Edgar Filing: Resolute Energy Corp

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2014

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

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)

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 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). ¨ No x

As of April 30, 2014, 77,921,375 shares of the Registrant’s $0.0001 par value Common Stock were outstanding.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q 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 development opportunities; expectations regarding our development activities and drilling plans, particularly with respect to our Permian Properties (as defined in this Quarterly Report), the expected benefits to be realized from newly acquired properties including our ability to achieve the growth we expect from acquisitions; our plans for capital expenditures and the sources of such funding. Although we believe that these statements are based upon reasonable current assumptions, no assurance can be given that the future results covered by the forward-looking statements will be achieved. Forward-looking statements can be subject to risks, uncertainties and other factors that could cause actual results to differ materially from future results expressed or implied by the forward-looking statements. The forward-looking statements in this report are primarily located under the heading “Risk Factors.” 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, if any, in our Annual Report on Form 10-K for the year ended December 31, 2013, and such things as:

•

risks associated with all of our Aneth field oil production being purchased by a single customer and connected to such customer with a pipeline that we do not own or control;

•

volatility of oil and gas prices, including reductions in prices that would adversely affect our revenue, income, cash flow from operations and liquidity and the 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;

•

our relationship with the Navajo Nation, the local community in the area where we operate Aneth Field, and Navajo Nation Oil and Gas Company, as well certain purchase rights held by Navajo Nation Oil and Gas Company;

•

potential delays in the upgrade of third-party electrical infrastructure serving Aneth Field and potential power supply limitations;

•

a lack of available capital and financing, including the capital needed to pursue our production and other plans for our properties, on acceptable terms, including as a result of a reduction in the borrowing base under our credit facility;

•

the effectiveness and results of our CO₂ flood program at Aneth Field;

•

the impact of U.S. and global economic recession;

•

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

•

the success of the development plan for and production from our oil and gas properties;

•

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

•

the completion, timing and success of exploratory drilling on our properties;

•

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

•

risks and uncertainties in the application of available horizontal drilling and completion techniques;

•

uncertainty surrounding occurrence and timing of identifying drilling locations and necessary capital to drill such locations;

•

our ability to fund and develop our estimated proved undeveloped reserves;

•

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;

•

the concentration of our producing properties in a limited number of geographic areas;

•

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

•

our relationships with the local communities in the areas where we operate;

•

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

•

the availability of water and our ability to adequately treat and dispose of water after drilling and completing wells;

•

potential changes to regulations affecting derivatives instruments;

•

the success of our derivatives program;

•

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

•

environmental liabilities under existing or future laws and regulations;

•

developments in oil and gas producing countries;

•

loss of senior management or key technical personnel;

•

timing of issuance of permits and rights of way, including the effects of any government shut-downs;

•

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

•

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

•

our ability to achieve the growth and benefits we expect from our acquisitions;

•

risks associated with unanticipated liabilities assumed, or title, environmental or other problems resulting from, our acquisitions;

•

acquisitions and other business opportunities (or the lack thereof) that may be presented to and pursued by us, and the risk that any opportunity currently being pursued will fail to consummate or encounter material complications;

•

risks related to our level of indebtedness;

•

our ability to fulfill our obligations under the senior notes;

•

constraints imposed on our business and operations by our credit agreement and our senior notes to generate sufficient cash flow to repay our debt obligations;

•

losses possible from pending or future litigation;

•

risk factors discussed or referenced in this report; and

•

other factors, many of which are beyond our control.

Additionally, the SEC requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and governmental regulations. The SEC permits the optional disclosure of probable and possible reserves. From time to time, we may elect to disclose “probable” reserves and “possible” reserves, excluding their valuation, in our SEC filings, press releases and investor presentations. The SEC defines “probable” reserves as “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC defines “possible” reserves as “those additional reserves that are less certain to be recovered than probable reserves.” The Company applies these definitions when estimating probable and possible reserves. Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates or potential resources provided in our public filings, press releases and investor presentations that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s reserves reporting guidelines.

The SEC’s rules prohibit us from including resource estimates in our public filings with the SEC. Our potential resource estimations include estimates of hydrocarbon quantities for (i) new areas for which we do not have sufficient information to date to classify as proved, probable or even possible reserves, (ii) other areas to take into account the low level of certainty of recovery of the resources and (iii) uneconomic proved, probable or possible reserves. Potential resource estimates do not take into account the certainty of resource recovery and are therefore not indicative of the expected future recovery and should not be relied upon for such purpose. Potential resources might never be recovered and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors. In our press releases and investor presentations, we sometimes include estimates of quantities of oil and gas using certain terms, such as “resource,” “resource potential,” “EUR,” “oil in place,” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC definition of proved, probable and possible reserves. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Resolute. The Company believes its potential resource estimates are reasonable, but such estimates have not been reviewed by independent engineers. Furthermore, estimates of potential resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.

Finally, 24 hour peak IP rates and 30 day peak IP rates for both our wells and for those wells that are located near to our properties are limited data points in each well’s productive history and not necessarily indicative or predictive of future production rates, EUR or economic rates of return from such wells and should not be relied upon for such purpose.

You are urged to consider closely the disclosure in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 2013, in particular the factors described under “Risk Factors.”

TABLE OF CONTENTS


PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			15

Item 3. Quantitative and Qualitative Disclosures About Market Risk			22

Item 4. Controls and Procedures			23

PART II - OTHER INFORMATION

Item 1. Legal Proceedings			24

Item 1 A. Risk Factors			24

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			24

Item 3. Defaults Upon Senior Securities			24

Item 4. Mine Safety Disclosures			24

Item 5. Other Information			24

Item 6. Exhibits			25

Signatures			26

RESOLUTE ENERGY CORPORATION

Condensed Consolidated Balance Sheets (UNAUDITED)

(in thousands, except share amounts)


	March 31,			December 31,
	2014			2013
Assets
Current assets:
Cash and cash equivalents	$	900		$	19
Accounts receivable		66,845			94,358
Deferred income taxes		8,177			8,330
Derivative instruments		493			1,378
Prepaid expenses and other current assets		1,138			1,152

Total current assets		77,553			105,237

Property and equipment, at cost:
Oil and gas properties, full cost method of accounting
Unproved		282,796			274,420
Proved		1,571,411			1,544,942
Other property and equipment		9,183			8,069
Accumulated depletion, depreciation and amortization		(525,889	)		(494,642	)

Net property and equipment		1,337,501			1,332,789

Other assets:
Restricted cash		18,220			18,219
Deferred financing costs		11,615			12,265
Other assets		615			299

Total assets	$	1,445,504		$	1,468,809

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	20,164		$	32,601
Accrued expenses		77,715			81,478
Accrued interest payable		14,240			5,739
Asset retirement obligations		1,812			1,825
Derivative instruments		13,263			11,955

Total current liabilities		127,194			133,598

Long term liabilities:
Credit facility		320,000			335,000
Senior notes, net of accumulated premium amortization of $255 at March 31, 2014 and $204 at December 31, 2013		401,620			401,671
Asset retirement obligations		30,665			30,164
Deferred income taxes		33,565			34,824
Other long term liabilities		992			—

Total liabilities		914,036			935,257

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 77,912,813 and 76,228,055 shares at March 31, 2014 and December 31, 2013, respectively		8			8
Additional paid-in capital		633,286			631,822
Accumulated deficit		(101,826	)		(98,278	)

Total stockholders’ equity		531,468			533,552

Total liabilities and stockholders’ equity	$	1,445,504		$	1,468,809

See notes to condensed consolidated financial statements

-1-

RESOLUTE ENERGY CORPORATION

Condensed Consolidated Statements of Operations (UNAUDITED)

(in thousands, except per share data)


	Three Months Ended March 31,
	2014			2013
Revenue:
Oil	$	80,605		$	72,936
Gas		7,986			4,535
Natural gas liquids		2,287			1,426

Total revenue		90,878			78,897

Operating expenses:
Lease operating		28,654			25,212
Production and ad valorem taxes		10,598			10,223
Depletion, depreciation, amortization, and asset retirement obligation accretion		31,908			24,882
General and administrative		8,643			8,568

Total operating expenses		79,803			68,885

Income from operations		11,075			10,012

Other income (expense):
Interest expense, net		(7,796	)		(8,081	)
Commodity derivative instruments loss		(7,934	)		(6,786	)
Other income		1			3

Total other expense		(15,729	)		(14,864	)

Loss before income taxes		(4,654	)		(4,852	)
Income tax benefit		1,106			1,803

Net loss	$	(3,548	)	$	(3,049	)

Net loss per common share:
Basic and diluted	$	(0.05	)	$	(0.05	)
Weighted average common shares outstanding:
Basic and diluted		73,540			59,802

See notes to condensed consolidated financial statements

-2-

RESOLUTE ENERGY CORPORATION

Condensed Consolidated Statements of Stockholders’ Equity (UNAUDITED)

(in thousands)


	Common Stock					Additional Paid-in						Total Stockholders’
	Shares			Amount		Capital			Accumulated Deficit			Equity
Balance as of January 1, 2014		76,228		$	8	$	631,822		$	(98,278	)	$	533,552
Issuance of stock, restricted stock and share-based compensation		1,868			—		2,956			—			2,956
Redemption of restricted stock for employee income tax and restricted stock forfeitures		(183	)		—		(1,492	)		—			(1,492	)
Net loss		—			—		—			(3,548	)		(3,548	)

Balance as of March 31, 2014		77,913		$	8	$	633,286		$	(101,826	)	$	531,468

See notes to condensed consolidated financial statements

-3-

RESOLUTE ENERGY CORPORATION

Condensed Consolidated Statements of Cash Flows (UNAUDITED)

(in thousands)


	Three Months Ended March 31,
	2014			2013
Operating activities:
Net loss	$	(3,548	)	$	(3,049	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation, amortization and asset retirement obligation accretion		31,908			24,882
Amortization of deferred financing costs and senior notes premium		599			603
Share-based compensation		2,890			2,502
Commodity derivative instruments loss		7,934			6,786
Commodity derivative settlements		(4,750	)		(6,892	)
Deferred income taxes		(1,106	)		(1,803	)
Change in operating assets and liabilities:
Accounts receivable		27,570			(12,820	)
Other current assets		24			788
Accounts payable and accrued expenses		(7,370	)		8,535
Accrued interest payable Accrued interest payable		8,501			8,859

Net cash provided by operating activities		62,652			28,391

Investing activities:
Oil and gas exploration and development expenditures `		(48,998	)		(43,531	)
Purchase of oil and gas properties		—			(256,977	)
Proceeds from sale of oil and gas properties and other		4,805			50,222
Purchase of other property and equipment		(1,114	)		(398	)
Restricted cash		(1	)		1,843
Other		29			(4,978	)

Net cash used in investing activities		(45,279	)		(253,819	)

Financing activities:
Proceeds from bank borrowings		106,000			279,000
Repayments of bank borrowings		(121,000	)		(51,000	)
Redemption of restricted stock for employee income taxes		(1,492	)		—
Payment of financing costs		—			(1,865	)

Net cash provided by (used in) financing activities		(16,492	)		226,135

Net increase in cash and cash equivalents		881			707
Cash and cash equivalents at beginning of period		19			934

Cash and cash equivalents at end of period	$	900		$	1,641

See notes to condensed consolidated financial statements

-4-

RESOLUTE ENERGY CORPORATION

Notes to Condensed Consolidated Financial Statements

Note 1 — Organization and Nature of Business

Resolute Energy Corporation (“Resolute” or the “Company”), is an independent oil and gas company engaged in the exploitation, development, exploration for and acquisition of oil and gas properties. The Company’s asset base is comprised of properties in Aneth Field located in the Paradox Basin in southeast Utah (the “Aneth Field Properties” or “Aneth Field”), the Permian Basin in west Texas and southeast New Mexico and the Big Horn and Powder River Basins in Wyoming. The Company conducts all of its activities in the United States of America.

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

Basis of Presentation

The unaudited condensed consolidated financial statements include Resolute and its subsidiaries, and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and Regulation S-X for interim financial reporting. Except as disclosed herein, there has been no material change in our basis of presentation from the information disclosed in the notes to Resolute’s consolidated financial statements for the year ended December 31, 2013. In the opinion of management, all adjustments consisting of normal recurring accruals considered necessary for a fair presentation of the interim financial information have been included. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. 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 condensed consolidated financial statements, Resolute evaluated subsequent events that occurred after the balance sheet date, through the date of filing.

Significant Accounting Policies

The significant accounting policies followed by Resolute are set forth in Resolute’s consolidated financial statements for the year ended December 31, 2013. These unaudited condensed consolidated financial statements are to be read in conjunction with the consolidated financial statements appearing in Resolute’s Annual Report on Form 10-K and related notes for the year ended December 31, 2013.

Assumptions, Judgments and Estimates

The preparation of the condensed 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.

Significant estimates with regard to the condensed consolidated financial statements include proved oil and gas reserve volumes and the related present value of estimated future net cash flows used in the ceiling test applied to capitalized oil and gas properties; asset retirement obligations; valuation of derivative assets and liabilities; the estimated fair value and allocation of the purchase price related to business combinations; share-based compensation expense; depletion, depreciation and amortization; accrued liabilities; revenue and related receivables and income taxes.

Oil and Gas Properties

The Company uses the full cost method of accounting for its oil and gas operations. Accounting rules require Resolute to perform a quarterly “ceiling test” calculation to test its oil and gas properties for possible impairment. The primary components affecting this calculation are commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. If the net capitalized cost of the Company’s oil and gas properties subject to amortization (the “carrying value”) exceeds the ceiling limitation, the excess would be charged to expense. The ceiling limitation is equal to the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects.

At March 31, 2014, the calculated value of the ceiling limitation exceeded the carrying value of Resolute’s oil and gas properties subject to the test and no impairment was necessary. However, if there is a negative impact on one or more of the components of the calculation, including market prices of oil and gas, including differentials from posted prices, future drilling and capital plans, operating costs or expected production, the Company may incur a full cost ceiling impairment related to its oil and gas properties in future periods.

-5-

Note 3 — Acquisitions and Divestitures

Permian Property Acquisitions

On December 28, 2012, the Company purchased properties in the Wolfberry play in the Midland Basin portion of the Permian Basin in Midland and Ector counties, Texas, for a purchase price of approximately $133 million. Concurrently with that transaction, the Company acquired, for additional consideration of $6 million, the option to buy the balance of the working interest in and operatorship of the properties under substantially the same terms as the initial transaction (the “Option Properties”). On March 22, 2013, the Company exercised the option and acquired the Option Properties for $258 million, net of the option fee, after customary purchase price adjustments, which were estimated at closing. Revenue and expenses related to the acquired properties are included in the consolidated statement of operations beginning on the closing date of the respective transaction. Together, the December 2012 and March 2013 acquisitions, which the Company refers to as the “Permian Acquisitions,” were accounted for using the acquisition method.

The purchase price of the Option Properties was comprised of the following (in thousands):


	2013
Purchase price	$	258,000

The Company has completed its assessment of the fair values of the assets acquired and liabilities assumed. Accordingly, the following table presents the final purchase price allocation of the Option Properties at December 31, 2013, based on the fair values of assets acquired and liabilities assumed (in thousands):


	2013
Proved oil and gas properties	$	93,000
Unproved oil and gas properties		167,000
Asset retirement obligations assumed		(2,000	)

Total purchase price	$	258,000

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 purchase of the Option Properties in March 2013 had occurred on January 1, 2013. 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 of the Option Properties had taken place at the beginning of the earliest periods presented or that may result in the future. The pro forma adjustments made utilize certain assumptions that Resolute believes are reasonable based on the available information.

The unaudited pro forma financial information for the quarter ended March 31, 2013, combine the historical results of the Option Properties and Resolute (in thousands, except per share amounts):


	Three Months Ended March 31, 2013
Revenue	$	89,955
Revenue in excess of operating expenses		52,634
Net loss		(486	)
Basic and diluted net loss per share	$	(0.01	)

Aneth Field Transactions

During the second quarter of 2012, Resolute and Navajo Nation Oil and Gas Company (“NNOGC”) entered into an amendment to their Cooperative Agreement. Among other changes, this amendment allowed NNOGC to exercise options to purchase 10% of the Company’s interest in the Aneth Field Properties. These options were exercised for cash consideration of $100 million. Resolute entered into a purchase and sale agreement relating to the exercise of the options which provided that the transaction be closed and paid for in two equal transfers, each for 5% of Resolute’s interest in the properties. The first transfer took place in July 2012 and the second transfer took place in January 2013, each with an effective date of January 1, 2012.

-6-

The Cooperative Agreement amendment also provides for the cancellation of a second set of options held by NNOGC to purchase an additional 10% interest in the Aneth Field Properties and stipulates that NNOGC has one remaining option to purchase an additional 10% of Resolute’s interest in the Aneth Field Properties. The remaining option is exercisable in July 2017 at the then-current fair market value of such interest at that time. No gain or loss was recognized upon these sales as it did not represent a significant portion of the Company’s oil and gas properties and did not significantly alter the relationship of capitalized costs and proved reserves.

Sale of New Home Properties

On June 27, 2013, the Company entered into a purchase and sale agreement with HRC Energy, LLC, a Colorado limited liability company, and a wholly-owned subsidiary of Halcón Resources Corporation, a Delaware corporation, effective March 1, 2013, to dispose of certain Bakken properties located in Williams County, North Dakota (the “New Home Properties”) and other non-operated Bakken properties for proceeds of $70.1 million. The transaction closed on July 15, 2013, and net proceeds received were recorded as a reduction to the capitalized costs of the Company’s oil and gas properties.

Note 4 — Earnings per Share

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 which 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):


	Three Months Ended March 31,
	2014		2013
Potential dilutive warrants		—		—
Potential dilutive restricted stock		2,826		1,634
Anti-dilutive securities		35,867		34,675

The following table sets forth the computation of basic and diluted net loss per share of common stock for the three months ended March 31, 2014 and 2013 (in thousands, except per share amounts):


	Three Months Ended March 31,
	2014			2013
Net loss	$	(3,548	)	$	(3,049	)
Basic weighted average common shares outstanding		73,540			59,802
Add: dilutive effect of non-vested restricted stock		—			—
Add: dilutive effect of outstanding warrants		—			—

Diluted weighted average common shares outstanding		73,540			59,802

Basic and diluted net loss per common share	$	(0.05	)	$	(0.05	)

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Note 5 — Long Term Debt

As of the dates indicated, the Company’s long-term debt consisted of the following (in thousands):


	March 31,		December 31,
	2014		2013
Credit facility	$	320,000	$	335,000
Senior notes		400,000		400,000
Unamortized premium on senior notes		1,620		1,671

Total long-term debt	$	721,620	$	736,671

Credit Facility

Resolute’s credit facility is with a syndicate of banks led by Wells Fargo Bank, National Association, as Administrative Agent, and Bank of Montreal, as Syndication Agent (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. 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.

In March 2013, and in connection with the purchase of the Option Properties, the Company entered into the Sixth Amendment to the amended and restated Credit Facility agreement, resulting in a borrowing base increase to $485 million, consisting of a $445 million conforming tranche and a $40 million non-conforming tranche (which expired on May 14, 2013). The Sixth Amendment, among other things, also extended the maturity date of the revolving Credit Facility from April 2017 to March 2018. On March 7, 2014, the Company entered into the Ninth Amendment to the amended and restated Credit Facility which redefined and adjusted the Maximum Leverage Ratio to (a) 4.90:1.00 for the fiscal quarters ending March 31, 2014, and June 30, 2014, (b) 4.75:1.00 for the fiscal quarters ending September 30, 2014, and December 31, 2014, and (c) 4.00:1.00 for all quarters thereafter. The Ninth Amendment also provided that as of the last day of each fiscal quarter in 2014, the ratio of senior secured debt as of such date to Adjusted EDITDA for the four quarter period ending on such date may not exceed 2.75:1.00.

Each base rate borrowing under the Credit Facility accrues interest at either (a) the London Interbank Offered Rate, plus a margin which varies from 1.50% to 2.50% (or 3.0% if the Company utilizes any portion of the non-conforming tranche) 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 (“LIBOR”) plus a margin which ranges from 0.50% to 1.50% (or 2.0% if the Company utilizes any portion of the non-conforming tranche). Each such margin is based on the level of utilization under the borrowing base. In March 2014, the Company entered into the Tenth Amendment to the amended and restated Credit Facility agreement. In connection with the Tenth Amendment, the semi-annual redetermination of the Company’s borrowing base was completed, resulting in a borrowing base of $425 million, consisting of a $400 million conforming tranche and a $25 million non-conforming tranche (which non-conforming tranche will expire no later than the Company’s next borrowing base redetermination date). The Tenth Amendment also required that the Company enter into commodity derivative agreements by March 31, 2014, on production of not less than 5,100 barrels of oil per day in the aggregate for the fiscal year ending December 31, 2015, at a weighted average price floor of not less than $84.17 per barrel. This requirement was satisfied in the first quarter of 2014.

As of March 31, 2014, outstanding borrowings were $320 million under the borrowing base of $425 million. The borrowing base availability had been reduced by $3.1 million in conjunction with letters of credit issued to vendors at March 31, 2014. 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 Resolute Aneth, LLC, Resolute Wyoming, Inc. and Resolute Natural Resources Southwest, LLC, which are wholly-owned subsidiaries of the Company.

As of March 31, 2014, the weighted average interest rate on the outstanding balance under the Credit Facility was 2.41%. The recorded value of the Credit Facility approximates its fair market value because the interest rate of the Credit Facility is variable over the term of the loan (Level 2 fair value measurement).

The Credit Facility includes customary 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 March 31, 2014.

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.

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Senior Notes

In April 2012, the Company consummated a private placement of senior notes with a principal amount of $250 million, and in December 2012 placed a follow-on issuance of senior notes with a principal amount of $150 million. The Senior Notes are due May 1, 2020, and bear an annual interest rate of 8.50% with the interest on the Notes payable semiannually in cash on May 1 and November 1 of each year.

The Senior Notes were issued under an Indenture (the “Indenture”) among the Company, the Company’s existing subsidiaries (the “Guarantors”) and U.S. Bank National Association, as trustee (the “Trustee”) in a private transaction not subject to the registration requirements of the Securities Act of 1933. In March 2013, the Company registered the Senior Notes with the Securities and Exchange Commission by filing an amendment to the registration statement on Form S-4 enabling holders of the Senior Notes to exchange the privately placed Notes for publically registered Notes with substantially identical terms. The Indenture contains affirmative and negative covenants that, among other things, limit the Company’s and the Guarantors’ ability to make investments, incur additional indebtedness or issue preferred stock, create liens, sell assets, enter into agreements that restrict dividends or other payments by restricted subsidiaries, consolidate, merge or transfer all or substantially all of the assets of the Company, engage in transactions with the Company’s affiliates, pay dividends or make other distributions on capital stock or prepay subordinated indebtedness and create unrestricted subsidiaries. The Indenture also contains customary events of default. Upon occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the Trustee or the holders of the Senior Notes. Upon the occurrence of certain other events of default, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under its Senior Notes as of March 31, 2014.

The Senior Notes are general unsecured senior obligations of the Company and guaranteed on a senior unsecured basis by the Guarantors. The Senior Notes rank equally in right of payment with all existing and future senior indebtedness of the Company, will be subordinated in right of payment to all existing and future senior secured indebtedness of the Guarantors, will rank senior in right of payment to any future subordinated indebtedness of the Company and will be fully and unconditionally guaranteed by the Guarantors on a senior basis.

The Senior Notes are redeemable by the Company on or after May 1, 2016, on not less than 30 or more than 60 days’ prior notice, at redemption prices set forth in the Indenture. In addition, at any time prior to May 1, 2015, the Company may use the net proceeds from equity offerings and warrant exercises to redeem up to 35% of the principal amount of Notes issued under the Indenture at a redemption price equal to 108.50% of the principal amount of the Notes redeemed, plus accrued and unpaid interest. The Senior Notes may also be redeemed at any time prior to May 1, 2016, at the option of the Company at a redemption price equal to 100% of the principal amount of the Notes redeemed plus the applicable premium, and accrued and unpaid interest and additional interest, if any, to the applicable redemption date as set forth in the Indenture. If a change of control occurs, each holder of the Notes will have the right to require that the Company purchase all of such holder’s Notes in an amount equal to 101% of the principal of such Notes, plus accrued and unpaid interest, if any, to the date of the purchase.

The fair value of the Senior Notes at March 31, 2014, was estimated to be $419.5 million based upon data from independent market makers (Level 2 fair value measurement).

For the three months ended March 31, 2014 and 2013, the Company incurred interest expense on long-term debt of $7.8 million and $8.1 million, respectively. The Company capitalized $3.8 million and $2.7 million of interest expense during the quarters ended March 31, 2014 and 2013, respectively.

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Note 6 — Income Taxes

Income tax benefit (expense) during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income (loss), plus any significant unusual or infrequently occurring items that are recorded in the interim period. The provision for income taxes for the quarters ended March 31, 2014 and 2013, 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. The lower effective rate in 2014 relates primarily to the permanent differences in the fair value of share-based compensation expensed under GAAP and the realized value deductible for income tax purposes.

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


	Three Months Ended March 31,
	2014		2013
Current income tax benefit (expense)	$	—	$	—
Deferred income tax benefit		1,106		1,803

Total income tax benefit	$	1,106	$	1,803

The Company had no reserve for uncertain tax positions as of March 31, 2014. A valuation allowance against deferred tax assets at March 31, 2014 and 2013, is not considered necessary because in the Company’s opinion it is more likely than not that the deferred tax asset will be fully realized.

Note 7 — 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 March 31, 2014, or December 31, 2013.

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 March 31, 2014, and December 31, 2013, the Company had 77,912,813 and 76,228,055 shares of common stock issued and outstanding, respectively.

During the second quarter of 2013, the Company issued 13.3 million shares of common stock in a public offering at $8.00 per share resulting in net proceeds of $101.8 million, after underwriting discounts and commissions. The net proceeds were used to repay outstanding borrowings under the Credit Facility.

During the first quarter of 2014 and 2013, no warrants were repurchased or exercised. At March 31, 2014, 33,040,682 warrants remain outstanding.

Share-Based Compensation

The Company accounts for share-based compensation in accordance with FASB ASC Topic 718, Stock 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 shares of common stock that may be issued under the Incentive Plan is 9,157,744.

Time-Based Awards

Shares of time-based restricted stock generally vest in three or four year increments at specified dates based on continued employment.

The compensation expense recognized for the time-based awards was measured based on the Company’s closing stock price on the dates of grant, utilizing estimated forfeiture rates between 0% and 10% which are updated periodically based on actual employee turnover. During the quarter ended March 31, 2014, the Company granted 1,379,717 shares of time-based restricted stock to employees and directors, pursuant to the Incentive plan.

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For the quarters ended March 31, 2014 and 2013, the Company recorded $2.5 million and $2.0 million of share-based compensation expense related to time-based awards, net of amounts billed to partners, respectively. There was unrecognized compensation expense of approximately $25.0 million at March 31, 2014, which is expected to be recognized over a weighted-average period of 2.3 years. The following table summarizes the changes in non-vested time-based awards for the quarter ended March 31, 2014:


	Shares			Weighted Average Grant Date Fair Value
Non-vested, beginning of period		2,005,721		$	10.62
Granted		1,379,717			9.19
Vested		(491,373	)		10.50
Forfeited		(17,893	)		10.05

Non-vested, end of period		2,876,172		$	9.96

Performance-Based Awards

For grants made through year-end 2012, performance-based shares generally vest in equal tranches beginning on December 31 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 of the year prior to the grant (which was $14.227 for 2011 grants and $11.639 for 2012 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 subject to a four year maximum vesting period. These awards are referred to as “Stock Appreciation Awards.”

For the quarters ended March 31, 2014 and 2013, the Company recorded share-based compensation expense related to the Stock Appreciation Awards of $0.1 million and $0.2 million, respectively. There was unrecognized compensation expense for the Stock Appreciation Awards of approximately $0.2 million at March 31, 2014, which is expected to be recognized over a weighted-average period of 1.4 years. The following table summarizes the changes in non-vested Stock Appreciation Awards for the three month period ended March 31, 2014:


	Shares			Weighted Average Grant Date Fair Value
Non-vested, beginning of period		444,571		$	7.60
Granted		—			—
Vested		—			—
Forfeited		(2,010	)		7.79

Non-vested, end of period		442,561		$	7.60

In March 2014, the Compensation Committee awarded 487,819 performance-based restricted shares to executive officers of the Company under the Incentive Plan. The restricted stock grants vest only upon achievement of thresholds of cumulative total shareholder return (“TSR”) as compared to a specified peer group (the “Performance-Vested Shares”). A TSR percentile (the “TSR Percentile”) is calculated based on the change in the value of the Company’s common stock between the grant date and the applicable vesting date, including any dividends paid during the period, as compared to the respective TSRs of a specified group of seventeen peer companies. The Performance-Vested Shares vest in three installments to the extent that the applicable TSR Percentile ranking thresholds are met upon the one-, two- and three-year anniversaries of the grant date. Performance-Vested Shares that are eligible to vest on a vesting date, but do not qualify for vesting, become eligible for vesting again on the next vesting date. All Performance-Vested Shares that have not vested as of the final vesting date will be forfeited on such date.

The Compensation Committee also granted rights to earn additional shares of common stock upon achievement of a higher TSR Percentile (“Outperformance Shares”). The Outperformance Shares are earned in increasing increments based on a TSR Percentile attained over a specified threshold. Outperformance Shares may be earned on any vesting date to the extent that the applicable TSR Percentile ranking thresholds are met in three installments on the one-, two- and three-year anniversaries of the grant date. Outperformance Shares that are earned at a vesting date will be issued to the recipient; however, prior to such issuance, the recipient is not entitled to stockholder rights with respect to Outperformance Shares. Outperformance Shares that are eligible to be earned but remain unearned on a vesting date become eligible to be earned again on the next vesting date. The right to earn any theretofore unearned Outperformance Shares terminates immediately following the final vesting date. The Performance-Vested Shares and the Outperformance Shares are referred to as the “TSR Awards.”

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The compensation expense to be recognized for the TSR Awards and Stock Appreciation Awards was measured based on the estimated fair value at the date of grant using a Monte Carlo simulation model and utilizes estimated forfeiture rates between 4% and 15% which are updated periodically based on actual employee turnover.

The valuation model for the TSR Awards used the following assumptions:


Grant Year	Average Expected Volatility	Expected Dividend Yield	Risk-Free Interest Rate
2013	35.0%	0%	0.42%
2014	39.4%	0%	0.69%

For the quarters ended March 31, 2014 and 2013, the Company recorded share-based compensation expense related to the TSR Awards of $0.3 million and $0.3 million, respectively. There was unrecognized compensation expense for TSR Awards of approximately $8.2 million at March 31, 2014, which is expected to be recognized over a weighted-average period of 2.6 years. The following table summarizes the changes in non-vested TSR Awards for the three month period ended March 31, 2014:


	Shares			Weighted Average Grant Date Fair Value
Non-vested, beginning of period		340,166		$	15.91
Granted		487,819			13.32
Vested		(63,387	)		15.91
Forfeited		—			—

Non-vested, end of period		764,598		$	14.26

Note 8 — 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 12%. 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 for the periods presented (in thousands):


	Three Months Ended March 31,
	2014			2013
Asset retirement obligations at beginning of period	$	31,989		$	19,155
Additional liability incurred / acquired		—			402
Accretion expense		661			318
Liabilities settled		(173	)		(193	)

Asset retirement obligations at end of period		32,477			19,682
Less: current asset retirement obligations		(1,812	)		(3,390	)

Long-term asset retirement obligations	$	30,665		$	16,292

Note 9 — Derivative Instruments

Resolute enters into commodity derivative contracts to manage its exposure to oil and gas price volatility. Resolute has not elected to designate derivative instruments as 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 consolidated statements of operations. Gains and losses on commodity derivative instruments from Resolute’s price risk management activities are recognized in other income (expense). The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as financing activities in the condensed consolidated statement of cash flows.

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The Company utilizes fixed price swaps, basis swaps, option contracts and two-and three-way collars. These instruments generally entitle Resolute (the floating price payer in most cases) to receive settlement from the counterparty (the fixed price payer in most cases) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable to each calculation period is less than the fixed strike price or floor price. The Company would pay the counterparty if the settlement price for the scheduled trading days applicable to each calculation period exceeds the fixed strike price or ceiling price. The amount payable by Resolute, if the floating price is above the fixed or ceiling price, is the product of the notional contract quantity and the excess of the floating price over the fixed or ceiling price per calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional contract quantity and the excess of the fixed or floor price over the floating price per calculation period. A three-way collar consists of a two-way collar contract combined with a put option contract sold by the Company with a strike price below the floor price of the two-way collar. The Company receives price protection at the purchased put option floor price of the two-way collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike price, the Company receives the cash market price plus the variance between the two put option strike prices. This type of instrument captures more value in a rising commodity price environment, but limits the benefits in a downward commodity price environment. Basis swaps are used 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.

As of March 31, 2014, the fair value of the Company’s commodity derivatives was a net liability of $13.8 million.

The following table represents Resolute’s commodity swap contracts as of March 31, 2014:


	Oil (NYMEX WTI)				Gas (NYMEX Henry Hub)
Remaining Term	Bbl per Day		Weighted Average Swap Price Per Bbl		MMBtu per Day		Weighted Average Swap Price Per MMBtu
Apr – Dec 2014		5,500	$	92.94		5,000	$	4.165
Jan – Dec 2015		4,100	$	88.93		—		—

The following table represents Resolute’s two-way commodity collar contracts as of March 31, 2014:


	Oil (NYMEX WTI)
Remaining Term	Bbl per Day		Weighted Average Floor Price Per Bbl		Weighted Average Ceiling Price Per Bbl
Apr – Dec 2014		1,500	$	65.00	$	110.00
Jan – Dec 2015		1,000	$	84.17	$	92.10

The following table represents Resolute’s commodity call and put option contracts as of March 31, 2014:


	Oil (NYMEX WTI)
Remaining Term	Bought Call Bbl per Day		Weighted Average Bought Call Price Per Bbl		Bought Put Bbl per Day		Weighted Average Bought Put Price Per Bbl		Sold Put Bbl Per Day		Weighted Average Sold Put Price Per Bbl
Apr – Dec 2014		2,500	$	108.66		1,200	$	85.00		3,700	$	70.68

The following table represents Resolute’s three-way oil collar contracts as of March 31, 2014:


	Oil (NYMEX WTI)
Remaining Term	Bbl Per Day		Weighted Average Short Put Price Per Bbl		Weighted Average Floor Price Per Bbl		Weighted Average Ceiling Price Per Bbl
Apr – Dec 2014		2,000	$	70.00	$	85.00	$	100.83

The following table represents Resolute’s three-way gas collar contracts as of March 31, 2014:


	Gas (NYMEX Henry Hub)
Remaining Term	MMBtu Per Day		Weighted Average Short Put Price Per MMBtu		Weighted Average Floor Price Per MMBtu		Weighted Average Ceiling Price Per MMBtu
Jan – Mar 2015		5,000	$	3.75	$	4.50	$	5.55

The following table represents Resolute’s basis swaps as of March 31, 2014:


	Gas (Rocky Mountain CIG)
Remaining Term	MMBtu per Day		Weighted Average Price Differential per MMBtu
Apr – Dec 2014		1,000	$	0.590

Subsequent to March 31, 2014, Resolute entered into additional commodity derivative contracts as summarized below:


	Oil (NYMEX WTI)
Call Option	Sold Call Bbl Per Day		Weighted Average Sold Call Per Bbl
May – Dec 2014		1,200	$	97.00

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


	Three Months Ended March 31,
	2014			2013
Other income (expense):
Commodity derivative settlements	$	(4,750	)	$	(6,892	)
Mark-to-market gain (loss)		(3,184	)		106

Commodity derivative instruments loss	$	(7,934	)	$	(6,786	)

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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 each ISDA include credit support requirements, cross default provisions, termination events, and set-off provisions. Resolute generally 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.

Resolute does not offset the fair value amounts of commodity derivative assets and liabilities with the same counterparty for financial reporting purposes. The following is a listing of Resolute’s commodity derivative assets and liabilities required to be measured at fair value on a recurring basis and where they are classified within the hierarchy as of March 31, 2014, and December 31, 2013 (in thousands):


	Level 2
	March 31, 2014		December 31, 2013
Assets
Derivative instruments, current	$	493	$	1,378
Other long term assets		—		—

Total assets	$	493	$	1,378

Liabilities
Derivative instruments, current	$	13,263	$	11,955
Other long term liabilities		992		—

Total liabilities	$	14,255	$	11,955

Note 10 — 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.

Future minimum CO₂ purchase commitments as of March 31, 2014, under this purchase agreement, based on prices in effect at March 31, 2014, are as follows (in thousands):


Year	CO2 Purchase Commitments
2014	$	18,349
2015		26,567
2016		24,420
2017		1,103

Total	$	70,439

Lease Obligations

During the first quarter of 2014, the Company entered into a new office lease agreement for the Denver corporate office. The lease expires in June 2022. Total rental commitments for the office space are $8.6 million at March 31, 2014. The future minimum lease payments under this non-cancelable lease are as follows: $0.6 million in 2015, $1.2 million in 2016 and 2017 and $5.7 million in 2018 and thereafter.

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ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2013, as well as the accompanying financial statements and the related notes contained elsewhere in this report. References to “Resolute,” “the Company,” “we,” “ours,” and “us” refer to Resolute Energy Corporation and its subsidiaries.

Overview

We are a publicly traded, independent oil and gas company engaged in the exploitation, development, exploration for and acquisition of oil and gas properties. Our asset base is comprised of properties in Aneth Field located in the Paradox Basin in southeast Utah (the “Aneth Field Properties” or “Aneth Field”), the Permian Basin in west Texas and southeast New Mexico (the “Permian Properties”) and the Big Horn and Powder River Basins in Wyoming (the “Wyoming Properties”). Our primary operational focus is on increasing reserves and production from these properties while improving efficiency and optimizing operating costs. We plan to expand our reserve base through an organic growth strategy focused on the expansion of tertiary oil recovery in Aneth Field, the exploitation and development of oil-prone acreage, particularly in our Permian Properties, and through carefully targeted exploration activities in our Wyoming Properties. We also expect to engage in opportunistic acquisitions.

As of December 31, 2013, our estimated net proved reserves were approximately 59.4 million equivalent barrels of oil (“MMBoe”), of which approximately 79% and 57% were proved developed reserves and proved developed producing reserves, respectively. Approximately 80% of our net proved reserves were oil and approximately 88% were oil and natural gas liquids (“NGL”). The December 31, 2013, pre-tax present value discounted at 10% of our net proved reserves was $1,054 million and the standardized measure of our estimated net proved reserves was $893 million. We focus our efforts on increasing reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flow from existing operations are dependent on a variety of factors including commodity prices, exploitation and recovery activities and our ability to manage our overall cost structure at a level that allows for profitable operation.

Our management uses a variety of financial and operational measurements to analyze our operating performance, including but not limited to, production levels, pricing and cost trends, reserve trends, operating and general and administrative expenses, operating cash flow and Adjusted EBITDA. The analysis of these measurements should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2013.

Aneth Field Properties

Our largest asset, constituting 59% of our net proved reserves as of December 31, 2013, is our ownership of working interests in Aneth Field, a mature, long-lived oil producing field, most of which is located on the Navajo Reservation in southeast Utah. We own a majority of the working interests in, and are the operator of, three federal production units which constitute the Aneth Field Properties. These are the Aneth Unit, the McElmo Creek Unit and the Ratherford Unit, in which we owned working interests of 62%, 68% and 59%, respectively, at March 31, 2014. 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. We believe that significantly more oil can be recovered from our Aneth Field Properties through industry standard secondary and tertiary recovery techniques.

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Permian Properties

Our Permian Properties, constituting 33% of net proved reserves as of December 31, 2013, are located in the Permian Basin of west Texas and southeast New Mexico, and are divided between three principal project areas. Our project area located in the Midland Basin portion of the Permian Basin, in Howard, Martin, Midland and Ector counties, primarily targets the Wolfcamp and Spraberry formations with secondary objectives in the Mississippian, Cline and Dean formations. Our project area located in the Delaware Basin portion of the Permian Basin, in Reeves County, primarily targets the Wolfcamp and Bone Spring formations. Our third project area, the Northwest Shelf in Lea County, New Mexico, is centered on conventional production in Denton, Gladiola and South Knowles fields where we are focused on improving field-level economics through production enhancements and operating cost reductions. We also believe upside exists in these properties through well deepenings and infill drilling. Historic drilling activity in our Midland and Delaware basin project areas has focused on vertical wells with completions in multiple pay zones. Recently the industry has increased its focus on horizontal drilling, primarily in the Wolfcamp formation, as well as the Spraberry and Cline formations in the Midland Basin and the Bone Spring formation in the Delaware Basin. We anticipate that our drilling activity in these areas will be increasingly focused on horizontal drilling activity targeting these same formations.

During the first quarter of 2014, we completed 3 gross (1.4 net) wells on our Permian Properties. We were in the process of drilling 1 gross (1.0 net) well and had 2 gross (1.5 net) wells awaiting completion operations at quarter end.

On December 28, 2012, we purchased an undivided 32.35% interest in certain oil and gas properties from RSP Permian, LLC and certain other sellers (“RSP”) containing proved reserves of approximately 5.4 MMBoe in the Midland Basin portion of the Permian Basin in Midland and Ector counties, Texas, for a purchase price of approximately $133 million, which included a $6 million fee paid in exchange for the option to acquire the remaining 67.65% interest in the RSP properties. This fee was nonrefundable but would be applied towards the purchase price if the option were to be exercised. On March 22, 2013, we exercised our option and acquired the remaining 67.65% interest in the RSP properties. The purchase price for the acquired properties, which we refer to as our Gardendale area, was $258 million, net of the option fee, after customary purchase price adjustments, which were estimated at closing. The RSP acquisitions included approximately 4,700 gross (4,600 net) acres and 80 producing wells and facilities for gathering, water sourcing and water disposal. The acreage is largely held by production. We believe that growth potential exists from approximately 23 gross prospective horizontal locations with multiple targets in the Wolfcamp, Spraberry and Atoka formations, along with potentially 85 recompletion opportunities across the entire acreage position in the Midland Basin.

Wyoming Properties

Hilight Field, constituting 8% of net proved reserves as of December 31, 2013, is located in the Powder River Basin in Campbell County, Wyoming. We have an inventory of low risk re-stimulation and infill drilling projects which we expect will moderate the natural decline of this field. Hilight Field is located in a basin experiencing transformation due to horizontal drilling targeting oil-bearing formations such as the Turner, Niobrara and Mowry. Along with these unconventional opportunities, the Powder River Basin continues to see exploration activity targeting the conventional Minnelusa formation. We have focused our geological, geophysical and engineering efforts to prepare for testing these formations. These activities have included a 3D seismic survey of the field and the review of our extensive log data and data from operators drilling wells in close proximity to Hilight. In the fourth quarter of 2013, we successfully completed a horizontal well in the Turner/Frontier formation. The well delivered a 24 hour peak production rate of 1,134 Boe per day, a 30 day peak production rate of 679 Boe per day and continues to produce strongly in 2014. Based on this success, we plan to drill additional appraisal wells in the Turner/Frontier formation in 2014. We believe there may be as many as 40 drilling locations in the Turner/Frontier inside our existing leasehold. We plan to collect additional petrophysical data in the Parkman, Shannon, Sussex and Niobrar during our 2014 drilling program.

Divestiture of North Dakota Properties

During 2013, we divested all of our non-operated properties located in the Bakken trend of North Dakota through three separate transactions for net proceeds of approximately $70.1 million. During March 2014, we divested our remaining operated properties in North Dakota for approximately $4.8 million.

Factors That Significantly Affect Our Financial Results

Revenue, cash flow from operations and future growth depend on many factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Historical oil prices have been volatile and are expected to fluctuate widely in the future. Sustained periods of low prices for oil and lower realized prices for our oilcould materially and adversely affect our financial position, our results of operations, the quantities of oil and gas that we can economically produce, and our ability to obtain capital.

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

Results of Operations

For the purposes of management’s discussion and analysis of the results of operations, management has analyzed the operational results for the quarter ended March 31, 2014, in comparison to results for the quarter ended March 31, 2013.

The following table presents our sales volumes, revenues and operating expenses, and sets forth our sales prices, costs and expenses on a barrel of oil equivalent (“Boe”) basis for the periods indicated:


	Three Months Ended March 31,
	2014		2013
Net Sales:
Total sales (MBoe)		1,134		1,047
Average daily sales (Boe/d)		12,598		11,633
Average Sales Prices ($/Boe):
Average sales price (excluding commodity derivative settlements)	$	80.15	$	75.36
Operating Expenses ($/Boe):
Lease operating	$	25.27	$	24.08
Production and ad valorem taxes		9.35		9.76
General and administrative		7.62		8.18
General and administrative (excluding non-cash compensation expense)		5.24		5.90
Depletion, depreciation, amortization and accretion		28.14		23.77

Quarter Ended March 31, 2014, Compared to the Quarter Ended March 31, 2013

Revenue. Revenue from oil and gas activities increased by 15% to $90.9 million during 2014, from $78.9 million during 2013. Of the $12.0 million increase in revenue, approximately $6.6 million was attributable to increased production and $5.4 million in increased commodity pricing. Average sales price for the quarter, excluding derivative settlements, increased from $75.36 per Boe in 2013 to $80.15 per Boe in 2014, primarily as a function of increased commodity pricing. Sales volumes increased 8% during 2014 as compared to 2013, from 1,047 MBoe to 1,134 MBoe. The majority of the production increase was due to wells associated with the Permian Acquisitions and drilling activities during 2013 and 2014.

Operating Expenses. Lease operating expenses include direct labor, contract services, field office rent, production and ad valorem taxes, vehicle expenses, supervision, transportation, minor maintenance, tools and supplies, workover expenses, utilities and other customary charges. Resolute assesses lease operating expenses in part by monitoring the expenses in relation to production volumes and the number of wells operated.

Lease operating expenses increased to $28.7 million during 2014, from $25.2 million during 2013. The $3.5 million, or 14%, increase was attributable to additional operating expenses associated with the Permian Acquisitions and increased operational activity in the Permian Basin. On a per-unit basis, lease operating expense increased 5%, from $24.08 to $25.27.

Production and ad valorem taxes in 2014 of $10.6 million were consistent with 2013 and were less on a per-unit basis, due to decreased ad valorem tax estimates and increased revenue in areas with lower tax rates. Production and ad valorem taxes were 11.7% of total revenue in 2014 versus 13.0% of total revenue in 2013.

General and administrative expenses include the costs of employees and executive officers, related benefits, share-based compensation, office leases, professional fees, general corporate overhead and other costs not directly associated with field operations. We monitor our general and administrative expenses carefully, attempting to balance the cash effect of incurring general and administrative costs against the related benefits with a focus on hiring and retaining highly qualified staff who can add value to our asset base.

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General and administrative expenses of $8.6 million in 2014 were consistent with 2013 and were less on a per-unit basis. However, increases of $0.3 million in share-based compensation were offset by decreases of $0.3 million in salaries and wages. Cash-based general and administrative expense decreased from $6.2 million to $5.9 million, or 4%.

Depletion, depreciation, amortization and accretion expenses increased to $31.9 million during 2014, as compared to $24.9 million during 2013. The $7.0 million, or 28%, increase is principally due to increased production and an increase in the depletion, depreciation and amortization rate as a result of the decrease in proved undeveloped reserves at year end 2013 due to the SEC five-year development rule. On a per-unit basis, depreciation, amortization and accretion expenses increased from $23.77 per Boe in 2013 to $28.14 per Boe in 2014.

Other Income (Expense). All of our 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 2014, the loss on oil and gas commodity derivatives was $7.9 million, consisting of $4.7 million of derivative settlements and $3.2 million of mark-to-market losses. During 2013, the loss on oil and gas commodity derivatives was $6.8 million, consisting of $6.9 million of derivative settlements and $0.1 million of mark-to-market gains on oil and gas derivatives.

Interest expense in 2014 decreased to $7.8 million from the $8.0 million recorded in 2013. The $0.2 million decrease in interest expense was primarily due to $1.1 million of increased capitalized interest as a result of higher unproved property balances, offset by $0.9 million in increased interest expense due to increased levels of borrowings and other. The components of our interest expense are as follows (in thousands):


	Year Ended March 31,
	2014			2013
8.50% senior notes	$	8,500		$	8,500
Credit facility		2,707			1,649
Amortization of deferred financing costs and senior notes premium		599			603
Other, net		(220	)		(3	)
Capitalized interest		(3,790	)		(2,668	)

Total interest expense	$	7,796		$	8,081

Income Tax Benefit (Expense). Income tax benefit recognized during 2014 was $1.1 million, or 23.8% of the loss before income taxes, as compared to an income tax benefit of $1.8 million, or 37.2% of the loss before income taxes in 2013. The lower effective rate in 2014 relates primarily to the permanent differences in the fair value of share-based compensation expensed under GAAP and the realized value deductible for income tax purposes.

Liquidity and Capital Resources

Our primary sources of liquidity have been cash generated from operations, amounts available under our credit facility, proceeds from warrant exercises, proceeds from the issuance of Senior Notes (defined below) and sales of non-strategic oil and gas properties. For purposes of Management’s Discussion and Analysis of Liquidity and Capital Resources, we have analyzed our cash flows and capital resources for the quarters ended March 31, 2014 and 2013.


	Three Months Ended March 31,
	2014			2013
	(in thousands)
Cash provided by operating activities	$	62,652		$	28,391
Cash used in investing activities		(45,279	)		(253,819	)
Cash provided by (used in) financing activities		(16,492	)		226,135

Net cash provided by operating activities was $62.7 million for the first quarter of 2014 compared to $28.4 million for the 2013 period. The increase in net cash provided by operating activities in 2014 over 2013 was primarily due to an increase in revenue from oil and gas activities and changes in working capital.

We plan to reinvest a sufficient amount of our cash flow into our development operations in order to maintain our production over the long term, and plan to use external financing sources as well as cash flow from operations and cash reserves to increase our production.

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Net cash used in investing activities was $45.3 million in 2014 compared to $253.8 million in 2013. The primary investing activity in 2014 was cash used for capital expenditures of $49.0 million. Capital expenditures consisted of $10.3 million in compression and facility and drilling projects in Aneth Field, $3.9 million in CO₂ acquisition, $33.1 million in drilling activities and infrastructure projects in the Permian Basin of west Texas and $1.3 million in recompletion and drilling activities in our Wyoming Properties. Capital divestitures included $4.8 million of proceeds from the sale of certain operated properties in the Bakken trend of North Dakota. The 2013 capital expenditures consisted of $257 million paid to acquire additional interest in the Permian Properties, $5.1 million in compression and facility and drilling projects in Aneth Field, $5.1 million in CO₂ acquisition, $21.6 million in drilling activities and infrastructure projects in the Permian Basin of west Texas, $7.1 million in drilling and completion activities in the Bakken trend of North Dakota and $1.5 million in recompletion and drilling activities in our Wyoming Properties. Capital divestitures included $50.2 million of proceeds from the sale of certain interests in Aneth Field to Navajo Nation Oil and Gas Company in January 2013. A portion of these capital costs were accrued and not paid at period end.

Net cash used in financing activities was $16.5 million in 2014 compared to net cash provided of $226.1 million in 2013. The primary financing activity in 2014 was net repayments on borrowings of $15.0 million under the Credit Facility (defined below). The primary financing activity in 2013 was $228.0 million in net borrowings under the Credit Facility.

If cash flow from operating activities does not meet expectations, we may reduce our expected level of capital expenditures and/or fund a portion of our capital expenditures using borrowings under our Credit Facility, issuances of debt and equity securities or from other sources, such as asset sales. We have in place an effective shelf registration pursuant to which an aggregate of $394 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. Our ability to raise funds through the incurrence of additional indebtedness could be limited by a reduced borrowing base, or restrictions in the covenants in our Credit Facility or our Senior Notes (defined below). If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain production or proved reserves.

We plan to continue our practice of hedging a significant portion of our production through the use of various derivative transactions. Our existing derivative transactions do not qualify as cash flow hedges, and we anticipate that future transactions will receive similar accounting treatment. Derivative settlements usually occur within five days of the end of the month. As is typical in the oil and gas industry, however, we do not generally receive the proceeds from the sale of our 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, we 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, we may use working capital or borrowings under the Credit Facility to fund our operations.

Revolving Credit Facility

Our credit facility is with a syndicate of banks led by Wells Fargo Bank, National Association, as Administrative Agent, and Bank of Montreal, as Syndication Agent (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 our 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. Under certain circumstances, either the Company or the lenders may request an interim redetermination.

In March 2013, and in connection with the purchase of the Option Properties, we entered into the Sixth Amendment to the amended and restated Credit Facility agreement, resulting in a borrowing base increase to $485 million, consisting of a $445 million conforming tranche and a $40 million non-conforming tranche (which expired on May 14, 2013). The Sixth Amendment, among other things, also extended the maturity date of the revolving Credit Facility from April 2017 to March 2018. On March 7, 2014, we entered into the Ninth Amendment to the amended and restated Credit Facility which redefined and adjusted the Maximum Leverage Ratio to (a) 4.90:1.00 for the fiscal quarters ending March 31, 2014, and June 30, 2014, (b) 4.75:1.00 for the fiscal quarters ending September 30, 2014, and December 31, 2014, and (c) 4.00:1.00 for all quarters thereafter. The Ninth Amendment also provided that as of the last day of each fiscal quarter in 2014 the ratio of senior secured debt as of such date to Adjusted EBITDA as defined in the Credit Facility for the four quarter period ending on such date may not exceed 2.75:1.00.

Each base rate borrowing under the Credit Facility accrues interest at either (a) the London Interbank Offered Rate, plus a margin which varies from 1.50% to 2.50% (or 3.0% if the Company utilizes any portion of the non-conforming tranche) 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 (“LIBOR”) plus a margin which ranges from 0.50% to 1.50% (or 2.0% if the Company utilizes any portion of the non-conforming tranche). Each such margin is based on the level of utilization under the borrowing base. In March 2014, we entered into the Tenth Amendment to the amended and restated Credit Facility agreement. In connection with the Tenth Amendment, the semi-annual redetermination of our borrowing base was completed, resulting in a borrowing base of $425 million, consisting of a $400 million conforming tranche and a $25 million non-conforming tranche (which non-conforming tranche will expire no later than our next borrowing base redetermination date). The Tenth Amendment also required that we enter into commodity derivative agreements by March 31, 2014, on production of not less than 5,100 barrels of oil per day in the aggregate for the fiscal year ending December 31, 2015, at a weighted average price floor of not less than $84.17 per barrel. This requirement was satisfied in the first quarter of 2014

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As of March 31, 2014 outstanding borrowings were $320 million under the borrowing base of $425 million. The borrowing base availability had been reduced by $3.1 million in conjunction with letters of credit issued to vendors at March 31, 2014. 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 our subsidiaries and is collateralized by substantially all of the proved oil and gas assets of Resolute Aneth, LLC, Resolute Wyoming, Inc. and Resolute Natural Resources Southwest, LLC, which are wholly-owned subsidiaries of the Company

The Credit Facility includes customary terms and covenants that place limitations on certain types of activities, the payment of dividends, and require satisfaction of certain financial tests. We were in compliance with all terms and covenants of the Credit Facility at March 31, 2014.

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

Senior Notes

In April 2012, we consummated a private placement of senior notes with a principal amount of $250 million, and a follow on issuance of senior notes with a principal amount of $150 million. The Senior Notes are due May 1, 2020, and bear an annual interest rate of 8.50% with the interest on the notes is payable semiannually in cash on May and November 1 of each year.

The Senior Notes were issued under an Indenture (the “Indenture”) among the Company, our existing subsidiaries (the “Guarantors”) and U.S. Bank National Association, as trustee (the “Trustee”) in a private transaction not subject to the registration requirements of the Securities Act of 1933. In March 2013, the Company registered the Senior Notes with the Securities and Exchange Commission by filing an amendment to the registration statement on Form S-4 enabling holders of the Senior Notes to exchange the privately placed Notes for publically registered Notes with substantially identical terms. The Indenture contains affirmative and negative covenants that, among other things, limit our and the Guarantors’ ability to make investments, incur additional indebtedness or issue preferred stock, create liens, sell assets, enter into agreements that restrict dividends or other payments by restricted subsidiaries, consolidate, merge or transfer all or substantially all of our assets, engage in transactions with our affiliates, pay dividends or make other distributions on capital stock or prepay subordinated indebtedness and create unrestricted subsidiaries. The Indenture also contains customary events of default. Upon occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the Trustee or the holders of the Senior Notes. Upon the occurrence of certain other events of default, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. We were in compliance with all financial covenants under our Senior Notes as of March 31, 2014.

The Senior Notes are general unsecured senior obligations of the Company and guaranteed on a senior unsecured basis by the Guarantors. The Senior notes rank equally in right of payment with all existing and future senior indebtedness of the Company, will be subordinated in right of payment to all existing and future senior secured indebtedness of the Guarantors, will rank senior in right of payment to any future subordinated indebtedness of the Company and will be fully and unconditionally guaranteed by the Guarantors on a senior basis.

The Senior Notes are redeemable by us on or after May 1, 2016, on not less than 30 or more than 60 days prior notice, at redemption prices set forth in the Indenture. In addition, at any time prior to May 1, 2015, we may use the net proceeds from equity offerings and warrant exercises to redeem up to 35% of the principal amount of notes issued under the Indenture at a redemption price equal to 108.50% of the principal amount of the notes redeemed, plus accrued and unpaid interest. The Senior Notes may also be redeemed at any time prior to May 1, 2016, at the option of the Company at a redemption price equal to 100% of the principal amount of the notes redeemed plus the applicable premium, and accrued and unpaid interest and additional interest, if any, to the applicable redemption date as set forth in the Indenture. If a change of control occurs, each holder of the Notes will have the right to require that we purchase all of such holder’s Notes in an amount equal to 101% of the principal of such Notes, plus accrued and unpaid interest, if any, to the date of the purchase.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet financing arrangements other than operating leases and have not guaranteed any debt or commitments of other entities or entered into any options on non-financial assets.

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Contractual Obligations

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ITEM 3.

QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk and Derivative Arrangements

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

We employ derivative instruments such as swaps, puts, calls, collars and other such agreements. The purpose of these instruments is to manage our exposure to commodity price risk in order to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices.

Under the terms of our credit agreement the form of derivative instruments to be entered into is at our discretion, not to exceed (i) for the next two years, 85% of our anticipated production from proved properties and (ii) for the subsequent three years, the greater of 75% of our anticipated production from proved properties or 85% of our anticipated production from proved developed producing properties, utilizing economic parameters specified in our credit agreement, including escalated prices and costs.

By removing the price volatility from a significant portion of our oil and gas production, we have mitigated, but not eliminated, the potential effects of volatile prices on cash flow from operations for the periods hedged. While mitigating negative effects of falling commodity prices, certain of these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers, all but one of which are members of Resolute’s Credit Facility bank syndicate at March 31, 2014. As of March 31, 2014, the fair value of our commodity derivatives was a net liability of $13.8 million.

The following table represents our commodity swap contracts as of March 31, 2014:


	Oil (NYMEX WTI)							Gas (NYMEX Henry Hub)
Remaining Term	Bbl per Day		Weighted Average Swap Price Per Bbl		Fair Value of Asset (Liability) (in thousands)			MMBtu per Day		Weighted Average Swap Price Per MMBtu		Fair Value of Asset (Liability) (in thousands)
Apr – Dec 2014		5,500	$	92.94	$	(5,454	)		5,000	$	4.165	$	(402	)
Jan – Dec 2015		4,100	$	88.93	$	(1,288	)		—	$	—	$	—

The following table represents our two-way commodity collar contracts as of March 31, 2014:


	Oil (NYMEX WTI)
Remaining Term	Bbl per Day		Weighted Average Floor Price Per Bbl		Weighted Average Ceiling Price Per Bbl		Fair Value of Asset (Liability) (in thousands)
Apr – Dec 2014		1,500	$	65.00	$	110.00	$	(3,780	)
Jan – Dec 2015		1,000	$	84.17	$	92.10	$	(345	)

The following table represents our commodity call and put option contracts as of March 31, 2014:


	Oil (NYMEX WTI)
RemainingTerm	Bought Call Bbl Per Day		Weighted Average Bought Call Price Per Bbl		Bought Put Bbl per Day		Weighted Average Bought Put Price Per Bbl		Sold Put Bbl Per Day		Weighted Average Sold Put Price Per Bbl		Fair Value of Asset (Liability) (in thousands)
Apr – Dec 2014		2,500	$	108.66		1,200	$	85.00		3,700	$	70.68	$	(1,171	)

The following table represents our three-way oil collar contracts as of March 31, 2014:


	Oil (NYMEX WTI)
Remaining Term	Bbl Per Day		Weighted Average Sold Put Price Per Bbl		Weighted Average Floor Price Per Bbl		Weighted Average Ceiling Price Per Bbl		Fair Value of Asset (Liability) (in thousands)
Apr – Dec 2014		2,000	$	70.00	$	85.00	$	100.83	$	(1,233	)

The following table represents our three-way gas collar contracts as of March 31, 2014:


	Gas (NYMEX Henry Hub)
Remaining Term	MMBtu Per Day		Weighted Average Short Put Price Per MMBtu		Weighted Average Floor Price Per MMBtu		Weighted Average Ceiling Price Per MMBtu		Fair Value of Asset (Liability) (in thousands)
Jan – Mar 2015		5,000	$	3.75	$	4.50	$	5.55	$	24

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The following table represents our basis swaps as of March 31, 2014:


	Gas (Rocky Mountain CIG)
Remaining Term	MMBtu per Day		Weighted Average Price Differential per MMBtu		Fair Value of Asset (Liability) (in thousands)
Apr – Dec 2014		1,000	$	0.590	$	(112	)

Subsequent to March 31, 2014, we entered into additional commodity derivative contracts as summarized below:


	Oil (NYMEX WTI)
Call Option	Sold Call Bbl Per Day		Weighted Average Sold Call Per Bbl
May – Dec 2014		1,200	$	97.00

Interest Rate Risk

At March 31, 2014, we had $320 million of outstanding debt under the Credit Facility. Interest is calculated under the terms of the agreement based principally on a LIBOR spread. A 10% increase in LIBOR would result in an estimated $0.1 million increase in annual interest expense. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness.

Credit Risk and Contingent Features in Derivative Instruments

We are exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above. All counterparties are also lenders under our Credit Facility. For these contracts, we are not required to provide any credit support to our counterparties other than cross collateralization with the properties securing the Credit Facility. Our 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. We have set-off provisions with our lenders that, in the event of counterparty default, allow us to set-off amounts owed under the Credit Facility or other general obligations against amounts owed for derivative contract liabilities.

ITEM 4.

CONTROLS AND PROCEDURES

Our management, with the participation of Nicholas J. Sutton, our Chief Executive Officer, and Theodore Gazulis, our Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2014. Based on the evaluation, those officers have concluded that:

•

our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and

•

our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 was accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

There has not been any change in the Company’s internal control over financial reporting that occurred during the quarterly period ended March 31, 2014, that has materially affected, or is reasonably likely to affect, the Company’s internal control over financial reporting.

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PART II OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

Resolute is not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any of our pending proceedings will not have a material adverse effect on our financial condition or results of operations.

ITEM 1A.

RISK FACTORS

Information about material risks related to our business, financial condition and results of operations for the quarter ended March 31, 2014, does not materially differ from those set out in Part I, Item 1A of the Annual Report on Form 10-K for the year ended December 31, 2013. These risks are not the only risks facing the Company.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not applicable

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

Not applicable

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable

ITEM 5.

OTHER INFORMATION

Not applicable.

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ITEM 6.

EXHIBITS


Exhibit Number		Description of Exhibits

31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith)

31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (filed herewith)

32.1		Certification of the Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith)

101		The following materials are filed herewith: (i) XBRL Instance Document, (ii) XBRL Taxonomy Extension Schema Document, (iii) XBRL Taxonomy Extension Calculation Linkbase Document, (iv) XBRL Taxonomy Extension Labels Linkbase Document, (v) XBRL Taxonomy Extension Presentation Linkbase Document, and (vi) XBRL Taxonomy Extension Definition Linkbase Document.

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SIGNATURES

Pursuant to the requirements of the Exchange Act of 1934, the Registrant caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


Signature	Capacity	Date

/s/ Nicholas J. Sutton
Nicholas J. Sutton	Chief Executive Officer (Principal Executive Officer)	May 12, 2014

/s/ Theodore Gazulis
Theodore Gazulis	Chief Financial Officer (Principal Financial Officer)	May 12, 2014

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