipment, maintenance and supplies, $1.9 million in increased utilities and fuel due to increased compression capability and additional fuel purchases in the Aneth Field Properties, and $0.8 million in increased labor costs.

Production and ad valorem taxes increased by 30% to $31.4 million during 2011, versus $24.2 million during 2010, mainly due to the increase in commodity pricing and production over 2010. Production and ad valorem taxes were 14% of total revenue in 2011 and 2010.

Depletion, depreciation, amortization and accretion expenses increased to $57.7 million during 2011, as compared to $47.0 million during 2010. The $10.6 million, or 23%, increase is principally due a higher depletable base and increased production in 2011.

Pursuant to full cost accounting rules, Resolute performs a ceiling test each quarter on its proved oil and gas assets. No provision for impairment was recorded in 2011 or 2010.

General and administrative expenses increased to $20.9 million during 2011, as compared to $19.4 million during 2010. The $1.5 million, or 8%, increase resulted from a $0.5 million increase in salaries and wages due to additional hiring to meet the demands of increased operations and $1.5 million of increased stock based compensation expense related to additional restricted stock grants awarded to employees in 2011. These increases were offset by decreased professional service fees, a significant portion of which were charges associated with the implementation of the provisions of the Sarbanes-Oxley act in 2010.

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 2011, the realized and unrealized losses on our oil and gas derivatives totaled $5.3 million. This amount included approximately $20.8 million of realized losses, including $5.0 million of partial terminations of certain derivative contracts, offset by $15.5 million of increases in the unrealized fair value of oil and gas derivatives. During 2010, the realized and unrealized losses on oil and gas derivatives totaled $17.8 million and included approximately $9.6 million of unrealized losses in the fair value of oil and gas derivatives and $8.2 million of realized losses from monthly settlements.

Interest expense was $3.8 million during 2011, as compared to $4.9 million during 2010. The $1.1 million, or 21%, decrease is attributable to lower interest rates, a lower average debt balance and higher interest capitalization during 2011.

Income Tax Benefit (Expense). Income tax expense recognized during 2011 was $17.9 million, or 37.0% of income before income taxes, as compared to income tax expense of $2.4 million, or 27.9% of income before income taxes for Resolute in 2010. The change in the effective rate reflects changes in permanent differences and revisions in 2010 to prior year estimates as a result of final income tax return filings. 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 and estimated permanent differences. The Company expects income taxes to be between 36% and 39% of income (loss) before income taxes in future years. Resolute carried a $13.7 million current deferred tax asset at December 31, 2011, 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.

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). 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 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.

Liquidity and Capital Resources

		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Cash provided by (used in) operating activities	$	101,087		$	58,495		$	(12,164	)
Cash provided by (used in) investing activities		(217,006	)		(69,123	)		209,987
Cash provided by (used in) financing activities		115,210			12,017			(198,187	)

Resolute’s primary sources of liquidity are cash generated from operations, amounts available under its revolving Credit Facility (as defined below), proceeds from warrant exercises and proceeds from sale of non-strategic oil and gas properties.

Net cash provided by operating activities during 2011 was $101.1 million, as compared to $58.5 million during 2010 and net cash used in operating activities of $12.2 million in 2009. The increase from 2010 to 2011 was primarily due to higher commodity prices and production volumes and changes in working capital in 2011 and the increase from 2009 to 2010 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 $217.0 million in 2011, compared to $69.1 million in 2010 and $210.0 million of net cash provided in 2009. The primary investing activity in 2011 was cash used for capital expenditures of $218.8 million, consisting of $169.2 million of acquisition, exploration and development expenditures and $49.6 million in purchased of proved oil and gas properties. The 2011 capital expenditures were comprised of $61.0 million in compression and facility related projects, $15.8 million in CO₂ acquisition, $74.5 million in acquisition and leasehold costs and $12.8 million in drilling activities in the Permian Basin of West Texas, $46.0 million in drilling and completion activities in the Bakken trend of North Dakota and $20.7 million in recompletion and drilling activities in the Company’s Wyoming properties. A portion of these capital costs are accrued and not paid at year end. The primary investing activity in 2010 was capital expenditures of $69.1 million. The 2010 capital expenditures were comprised of $30.8 million in leasehold and exploratory costs in North Dakota, $12.9 million in CO₂ acquisition and $21.6 million in other capital expenditures. The cash provided in 2009 was the result of activities related to the Resolute Transaction.

Net cash provided by financing activities was $115.2 million in 2011 compared to $12.0 million in 2010 and net cash used in financing activities of $198.2 million in 2009. The primary financing activities in 2011 were $42.1 million in net borrowings under the Credit Facility and receipt of proceeds of $74.4 million from warrants exercised. Primary financing activities in 2010 were $18.3 million in net borrowings under the Credit Facility and $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. The Company is unable to predict the amount or timing of future warrant exercises.

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. The Company has in place an effective shelf registration pursuant to which an aggregate of $500 million of any such equity or debt securities could be issued. 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 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 initially established at $260.0 million and the maturity date was extended to March 2014.

During April 2011, the Company entered into two additional amendments to the amended and restated Credit Facility agreement. Under the terms of the amendments, the Company is permitted to use proceeds received from the exercise of outstanding warrants to repurchase equity securities, the borrowing base was increased from $260.0 million to $300.0 million and, 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 1.75% to 2.75% 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 0.75% to 1.75%. Each such margin is based on the level of utilization under the borrowing base. As of December 31, 2011 and 2010, the weighted average interest rate on the outstanding balance under the Credit Facility was 2.60% and 3.15%, respectively. The recorded value of the Credit Facility approximates its fair market value.

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. During November 2011, as the result of a redetermination, the borrowing base was increased to $330.0 million. As of December 31, 2011, outstanding borrowings were $170.0 million and unused availability under the borrowing base was $156.9 million. The borrowing base availability had been reduced by $3.1 million in conjunction with letters of credit issued to vendors at December 31, 2011. 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 guaranteed by all of Resolute’s subsidiaries and is collateralized by substantially all of the proved oil and gas assets of Aneth and Resolute Wyoming, Inc., which are wholly-owned subsidiaries of the Company.

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 material terms and covenants of the Credit Facility at December 31, 2011.

Resolute Energy Corporation, the stand-alone parent entity, has insignificant independent assets and no operations. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from its subsidiaries, except those imposed by applicable law.

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 had the following contractual obligations and commitments for the next five years as of December 31, 2011:

		September 30,		September 30,		September 30,		September 30,		September 30,
	Less than 1 year		1-3 Years		3–5 Years		More Than 5 Years		Total (6)
	(in thousands)
Obligations:
Long-term debt ⁽¹⁾	$	—	$	170,000	$	—	$	—	$	170,000
Office and equipment leases		841		848		357		—		2,046
Operating equipment leases ⁽²⁾		2,635		5,270		3,873		1,718		13,496
Vehicle leases		522		587		64		—		1,173
Derivative premiums		1,042		3,840		—		—		4,882
ExxonMobil escrow agreement ⁽³⁾		1,800		3,600		3,600		14,300		23,300
Construction purchase obligations ⁽⁴⁾		196		—		—		—		196
CO₂ purchases ⁽⁵⁾		20,723		44,346		34,491		26,492		126,052

Total	$	27,759	$	228,491	$	42,385	$	42,510	$	341,145

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, 2011 related to construction projects in the Aneth Field Properties.

Represents the minimum take-or-pay quantities associated with Resolute’s existing CO₂purchase 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, 2011.

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.

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.

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. Resolute enters into derivative contracts to manage its exposure to oil and gas price volatility and may take the form of futures contracts, swaps or options. Derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. Resolute’s management has determined that the benefit of cash flow hedge accounting, which may allow for its derivative instruments to be reflected as cash flow hedges in other comprehensive income, is not commensurate with the administrative burden required to support that treatment. As a result, Resolute marks its derivative instruments to fair value on the consolidated balance sheets and recognizes the changes in fair market value in earnings. Realized gains and losses on derivative instruments are recognized in the period in which the related contract is settled. Both the realized and unrealized gains and losses on derivative instruments are reflected in other income (expense) in the consolidated statements of operations. 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 statement of cash flows.

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, 2011, 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.

Share-Based Compensation. Share-based compensation is measured based on 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.

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, 2011, Resolute had entered into certain derivative instruments that are summarized in the tables below.

		September 30,		September 30,		September 30,		September 30,		September 30,
	Oil Swap		Oil (NYMEX WTI)		Oil Collar		(NYMEXWTI)
Year	Volumes Bbl per Day		Weighted Average Hedge Price per Bbl		Volumes Bbl per Day		Floor Price		Ceiling Price
2012		2,750	$	69.40		1,375	$	71.64	$	102.45
2013		2,000	$	60.47		775	$	80.00	$	105.00
2014		—		—		1,500	$	65.00	$	110.00

		September 30,		September 30,
	Gas Swap		Gas (NYMEX HH)
	Volumes		Weighted Average
Year	MMBtu per Day		Hedge Price per MMBtu
2012		2,100	$	7.42
2013		1,900	$	7.40

	September 30,		September 30,		September 30,
	Basis Hedges
Year	Index	MMBtu per Day		Hedged Price Differential per MMBtu
2012 – 2013	Rocky Mountain NWPL		1,800	$	2.100
2012	Rocky Mountain CIG		1,000	$	0.575
2013	Rocky Mountain CIG		500	$	0.590
2014	Rocky Mountain CIG		1,000	$	0.590

The Company will incur premium payments associated with the oil collars of $1.0 million, $1.2 million and $2.7 million in 2012, 2013 and 2014, respectively.

Resolute’s management has determined that the benefit of cash flow hedge accounting, which may allow for its derivative instruments to be reflected as cash flow hedges in other comprehensive income, is not commensurate with the administrative burden required to support that treatment.

Derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. Resolute marks its derivative instruments to fair value on the consolidated balance sheets and recognizes the changes in fair market value in earnings. At December 31, 2011, the fair value of our commodity derivatives was a net liability of $59.2 million.

Interest Rate Risk

At December 31, 2011, Resolute had $170.0 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 have or 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 report 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, 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, 2011. 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, 2011, 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, 2011, and has concluded that the Company maintained effective internal control over financial reporting as of December 31, 2011. 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 2012 annual stockholders’ meeting and is incorporated by reference in this report.

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

See “Index to Consolidated Financial Statements” on page F-1.


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, Ratherford 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).

10.2.1#		Amendment No. 1 to 2009 Performance Incentive Plan (incorporated by reference to Exhibit A to the Proxy Statement on Schedule 14A as filed with the SEC on April 25, 2011).

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).


Exhibit Number		Description of Exhibits
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 CO₂ 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).

10.7.1		Amendment No. 4 to Product Sale and Purchase contract dated July 1, 2007 by and between Resolute Natural Resources Company, LLC and Kinder Morgan CO₂ Company, LP (incorporated by reference to Exhibit 10.1 to the 10-Q filed on November 7, 2011).

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 31, 2011 between Western Refining Southwest, Inc., as purchaser, and Resolute Natural Resources Company, LLC as seller. (incorporated by reference to the current report on Form 8-K filed on September 7, 2011).

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).

10.19#		Employment Agreement, effective as of April 1, 2011, by and between the Company and Nicholas J. Sutton (incorporated by reference as Exhibit 10.1 to the current report on Form 8-K filed on April 26, 2011).

10.20#		Employment Agreement, effective as of April 1, 2011, by and between the Company and James M. Piccone (incorporated by reference as Exhibit 10.2 to the current report on Form 8-K filed on April 26, 2011).

10.21#		Employment Agreement, effective as of April 1, 2011, by and between the Company and Theodore Gazulis (incorporated by reference as Exhibit 10.3 to the current report on Form 8-K filed on April 26, 2011).

10.22#		Employment Agreement, effective as of April 1, 2011, by and between the Company and Richard F. Betz (incorporated by reference as Exhibit 10.4 to the current report on Form 8-K filed on April 26, 2011).

10.23#		Employment Agreement, effective as of April 1, 2011, by and between the Company and Bobby D. Brady, Jr. (incorporated by reference as Exhibit 10.5 to the current report on Form 8-K filed on April 26, 2011).

12.1		Statement of Ratio of Earnings to Fixed Charges (incorporated by reference as Exhibit 12.1 to the Annual Report on Form 10-K of Resolute Energy Corporation filed on March 15, 2011).


Exhibit Number		Description of Exhibits
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.

99.1		Report of Netherland, Sewell & Associates, Inc. regarding the registrant’s reserves as of December 31, 2011.

101		The following materials from the Resolute Energy Corporation Annual Report on Form 10-K for the year ended December 31, 2011, formatted in XBRL (Extensible Business Reporting Language) include (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Stockholders’ Equity, (iv) the Consolidated Statements of Cash Flows, and (v) Notes to the Consolidated Financial Statements, tagged as blocks of text. The information in Exhibit 101 is “furnished” and not “filed”, as provided in Rule 402 of Regulation S-T.

†

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.

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.

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 8, 2012

/s/ James M. Piccone James M. Piccone	President and Director	March 8, 2012

/s/ Theodore Gazulis Theodore Gazulis	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	March 8, 2012

/s/ James A. Tuell James A. Tuell	Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 8, 2012

/s/ Richard L. Covington Richard L. Covington	Director	March 8, 2012

/s/ William H. Cunningham William H. Cunningham	Director	March 8, 2012

/s/ James E. Duffy James E. Duffy	Director	March 8, 2012

/s/ Thomas O. Hicks, Jr. Thomas O. Hicks, Jr.	Director	March 8, 2012

/s/ William J. Quinn William J. Quinn	Director	March 8, 2012

/s/ Robert M. Swartz Robert M. Swartz	Director	March 8, 2012

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


RESOLUTE ENERGY CORPORATION

Reports of Independent Registered Public Accounting Firm			F-2

Resolute Energy Corporation Consolidated Balance Sheets as of December 31, 2011 and 2010			F-4

Resolute Energy Corporation Consolidated Statements of Operations, for the years ended December 31, 2011, 2010 and 2009			F-5

Resolute Energy Corporation Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2011, 2010 and 2009			F-6

Resolute Energy Corporation Consolidated Statements of Cash Flows, for the years ended December 31, 2011, 2010 and 2009			F-7

Notes to Resolute Energy Corporation Consolidated Financial Statements			F-8

PREDECESSOR RESOLUTE

Report of Independent Registered Public Accounting Firm			F-26

Predecessor Resolute Combined Statement of Operations, for the 267 day period ended September 24, 2009			F-27

Predecessor Resolute Combined Statement of Shareholder’s/Member’s Equity for the 267 day period ended September 24, 2009			F-28

Predecessor Resolute Combined Statement of Cash Flows, for the 267 day period ended September 24, 2009			F-29

Notes to Predecessor Resolute Combined Financial Statements			F-30

F-1

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, 2011 and 2010, 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, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial 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, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, 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, 2011, 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 12, 2012 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Denver, Colorado

March 12, 2012

F-2

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, 2011, 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, 2011, 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, 2011 and 2010, 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, 2011, and our report dated March 12, 2012 expressed an unqualified opinion on these consolidated financial statements.

/s/ KPMG LLP

Denver, Colorado

March 12, 2012

F-3

RESOLUTE ENERGY CORPORATION

Consolidated Balance Sheets

(in thousands, except share amounts)

		September 30,			September 30,
	December 31,
	2011			2010
Assets
Current assets:
Cash and cash equivalents	$	1,135		$	1,844
Accounts receivable		61,930			45,154
Deferred income taxes		13,694			11,954
Derivative instruments		3,170			4,745
Prepaid expenses and other current assets		1,829			1,596

Total current assets		81,758			65,293

Property and equipment, at cost:
Oil and gas properties, full cost method of accounting
Unproved		64,357			37,235
Proved		885,503			689,021
Other property and equipment		4,070			2,869
Accumulated depletion, depreciation and amortization		(114,214	)		(57,564	)

Net property and equipment		839,716			671,561

Other assets:
Restricted cash		16,601			14,781
Derivative instruments		2,291			3,098
Deferred financing costs		2,433			3,281
Other assets		4,761			2,509

Total assets	$	947,560		$	760,523


Liabilities and Stockholders’ Equity

Current liabilities:
Accounts payable and accrued expenses	$	87,585		$	58,144
Asset retirement obligations		3,953			3,072
Derivative instruments		33,910			31,193

Total current liabilities		125,448			92,409

Long term liabilities:
Long term debt		170,000			127,900
Asset retirement obligations		12,600			11,693
Derivative instruments		30,701			51,279
Deferred income taxes		92,986			73,376

Total liabilities		431,735			356,657


Commitments and contingencies

Stockholders’ equity:
Preferred stock, $0.0001 par value; 1,000,000 shares authorized; none issued or outstanding		—			—
Common stock, $0.0001 par value; 225,000,000 shares authorized; issued and outstanding 60,947,329 and 54,717,571 shares at December 31, 2011 and December 31, 2010, respectively		6			5
Additional paid-in capital		518,267			436,794
Accumulated deficit		(2,448	)		(32,933	)

Total stockholders’ equity		515,825			403,866

Total liabilities and stockholders’ equity	$	947,560		$	760,523

See notes to consolidated financial statements

F-4

RESOLUTE ENERGY CORPORATION

Consolidated Statements of Operations

(in thousands, except per share data)

		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009
Revenue:
Oil	$	203,876		$	152,953		$	37,528
Gas		19,376			17,204			4,149
Other		3,656			3,238			739

Total revenue		226,908			173,395			42,416

Operating expenses:
Lease operating		59,516			51,618			16,185
Production and ad valorem taxes		31,379			24,151			5,807
Depletion, depreciation, amortization, and asset retirement obligation accretion		57,664			47,016			11,541
General and administrative		20,914			19,440			20,328
Write-off of deferred acquisition costs		—			—			3,500

Total operating expenses		169,473			142,225			57,361

Income (loss) from operations		57,435			31,170			(14,945	)

Other income (expense):
Interest income		—			—			776
Interest expense, net		(3,844	)		(4,855	)		(1,538	)
Realized and unrealized losses on derivative instruments		(5,321	)		(17,842	)		(49,514	)
Other income		85			100			91

Total other expense		(9,080	)		(22,597	)		(50,185	)

Income (loss) before income taxes		48,355			8,573			(65,130	)
Income tax benefit (expense)		(17,870	)		(2,388	)		19,887

Net income (loss)	$	30,485		$	6,185		$	(45,243	)


Net income (loss) per common share:
Basic	$	0.53		$	0.12		$	(0.93	)
Diluted	$	0.47		$	0.12		$	(0.93	)
Weighted average common shares outstanding:
Basic		57,612			49,900			46,394
Diluted		65,029			50,475			46,394

See notes to consolidated financial statements

F-5

RESOLUTE ENERGY CORPORATION

Consolidated Statements of Stockholders’ Equity

(in thousands)

		September 30,			September 30,			September 30,			September 30,			September 30,
	Common Stock						Additional Paid-in			Accumulated (Deficit)/ Retained			Stockholders’
	Shares			Amount			Capital			Earnings			Equity
Balance as of January 1, 2009		69,000		$	5		$	357,999		$	4,195		$	362,199
Reclassification of common stock subject to possible redemption		—			2			160,796			2,510			163,308
Common stock redeemed		(11,592	)		(1	)		(112,557	)		(580	)		(113,138	)
Purchase of common stock		(7,503	)		(1	)		(73,345	)		—			(73,346	)
Cancellation of common stock previously issued to founding stockholder		(7,335	)		(1	)		—			—			(1	)
Redemption of 27,600,000 warrants		—			—			(15,180	)		—			(15,180	)
Forgiveness of deferred underwriters’ commission		—			—			11,738			—			11,738
Issuance of common stock for acquisition		9,200			1			88,779			—			88,780
Issuance of earnout shares for acquisition		1,385			—			10,024			—			10,024
Issuance of warrants for acquisition		—			—			3,202			—			3,202
Equity based compensation		—			—			1,194			—			1,194
Net loss		—			—			—			(45,243	)		(45,243	)

Balance as of December 31, 2009		53,155			5			432,650			(39,118	)		393,537
Grant of stock and restricted stock		1,747			—			6,413			—			6,413
Redemption of restricted stock for employee income taxes		(184	)		—			(2,270	)		—			(2,270	)
Exercise of warrants		—			—			1			—			1
Net income		—			—			—			6,185			6,185

Balance as of December 31, 2010		54,718			5			436,794			(32,933	)		403,866
Issuance of stock, restricted stock and equity based compensation		681			—			8,169			—			8,169
Redemption of restricted stock for employee income tax and restricted stock forfeitures		(176	)		—			(1,112	)		—			(1,112	)
Exercise of warrants		5,724			1			74,416			—			74,417
Net income		—			—			—			30,485			30,485

Balance as of December 31, 2011		60,947		$	6		$	518,267		$	(2,448	)	$	515,825

See notes to consolidated financial statements

F-6

RESOLUTE ENERGY CORPORATION

Consolidated Statements of Cash Flows

(in thousands)

		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009
Operating activities:
Net income (loss)	$	30,485		$	6,185		$	(45,243	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation, amortization and asset retirement obligation accretion		57,664			47,016			11,541
Amortization of deferred financing costs		1,044			757			—
Equity-based compensation, net		7,927			6,247			1,084
Write-off of deferred acquisition costs		—			—			3,500
Unrealized (gain) loss on derivative instruments		(15,478	)		9,566			46,321
Deferred income taxes		17,870			6,005			(19,813	)
Change in operating assets and liabilities, net of acquired amounts:
Accounts receivable		(16,535	)		(17,941	)		(3,786	)
Other current assets		(233	)		334			(883	)
Accounts payable and accrued expenses		18,343			326			(4,866	)
Accounts payable — related party		—			—			(19	)

Net cash provided by (used in) operating activities		101,087			58,495			(12,164	)

Investing activities:
Acquisition of subsidiary, net of cash acquired		—			—			(323,822	)
Decrease (increase) in cash and cash equivalents in trust		—			—			250,024
Purchase of marketable securities held in trust		—			—			(249,654	)
Sales / maturities of marketable securities held in trust		—			—			539,771
Oil and gas acquisition, exploration and development expenditures		(169,216	)		(65,254	)		(6,640	)
Purchase of proved oil and gas properties		(49,604	)		—			—
Proceeds from sale of oil and gas properties and other		4,744			260			59
Purchase of other property and equipment		(1,201	)		(459	)		(224	)
Increase in restricted cash		(1,820	)		(1,817	)		—
Settlement of notes receivable — related parties		—			—			52
Other noncurrent assets		91			(1,853	)		421

Net cash provided by (used in) investing activities		(217,006	)		(69,123	)		209,987

Financing activities:
Payments due to Holdings		—			—			(1,248	)
Redemption of common stock		—			—			(113,139	)
Forward purchase of common stock		—			—			(73,346	)
Redemption of warrants		—			—			(15,180	)
Payment of deferred underwriters’ fees		—			—			(5,650	)
Proceeds from bank borrowings		353,200			215,275			53,376
Repayments of bank borrowings		(311,100	)		(196,950	)		(43,000	)
Payment of financing costs		(195	)		(4,039	)		—
Redemption of restricted stock for employee income taxes		(1,112	)		(2,270	)		—
Proceeds from exercise of warrants		74,417			1			—

Net cash provided by (used in) financing activities		115,210			12,017			(198,187	)

Net increase (decrease) in cash and cash equivalents		(709	)		1,389			(364	)
Cash and cash equivalents at beginning of period		1,844			455			819

Cash and cash equivalents at end of period	$	1,135		$	1,844		$	455

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest, net of amounts capitalized	$	3,091		$	4,135		$	3,584

Income taxes	$	—		$	32		$	1,004

Supplemental schedule of non-cash investing and financing activities:
Capital expenditures financed through current liabilities	$	26,608		$	15,855		$	2,755

Increase to asset retirement obligations	$	1,862		$	6,215		$	—

Asset retirement obligations sold	$	1,307		$	—		$	—

Issuance of common stock for acquisition	$	—		$	—		$	88,780

Issuance of warrants for acquisition	$	—		$	—		$	3,202

Issuance of earnout shares for acquisition	$	—		$	—		$	10,024

Forgiveness of deferred underwriters’ commission	$	—		$	—		$	11,738

See notes to consolidated financial statements

F-7

RESOLUTE ENERGY CORPORATION

Notes To Consolidated Financial Statements

Note 1 — Organization and Nature of 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. Resolute is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, gas and natural gas liquids (“NGL”). The Company conducts all of its activities in the United States of America.

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, and HACI received proceeds of approximately $529.1 million. Upon the consummation of the Resolute Transaction, described below, $11.7 million of deferred underwriters’ commission were forgiven and were recognized as additional paid in capital. HACI sold to the public 55,200,000 units (one share and one warrant) at a price of $10.00 per unit, including 7,200,000 units issued pursuant to the exercise of the underwriter’s over-allotment option. Simultaneous with the consummation of the Offering, HACI consummated the private sale of 7,000,000 warrants (the “Sponsor Warrants”) to HH-HACI, L.P., a Delaware limited partnership (the “Sponsor”), at a price of $1.00 per Sponsor Warrant, generating gross proceeds, before expenses, of $7.0 million (the “Private Placement”). Net proceeds received from the consummation of both the Offering and Private Placement of Sponsor Warrants totaled approximately $536.1 million, net of underwriter’s commissions and offering costs. HACI had neither engaged in any operations nor 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”). Immediately prior to the consummation 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 owned 99.996%), which in turn is a wholly owned subsidiary of Resolute Holdings, LLC (“Holdings”). Effective December 31, 2010, Aneth became a wholly-owned subsidiary of the Company.

The Resolute Transaction was accounted for using the acquisition method, with HACI as the accounting acquirer, and resulted in a new basis of accounting reflecting the fair values of the Predecessor Resolute assets and liabilities at the Acquisition Date. Accordingly, the accompanying consolidated financial statements are presented on Resolute’s new basis of accounting (see Note 3 for details). HACI is the surviving entity and periods prior to September 25, 2009 reflected in this report represent activity related to HACI’s formation, its initial public offering and efforts to identify and consummate a business combination. The operations of Predecessor Resolute have been incorporated beginning September 25, 2009.

Note 2 — Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The consolidated financial statements include Resolute and its subsidiaries, and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). All significant intercompany transactions have been eliminated upon consolidation. Certain prior period amounts have been reclassified to conform to the current period presentation.

In connection with the preparation of the consolidated financial statements, Resolute evaluated subsequent events after the balance sheet date, through the date of filing.

Assumptions, Judgments and Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events. Accordingly, actual results could differ from amounts previously established.

F-8

Significant estimates with regard to the consolidated financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, the estimated cost and timing related to asset retirement obligations, the estimated fair value of derivative assets and liabilities, the estimated expense for share based compensation and depletion, depreciation, and amortization.

Fair Value of Financial Instruments

The carrying amount of Resolute’s financial instruments, namely cash and cash equivalents, accounts receivable and accounts payable, approximate their fair value because of the short-term nature of these instruments. The long-term debt (see Note 6) has a recorded value that approximates its fair market value. The fair value of derivative instruments (see Note 10) is estimated based on market conditions in effect at the end of each reporting period.

The Company’s accounts receivable at December 31, consists of the following (in thousands):

		September 30,		September 30,
	2011		2010
Trade receivables	$	57,549	$	40,640
Income tax receivable		3,642		3,645
Derivative receivables		—		98
Other receivables		739		771

Total accounts receivable	$	61,930	$	45,154

Industry Segment and Geographic Information

Resolute conducts crude oil, gas and NGL exploration and production operations in one segment. All of Resolute’s operations and assets are located in the United States, and all of its revenue is attributable to domestic customers. Resolute considers gathering, processing and marketing functions as ancillary to its oil and gas producing activities, and therefore these activities are not reported as a separate segment.

Cash, Cash Equivalents, and Marketable Securities

Resolute considers all highly liquid investments with original maturities of three months or less at the date of purchase to be cash equivalents. Resolute periodically maintains cash and cash equivalents in bank deposit accounts and money market funds which may be in excess of federally insured amounts. Resolute has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.

Deferred Financing Costs

Deferred financing costs are amortized over the estimated life of the related obligation. The Company incurred $0.2 million in deferred financing costs in 2011 and $4.0 million in 2010, of which $1.0 million and $0.8 million was amortized to expense during 2011 and 2010, respectively. No deferred financing costs were incurred prior to 2010.

Capitalized Interest

Interest is capitalized when associated with significant investments in unproved properties and major development projects that are excluded from current depreciation, depletion and amortization calculations and on which exploration or development activities are in progress. Capitalized interest is calculated by multiplying the Company’s weighted-average interest rate on debt by the amount of identified costs. Excluded oil and gas costs are classified as unproved properties along with any associated capitalized interest. Capitalized interest totaled $1.3 million and $0.5 million for the twelve months ended December 31, 2011 and December 31, 2010, respectively. No interest was capitalized during 2009.

Concentration of Credit Risk

Financial instruments that potentially subject Resolute to concentrations of credit risk consist primarily of trade, production and derivative settlement receivables. Resolute derived approximately 82% and 8% of its total 2011 revenue and 84% and 9% of its total 2010 revenue from Western Refining, Inc. and affiliates of Anadarko Petroleum Corporation, respectively. If Resolute was compelled to sell its crude oil to an alternative market, costs associated with the transportation of its production would increase, and such increase could materially and negatively affect its operations. The concentration of credit risk in the oil and gas industry affects the overall exposure to credit risk because customers may be similarly affected by changes in economic or other conditions. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. Commodity derivative contracts expose Resolute to the credit risk of non-performance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, all of which are financial institutions participating in Resolute’s Credit Facility (see Note 6).

F-9

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 on a country-wide basis (the “cost center”).

Resolute conducts tertiary recovery projects on certain 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, and 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 carbon dioxide (“CO₂”). The development costs 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, provides future economic value over the life of the project.

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, compression, electricity, separation, re-injection of recovered CO₂ and water and reservoir pressure maintenance.

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. Resolute capitalized general and administrative and operating costs related to its acquisition, exploration and development activities of $5.2 million during 2011, $2.0 million during 2010 and $0.1 million during 2009.

Investments in unproved properties are not depleted, pending determination of the existence of proved reserves. The Company’s investments in unproved properties are related to exploration plays in the Big Horn Basin in Wyoming, the Williston Basin in North Dakota and the Permian Basin in Texas. The Company expects to evaluate these locations for the existence of proved reserves in the next 1 to 3 years. Unproved properties are assessed at least annually to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense as appropriate. During 2011, 2010 and 2009 Resolute transferred $67.8 million, $2.5 million and $3.9 million in unproved property costs to the full cost pool, respectively.

No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil and gas properties and the gain or loss significantly alters the relationship between the 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, construct and install production and processing facilities, and improved recovery systems, including the cost of required future CO₂purchases.

F-10

At December 31, 2009, the Company’s full cost pool was solely comprised of assets attributable to the Resolute Transaction. In accordance with Regulation S-X Article 4-10 and rules for full cost accounting for proved oil and gas properties, Resolute performed a ceiling test at December 31, 2009 using its year-end reserve estimates. Total capitalized costs exceeded the full cost ceiling by approximately $150 million; however, no impairment was recognized as the Company requested and received an exemption from the Securities and Exchange Commission (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. The request for exemption was made because the Company could demonstrate beyond a reasonable doubt that the fair value of the Resolute Transaction oil and gas properties exceeded unamortized cost at the Acquisition Date and at December 31, 2009.

Other Property and Equipment

Other property and equipment are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the assets. Office furniture, automobiles, and computer hardware and software are depreciated over three to five years. Field offices are depreciated over fifteen to twenty years. Leasehold improvements are depreciated, using the straight line method, over the shorter of the lease term or the useful life of the asset. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation and amortization are removed from the accounts.

Impairment of Long-Lived Assets Other than Oil and Gas Properties

Resolute evaluates long-lived assets for impairment when indicators of possible impairment are present. Resolute performs an analysis of the anticipated undiscounted future net cash flows of the related long-lived assets and if the carrying value of the related asset exceeds the undiscounted cash flows, the carrying value is reduced to the assets’ fair value and an impairment loss is recorded against the long-lived asset. There have been no provisions for impairment recorded for the years ended December 31, 2011, 2010 and 2009.

Asset Retirement Obligation

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 and the cost of such liability is recorded as an increase in 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.

The restricted cash of $16.6 million located on the Company’s consolidated balance sheet at December 31, 2011 in non-current other assets is legally restricted for the purpose of settling asset retirement obligations of Aneth (“ExxonMobil Properties”) (See Note 12).

Derivative Instruments

Resolute enters into derivative contracts to manage its exposure to oil and gas price volatility and may take the form of futures contracts, swaps or options. Derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. Resolute’s management has determined that the benefit of cash flow hedge accounting, which may allow for its derivative instruments to be reflected as cash flow hedges in other comprehensive income, is not commensurate with the administrative burden required to support that treatment. As a result, Resolute marks its derivative instruments to fair value on the consolidated balance sheets and recognizes the changes in fair market value in earnings. Realized gains and losses on derivative instruments are recognized in the period in which the related contract is settled. Both the realized and unrealized gains and losses on derivative instruments are reflected in other income (expense) in the consolidated statements of operations. 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 statement of cash flows.

Revenue Recognition

Oil and gas revenue is recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred and the collectability of the revenue is probable. Oil and gas revenue is recorded using the sales method.

F-11

General and Administrative Expenses

General and administrative expenses are reported net of amounts capitalized to oil and gas properties and of reimbursements of overhead costs that are billed to working interest owners of the oil and gas properties operated by Resolute. During 2009, the Company recorded $16.6 million of transaction costs in general and administrative expense related to the Resolute Transaction.

Share-Based Compensation Expense

Share-based compensation expense is measured at the estimated grant date fair value of the awards and is amortized over the requisite service period (usually the vesting period). The Company estimates forfeitures in calculating the cost related to share-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur.

Income Taxes

Income taxes and uncertain tax positions are accounted for in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 740, Accounting for Income Taxes. Deferred income taxes are provided for the differences between the bases of assets and liabilities for financial reporting and income tax purposes. A valuation allowance is established when necessary to reduce deferred tax assets to the amount expected to be realized. Tax positions meeting the more-likely-than-not recognition threshold are measured pursuant to the guidance set forth FASB ASC Topic 740.

Note 3 — Acquisitions and Divestitures

Resolute Transaction

The Resolute Transaction was accounted for using the acquisition method, in which HACI was the accounting acquirer, and resulted in a new basis of accounting reflecting the fair values of the Predecessor Resolute assets acquired and liabilities assumed. In connection with the Resolute Transaction, HACI acquired an estimated 72.8% membership interest in Aneth in exchange for HACI’s payment to Aneth of $325 million (the “HACI Contribution”), which Aneth used to repay a portion of the debt outstanding under Aneth’s credit facilities.

Immediately following the repayment of debt, Sub contributed to the Company its interests in Predecessor Resolute in exchange for:

(i)

9,200,000 shares of Company common stock, 200,000 of which were issued to service providers (employees of Predecessor Resolute who became employees of Resolute upon consummation of the Resolute Transaction) in recognition of their services. 100,000 shares vested immediately on September 25, 2009 and the remaining shares less forfeitures vested on the one year anniversary of the Acquisition Date;

(ii)

4,600,000 new Company Founders Warrants, (“New Founder Warrants”) issued in exchange for Old Founder’s Warrants (defined below) to purchase Company common stock with a strike price of $13.00, a trigger price of $13.75 and a five year term from the date of the Resolute Transaction; and

(iii)

1,385,000 Company earnout shares, which are shares of Company common stock (with voting rights) (“Earnout Shares”) that were forfeitable if the price of Company common stock did not exceed $15.00 per share for 20 trading days in any 30 trading day period within five years from the date of the Resolute Transaction. The Earnout Shares vested on February 2, 2011.

Immediately prior to the Resolute Transaction, 7,335,000 shares of common stock and 4,600,000 sponsor warrants of HACI that had been issued to the founder of HACI (“Founder Shares” and “Old Founder Warrants,” respectively) were cancelled and forfeited. Sponsor Warrants of 2,333,333 were sold to Sub by the sponsor in exchange for Sub’s payment of $1,166,667 to the Sponsor. Sponsor Warrants were warrants to purchase the common stock of HACI held by the Sponsor that were exchanged in the Resolute Transaction for New Sponsor Warrants to purchase Company common stock with a strike price of $13.00 and a five year term.

Immediately following the HACI Contribution and simultaneously with Sub’s contribution of Predecessor Resolute, Resolute Subsidiary Corporation, a wholly owned subsidiary of Resolute, merged with and into HACI, with HACI surviving. HACI continues as a wholly-owned subsidiary of Resolute and the outstanding shares of HACI common stock and outstanding HACI warrants, including outstanding Old Founder Warrants and Sponsor Warrants, were exchanged for Sub’s contribution. After the Resolute Transaction, the former HACI stockholders and warrant holders have no direct equity ownership interest in HACI.

F-12

Pro Forma Financial Information

The unaudited pro forma consolidated financial information in the table below summarizes the results of operations of the Company as though the Resolute Transaction had occurred as of the beginning of the period presented. The pro forma financial information is presented for informational purposes only and is not indicative of the results of operations that would have been achieved if the acquisition had taken place at the beginning of the earliest period presented or that may result in the future. The pro forma adjustments made were based on certain assumptions that Resolute believed were reasonable based on the available information.

The unaudited pro forma financial information for the year ended December 31, 2009, combines the historical results of HACI and Predecessor Resolute.

		September 30,
	2009
	(in thousands, except per share amount)
Total revenue	$	127,760
Operating loss		(26,558	)
Net loss		(64,827	)
Basic and diluted net loss per share	$	(1.22	)

Note 4 — Earnings per Share

Prior to the date of the Resolute Transaction, the Company computed earnings per share using the two class method due to the common stock subject to redemption. The liquidation rights of the holders of the Company’s common stock and common stock subject to redemption were identical, except with respect to redemption rights for dissenting shareholders in an acquisition by the Company. As a result, the undistributed earnings for periods prior to the Resolute Transaction were allocated based on the contractual participation rights of the common stock and common stock subject to redemption as if the earnings for the year had been distributed. The undistributed earnings were allocated to common stock subject to redemption based on their pro-rata right to income earned on offering proceeds by the trust. Subsequent to the Resolute Transaction, no common stock subject to redemption remains outstanding.

The Company computes basic net income (loss) per share using the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) per share is computed using the weighted average number of shares of common stock and, if dilutive, potential shares of common stock outstanding during the period. Potentially dilutive shares consist of the incremental shares issuable under the outstanding warrants, which entitle the holder to purchase one share of the Company’s common stock at a price of $13.00 per share and expire on September 25, 2014, and incremental shares issuable under the Company’s 2009 Performance Incentive Plan (the “Incentive Plan”). The treasury stock method is used to measure the dilutive impact of potentially dilutive shares.

The following table details the potential weighted average dilutive and anti-dilutive securities for the periods presented (in thousands):

		September 30,		September 30,		September 30,
	Twelve Months Ended December 31,
	2011		2010		2009

Dilutive warrants		32,523		—		—
Dilutive restricted stock		1,296		663		—
Anti-dilutive securities		10,757		34,600		34,600

F-13

The following table sets forth the 2011 and 2010 computation of basic and diluted net income per share of common stock (in thousands, except per share amounts):

		September 30,		September 30,
	2011		2010
Net income	$	30,485	$	6,185

Basic weighted average common shares outstanding		57,612		49,900
Add: dilutive effect of non-vested restricted stock		1,169		575
Add: dilutive effect of outstanding warrants		6,248		—

Diluted weighted average common shares outstanding		65,029		50,475


Basic net income per common share	$	0.53	$	0.12
Diluted net income per common share	$	0.47	$	0.12

The following table sets forth the 2009 computation of basic and diluted net loss per share of common stock and common stock subject to redemption (in thousands, except per share amounts):

		September 30,			September 30,
	2009
				Common
	Common Stock			Stock Subject to Redemption
Numerator:
Allocation of undistributed loss	$	(43,313	)	$	(1,930	)
Denominator:
Weighted average of issued shares outstanding		46,394			12,114

Basic and diluted loss per share	$	(0.93	)	$	(0.16	)

Warrants entitle the holder to purchase one share of Company common stock at a price of $13.00 per share and expire on September 25, 2014. A summary of the activity associated with warrants during 2011, 2010 and 2009 is as follows (in thousands):

		September 30,
	Warrants
Balance at January 1, 2009		76,000
Redemption of warrants in Resolute Transaction		(27,600	)
Cancellation of Old Founder Warrants		(4,600	)
Issuance of New Founder Warrants		4,600

Balance at December 31, 2009 and 2010		48,400

Warrants exercised		(5,724	)

Balance at December 31, 2011		42,676

Subsequent to December 31, 2011, and through February 29, 2012, no warrants have been exercised.

Note 5 — Related Party Transactions

HACI agreed to pay up to $10,000 a month for office space and general and administrative services to Hicks Holdings Operating LLC, an affiliate of HACI’s founder and chairman of the board, Thomas O. Hicks. Services commenced after the effective date of the Offering and were terminated on the Acquisition Date due to the consummation of the Resolute Transaction. Under this agreement, the Company expensed $0.1 million during 2009.

Note 6 — Long Term Debt

During April of 2011, the Company entered into two additional amendments to the amended and restated Credit Facility agreement. Under the terms of the amendments, the Company is permitted to use proceeds received from the exercise of outstanding warrants to repurchase equity securities, the borrowing base was increased from $260.0 million to $300.0 million and, 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 1.75% to 2.75% 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 0.75% to 1.75%. Each such margin is based on the level of utilization under the borrowing base. As of December 31, 2011 and 2010, the weighted average interest rate on the outstanding balance under the Credit Facility was 2.60% and 3.15%, respectively. The recorded value of the Credit Facility approximates its fair market value. The Company capitalized $1.3 million and $0.5 million of interest expense during the year ended December 31, 2011 and 2010, respectively. No interest expense was capitalized during 2009.

F-14

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. During November of 2011, as the result of a redetermination, the borrowing base was increased to $330.0 million. As of December 31, 2011, outstanding borrowings were $170.0 million and unused availability under the borrowing base was $156.9 million. The borrowing base availability had been reduced by $3.1 million in conjunction with letters of credit issued to vendors at December 31, 2011. 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 guaranteed by all of Resolute’s subsidiaries and is collateralized by substantially all of the proved oil and gas assets of Aneth and Resolute Wyoming, Inc., which are wholly-owned subsidiaries of the Company.

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, 2011.

Note 7 — Income Taxes

The following table summarizes the components of the provision for income taxes (in thousands):

		September 30,			September 30,			September 30,
	2011			2010			2009
Current income tax benefit	$	—		$	3,617		$	74
Deferred income tax benefit (expense)		(17,870	)		(6,005	)		19,813

Total income tax benefit (expense)	$	(17,870	)	$	(2,388	)	$	19,887

The provision for income taxes for the years ended December 31, 2011, 2010 and 2009 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to income before income taxes. This difference relates primarily to state income taxes and estimated permanent differences as follows (in thousands):

		September 30,			September 30,			September 30,
	2011			2010			2009
Expected statutory income tax benefit (expense)	$	(16,924	)	$	(3,001	)	$	22,120
State income tax benefit (expense)		(1,112	)		(98	)		1,612
Equity based compensation		—			—			(322	)
Non-deductible merger costs		—			—			(3,615	)
Provision to tax return revision		46			969			—
Other		120			(258	)		92

Total income tax benefit (expense)	$	(17,870	)	$	(2,388	)	$	19,887

F-15

The tax effects of temporary differences that give rise to significant portions of the deferred income tax assets and liabilities are presented below (in thousands):

		September 30,			September 30,
	December 31,
	2011			2010
Current deferred income tax assets (liabilities):
Derivative financial instruments	$	11,474		$	10,048
Asset retirement obligation		1,476			1,123
Other		744			783

Total current		13,694			11,954


Long term deferred income tax assets (liabilities):
Derivative financial instruments		10,605			18,198
Net operating loss carryovers		21,318			7,833
Asset retirement obligation		4,703			4,272
Startup and organization costs		196			235
Deferred acquisition costs		45			45
Percentage depletion		923			608
Property and equipment costs		(131,617	)		(104,469	)
Other		841			(98	)

Total long term		(92,986	)		(73,376	)

Net deferred tax liability	$	(79,292	)	$	(61,422	)

The Company has U.S. net operating loss carryforwards of $57.8 million at December 31, 2011, which will begin expiring in 2026. Of the $57.8 million, $1.1 million would not be available for use until 2013 and after.

The Company adopted the accounting for uncertain tax positions per FASB ASC Topic 740, Accounting for Income Taxes, from inception. This guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This guidance requires that the Company recognize in the consolidated financial statements, only those tax positions that are “more-likely-than-not” of being sustained, based on the technical merits of the position. As a result of the implementation of this guidance, the Company performed a comprehensive review of the Company’s material tax positions. This guidance had no effect on the Company’s financial position, cash flows or results of operations for 2011, 2010 or 2009 as the Company had no unrecognized tax benefits. The Company’s policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. The Company has no accrued interest or penalties related to uncertain tax positions as of December 31, 2011 or 2010.

The Company is subject to the following material taxing jurisdictions: U.S. federal, Colorado, Utah, North Dakota and Texas. The tax years that remain open to examination by the Internal Revenue Service are the years 2007 through 2011. The tax years that remain open to examination by state taxing authorities are 2006 through 2011.

Note 8 — Stockholders’ Equity and Equity Based Awards

Preferred Stock

The Company is authorized to issue up to 1,000,000 shares of preferred stock, par value $0.0001 with such designations, voting and other rights and preferences as may be determined from time to time by the Board of Directors. No shares were issued and outstanding as of December 31, 2011 or December 31, 2010.

Common Stock

The authorized common stock of the Company consists of 225,000,000 shares. The holders of the common shares are entitled to one vote for each share of common stock. In addition, the holders of the common stock are entitled to receive dividends when, as and if declared by the Board of Directors. At December 31, 2011 and 2010, the Company had 60,947,329 and 54,717,571 shares of common stock issued and outstanding, respectively. During the first quarter of 2011, 3,250,000 Earnout Shares vested. Earnout Shares were shares of the Company’s common stock that were issued at the time of the merger between the Company and HACI in September 2009. These shares had voting rights and were transferable, but were not registered for resale and were not able to participate in dividends until the trading price of the Company’s common stock exceeded $15.00 per share for 20 consecutive trading days. This target was met and the Earnout Shares vested on February 2, 2011.

During the year ended December 31, 2011, 5,724,397 warrants were exercised for proceeds to the Company of $74.4 million. At December 31, 2011, 42,675,503 warrants remain outstanding.

F-16

Prior to the consummation of the Resolute Transaction, holders of 30% of public common stock, less one share, had the right to vote against any acquisition proposal and demand conversion of their shares for a pro rata portion of cash and marketable securities held in trust, less certain adjustments. As a result, HACI classified 16,559,999 of the total 69,000,000 common shares issued during 2007 as common stock, subject to possible redemption for $160.8 million. The common stock subject to redemption participated in the net income of HACI. Income or loss attributable to common stock subject to redemption was considered in the calculation of earnings per share and the deferred interest attributable to common stock subject to possible redemption was accrued. Upon consummation of the Resolute Transaction, the $160.8 million temporary equity was reclassified to common stock and additional paid-in capital and 11,592,084 shares were redeemed. The deferred interest attributable to the shares of common stock not redeemed of $1.9 million was reclassified to stockholders’ equity.

Share-Based Compensation

On July 31, 2009, the Company adopted the Incentive Plan, providing for long-term share based awards intended as a means for the Company to attract, motivate, retain and reward directors, officers, employees and other eligible persons through the grant of awards and incentives for high levels of individual performance and improved financial performance of the Company. The share-based awards are also intended to further align the interests of award recipients and the Company’s stockholders. The maximum number of common shares that may be issued under the Incentive Plan was increased from 2,657,744 to 9,157,744 pursuant to an amendment to the Incentive Plan that received stockholder approval at the Company’s Annual Meeting on June 2, 2011.

The Incentive Plan authorizes stock options, stock appreciation rights, restricted stock, restricted stock units, stock bonuses and other forms of awards that may be granted or denominated in Company common stock or units of Company common stock, as well as cash bonus awards. The Incentive Plan retains flexibility to offer competitive incentives and to tailor benefits to specific needs and circumstances. Any award may be paid or settled in cash at the Company’s option.

During the year ended December 31, 2011, the Company granted 681,537 shares of restricted stock to employees and directors, pursuant to the Incentive Plan. Shares of restricted stock issued to employees generally vest in four year increments at specified dates based on continued employment and the satisfaction of certain market performance metrics.

Generally, two-thirds of each grant of restricted stock is time-based and will vest with continued employment in four equal tranches. The compensation expense to be recognized for the time-based awards was measured based on the Company’s traded stock price on the dates of grant, utilizing estimated forfeiture rates between 0% and 9%.

The remaining one-third of each grant is subject to the satisfaction of pre-established market performance targets. The performance-based shares will generally vest in equal tranches beginning on December 31^st of the year of the grant if there has been a 10% annual appreciation in the trading price of the Company’s common stock, compounded annually, from the twenty trading day average stock price ended on December 31^st of the year prior to the grant (which was $11.134 for 2010 grants and $14.227 for 2011 grants). At the end of each year, the twenty trading day average stock price will be measured, and if the 10% threshold is met, the stock subject to the performance criteria will vest. If the 10% threshold is not met, shares that have not vested will be carried forward to the following year. In that way, an underperforming year can be offset by an over-performing year.

The compensation expense to be recognized for the performance-based awards was measured based on the estimated fair value at the date of grant using a binomial lattice model that incorporates a Monte Carlo simulation. Awards granted prior to September 25, 2011 incorporated the volatility of a peer group due to the limited historical data on Resolute’s stock at that time. Companies included in the peer group had similar market cap, leverage and were all heavily weighted in oil sales and the average expected volatility was based on 3.5 year historical volatility levels. Awards granted subsequent to September 25, 2011 incorporate the Company’s historical volatility. Risk-free interest rates reflect the yield on an average of three and five year zero coupon U.S. Treasury bonds, based on the shares’ contractual terms.

The valuation model for the performance portion of the award used the following assumptions:

	September 30,		September 30,		September 30,
Grant Year	Average Expected Volatility	Expected Dividend Yield			Risk-Free Interest Rate
2010	70.5% – 76.4%		0.0	%	1.04% – 1.75%
2011	31.9% – 74.5%		0.0	%	0.63% – 1.77%

On September 25, 2009, the Company and Sub entered into a Retention Bonus Award Agreement calling for the award to employees of the Company of 200,000 shares of Company common stock that would otherwise have been issued to Sub in the Resolute Transaction. Fifty percent of each employee award was awarded without restriction and fifty percent of each employee award was granted contingent upon the employee remaining employed by the Company for one year following the closing of the Resolute Transaction. As of September 25, 2010, the vesting date, employees had forfeited 15,039 shares under this agreement, which were transferred to Holdings, and had relinquished 25,086 shares in satisfaction of withholding taxes, which were retired by the Company. The compensation expense recognized for the awards was measured based on the Company’s traded stock price at the date of the Resolute Transaction.

F-17

For the twelve months ended December 31, 2011, 2010 and 2009, the Company recorded $7.9 million, $6.2 million and $4.0 million of stock based compensation expense, net of partner billings, respectively. There was unrecognized compensation expense for all awards of restricted stock under the Incentive Plan of approximately $14.7 million at December 31, 2011, which is expected to be recognized over a weighted-average period of 2.4 years. The following table summarizes changes in non-vested restricted stock for the periods presented.

		September 30,			September 30,		September 30,			September 30,
	2011					2010
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value

Non-vested, beginning of period		1,321,599		$	11.40		—		$	—
Granted		681,537		$	16.01		1,746,692		$	11.51
Vested		(375,218	)	$	13.68		(408,543	)	$	11.84
Forfeited		(74,688	)	$	13.26		(16,550	)	$	11.50

Non-vested, end of period		1,553,230		$	12.80		1,321,599		$	11.40

Note 9 — Asset Retirement Obligation

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 that ranges between 7% and 10%. 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. Asset retirement obligations are valued utilizing Level 3 fair value measurement inputs.

The following table provides a reconciliation of Resolute’s asset retirement obligations at December 31, (in thousands):

		September 30,			September 30,
	2011			2010
Asset retirement obligations at beginning of period	$	14,765		$	10,438
Additional liability incurred		310			4
Accretion expense		1,013			774
Liabilities settled		(1,647	)		(2,662	)
Revisions to previous estimates		2,112			6,211

Asset retirement obligations at end of period		16,553			14,765
Less: current asset retirement obligations		(3,953	)		(3,072	)

Long-term asset retirement obligations	$	12,600		$	11,693

Note 10 — Derivative Instruments

As of December 31, 2011, Resolute had entered into certain commodity swap contracts. The following table represents Resolute’s commodity swaps through 2013:

		September 30,		September 30,		September 30,		September 30,
Year	Bbl per Day		Oil (NYMEX WTI) Weighted Average Hedge Price per Bbl		MMBtu per Day		Gas (NYMEX HH) Weighted Average Hedge Price per MMBtu
2012		2,750	$	69.40		2,100	$	7.42
2013		2,000	$	60.47		1,900	$	7.40

Resolute also uses basis swaps in connection with gas swaps in order to fix the price differential between the NYMEX Henry Hub price and the index price at which the gas production is sold. The table below sets forth Resolute’s outstanding basis swaps as of December 31, 2011.

	September 30,		September 30,		September 30,
Year	Index	MMBtu per Day		Hedged Price Differential per MMBtu
2012 – 2013	Rocky Mountain NWPL		1,800	$	2.100
2012	Rocky Mountain CIG		1,000	$	0.575
2013	Rocky Mountain CIG		500	$	0.590
2014	Rocky Mountain CIG		1,000	$	0.590

F-18

As of December 31, 2011, Resolute had entered into certain commodity collar contracts. The following table represents Resolute’s commodity collars:

		September 30,		September 30,		September 30,
	Oil Collar		(NYMEXWTI)
Year	Volumes Bbl per Day		Floor Price		Ceiling Price
2012		1,375	$	71.64	$	102.45
2013		775	$	80.00	$	105.00
2014		1,500	$	65.00	$	110.00

The Company will incur premium payments associated with the oil collars of $1.0 million, $1.2 million and $2.7 million in 2012, 2013 and 2014, respectively.

Resolute does not offset the fair value amounts of derivative assets and liabilities with the same counterparty for financial reporting purposes. See Note 11 for the location and fair value amounts of Resolute’s commodity derivative instruments reported in the consolidated balance sheets at December 31, 2011.

The table below summarizes the location and amount of commodity derivative instrument losses reported in the consolidated statements of operations (in thousands):

		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009
Other income (expense):
Realized losses	$	(20,799	)	$	(8,276	)	$	(3,193	)
Unrealized gains (losses)		15,478			(9,566	)		(46,321	)

Total loss on derivative instruments	$	(5,321	)	$	(17,842	)	$	(49,514	)

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 lenders under Resolute’s Credit Facility. Accordingly, 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.

The maximum amount of loss in the event of all counterparties defaulting is $0 as of December 31, 2011, due to the set off provisions noted above.

Note 11 — Fair Value Measurements

•

Level 1 — Quoted prices in active markets for identical assets or liabilities.

•

Level 3 — Significant inputs to the valuation model are unobservable.

The following is a listing of Resolute’s assets and liabilities required to be measured at fair value on a recurring basis and where they are classified within the hierarchy as of December 31, 2011 and December 31, 2010 (in thousands):

		September 30,		September 30,
Description	Level 2
Description	December 31, 2011		December 31, 2010
Assets
Commodity swaps	$	3,170	$	4,745

Current assets: derivative instruments	$	3,170	$	4,745


Commodity swaps	$	2,291	$	3,098

Other assets: derivative instruments	$	2,291	$	3,098


Liabilities
Commodity swaps	$	30,171	$	585
Commodity collars		3,739		30,608

Current liabilities: derivative instruments	$	33,910	$	31,193


Commodity swaps	$	25,116	$	50,793
Commodity collars		5,585		486

Long term liabilities: derivative instruments	$	30,701	$	51,279

Note 12 — Commitments and Contingencies

CO₂ Take-or-Pay Agreements

Resolute is party to a take-or-pay purchase agreement with Kinder Morgan CO₂ Company L.P., under which Resolute has committed to buy specified volumes of CO₂. The purchased CO₂ is for use in Resolute’s enhanced tertiary recovery projects in Aneth Field. Resolute is obligated to purchase a minimum daily volume of CO₂ or pay for any deficiencies at the price in effect when delivery was to have occurred. The CO₂volumes planned for use on the enhanced recovery projects exceed the minimum daily volumes provided in these take-or-pay purchase agreements. Therefore, Resolute expects to avoid any payments for deficiencies.

On October 5, 2010, Resolute entered into an amendment of the contract effective September 1, 2010. The amendment extends the term of the contract to December 31, 2020, and allows the Company flexibility to adjust the minimum purchase commitments; therefore, these yearly commitments may change. During 2011, the Company entered into an additional amendment, effective January 2012, which amended the yearly minimum purchase commitments but not the aggregate volume commitment. Future minimum CO₂ purchase commitments as of December 31, 2011 under this purchase agreement based on prices in effect at December 31, 2011, are as follows (in thousands):

		September 30,
Year	CO₂ Purchase Commitments
2012	$	20,723
2013		22,389
2014		21,957
2015		17,222
2016		17,269
Thereafter		26,492

Total	$	126,052

Crude Production Purchase Agreement

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 purchase agreement effective August, 2011, which provides for a fixed differential to the NYMEX price for crude oil of $6.25 per barrel, with future adjustments to reflect any increase in transportation costs from the field to the refinery. The agreement covers up to 8,000 combined barrels per day of Resolute and Navajo Nation Oil and Gas Company volumes (the “Base Volume”) and an additional volume of up to 3,000 barrels per day (the “Additional Volume”). The agreement contains a two year term for the Base Volume and a six month term for the Additional Volume, each commencing on August 1, 2011. Both continue automatically on a month-to-month basis after expiration of the initial term unless terminated by either party with 180 day prior written notice (120 days for the Additional Volume). The agreement 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.

F-20

Operating Leases

Monthly office facility rental payments charged to expense during 2011 were $1.1 million. For 2010 and 2009, month-to-month office facilities rental payments charged to expense were approximately $1.0 million and $0.3 million, respectively. Future rental payments for office facilities under the terms of non-cancelable operating leases as of December 31, 2011 were approximately $0.8 million in 2012, $0.6 million in 2013, $0.2 million in 2014 and 2015 and $0.1 million in 2016.

The Company is also party to several field equipment and compressor leases used in the CO₂project. Total gross future rental payments under the terms of these leases amount to annual payments of $2.6 million through 2014, $2.2 million in 2015, $1.6 million in 2016 and total lease obligations of $1.7 million thereafter. Rental expense net to the Company’s interest for 2011 and 2010 was $1.9 million and was $0.5 million for 2009.

Escrow Funding Agreement

Under the terms of Predecessor Resolute’s purchase of the ExxonMobil Properties, Predecessor Resolute and Navajo Nation Oil and Gas Company (“NNOG”) were required to fund an escrow account sufficient to complete abandonment, well plugging, site restoration and related obligations arising from ownership of the acquired interests. The contribution net to Aneth’s working interest, is included in other assets: restricted cash in the consolidated balance sheets of December 31, 2011. Aneth is required to make additional deposits to the escrow account annually. From 2012 through 2016, Aneth must fund approximately $1.8 million per year. In years after 2016, Aneth must fund additional payments averaging approximately $0.9 million per year until 2031. Total contributions from the date of acquisition through 2031 will aggregate $28.7 million. Annual interest earned in the escrow account becomes part of the balance and reduces the payment amount required for funding the escrow account each year. As of December 31, 2011, Aneth has funded the 2011 annual contractual amount of approximately $1.8 million required to meet its future obligation.

NNOG Purchase Options

In connection with Predecessor Resolute’s acquisition of the ExxonMobil Properties and the acquisition from Chevron Corporation and its affiliates (“Chevron”) of 75% of Chevron’s interest in Aneth Field (“Chevron Properties”) in 2005, pursuant to the terms of the Cooperative Agreement, Predecessor Resolute granted to NNOG three separate but substantially similar purchase options which became obligations of Resolute through the Resolute Transaction. Each purchase option entitles NNOG to purchase from Resolute up to 10% of Resolute’s interest in each of the Chevron Properties and the ExxonMobil Properties. Each purchase option entitles NNOG to purchase, for a limited period of time, the applicable portion of Resolute’s interest in the Chevron Properties or the ExxonMobil Properties, at Fair Market Value (as defined in the agreement), which is determined without giving effect to the existence of the Navajo Nation preferential purchase right or the fact that the properties are located within the Navajo Nation. Each option becomes exercisable based upon Resolute’s achieving a certain multiple of payout of the relevant acquisition costs, subsequent capital costs and ongoing operating costs attributable to the applicable working interests. Revenue applicable to the determination of payout includes the effect of Resolute’s derivative program. The multiples of payout that trigger the exercisability of the purchase option are 100%, 150% and 200%. The options are not exercisable prior to four years from the acquisition except in the case of a sale of such assets by, or a change of control of, Aneth. In that case, the first option for 10% would be accelerated and the other options would terminate. Assuming the purchase options are not accelerated due to a change of control of Aneth, Resolute expects that the initial payout associated with the purchase options granted will occur no sooner than 2013.

F-21

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

		September 30,			September 30,			September 30,
				McElmo			Ratherford
	Aneth Unit			Creek Unit			Unit

Chevron Properties:
Option 1 (100% Payout)		5.30	%		1.50	%		0.30	%
Option 2 (150% Payout)		5.30	%		1.50	%		0.30	%
Option 3 (200% Payout)		5.30	%		1.50	%		0.30	%


Total		15.90	%		4.50	%		0.90	%

		September 30,			September 30,			September 30,
				McElmo			Ratherford
	Aneth Unit			Creek Unit			Unit

ExxonMobil Properties:
Option 1 (100% Payout)		0.75	%		6.00	%		5.60	%
Option 2 (150% Payout)		0.75	%		6.00	%		5.60	%
Option 3 (200% Payout)		0.75	%		6.00	%		5.60	%


Total		2.25	%		18.00	%		16.80	%

Note 13 — Supplemental Oil and Gas Information (unaudited)

Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities

Costs incurred during 2011, 2010 and 2009 related to oil and gas property acquisition, exploration and development activities, including the fair value of oil and gas properties acquired in the Resolute Transaction are summarized as follows (in thousands):

		September 30,		September 30,		September 30,
	2011		2010		2009
Acquisition costs
Proved	$	53,577	$	635	$	622,495
Unproved		26,135		21,638		11,203
Exploration costs		72,730		14,866		2
Development costs*		77,210		47,640		7,989

Total	$	229,652	$	84,779	$	641,689

*	Includes $15.8 million, $12.9 million and $4.4 million of acquired CO₂during 2011, 2010 and 2009, respectively_.

Capitalized Costs of Oil and Gas Properties

Net capitalized costs related to Resolute’s oil and gas producing activities at December 31, were as follows (in thousands):

		September 30,			September 30,
	2011			2010
Proved oil and gas properties	$	885,503		$	689,021
Unevaluated oil and gas properties, not subject to amortization		64,357			37,235
Accumulated depletion, depreciation and amortization		(113,079	)		(56,967	)

Oil and gas properties, net	$	836,781		$	669,289

Reserve Engineering and Auditor Qualifications

Resolute’s reserve report was prepared under the direct supervision of Resolute’s Vice President of Reservoir Engineering, M. David Clouatre, who is a qualified reserve estimator and auditor. His qualifications 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. They 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 29 years of practical petroleum engineering experience in estimating and evaluating reserves information with at least seven of these years being in charge of estimating and evaluating reserves. Subsequent to December 31, 2011, Mr. Clouatre has retired, remaining with the Company in a consulting role. Resolute has appointed Paul J. Taylor to the position of Resolute’s Reservoir Engineering Manager. Mr. Taylor will succeed Mr. Clouatre with responsibility for direction and supervision of the reserve report preparation process. Mr. Taylor has more than 25 years of experience in the oil and gas industry including engineering, business development and economic analysis. During his career, Mr. Taylor has worked in Alaska, California, Texas, the UK and the Middle East, has experience with nearly all forms of primary, secondary, and tertiary recovery methods and has worked on-shore and on shallow water and deep water projects. Mr. Taylor has a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines, a Master of Science in Energy Economics from the University of Wisconsin-Madison and is registered as a Professional Petroleum Engineer in Colorado and Alaska. His qualifications also 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.

F-22

The Company’s reserve data is audited by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis. Within NSAI, the technical person primarily responsible for auditing the Company’s reserve estimates has been practicing consulting petroleum engineering at NSAI since 1997. Additionally, this person has more than 30 years of practical experience in petroleum engineering, with more than 14 years experience in the estimation and evaluation of reserves.

Oil and Gas Reserve Quantities

Resolute had no oil and gas reserves prior to the acquisition of Predecessor Resolute. Accordingly, the following table begins with Resolute’s purchase of estimated net proved oil and gas reserves and the present value of such estimated net proved reserves as of September 25, 2009. The reserve data as of December 31, 2011 was prepared by Resolute and was audited by NSAI. Users of this information should be aware that the process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions to be made in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure reserves estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Presented below is a summary of the changes in estimated reserves (in thousands):

		September 30,			September 30,			September 30,			September 30,
	Oil (Bbl)			Gas (Mcf)			NGL (Bbl)			Oil Equivalent (Boe)
Purchases of minerals in place on September 25, 2009		64,946			52,203			6,997			80,643
Production		(543	)		(895	)		(4	)		(696	)
Revisions of previous estimates ⁽¹⁾		(14,544	)		(13,079	)		1,210			(15,514	)

Proved reserves as of December 31, 2009		49,859			38,229			8,203			64,433
Purchases of minerals in place		19			26			—			24
Production		(2,089	)		(3,423	)		(20	)		(2,680	)
Extensions, discoveries and other additions		49			45			—			58
Revisions of previsions estimates		2,394			4,221			(264	)		2,834

Proved reserves as of December 31, 2010		50,232			39,098			7,919			64,669
Purchases of minerals in place		1,811			5,251			1,340			4,026
Production		(2,299	)		(3,415	)		(17	)		(2,885	)
Extensions, discoveries and other additions		1,204			890			—			1,352
Sales of minerals in place		(291	)		(8	)		—			(293	)
Revisions of previous estimates		2,184			(6,659	)		(3,145	)		(2,071	)

Proved reserves as of December 31, 2011		52,841			35,157			6,097			64,798

Proved developed reserves:
As of December 31, 2011		32,347			17,523			1,603			36,871
As of December 31, 2010		30,818			13,968			1,165			34,312
As of December 31, 2009		30,895			15,524			1,456			34,938
Proved undeveloped reserves:
As of December 31, 2011		20,494			17,634			4,494			27,927
As of December 31, 2010		19,414			25,130			6,754			30,357
As of December 31, 2009		18,964			22,705			6,747			29,495

1)	The negative revisions are primarily due to commodity pricing attributable to utilization of average first of month fiscal year commodity prices.

F-23

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:

The following summarizes the policies used in the preparation of the accompanying oil and gas reserves disclosures, standardized measures of discounted future net cash flows from proved oil and gas reserves and the reconciliations of standardized measures at December 31, 2011. The information disclosed is an attempt to present the information in a manner comparable with industry peers.

The information is based on estimates of proved reserves attributable to Resolute’s interest in oil and gas properties as of December 31, 2011. Proved reserves are estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

Estimates were made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions.

The estimated future cash flows was compiled by applying average annual prices of crude oil and gas relating to Resolute’s proved reserves to the year-end quantities of those reserves.

The future cash flows were reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions.

Future income tax expenses were based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and gas properties, other deductions, credits and allowances relating to Resolute’s proved oil and natural gas reserves.

Future net cash flows were discounted to present value by applying a discount rate of 10%.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of Resolute’s oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. The following summary sets forth Resolute’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed by FASB ASC Topic 932:

		September 30,			September 30,			September 30,
	December 31,
	2011			2010			2009
	(in thousands)
Future cash inflows	$	5,190,000		$	4,124,000		$	3,056,000
Future production costs		(2,081,000	)		(1,684,000	)		(1,483,000	)
Future development costs		(648,000	)		(523,000	)		(432,000	)
Future income taxes		(733,000	)		(589,000	)		(290,000	)

Future net cash flows		1,728,000			1,328,000			851,000
10% annual discount for estimated timing of cash flows		(912,000	)		(741,000	)		(490,000	)

Standardized measure of discounted future net cash flows	$	816,000		$	587,000		$	361,000

F-24

The principal sources of change in the standardized measure of discounted future net cash flows are:

		September 30,			September 30,			September 30,
	December 31,
	2011			2010			2009
	(in thousands)
Standardized measure, beginning of year	$	587,000		$	361,000		$	—
Sales of oil and gas produced, net of production costs		(105,000	)		(63,000	)		(22,000	)
Net changes in prices and production costs		274,000			341,000			(288,000	)
Purchases of minerals in place		43,000			—			555,000
Sales of minerals in place		(5,000	)		—			—
Previously estimated development costs incurred during the year		64,000			41,000			5,000
Extensions and discoveries		25,000			1,000			—
Changes in estimated future development costs		(65,000	)		(87,000	)		43,000
Revisions of previous quantity estimates		11,000			46,000			(131,000	)
Accretion of discount		60,000			36,000			14,000
Net change in income taxes		(53,000	)		(142,000	)		122,000
Changes in timing and other		(20,000	)		53,000			63,000

Standardized measure, end of year	$	816,000		$	587,000		$	361,000

Note 14 — Quarterly Financial Data (unaudited)

The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 2011 and 2010. (in thousands except per share data):

		September 30,			September 30,			September 30,			September 30,
	Three Months Ended
	March 31,			June 30,			September 30,			December 31,
	2011			2011			2011			2011
Year Ended December 31, 2011:
Revenue	$	54,056		$	59,908		$	54,024		$	58,920
Operating expenses		(39,499	)		(40,204	)		(42,041	)		(47,729	)

Income from operations		14,557			19,704			11,983			11,191
Net income (loss)		(16,773	)		25,668			37,570			(15,980	)
Earnings (loss) per common share:
Basic	$	(0.32	)	$	0.44		$	0.64		$	(0.27	)
Diluted	$	(0.32	)	$	0.37		$	0.59		$	(0.27	)
Weighted average common shares outstanding:
Basic		53,204			58,883			59,138			59,146
Diluted		53,204			70,154			64,039			59,146

	Three Months Ended
	March 31,			June 30,			September 30,			December 31,
	2010			2010			2010			2010
Year Ended December 31, 2010:
Revenue	$	41,132		$	40,642		$	41,828		$	49,793
Operating expenses		(32,914	)		(33,056	)		(36,179	)		(40,076	)

Income from operations		8,218			7,586			5,649			9,717
Net income (loss)		4,704			19,068			(7,060	)		(10,527	)
Earnings (loss) per common share:
Basic and diluted	$	0.09		$	0.38		$	(0.14	)	$	(0.21	)
Weighted average common shares outstanding:
Basic		49,906			49,905			49,905			49,900
Diluted		49,906			50,526			49.905			49,900

F-25

To the Managing Members of

Resolute Natural Resources Company, LLC, Resolute Aneth, LLC, WYNR, LLC, and BWNR, LLC

and

To the Board of Directors of RNRC Holdings, Inc. and Resolute Wyoming, Inc

Denver, Colorado

We have audited the accompanying combined statements of operations, shareholder’s/member’s equity (deficit), and cash flows of Resolute Natural Resources Company, LLC and related combined companies for the period from January 1, 2009 to September 24, 2009. The combined financial statements include the accounts of Resolute Natural Resources Company, LLC and five related companies, Resolute Aneth, LLC, WYNR, LLC, BWNR, LLC, RNRC Holdings, Inc. and Resolute Wyoming, Inc. These companies are under common ownership and common management. These combined financial statements are the responsibility of the companies’ management. Our responsibility is to express an opinion on the combined financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The companies are not required to have, nor were we engaged to perform, an audit of their internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the companies’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such combined financial statements present fairly, in all material respects, the combined results of operations and combined cash flows of Resolute Natural Resources Company, LLC and related companies for the period from January 1, 2009 to September 24, 2009, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Denver, Colorado

March 29, 2010

F-26

RESOLUTE NATURAL RESOURCES COMPANY, LLC,

RESOLUTE ANETH, LLC, WYNR, LLC, BWNR, LLC,

RESOLUTE WYOMING, INC.,

RNRC HOLDINGS, INC.

Combined Statement of Operations

(in thousands)

		September 30,
	For the 267 Day Period Ended September 24,
	2009
Revenue:
Oil	$	72,655
Gas		10,183
Other		2,506

Total revenue		85,344

Operating expenses:
Lease operating		46,771
Depletion, depreciation, amortization, and asset retirement obligation accretion		21,925
Impairment of proved properties		13,295
General and administrative		8,076

Total operating expenses		90,067

Loss from operations		(4,723	)

Other income (expense):
Interest expense		(18,416	)
Loss on derivative instruments		(23,519	)
Other income		47

Total other expense		(41,888	)

Loss before income taxes		(46,611	)
Income tax benefit		5,019

Net loss	$	(41,592	)

See notes to combined financial statements

F-27

RESOLUTE NATURAL RESOURCES COMPANY, LLC

RESOLUTE ANETH, LLC

WYNR, LLC

BWNR, LLC

RESOLUTE WYOMING, INC.

RNRC HOLDINGS, INC.

Combined Statement of Shareholder’s/Member’s Equity (Deficit)

(in thousands, except for shares)

		September 30,		September 30,		September 30,		September 30,			September 30,			September 30,
													Total
					Additional					Member’s			Shareholder’s/
	Common Stock				Paid-in		Accumulated			Equity			Member’s
	Shares		Amount		Capital		Deficit			(Deficit)			Equity (Deficit)
Balances at January 1, 2009		2,000	$	1	$	37,594	$	(29,436	)	$	(153,828	)	$	(145,669	)
Capital contributions		—		—		—		—			125			125
Distributions		—		—		—		—			(125	)		(125	)
Equity-based compensation		—		—		—		—			2,818			2,818
Net loss		—		—		—		(8,257	)		(33,335	)		(41,592	)

Balances at September 24, 2009		2,000	$	1	$	37,594	$	(37,693	)	$	(184,345	)	$	(184,443	)

See notes to combined financial statements

F-28

RESOLUTE NATURAL RESOURCES COMPANY, LLC

RESOLUTE ANETH, LLC

WYNR, LLC

BWNR, LLC

RESOLUTE WYOMING, INC.

RNRC HOLDINGS, INC.

Combined Statement of Cash Flows

(in thousands)

		September 30,
	For the 267 Day Period Ended September 24,
	2009
Operating activities:
Net loss	$	(41,592	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization		21,244
Amortization and write-off of deferred financing costs		1,809
Deferred income taxes		(4,732	)
Equity-based compensation		2,818
Unrealized loss on derivative instruments		25,458
Accretion of asset retirement obligations		681
Impairment of proved properties		13,295
Loss on sale of other property and equipment		11
Other		(14	)
Change in operating assets and liabilities:
Accounts receivable		(630	)
Other current assets		365
Accounts payable and accrued expenses		(4,546	)
Other current liabilities		(1,172	)
Accounts payable — Holdings		(56	)

Net cash provided by operating activities		12,939

Investing activities:
Acquisition, exploration and development expenditures		(12,904	)
Proceeds from sale of oil and gas properties		218
Proceeds from sale of property and equipment		10
Purchase of other property and equipment		(66	)
Notes receivable — affiliated entities		7
Increase in restricted cash		(1,751	)
Other		63

Net cash used for investing activities		(14,423	)

Financing activities:
Deferred financing costs		(1,823	)
Proceeds from bank borrowings		95,670
Payment of bank borrowings		(93,120	)
Capital contributions		125
Capital distributions		(125	)

Net cash provided by financing activities		727

Net decrease in cash and cash equivalents		(757	)
Cash and cash equivalents at beginning of year		1,935

Cash and cash equivalents at end of year	$	1,178

Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest	$	20,211

Income taxes	$	—

Supplemental schedule of non-cash investing and financing activities:
Increase to asset retirement obligations	$	2,641

Capital expenditures financed through current liabilities	$	987

See notes to combined financial statements

F-29

RESOLUTE NATURAL RESOURCES COMPANY, LLC

RESOLUTE ANETH, LLC

WYNR, LLC

BWNR, LLC

RESOLUTE WYOMING, INC.

RNRC HOLDINGS, INC.

Notes to Combined Financial Statements

Note 1 — Description of the Companies and Business

Resolute Natural Resources Company, LLC (“Resources”), previously a Delaware corporation incorporated on January 22, 2004 and converted to a limited liability company on September 30, 2008, Resolute Aneth, LLC (“Aneth”), a Delaware limited liability company established on November 12, 2004, WYNR, LLC (“WYNR”), a Delaware limited liability company established on August 25, 2005, BWNR, LLC (“BWNR”), a Delaware limited liability company established on August 19, 2005, RNRC Holdings, Inc. (“RNRC”), a Delaware corporation incorporated on September 19, 2008 and Resolute Wyoming, Inc. (“RWI”) (formerly Primary Natural Resources, Inc. (“PNR”)), a Delaware corporation incorporated on November 21, 2003 (the change of name to RWI was effective September 29, 2008) (together, “Predecessor Resolute” or the “Companies”) are engaged in the acquisition, exploration, development, and production of oil, gas and natural gas liquids (“NGL”), primarily in the Paradox Basin in southeastern Utah and the Powder River Basin in Wyoming. The Companies are wholly owned subsidiaries of Resolute Holdings Sub, LLC (“Sub”), which in turn is a wholly owned subsidiary of Resolute Holdings, LLC (“Holdings”).

Note 2 — Basis of Presentation and Significant Accounting Policies

Basis of Presentation

The accompanying combined statements of operations, cash flows and statement of shareholders/members equity (deficit) of Predecessor Resolute have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The 2009 combined financial statements include the accounts of Resources and the five related companies: Aneth, WYNR, BWNR, RNRC and RWI. The conversion of Resources to an LLC and the formation of RNRC had no impact on the comparability of the combined financial statements. These companies are under common ownership and common management. All intercompany balances and transactions have been eliminated in combination.

On September 25, 2009 (the “Acquisition Date”), Hicks Acquisition Company I, Inc. (“HACI”) consummated a business combination under the terms of a Purchase and IPO Reorganization Agreement (the “Acquisition Agreement”) with Resolute Energy Corporation (“Resolute”), pursuant to which, through a series of transactions, HACI’s stockholders collectively acquired a majority of the outstanding equity of the Companies (the “Resolute Transaction”), and Resolute owns, directly or indirectly, 100% of the equity interests of Resources, WYNR, BWNR, RNRC, and RWI, and indirectly owns a 99.996% equity interest in Aneth. References to 2009 in these Notes relate to the 267 day period ended September 24, 2009, unless otherwise specified.

Assumptions, Judgments, and Estimates

The preparation of the combined financial statements in conformity with GAAP requires management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events. Accordingly, actual results could differ from amounts previously established.

Significant estimates with regard to the combined financial statements include the estimated carrying value of unproved properties, the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, the estimated cost and timing related to asset retirement obligations, the estimated fair value of derivative assets and liabilities, the estimated expense for equity based compensation and depletion, depreciation, and amortization.

F-30

Concentration of Credit Risk

Financial instruments that potentially subject Predecessor Resolute to concentrations of credit risk consist primarily of trade and production receivables. Predecessor Resolute derived 81% and 13% of its total 2009 revenue from Western Refining, Inc. and WGR Asset Holding Company, LLC, respectively. The concentration of credit risk in a single industry affects the overall exposure to credit risk because customers may be similarly affected by changes in economic or other conditions. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. Commodity derivative contracts expose Predecessor Resolute to the credit risk of non-performance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, each of which is a financial institution participating in Predecessor Resolute’s bank credit agreement.

Oil and Gas Properties

Predecessor 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 expenses are capitalized within the cost center.

Predecessor Resolute conducts tertiary recovery projects on certain 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.

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, compression, electricity, separation, re-injection of recovered CO₂ and water. Costs incurred to maintain reservoir pressure are also expensed as incurred.

Capitalized general and administrative and operating costs include salaries, employee benefits, costs of consulting services and other specifically identifiable costs and do not include costs related to production operations, general corporate overhead or similar activities. Predecessor Resolute capitalized general and administrative and operating costs of $0.3 million related to its acquisition, exploration and development activities in 2009.

Investments in unproved properties are not depleted, pending determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense as appropriate.

Pursuant to full cost accounting rules, Predecessor 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. As a result of this limitation on capitalized costs, the accompanying combined statements of operations include a provision for an impairment of oil and gas property cost in 2009 of $13.3 million.

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 or loss significantly alters the relationship between the capitalized costs and proved oil reserves of the cost center.

F-31

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 CO₂purchases.

Other Property and Equipment

Other property and equipment are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the assets. Office furniture, automobiles, and computer hardware and software are depreciated from three to five years. Field offices are depreciated from fifteen to twenty years. Leasehold improvements are depreciated, using the straight line method, over the shorter of the lease term or the useful life of the asset. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation and amortization are removed from the accounts.

Asset Retirement Obligations

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 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 asset retirement obligations result in adjustments to the related capitalized asset and corresponding liability. See Note 3.

Impairment of Long-Lived Assets

For non-oil and gas properties, Predecessor Resolute follows Financial Accounting Standards Board (“FASB”) Accounting Standards Codifications (“ASC”) Topic 360, Property Plant and Equipment, which requires impairment losses to be recorded on long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amount of such assets. In the evaluation of the fair value and future benefits of long-lived assets, Predecessor Resolute performs an analysis of the anticipated undiscounted future net cash flows of the related long-lived assets. If the carrying value of the related asset exceeds the undiscounted cash flows, the carrying value is reduced to its fair value. Other than the full cost ceiling test impairment discussed in the oil and gas properties accounting policy, there was no provision for impairment in 2009.

Deferred Financing Costs

Deferred financing costs are amortized over the estimated lives of the related obligations or, in certain circumstances, accelerated if the obligation is refinanced.

Derivative Instruments

Predecessor 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 statement of cash flows.

Predecessor Resolute recognizes 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 are recorded in current earnings, depending on the nature and designation of the instrument. Presently, Predecessor Resolute’s management has determined that the benefit of the financial statement presentation 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, Predecessor Resolute marked its derivative instruments to fair value during 2009 and recognized the changes in fair market value in earnings. The gain or loss on derivative instruments reflected in the combined statement of operations incorporate both the realized and unrealized amounts.

F-32

Revenue Recognition

Oil revenue is recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred and if the collectability of the revenue is probable. Gas revenue is recorded using the sales method. Under this method, Predecessor Resolute recognizes revenue based on actual volumes of gas sold to purchasers. Predecessor Resolute and other joint interest owners may sell more or less than their entitlement share of the volumes produced. A liability is recorded and the revenue is deferred if Predecessor Resolute’s excess sales of gas volumes exceed its estimated remaining recoverable reserves.

RWI is party to a twenty year Well Suspension Agreement (the “Agreement”) with Thunder Basin Coal Company, LLC and Ark Land Company (collectively “TBCC”). The initial term of the agreement does not exceed 20 years from October 1, 2006. However, both RWI or TBCC have the option to extend the agreement 10 years beyond the expiration of the initial term. Under the agreement, TBCC will pay RWI $2.6 million in exchange for suspension of well operations or deferral of drilling plans by RWI on certain acreage under lease to RWI. The non-refundable payment is payable to RWI in three installments over a period of three years beginning January 1, 2008. Revenue is recognized over TBCC’s expected development plan or until such time the specified properties are released from suspension and RWI may proceed with exploration of these properties. RWI recognized revenue related to the Agreement of $0.5 million in other revenue during 2009.

RWI is party to two additional well suspension agreements (the “Agreements”). The counterparties to these Agreements from time to time may submit a request to RWI to suspend well operations or defer drilling plans on certain acreage under lease to RWI in exchange for non-refundable payments. Revenue is recognized for these payments over the expected development plan or until such time the specified properties are released from suspension and RWI may proceed with exploration of these properties. During 2009, the Company recognized $0.1 million in income related to the Agreements.

General and Administrative Expenses

General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to working interest owners of the oil and gas properties operated by Predecessor Resolute.

Income Taxes

Income taxes are provided based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. RNRC and RWI use the asset and liability method of accounting for deferred income taxes. Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the combined financial statements. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized. Resources (prior to converting to an LLC) and RWI adopted the uncertainty provision of FASB ASC Topic 740, Accounting for Income Taxes. In accordance with this guidance, Resources (prior to converting to an LLC), RNRC and RWI income tax positions must meet a more-likely-than-not recognition threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within interest expense and general and administrative expenses, respectively.

Aneth, WYNR, BWNR and Resources are limited liability companies. As limited liability companies, Aneth, WYNR, BWNR and Resources (subsequent to converting to an LLC) are tax flow-through entities and, therefore, the related tax obligation, if any, is borne by the owners.

Industry Segment and Geographic Information

At September 24, 2009, Predecessor Resolute conducted operations in one industry segment, that being the crude oil, gas and natural gas liquids exploration and production industry. Predecessor Resolute considers gathering, processing and marketing functions as ancillary to its oil and gas producing activities, and therefore are not reported as a separate segment. All of Predecessor Resolute’s operations and assets are located in the United States, and all of its revenue is attributable to domestic customers.

Accounting Standards Update

Predecessor Resolute adopted Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, Business Combinations on January 1, 2009. FASB ASC Topic 805 establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the contingent and identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The statement also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statement to evaluate the nature and financial effects of the business combination. FASB ASC Topic 805 is effective for financial statements issued for fiscal years beginning after December 15, 2008. The nature and magnitude of the specific effects of FASB ASC Topic 805 on the combined financial statements will depend upon the nature, terms and size of the acquisitions consummated after the effective date. There have not been any acquisitions since adoption.

F-33

In April 2009, the FASB issued ASC Topic 825-10-65-1, Interim Disclosures about Fair Value of Financial Instruments which requires disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. FASB ASC Topic 825-10-65-1 is effective for interim and annual reporting periods ending after June 15, 2009. The adoption of this pronouncement did not have an impact on Predecessor Resolute’s combined financial statements, other than additional disclosures.

In April 2009, the FASB issued ASC 820-10-65-4, Determining Fair Value When the Volume or Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly. FASB ASC Topic 820-10-65-4 provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and requires that companies provide interim and annual disclosures of the inputs and valuation technique(s) used to measure fair value. FASB ASC Topic 820-10-65-4 is effective for interim and annual reporting periods ending after June 15, 2009 and is to be applied prospectively. The adoption of this pronouncement did not have an impact on Predecessor Resolute’s combined financial statements.

Predecessor Resolute adopted FASB ASC Topic 810-10-65-1, Noncontrolling Interests in Consolidated Financial Statements — an amendment to Accounting Research Bulletin (“ARB”) No. 51, on January 1, 2009. FASB ASC Topic 810-10-65-1 changed the accounting and reporting requirements for minority interests, which are now characterized as noncontrolling interests and are classified as a component of equity in the accompanying combined balance sheet. FASB ASC Topic 810-10-65-1 requires retroactive adoption of the presentation and disclosure requirements for existing noncontrolling interests, with all other requirements applied prospectively. The adoption of this pronouncement did not have an impact on Predecessor Resolute’s 2009 combined financial statements.

In March 2008, the FASB issued ASC Topic 815-10-65, Disclosures about Derivative Instruments and Hedging Activities — An Amendment of FASB Statement 133. FASB ASC Topic 815-10-65 enhances required disclosures regarding derivatives and hedging activities, including enhanced disclosures regarding: (a) how an entity uses derivative instruments; (b) how derivative instruments and related hedged items are accounted for under the derivatives and hedging Topic of the ASC, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. Predecessor Resolute adopted this pronouncement as of January 1, 2009 (see Note 8).

Predecessor Resolute adopted FASB ASC Topic 855, Subsequent Events on April 1, 2009, which established general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The adoption of this pronouncement did not have a material impact on Predecessor Resolute’s combined financial statements.

Predecessor Resolute adopted FASB ASC Topic 105-10-65-1, The “FASB Accounting Standards Codification” and the Hierarchy of Generally Accepted Accounting Principles on July 1, 2009. This pronouncement is effective for financial statements for interim or annual reporting periods ending after September 15, 2009. This pronouncement established only two levels of GAAP, authoritative and nonauthoritative. The ASC was not intended to change or alter existing GAAP, and it therefore did not have any impact on Predecessor Resolute’s combined financial statements, other than to modify certain existing disclosures. The ASC is the source of authoritative, nongovernmental GAAP, except for rules and interpretive releases of the SEC, which are sources of authoritative GAAP for SEC registrants. All other nongrandfathered, non-SEC accounting literature not included in the ASC is considered nonauthoritative.

Note 3 — Asset Retirement Obligations

Predecessor 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. The credit-adjusted risk-free rates used to discount Predecessor Resolute’s abandonment liabilities range from 3.90% to 13.50%. 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.

F-34

The following table provides a reconciliation of Predecessor Resolute’s asset retirement obligation (in thousands):

		September 30,
	Period Ended September 24,
	2009
Asset retirement obligations at beginning of period	$	9,828
Accretion expense		681
Additional liability incurred		—
Liabilities settled		(1,337	)
Revisions to previous estimates		2,641

Asset retirement obligations at end of period		11,813
Less current asset retirement obligations		2,565

Long-term asset retirement obligations	$	9,248

Note 4 — Long Term Debt

First Lien Facility

Predecessor Resolute’s credit facility is with a syndicate of banks led by Wachovia Bank, National Association (the “First Lien Facility”) with Aneth as the borrower. The First Lien Facility specifies a maximum borrowing base as determined by the lenders. The determination of the borrowing base takes into consideration the estimated value of Predecessor Resolute’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. The borrowing base is redetermined semi-annually, and the amount available for borrowing could be increased or decreased as a result of such redeterminations. As of September 24, 2009, the borrowing base was $240.0 million and the unused availability under the borrowing base was $32.8 million. The First Lien Facility matures on April 13, 2011 and, to the extent that the borrowing base, as adjusted from time to time, exceeds the outstanding balance, no repayments of principal are required prior to maturity. On May 12, 2009, Predecessor Resolute entered into the Fourth Amendment to the Amended and Restated First Lien Credit Facility (“Fourth Amendment”) to redetermine its borrowing base and interest rates, and to amend its Maximum Leverage Ratio covenant (effective March 31, 2009). Under the terms of the Fourth Amendment, at Aneth’s option, the outstanding balance under the First Lien Facility accrues interest at either (a) the London Interbank Offered Rate, plus a margin which varies from 2.5% to 3.5%, or (b) the Alternative Base Rate defined as the greater of (i) the Administrative Agent’s Prime Rate, (ii) the Administrative Agent’s Base CD rate plus 1%, or (iii) the Federal Funds Effective Rate plus 0.5%, plus a margin which varies from 1.0% to 2.0%. Each such margin is based on the level of utilization under the borrowing base. On July 28, 2009, Resolute entered into the Fifth Amendment to the Amended and Restated First Lien Credit Facility (“Fifth Amendment”) to amend its Current Ratio covenant. Under the terms of the Fifth Amendment, the Current Ratio covenant was not applicable for the quarters ended March 31, 2009 and June 30, 2009. On September 17, 2009, Predecessor Resolute entered into the Sixth Amendment to the Amended and Restated First Lien Credit Facility to amend certain terms and sections in the agreement in order to allow for the Resolute Transaction. As of September 24, 2009, the weighted average interest rate on the outstanding balance under the facility was approximately 4.0%. The First Lien Facility is collateralized by substantially all of the proved oil and gas assets of Aneth and RWI, and is guaranteed by all of the companies other than Aneth.

The First Lien Facility includes terms and covenants that place limitations on certain types of activities, the payment of dividends, and require satisfaction of certain financial tests. Predecessor Resolute was not in compliance with the First Lien Facility June 30, 2009 Maximum Leverage Ratio covenant. The Company entered into a waiver agreement with its First Lien Facility lenders on August 27, 2009, whereby the requirement to comply with the Maximum Leverage Ratio covenant for the period ended June 30, 2009 had been waived until the earlier to occur of (a) October 15, 2009 or (b) the Early Termination Date, defined as the date on which the lenders notify Predecessor Resolute that it has determined in its sole discretion that a material condition to the merger between Predecessor Resolute and HACI is unlikely to be satisfied by October 15, 2009 (“Waiver Termination Date”). Upon the Waiver Termination Date, the Maximum Leverage Ratio shall be calculated using the outstanding debt amount as of the Waiver Termination Date. The terms of the waiver allowed Predecessor Resolute to remain in compliance with the Maximum Leverage Ratio covenant at June 30, 2009 and September 24, 2009. Predecessor Resolute was in compliance with all other terms and covenants of the First Lien Facility at September 24, 2009.

On September 25, 2009, Resolute repaid $99.5 million outstanding under the First Lien Facility with cash received from the Resolute Transaction.

Second Lien Facility

Predecessor Resolute’s term loan was with a group of lenders, with Wilmington Trust FSB as the agent (the “Second Lien Facility”) and with Aneth as the borrower. The Second Lien Facility carries a borrowing base of $225.0 million which was fully utilized at September 24, 2009. Balances outstanding under the Second Lien Facility accrue interest at either (a) the adjusted London Interbank Offered Rate plus the applicable margin of 4.5%, or (b) the greater of (i) the Administrative Agent’s Prime Rate, (ii) the Administrative Agent’s Base CD rate plus 1%, or (iii) the Alternative Base Rate, plus the applicable margin of 3.5%. The Second Lien Facility was collateralized by substantially all of the proved oil and gas assets of Aneth and RWI, and was guaranteed by all of the companies other than Aneth. The claim of the Second Lien Facility lenders on the collateral was explicitly subordinated to the claim of the First Lien Facility lenders. As of September 24, 2009, the weighted average interest rate on the outstanding balance under the facility was approximately 5.0%.

F-35

The Second Lien Facility included terms and covenants that placed limitations on certain types of activities, the payment of dividends, and require satisfaction of certain financial tests. On August 28, 2009, Aneth gave notice to the lenders that it was in default of the Maximum Leverage Ratio covenant (calculated as the ratio of debt to trailing four quarter EBITDA), as measured at June 30, 2009. On September 1, 2009, lenders under the Second Lien Credit Facility declared the loan in default and accelerated the indebtedness. As a result of the declaration of default on September 1, 2009, default interest of an additional 2% per annum was imposed and the Company was prohibited from utilizing the Eurodollar interest option in future borrowings under the facility.

On September 25, 2009, Resolute repaid all amounts outstanding under the Second Lien Facility with cash received from the Resolute Transaction.

Note 5 — Income Taxes

Resources (prior to September 30, 2008), RNRC and RWI recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the combined financial statements or tax returns. Deferred tax assets and liabilities are determined based on the differences between the financial statement and tax basis of assets and liabilities using the enacted tax rates in effect for the year in which the differences are expected to reverse. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that are not expected to be realized based on available evidence. Resources (subsequent to September 30, 2008), Aneth, BWNR and WYNR are pass-through entities for federal and state income tax purposes. As such, neither current nor deferred income taxes are recognized by these entities.

The provision for income taxes is as follows (in thousands):

		September 30,
	Period Ended September 24,
	2009
Current income tax expense:
Federal	$	—
State		(104	)
Deferred income tax benefit		5,123
Valuation allowance		—

Total income tax benefit (expense)	$	5,019

Income tax expense (benefit) differed from amounts that would result from applying the U.S. statutory income tax rate to income before taxes as follows (in thousands):

		September 30,
	Period Ended September 24,
	2009
U.S. statutory income tax benefit	$	(4,626	)
State income tax benefit		(104	)
Share based compensation		—
Change in valuation allowance		—
Other		(289	)

Total tax benefit*	$	(5,019	)

*	Tax benefit is calculated based on taxable income of RNRC and RWI, which are taxable entities. Aneth, Sub, BWNR and WYNR are pass-through entities for federal and state income tax purposes. As such, neither current nor deferred income taxes are recognized by these entities.

As of September 24, 2009, RNRC had no regular tax loss carryforward and RWI had regular tax loss carryforwards of $11.3 million.

Resources and RWI adopted the uncertainty provisions of FASB ASC Topic 740, Accounting for Income Taxes, on January 1, 2007 and RNRC adopted the uncertainty provisions of FASB ASC Topic 740 on September 30, 2008. As a result of the implementation of this guidance, Resources recognized approximately $0.5 million, including accrued interest and penalties of $0.1 million, as a contingent liability and an increase to the January 1, 2007 balance of accumulated deficit. During 2009, the previously unrecognized tax benefit in the amount of $0.4 million related to the uncertain tax position was recognized. Previously accrued interest and penalties were also reversed. This recognition and reversal resulted from the expiration of the applicable statute of limitations on September 15, 2009.

F-36

Resources (prior to September 30, 2008), RNRC and RWI recognize interest and penalties related to uncertain tax positions in interest expense and general and administrative expense, respectively. RWI and RNRC had no uncertain tax positions. Resources and RWI file income tax returns in the U.S. federal jurisdiction and various states. Resources and RWI’s tax years of 2006 and forward are subject to examination by the federal and state taxing authorities.

The following table summarizes the activity during the years related to the liability for unrecognized tax benefits (in thousands):

		September 30,
Balance at January 1, 2009	$	386
Increases in unrecognized tax benefits		—
Decreases in unrecognized tax benefits		(386	)

Balance at September 24, 2009	$	—

Note 6 — Shareholder’s/Member’s Equity and Equity Based Awards

Common Stock

At September 24, 2009, RNRC and RWI each had 1,000 shares of common stock, par value $0.01 and $1.00 per share, authorized, issued and outstanding, respectively.

Member’s Equity

At September 24, 2009, member’s equity included Aneth, WYNR, BWNR and Resources.

Incentive Interests

Resources

“Incentive Units” were granted by Holdings to certain of its members who were also officers, as well as to other employees of Resources. The Incentive Units were intended to be compensation for services provided to Resources. The original terms of the five tiers of Incentive Units are as follows. Tier I units vest ratably over three years, but are subject to forfeiture if payout is not realized. Tier I payout is realized at the return of members’ invested capital and a specified rate of return. Tiers II through V vest upon certain specified multiples of cash payout. Incentive Units are forfeited if an employee of Predecessor Resolute is either terminated for cause or resigns as an employee. Any Incentive Units that are forfeited by an individual employee revert to the founding senior managers of Predecessor Resolute and, therefore, the number of Tier II through V Incentive Units is not expected to change.

On June 27, 2007, Holdings made a capital distribution of $100 million to its equity owners from the proceeds of the Second Lien Facility. This distribution caused both the Tier I payout to be realized and the Tier I Incentive Units to vest. As a result of the distribution, management determined that it was probable that Tiers II-V incentive unit payouts would be achieved.

Predecessor Resolute recorded $2.8 million of equity based compensation expense in general and administrative expense in the combined statements of operations for 2009. No equity compensation expense was capitalized in 2009.

Predecessor Resolute amortizes the estimated fair value of the Incentive Units over the remaining estimated vesting period using the straight-line method. The estimated weighted average fair value remaining of the Incentive Units was calculated using a discounted future net cash flows model. No Incentive Units vested during 2009 and there were no grants or forfeitures during 2009.

Total unrecognized compensation cost related to Predecessor Resolute’s non-vested Incentive Units totaled $5.3 million as of September 24, 2009. Total unrecognized compensation cost related to Predecessor Resolute’s non-vested Incentive Units as of September 24, 2009 is expected to be recognized over weighted-average periods of 0.75 years, 1.75 years, 2.75 years and 2.75 years for the Tier II, Tier III, Tier IV and Tier V Incentive Units, respectively.

Equity Appreciation Rights

In November 2006 and May 2008, 2,500,000 and 3,000,000 Equity Appreciation Rights (“EARs”) were authorized, respectively. The EARs are periodically granted by Sub to certain of Predecessor Resolute’s employees. The EARs represent contract rights to a certain portion of future distributions of cash by Sub.

F-37

Upon consummation of the Acquisition Agreement on September 25, 2009 the EARs plan was cancelled. Predecessor Resolute has not assigned any value or recognized any share based compensation expense related to the EARs because no distributions were made in respect of such EARs prior to the plan termination.

On May 29, 2008, Resources, on behalf of Sub, entered into Agreements with several employees permitting those employees to make an offer to exchange for cash some or all of the EARs issued in 2007 and prior under the EARs Plan, dated November 27, 2006. The participant could elect to offer to exchange all or any portion of their EARs for time vested cash awards equal to $2.00 per unit plus simple interest of 15% per annum, effective January 1, 2008.

Also on May 29, 2008, Resources, on behalf of Sub, granted incentive awards allowing employees to elect to receive a certain number of EARs or an amount of time vested cash awards of $1.00 per unit plus simple interest of 15% per annum, effective January 1, 2008.

All of the cash awards are payable in three installments on January 1, 2009, 2010 and 2011. Compensation expense related to the time vested cash awards of $0.2 million was recognized, during 2009. The time vested cash awards are accounted for as deferred compensation. The annual payments are paid based on the employee’s tenure with Resources and there is potential for forfeiture of the time vested payment, therefore Predecessor Resolute will accrue for each time vested payment and related return for the respective year on an annual basis.

A summary of the activity associated with the EARs plan during 2009 is as follows:

		September 30,
	EARs
January 1, 2009		3,076,000
Forfeited		(113,000	)

September 24, 2009		2,963,000

The EARs plan was terminated on September 25, 2009, and all outstanding EARs were cancelled due to the Resolute Transaction. The time vested cash awards were not terminated.

Note 7 — Defined Contribution Plan

Predecessor Resolute offers a 401(k) plan for all eligible employees. For the period ended September 24, 2009, Predecessor Resolute made no contributions in connection with matching of employee contributions made in 2009.

Note 8 — Derivative Instruments

Predecessor Resolute enters into commodity derivative contracts to manage its exposure to oil and gas price volatility. Predecessor Resolute has not elected to designate derivative instruments as cash flow hedges under the provisions of FASB ASC Topic 815, Derivatives and Hedging. As a result, these derivative instruments are marked to market at the end of each reporting period and changes in the fair value are recorded in the accompanying combined statements of operations. Realized and unrealized gains and losses from Predecessor Resolute’s price risk management activities are recognized in other income (expense), with realized gains and losses recognized in the period in which the related production is sold. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as financing activities in the statement of cash flows. Commodity derivative contracts may take the form of futures contracts, swaps or options.

As of September 24, 2009, Predecessor Resolute had entered into certain commodity swap contracts. The following table represents Predecessor Resolute’s commodity swaps with respect to its estimated oil and gas production from proved developed producing properties through 2013:

		September 30,		September 30,		September 30,		September 30,
Year	Bbl per Day		Oil (NYMEX WTI) Weighted Average Hedge Price per Bbl		MMBtu per Day		Gas (NYMEX HH) Weighted Average Hedge Price per MMBtu
2009		3,900	$	62.75		1,800	$	9.93
2010		3,650	$	67.24		3,800	$	9.69
2011		3,250	$	68.26		2,750	$	9.32
2012		3,250	$	68.26		2,100	$	7.42
2013		2,000	$	60.47		1,900	$	7.40

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Predecessor Resolute also uses basis swaps in connection with gas swaps in order to fix the price differential between the NYMEX Henry Hub price and the index price at which the gas production is sold. The table below sets forth Predecessor Resolute’s outstanding basis swaps as of September 24, 2009.

	September 30,		September 30,		September 30,
Year	Index	MMBtu per Day		Weighted Average Hedged Price Differential per MMBtu
2009 – 2013	Rocky Mountain NWPL		1,800	$	2.10

As of September 24, 2009, Predecessor Resolute had entered into certain commodity collar contracts. The following table represents Predecessor Resolute’s commodity collars with respect to its estimated oil and gas production from proved developed producing properties:

		September 30,		September 30,		September 30,		September 30,
Year	Bbl per Day		Oil (NYMEX WTI) Weighted Average Hedge Price per Bbl		MMBtu per Day		Gas (NYMEX HH) Weighted Average Hedge Price per MMBtu
2009		250	$	105.00-151.00		3,288	$	5.00-9.35
2010		200	$	105.00-151.00		—		—

Predecessor Resolute’s derivative instruments are not designated and do not qualify as hedging instruments under FASB ASC Topic 815, the gains and losses are included in other income (expense) in the combined statements of operations. The table below summarizes the location and amount of commodity derivative instrument gains and losses reported in the combined statements of operations for the periods presented below (in thousands):

		September 30,
	Period ended September 24,
	2009
Other income (expense)
Realized gains	$	1,939
Unrealized losses		(25,458	)

Total: gain (loss) on derivative instruments	$	(23,519	)

Credit Risk and Contingent Features in Derivative Instruments

Predecessor Resolute is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above. With the exception of one contract, all counterparties are also lenders under Predecessor Resolute’s First Lien Facility. For these contracts, Predecessor Resolute is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the First Lien Facility. The counterparty that is not among Predecessor Resolute’s lenders is a multinational energy company with a corporate credit rating of AA as classified by Standard and Poor’s. Predecessor 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. Predecessor Resolute has set-off provisions with its lenders that, in the event of counterparty default, allow Predecessor Resolute to set-off amounts owed under the First Lien Facility or other general obligations against amounts owed for derivative contract liabilities.

Note 9 — Fair Value Measurements

FASB ASC Topic 820, Fair Value Measurements and Disclosures clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements.

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FASB ASC Topic 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exact price) in an orderly transaction between market participants at the measurement date. The statement 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 statement establishes a hierarchy for grouping these 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 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. Predecessor 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 Predecessor Resolute as well as the general classification of such instruments pursuant to the hierarchy.

As of September 24, 2009, Predecessor Resolute’s commodity derivative instruments were required to be measured at fair value. Predecessor 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.

Note 10 — Commitments and Contingencies

CO₂ Take-or-Pay Agreements

Resolute entered into two take-or-pay purchase agreements, each with a different supplier, under which Resolute has committed to buy specified volumes of CO₂. The purchased CO₂is for use in Resolute’s enhanced tertiary recovery projects in Aneth Field. In each case, Resolute is obligated to purchase a minimum daily volume of CO₂ or pay for any deficiencies at the price in effect when delivery was to have occurred. The CO₂volumes planned for use on the enhanced recovery projects exceed the minimum daily volumes provided in this take-or-pay purchase agreement. Therefore, Resolute expects to avoid any payments for deficiencies. Predecessor Resolute acquired $8.9 million of CO₂during the period ended September 24, 2009. One contract was effective July 1, 2006, with a four year term. The second contract was entered into on May 25, 2005, and was amended on July 1, 2007, and had a ten year term.

Operating Leases

For the period ended September 24, 2009, month-to-month office facilities rental payments charged to expense under the terms of non-cancelable operating leases was approximately $0.5 million.

Predecessor Resolute is also party to several field equipment and compressor leases used in the CO₂project. Rental expense for these leases for 2009 was $1.3 million.

NNOG Purchase Options.

In connection with acquisition of 75% of the ExxonMobil interests in Aneth Field and various other related assets (the “ExxonMobil Properties”) and the acquisition from Chevron Corporation and its affiliates (“Chevron”) of 75% of Chevron’s interest in Aneth Field (“Chevron Properties”) in 2005, pursuant to the terms of the Cooperative Agreement, Predecessor Resolute granted to NNOG three separate but substantially similar purchase options. Each purchase option entitles NNOG to purchase from Predecessor Resolute up to 10% of Predecessor Resolute’s interest in the Chevron Properties and the ExxonMobil Properties. Each purchase option entitles NNOG to purchase, for a limited period of time, the applicable portion of Predecessor Resolute’s interest in the Chevron Properties and the ExxonMobil Properties, at Fair Market Value (as defined in the agreement), which is determined without giving effect to the existence of the Navajo Nation preferential purchase right or the fact that the properties are located within the Navajo Nation. Each option becomes exercisable based upon Predecessor Resolute’s achieving a certain multiple of payout of the relevant acquisition costs, subsequent capital costs and ongoing operating costs attributable to the applicable working interests. Revenue applicable to the determination of payout includes the effect of Predecessor Resolute’s hedging program. The options are not exercisable prior to four years from the acquisition except in the case of a sale of such assets by, or a change of control of, Aneth. In that case, the first option for 10% would be accelerated and the other options would terminate. Assuming the purchase options are not accelerated due to a change of control of Aneth, Predecessor Resolute expects that the initial payout associated with the purchase options granted will occur no sooner than 2013.

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		September 30,			September 30,			September 30,
				McElmo			Ratherford
	Aneth Unit			Creek Unit			Unit

Chevron Properties:
Option 1 (100% Payout)		5.30	%		1.50	%		0.30	%
Option 2 (150% Payout)		5.30	%		1.50	%		0.30	%
Option 3 (200% Payout)		5.30	%		1.50	%		0.30	%

Total		15.90	%		4.50	%		0.90	%

		September 30,			September 30,			September 30,
				McElmo			Ratherford
	Aneth Unit			Creek Unit			Unit

ExxonMobil Properties:
Option 1 (100% Payout)		0.75	%		6.00	%		5.60	%
Option 2 (150% Payout)		0.75	%		6.00	%		5.60	%
Option 3 (200% Payout)		0.75	%		6.00	%		5.60	%

Total		2.25	%		18.00	%		16.80	%

Crude Production Purchase Agreement

Predecessor Resolute sells all of its crude oil production from the Aneth field to a single customer, Western Refining Southwest, Inc. (“Western”), a subsidiary of Western Refining, Inc. Predecessor Resolute and Western entered into a new contract on August 27, 2009 effective September 1, 2009. The new contract provides for a minimum price equal to the NYMEX price for crude oil less a fixed differential of $6.25 per Bbl. The contract provides for an initial term of one year and continuing month-to-month thereafter, with either party having the right to terminate after the initial term, upon ninety days written notice. The contract may also be terminated by Western after December 31, 2009, upon sixty days written notice, if Western is not able to renew its right-of-way agreements with the Navajo Nation or if such rights-of-way are declared invalid and Western is prevented from using such rights-of-way.

Note 11 — Oil And Gas Producing Activities

Costs incurred in oil and gas property acquisition, exploration and development activities are summarized as follows (in thousands):

		September 30,
	Period Ended September 24,
	2009
Development costs	$	15,018
Exploration		10
Acquisitions:
Proved		209
Unproved		113

Total	$	15,350

Note 12 — Supplemental Oil and Gas Information (unaudited)

Oil and Gas Reserve Quantities:

The following table presents our estimated net proved oil and gas reserves and the present value of such estimated net proved reserves as of September 24, 2009. Users of this information should be aware that the process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions to be made in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure reserves estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosure.

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Presented below is a summary of the changes in estimated reserves (in thousands):

		September 30,			September 30,			September 30,
	Oil (Bbl) ⁽²⁾			Gas (Mcf)			Oil Equivalent (Boe)
Proved reserves as of January 1, 2009:		46,370			17,781			49,334
Production		(1,464	)		(2,971	)		(1,959	)
Extensions, discoveries and other additions		3,154			17,113			6,007
Revisions of previous estimates ⁽¹⁾		23,881			20,278			27,261

Proved reserves as of September 24, 2009		71,941			52,201			80,643

Proved developed reserves:
As of September 24, 2009		46,105			17,675			49,050

1)	The oil and gas revisions are attributable to the changes in prices of oil and gas.

2)	Includes NGL volumes.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:

The following summarizes the policies used in the preparation of the accompanying oil and gas reserves disclosures, standardized measures of discounted future net cash flows from proved oil and gas reserves and the reconciliations of standardized measures from year to year. The information disclosed is an attempt to present the information in a manner comparable with industry peers.

The information is based on estimates of proved reserves attributable to Predecessor Resolute’s interest in oil and gas properties as of September 24, 2009. Proved reserves are estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

Estimates were made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions.

The estimated future cash flows was compiled by applying year-end prices of crude oil and gas relating to Resolute’s proved reserves to the year-end quantities of those reserves.

The future cash flows were reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions.

Future net cash flows were discounted to present value by applying a discount rate of 10%.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of Predecessor Resolute’s oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

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The following summary sets forth Resolute’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed by FASB ASC Topic 932, Extractive Activities — Oil and Gas:

		September 30,
	Period Ended
	September 24, 2009
	(in, thousands)
Future cash inflows	$	4,476,000
Future production costs		(1,663,000	)
Future development costs		(555,000	)
Future income taxes (1)		(10,000	)

Future net cash flows		2,248,000
10% annual discount for estimating timing of cash flows		(1,462,000	)

Standardized measure of discounted future net cash flows	$	786,000

(1)	Future income taxes are related to RWI’s oil and gas properties. Aneth is a pass through entity, therefore, there are no future income taxes associated with its oil and gas properties.

The principal sources of change in the standardized measure of discounted future net cash flows are:

		September 30,
	September 24,
	2009
	(in thousands)
Standardized measure, beginning of period	$	248,000
Sales of oil and gas produced, net of production costs		(33,000	)
Net changes in prices and production costs		319,000
Extensions, discoveries and other, including infill reserves in an existing proved field, net of production costs		8,000
Improved recoveries		—
Purchase of minerals in place		—
Previously estimated development cost incurred during the period		12,000
Changes in estimated future development costs		(151,000	)
Revisions of previous quantity estimates		352,000
Accretion of discount		18,000
Net change in income taxes		(3,000	)
Changes in timing and other		16,000

Standardized measure, end of period	$	786,000

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