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 June 30, 2013

¨	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 July 31, 2013, 76,858,421 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 expansion of proved reserves; 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 as a result of the acquisitions; our plans with respect to future acquisitions; our hedging plans; 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, in our Annual Report on Form 10-K for the year ended December 31, 2012, and such things as:

•

volatility of oil and gas prices, including reductions in prices that would adversely affect our revenue, income, cash flow from operations 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, and Navajo Nation Oil and Gas Company, as well certain purchase rights held by Navajo Nation Oil and Gas Company;

•

a lack of available capital and financing, including the capital needed to pursue our production and other plans for the Permian 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;

•

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;

•

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

•

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

•

availability of electrical power supplies to our operating areas and the rates charged for such electrical power, including with respect to Aneth field, following the potential purchase of the infrastructure servicing such properties by the Navajo Tribal Utility Authority;

•

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;

•

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

•

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 the Permian Acquisitions (as defined in this Quarterly Report);

•

risks associated with unanticipated liabilities assumed, or title, environmental or other problems resulting from, the Permian Acquisitions;

•

legislative or regulatory charges, including initiatives related to drilling and completion techniques, including fracing;

•

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;

•

a lack of available capital and financing on acceptable terms, including as a result of a reduction in the borrowing base under our credit facility;

•

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.

TABLE OF CONTENTS


PART I -	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

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)


	June 30,			December 31,
	2013			2012
Assets
Current assets:
Cash and cash equivalents	$	879		$	934
Accounts receivable		92,476			78,356
Deferred income taxes		8,101			10,757
Derivative instruments		5,625			8,523
Prepaid expenses and other current assets		1,099			1,691

Total current assets		108,180			100,261

Property and equipment, at cost:
Oil and gas properties, full cost method of accounting
Unproved		303,280			157,079
Proved		1,423,393			1,259,667
Other property and equipment		6,201			5,602
Accumulated depletion, depreciation and amortization		(244,651	)		(191,625	)

Net property and equipment		1,488,223			1,230,723

Other assets:
Restricted cash		18,218			18,422
Derivative instruments		982			475
Deferred financing costs		13,802			13,006
Other assets		1,291			1,243

Total assets	$	1,630,696		$	1,364,130

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued expenses	$	102,002		$	96,263
Accrued interest payable		5,999			5,698
Asset retirement obligations		3,190			3,417
Derivative instruments		22,060			31,847

Total current liabilities		133,251			137,225

Long term liabilities:
Credit facility		320,000			162,000
Senior notes, net of accumulated premium amortization of $105 at June 30, 2013 and $10 at December 31, 2012		401,770			401,865
Asset retirement obligations		16,622			15,738
Derivative instruments		1,770			8,204
Deferred income taxes		102,834			101,914
Other long term liabilities		7,500			5,000

Total liabilities		983,747			831,946

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 76,856,653 and 61,872,694 shares at June 30, 2013 and December 31, 2012, respectively		8			6
Additional paid-in capital		625,439			516,650
Retained earnings		21,502			15,528

Total stockholders’ equity		646,949			532,184

Total liabilities and stockholders’ equity	$	1,630,696		$	1,364,130

See notes to condensed consolidated financial statements

-1-

RESOLUTE ENERGY CORPORATION

Condensed Consolidated Statements of Income (UNAUDITED)

(in thousands, except per share data)


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Revenue:
Oil	$	81,680		$	59,778		$	154,616		$	119,456
Gas		5,301			4,410			9,836			8,272
Natural gas liquids		2,135			291			3,561			291

Total revenue		89,116			64,479			168,013			128,019

Operating expenses:
Lease operating		25,588			19,564			50,800			36,748
Production and ad valorem taxes		10,876			9,642			21,099			19,868
Depletion, depreciation, amortization, and asset retirement obligation accretion		28,796			18,958			53,678			36,016
General and administrative		9,129			5,692			17,697			10,908

Total operating expenses		74,389			53,856			143,274			103,540

Income from operations		14,727			10,623			24,739			24,479

Other income (expense):
Interest expense, net		(7,181	)		(3,696	)		(15,262	)		(4,910	)
Realized and unrealized gains on derivative instruments		6,841			29,546			55			15,717
Other income (expense)		15			(17	)		18			(14	)

Total other income (expense)		(325	)		25,833			(15,189	)		10,793

Income before income taxes		14,402			36,456			9,550			35,272
Income tax expense		(5,379	)		(13,634	)		(3,576	)		(13,192	)

Net income	$	9,023		$	22,822		$	5,974		$	22,080

Net income per common share:
Basic	$	0.14		$	0.38		$	0.09		$	0.37
Diluted	$	0.14		$	0.37		$	0.09		$	0.36
Weighted average common shares outstanding:
Basic		66,782			59,405			63,322			59,401
Diluted		66,782			60,865			63,322			60,664

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			Retained Earnings		Equity
Balance as of January 1, 2013		61,873		$	6	$	516,650		$	15,528	$	532,184
Issuance of stock, restricted stock and share-based compensation		1,841			1		7,069			—		7,070
Restricted stock forfeitures		(107	)		—		(39	)		—		(39	)
Issuance of stock, net of underwriters discounts and commissions		13,250			1		101,759			—		101,760
Net income		—			—		—			5,974		5,974

Balance as of June 30, 2013		76,857		$	8	$	625,439		$	21,502	$	646,949

See notes to condensed consolidated financial statements

-3-

RESOLUTE ENERGY CORPORATION

Condensed Consolidated Statements of Cash Flows (UNAUDITED)

(in thousands)


	Six Months Ended June 30,
	2013			2012
Operating activities:
Net income	$	5,974		$	22,080
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization and asset retirement obligation accretion		53,678			36,016
Amortization of deferred financing costs and senior notes premium		1,245			704
Share-based compensation, net		7,123			4,145
Unrealized gain on derivative instruments		(13,830	)		(33,423	)
Deferred income taxes		3,576			13,192
Change in operating assets and liabilities:
Accounts receivable		(14,174	)		(11,433	)
Other current assets		592			(11	)
Accounts payable and accrued expenses		20,039			5,535
Accrued interest payable		301			3,765

Net cash provided by operating activities		64,524			40,570

Investing activities:
Oil and gas exploration and development expenditures `		(117,592	)		(98,440	)
Purchase of oil and gas properties		(256,977	)		(35,807	)
Proceeds from sale of oil and gas properties and other		50,252			19
Purchase of other property and equipment		(598	)		(1,100	)
Restricted cash		204			(1,820	)
Other		2,548			10,044

Net cash used in investing activities		(322,163	)		(127,104	)

Financing activities:
Proceeds from bank borrowings		384,000			279,200
Repayments of bank borrowings		(226,000	)		(422,200	)
Proceeds from issuance of Senior Notes		—			250,000
Payment of financing costs		(2,137	)		(8,736	)
Redemption of restricted stock for employee income taxes and restricted stock forfeitures		(39	)		(14	)
Retirement of public warrants		—			(9,999	)
Proceeds from issuance of common stock, net of underwriters discounts and commissions		101,760			—

Net cash provided by financing activities		257,584			88,251

Net increase (decrease) in cash and cash equivalents		(55	)		1,717
Cash and cash equivalents at beginning of period		934			1,135

Cash and cash equivalents at end of period	$	879		$	2,852

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, the Powder River and Big Horn basins in Wyoming and the Williston Basin in North Dakota. 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, 2012. 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, 2012. 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, 2012.

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 (1) 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; (2) asset retirement obligations; (3) valuation of derivative assets and liabilities; (4) the estimated fair value and allocation of the purchase price related to business combinations; (5) share-based compensation expense; (6) depletion, depreciation and amortization; (7) accrued liabilities; (8) revenue and related receivables and (9) income taxes.

Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its oil and natural gas operations. Accounting rules require Resolute to perform a quarterly “ceiling test” calculation to test its oil and natural gas properties for possible impairment. The primary components impacting 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 natural 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 June 30, 2013, the calculated value of the ceiling limitation exceeded the carrying value of Resolute’s oil and natural 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 natural gas, future drilling and capital plans, operating costs or expected production the Company may incur a full cost ceiling impairment related to its oil and natural gas properties in future periods.

-5-

Note 3 — Acquisitions and Divestitures

New Permian Properties

On December 21, 2012, the Company purchased properties in Denton Field on the Northwest Shelf in Lea County, New Mexico, and in the Spraberry trend in the Midland Basin portion of the Permian Basin in Howard County, Texas, for a purchase price of approximately $117 million. Additionally, on December 28, 2012, the Company purchased properties in the Wolfberry play in the Delaware Basin portion of the Permian Basin in Midland and Ector counties, Texas, for a purchase price of approximately $133 million. Concurrently with the latter transaction, the Company acquired, for additional consideration of $6.0 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 $257 million, net of the option fee after customary purchase price adjustments, which were estimated at closing. Revenue and expenses related to the Option Properties are included in the condensed consolidated statements of income beginning March 22, 2013, the closing date of the transaction. The properties acquired under the December and March acquisitions are referred to as the “New Permian Properties.” Together, the December and March acquisitions, which the Company refers to as the “Permian Acquisitions,” were accounted for using the acquisition method. The Permian Acquisitions are subject to certain customary conditions and purchase price adjustments.

The preliminary purchase price of the New Permian Properties was comprised of the following (in thousands):


	June 2013		December 2012
Purchase price	$	257,000	$	250,000

The Company has not completed its assessment of the fair values of the assets acquired and liabilities assumed, but intends to do so within twelve months of the purchase date. Accordingly, the following table presents the preliminary purchase price allocation of the New Permian Properties at June 30, 2013, and December 31, 2012, based on the fair values of assets acquired and liabilities assumed (in thousands):


	June 30, 2013		December 31, 2012
Proved oil and gas properties	$	121,000	$	131,000
Unproved oil and gas properties		136,000		122,000
Asset retirement obligations assumed		—		(3,000	)

Total purchase price	$	257,000	$	250,000

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, and the purchase of the properties in the Permian Basin in December 2012 had occurred on January 1, 2012. 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 Permian Acquisitions 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 three and six months ended June 30, 2013 and 2012 combine the historical results of the New Permian Properties and Resolute (in thousands, except per share amounts):


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Total revenue	$	89,116	$	89,899	$	179,071	$	179,658
Revenues in excess of operating expenses		52,652		53,849		105,286		109,939
Net income		9,023		25,042		8,537		28,413
Basic net income per share	$	0.14	$	0.42	$	0.13	$	0.48
Diluted net income per share	$	0.14	$	0.41	$	0.13	$	0.47

-6-

Aneth Field Transactions

During the second quarter of 2012 Resolute entered into two transactions regarding the Aneth Field Properties through which Resolute and Navajo Nation Oil and Gas Company (“NNOGC”) consolidated their interests in the field.

In the first transaction, effective January 1, 2012, Resolute and NNOGC together, on a 50%/50% basis, acquired from affiliates of Denbury Resources Inc. (“Denbury”) a 13% working interest in the Aneth Unit and an 11% working interest in the Ratherford Unit for a total cash consideration of $75 million. The acquisition from Denbury was accounted for using the acquisition method. After closing adjustments, the $37.7 million net purchase price was allocated to proved oil and gas properties. Revenue and expenses associated with the acquired interests are included in the consolidated statements of income concurrent with the closing of the transaction in April 2012.

Contemporaneously with this transaction, Resolute and NNOGC also 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, as they existed before giving effect to the Denbury transaction discussed above. 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.

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”) for proceeds of $75 million, net of customary purchase price adjustments. Under the terms of the agreement, the Company received a performance deposit of 10% of the purchase price, or $7.5 million, which is accounted for in other long term liabilities on the consolidated balance sheet. The transaction closed on July 15, 2013. The Company will record the net proceeds as a reduction to the capitalized costs of its 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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Potential dilutive warrants		—		—		—		—
Potential dilutive restricted stock		2,874		1,566		2,258		1,346
Anti-dilutive securities		33,041		42,464		33,041		42,570

-7-

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Net income	$	9,023	$	22,822	$	5,974	$	22,080
Basic weighted average common shares outstanding		66,782		59,405		63,322		59,401
Add: dilutive effect of non-vested restricted stock		—		1,460		—		1,263
Add: dilutive effect of outstanding warrants		—		—		—		—

Diluted weighted average common shares outstanding		66,782		60,865		63,322		60,664

Basic earnings per common share	$	0.14	$	0.38	$	0.09	$	0.37
Diluted earnings per common share	$	0.14	$	0.37	$	0.09	$	0.36

Note 5 — Long Term Debt

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


	June 30,		December 31,
	2013		2012
Credit Facility	$	320,000	$	162,000
Senior Notes		400,000		400,000
Unamortized premium on Senior Notes		1,770		1,865

Total long-term debt	$	721,770	$	563,865

Credit Facility

Resolute’s credit facility is with a syndicate of banks led by Wells Fargo Bank, National Association (the “Credit Facility”) with Resolute as the borrower. The Credit Facility specifies a maximum borrowing base as determined by the lenders. The determination of the borrowing base takes into consideration the estimated value of Resolute’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. 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 (which expires on March 22, 2018) and a $40 million non-conforming tranche. The Sixth Amendment, among other things, also amended the Maximum Leverage Ratio to (a) 4.50:1.00 for all fiscal quarters ending through December 31, 2013, (b) 4.25:1.00 for the fiscal quarter ending March 31, 2014, and (c) 4.00:1.00 for all fiscal quarters ending June 30, 2014, and thereafter. In addition, the maturity date of the revolving Credit Facility was extended from April 2017 to March 2018. In April 2013, the Company entered into the Seventh Amendment to the amended and restated Credit Facility which adjusted the Maximum Leverage Ratio to (b) 4.85:1:00 for the fiscal quarter ending March 31, 2013, (c) 4.50:1.00 for all fiscal quarters ending June 30, 2013 through December 31, 2013, (d) 4.25:1.00 for the fiscal quarter ending March 31, 2014, and (e) 4.00:1.00 for all fiscal quarters ending June 30, 2014 and thereafter. 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 Rate 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 connection with the equity offering that closed in May 2013, the $40 million non-conforming tranche of the borrowing base was automatically terminated, resulting in a borrowing base decrease to $445 million. In July 2013, the Credit Facility borrowing base was further reduced by $30 million, to $415 million, as a result of the disposition of the New Home Properties.

As of June 30, 2013, outstanding borrowings were $320 million under the borrowing base of $445 million. The borrowing base availability had been reduced by $3.1 million in conjunction with letters of credit issued to vendors at June 30, 2013, and other limitations based upon a multiple of trailing earnings as defined in the Credit Facility. 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.

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As of June 30, 2013, the weighted average interest rate on the outstanding balance under the Credit Facility was 2.20%. 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 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 June 30, 2013.

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.

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” or the “Notes”). 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. 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 June 30, 2013.

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 June 30, 2013 was estimated to be $408 million based upon data from independent market makers (Level 2 fair value measurement).

For the three months ended June 30, 2013 and 2012, the Company incurred interest expense on long-term debt of $7.2 million and $3.7 million, respectively. For the six months ended June 30, 2013 and 2012, the Company incurred interest expense on long-term debt of $15.3 million and $4.9 million, respectively. The Company capitalized $4.7 million and $1.3 million of interest expense during the quarters ended June 30, 2013 and 2012, respectively. The Company capitalized $7.3 million and $1.8 million of interest expense during the six months ended June 30, 2013 and 2012, respectively.

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 which are recorded in the interim period. The provision for income taxes for the three and six month periods ended June 30, 2013 and 2012 differ from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to income before income taxes. This difference relates primarily to state income taxes and estimated permanent differences.

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Current income tax expense	$	—		$	—		$	—		$	—
Deferred income tax expense		(5,379	)		(13,634	)		(3,576	)		(13,192	)

Total income tax expense	$	(5,379	)	$	(13,634	)	$	(3,576	)	$	(13,192	)

The Company had no reserve for uncertain tax positions as of June 30, 2013.

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 June 30, 2013 or December 31, 2012.

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 June 30, 2013 and December 31, 2012, the Company had 76,856,653 and 61,872,694 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 for net proceeds of $101.8 million, after underwriting discounts and commissions. The net proceeds were used to repay outstanding borrowings under our Credit Facility.

During the six months ended June 30, 2013, no warrants were repurchased. During the second quarter of 2012, the Company repurchased 9,634,821 warrants for aggregate consideration of approximately $10.0 million in a private transaction at an average price of $1.04 per warrant. During the six months ended June 30, 2013 and 2012, no warrants were exercised. At June 30, 2013, 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 to be 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 9%. During the six months ended June 30, 2013, the Company granted 1,486,213 time-based shares of restricted stock to employees and directors, pursuant to the Incentive Plan.

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The following table summarizes the changes in non-vested time-based awards for the six month period ended June 30, 2013:


	Shares			Weighted Average Grant Date Fair Value
Non-vested, beginning of period		1,176,890		$	12.00
Granted		1,486,213			10.40
Vested		(24,486	)		12.29
Forfeited		(74,953	)		11.22

Non-vested, end of period		2,563,664		$	11.08

For the three months ended June 30, 2013 and 2012, the Company recorded $3.2 million and $1.7 million of share-based compensation expense related to time-based awards, net of amounts billed to partners, respectively. For the six months ended June 30, 2013 and 2012, the Company recorded $5.2 million and $3.1 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 $22.7 million at June 30, 2013, which is expected to be recognized over a weighted-average period of 2.3 years.

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 $11.134 for 2010 grants, $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.”

In March 2013, the Compensation Committee awarded 354,517 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 17 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 do not vest as of the final vesting date will be forfeited on such date.

In March 2013, 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.”

The compensation expense to be recognized for the TSR Awards and Stock Appreciation Awards were measured based on the estimated fair value at the date of grant using a Monte Carlo simulation model.

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	%

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For the three months ended June 30, 2013 and 2012, the Company recorded $1.5 million and $0.6 million of share-based compensation expense related to the TSR Awards and the Stock Appreciation Awards, respectively. For the six months ended June 30, 2013 and 2012, the Company recorded $1.9 million and $1.0 million of share-based compensation expense related to the TSR Awards and Stock Appreciation Awards, respectively. There was unrecognized compensation expense for TSR and Stock Appreciation Awards of approximately $4.4 million and $0.9 million at June 30, 2013, which is expected to be recognized over a weighted-average period of 2.7 and 1.4 years, respectively. The following table summarizes changes in non-vested Performance-Based Awards for the six month period ended June 30, 2013:


	2013 TSR Awards				2012 and prior Stock Appreciation Awards
	Shares		Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Non-vested, beginning of period		—	$	—		895,892		$	8.43
Granted		354,517		15.91		—			—
Vested		—		—		—			—
Forfeited		—		—		(27,576	)		7.82

Non-vested, end of period		354,517	$	15.91		868,316		$	8.41

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 10%. Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. Asset retirement obligations are valued utilizing Level 3 fair value measurement inputs. The following table provides a reconciliation of Resolute’s asset retirement obligations for the periods presented, (in thousands):


	Six Months Ended June 30,
	2013			2012
Asset retirement obligations at beginning of period	$	19,155		$	16,553
Additional liability incurred / acquired		398			102
Accretion expense		651			488
Liabilities settled		(392	)		(987	)

Asset retirement obligations at end of period		19,812			16,156
Less: current asset retirement obligations		(3,190	)		(2,978	)

Long-term asset retirement obligations	$	16,622		$	13,178

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. Realized and unrealized gains and losses from Resolute’s price risk management activities are recognized in other income (expense), with realized gains and losses recognized in the period in which the related production is sold. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as financing activities in the condensed consolidated statement of cash flows.

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 June 30, 2013, the fair value of the Company’s commodity derivatives was a net liability of $17.2 million.

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The following table represents Resolute’s two-way commodity collar contracts as of June 30, 2013.


			(NYMEX WTI - $/Bbl)
Year	Bbl per Day		Weighted Average Floor Price		Weighted Average Ceiling Price
2013		775	$	80.00	$	105.00
2014		1,500	$	65.00	$	110.00

The following table represents Resolute’s three-way commodity collar contracts as of June 30, 2013.


			(NYMEX WTI - $/Bbl)
Year	Bbl Per Day		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price
2014		2,000	$	70.00	$	85.00	$	100.83

The following table represents Resolute’s commodity call option contracts as of June 30, 2013.


			(NYMEX WTI - $/Bbl)				(NYMEX WTI - $/Bbl)
Year	Bbl per Day		Weighted Average Bought Call Price		Bbl per Day		Weighted Average Sold Call Price
2013		2,000	$	82.50		4,000	$	87.63

The following table represents Resolute’s commodity put option contracts as of June 30, 2013.


			(NYMEX WTI - $/Bbl)
Year	Bbl per Day		Weighted Average Bought Put Price		Weighted Average Sold Put Price
2013		2,000	$	85.00	$	70.00
2014		1,200	$	85.00	$	70.00

The following table represents Resolute’s commodity swap contracts as of June 30, 2013.


Year	Bbl per Day		(NYMEX WTI - $/Bbl) Weighted Average Swap Price		MMBtu per Day		(NYMEX HH - $/MMBtu) Weighted Average Swap Price
2013		5,000	$	79.41		6,900	$	5.056
2014		2,000	$	89.08		5,000	$	4.165

The following table sets forth Resolute’s basis swaps as of June 30, 2013.


Year	Index	MMBtu per Day		Weighted Average Price Differential per MMBtu
2013	Rocky Mountain NWPL		1,800	$	2.100
2013	Rocky Mountain CIG		500	$	0.590
2014	Rocky Mountain CIG		1,000	$	0.590

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 June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Other income (expense):
Realized losses	$	(6,883	)	$	(9,189	)	$	(13,775	)	$	(17,706	)
Unrealized gains		13,724			38,735			13,830			33,423

Total gains on derivative instruments	$	6,841		$	29,546		$	55		$	15,717

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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 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 derivative assets and liabilities with the same counterparty for financial reporting purposes. The following is a listing of Resolute’s assets and liabilities required to be measured at fair value on a recurring basis and where they are classified within the hierarchy as of June 30, 2013 and December 31, 2012 (in thousands):


	Level 2
	June 30, 2013		December 31, 2012
Assets
Oil and gas commodity contracts, current assets	$	5,625	$	8,523
Oil and gas commodity contracts, long term assets		982		475

Total assets	$	6,607	$	8,998

Liabilities
Oil and gas commodity contracts, current liabilities	$	22,060	$	31,847
Oil and gas commodity contracts, long term liabilities		1,770		8,204

Total liabilities	$	23,830	$	40,051

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 June 30, 2013, under this purchase agreement, based on prices in effect at June 30, 2013, are as follows (in thousands):


Year	CO₂ Purchase Commitments
2013	$	15,011
2014		30,271
2015		30,271
2016		12,042

Total	$	87,595

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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, 2012, 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”), the Powder River and Big Horn basins in Wyoming (the “Wyoming Properties”) and the Williston Basin in North Dakota (the “Bakken 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, 2012, our estimated net proved reserves were approximately 78.8 million equivalent barrels of oil (“MMBoe”), of which approximately 59% and 43% were proved developed reserves and proved developed producing reserves, respectively. Approximately 79% of our net proved reserves were oil and approximately 90% were oil and natural gas liquids (“NGL”). The December 31, 2012, pre-tax present value discounted at 10% of our net proved reserves was $1,127 million and the standardized measure of our estimated net proved reserves was $872 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 and operating cash flow. 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, 2012.

Aneth Field Properties

Our largest asset, constituting 75% of our net proved reserves as of December 31, 2012, 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 June 30, 2013. 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.

During 2012, we and Navajo Nation Oil and Gas Company (“NNOGC”) entered into an amendment to our Cooperative Agreement. Among other changes, this amendment allowed NNOGC to exercise options to purchase 10% of our interest in Aneth Field. These options were exercised for cash consideration of $100 million. We 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 our 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. We remain the operator of our Aneth Field Properties.

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Permian Properties

On December 21, 2012, we purchased properties from Celero Energy II, LP containing proved reserves of approximately 4.1 MMBoe in Denton Field on the Northwest Shelf in Lea County, New Mexico, and in the Spraberry trend in the Midland Basin portion of the Permian Basin in Howard County, Texas, for a purchase price of approximately $117 million. Additionally, 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 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, 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 exercised. On March 22, 2013, we exercised that option and acquired the remaining 67.65% interest in the RSP properties, which contained proved reserves of approximately 11.1 MMBoe. The purchase price for the 67.65% interest was $257 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, and we estimate that a one-rig vertical drilling program for two years would hold all of the acquired leases. We believe that growth potential exists from approximately 28 gross prospective horizontal locations with multiple targets in the Wolfcamp, Spraberry and Atoka formations, approximately 45 vertical drilling locations targeting the Wolfcamp through Atoka interval, and 69 Spraberry recompletion opportunities. On a combined basis, our Permian Acquisitions in December 2012 and March 2013 contributed 20.6 MMBoe of proved reserves. The Permian Acquisitions were financed with the net proceeds from the $150 million senior notes offering in December 2012 and borrowings under our revolving credit facility.

Our Permian Properties are located in the Permian Basin of west Texas and southeast New Mexico, and are divided between three principal project areas. Our Wolfberry 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 Wolfbone 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 each of our Wolfberry and Wolfbone 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 the Wolfbone and Wolfberry areas will be increasingly focused on horizontal drilling activity targeting these same formations.

During the six months of 2013, we completed 15 gross (12 net) wells on our Permian Properties and were in the process of drilling 1 gross (1 net) well at quarter end.

Wyoming Properties

Hilight Field is located in the Powder River Basin in Campbell County, Wyoming. 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. Our objective for 2013 is to integrate these data and drill a horizontal well to test the Turner formation in the third quarter. We also plan to develop the Mowry formation through additional uphole recompletions. If this activity is successful, it could form the basis of a significant horizontal drilling program in Hilight in 2014 and beyond. In our exploration portfolio we also own acreage in the Big Horn Basin, which may be prospective for production from multiple formations, including the Frontier and Phosphoria. We continue to study these formations with the objective of testing them prior to facing significant lease expirations in 2015.

Bakken Properties

Our Bakken Properties are located in the Bakken trend of the Williston Basin in North Dakota. We have had two principal project areas: the New Home project located in Williams County and the Paris project area located in McKenzie County. We also have interests in various smaller project areas, primarily in McKenzie County. During the first six months of 2013, we completed 9 gross (2 net) wells on our Bakken Properties. On June 27, 2013, we entered into a purchase and sale agreement with HRC Energy, LLC, a Colorado limited liability company, and wholly-owned subsidiary of Halcón Resources Corporation, a Delaware corporation, effective March 1, 2013, to dispose of all of our Bakken properties located in Williams County (the “New Home Properties”) for proceeds of $75 million net of customary purchase price adjustments. The transaction closed on July 15, 2013. We will record the net proceeds as a reduction to the capitalized costs of the Company’s oil and gas properties.

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 could 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 three and six months ended June 30, 2013 and 2012, respectively.

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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands, except where indicated)				(in thousands, except where indicated)
Net Sales:
Total sales (MBoe)		1,193		858		2,240		1,620
Average daily sales (Boe/d)		13,107		9,427		12,374		8,903
Average Sales Prices ($/Boe):
Average sales price (excluding derivative settlements)	$	74.72	$	75.16	$	75.02	$	79.01
Operating Expenses ($/Boe):
Lease operating	$	21.45	$	22.81	$	22.68	$	22.68
Production and ad valorem taxes		9.12		11.24		9.42		12.26
General and administrative		7.65		6.64		7.90		6.73
General and administrative (excluding non-cash compensation expense)		4.08		4.17		4.93		4.38
Depletion, depreciation, amortization and accretion		24.14		22.10		23.97		22.23

Quarter Ended June 30, 2013, Compared to the Quarter Ended June 30, 2012

Revenue. Revenue from oil and gas activities increased by 38% to $89.1 million during 2013, from $64.5 million during 2012. Of the $24.6 million increase in revenue, approximately $25.1 million was attributable to increased production, offset by $0.5 million in decreased commodity pricing. Average sales price for the quarter, excluding derivative settlements, decreased from $75.16 per Boe in 2012 to $74.72 per Boe in 2013, primarily as a function of decreased commodity pricing. Sales volumes increased 39% during 2013 as compared to 2012, from 858 MBoe to 1,193 MBoe. The majority of the production increase was related to the consummation of the Permian Acquisitions occurring in December and March as well as the drilling of additional wells during the quarter ended June 30, 2012.

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 $25.6 million during 2013, from $19.6 million during 2012. The $6.0 million, or 31%, increase was mainly 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 decreased by 6% from $22.81 to $21.45.

Production and ad valorem taxes in 2013 of $10.9 million increased over production and ad valorem taxes in 2012 of $9.6 million, but were less on a per-unit basis, mainly due to a decrease in ad valorem tax estimates in Utah and increased revenue in areas with lower tax rates. As a result, we expect to see an overall lower production tax rate going forward. Production and ad valorem taxes were 12% of total revenue in 2013 versus 15% of total revenue in 2012.

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Depletion, depreciation, amortization and accretion expenses increased to $28.8 million during 2013, as compared to $19.0 million during 2012. The $9.8 million, or 52%, increase is principally due to higher production and an increase in the depletion, depreciation and amortization rate from $22.10 per Boe in 2012 to $24.14 per Boe 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. Resolute monitors its 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 the Company’s asset base.

General and administrative expenses increased to $9.1 million during 2013, as compared to $5.7 million during 2012. The $3.4 million, or 60%, increase in general and administrative expenses mainly resulted from $2.1 million of increased share-based compensation and increases of $1.9 million in salaries and wages required to meet the demand of increasing operations across our primary focus areas and $0.5 million in professional services, offset by increased capitalized general and administrative costs and overhead billings. On a unit-of-production basis, general and administrative expenses increased 15%. Cash based general and administrative expense increased from $3.6 million to $4.9 million, or 36%.

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 2013, the gain on oil and gas derivatives was $6.8 million, consisting of $6.9 million of realized derivative settlement losses and $13.7 million of unrealized gains. During 2012, the gain on oil and gas derivatives was $29.5 million, consisting of $9.2 million of realized losses and $38.7 million of unrealized gains.

Interest expense in 2013 increased to $7.2 million from the $3.7 million recorded in 2012 as a result of a higher average debt balance and higher weighted average interest rate due to the issuance of our 8.50% Senior Notes (defined below). The components of our interest expense were as follows (in thousands).


	Three Months Ended June 30,
	2013			2012
8.50% Senior Notes	$	8,500		$	3,896
Credit Facility		2,729			753
Amortization of deferred financing costs and Senior Notes premium		642			434
Other		(9	)		(64	)
Capitalized interest		(4,681	)		(1,323	)

	$	7,181		$	3,696

Income Tax Benefit (Expense). Income tax expense recognized during 2013 was $5.4 million, or 37.3% of the income before income taxes, as compared to income tax expense of $13.6 million, or 37.4% of income before income taxes in 2012.

Six Months Ended June 30, 2013, compared to Six Months Ended June 30, 2012

Revenue. Revenue from oil and gas activities increased by 31% to $168.0 million during 2013, from $128.0 million during 2012. Of the net $40.0 million increase in revenue, approximately $48.9 million was attributable to increased production offset by $8.9 million of lower commodity prices. Average sales price for the period, excluding derivative settlements, decreased from $79.01 per Boe in 2012 to $75.02 per Boe in 2013, primarily as a function of decreased commodity pricing. Sales volumes increased 38% during 2013 as compared to 2012, from 1,620 MBoe to 2,240 MBoe. The increase is mainly due to increased production from new wells in the Permian Basin Properties as a result of the consummation of the Permian Acquisitions occurring in December and March as well as the drilling of additional wells during the quarter ended June 30, 2012.

Operating Expenses. Aggregate lease operating expenses increased to $50.8 million during 2013, from $36.7 million during 2012. The $14.1 million, or 38%, increase was attributable to increased workover activity in our Aneth Field Properties and additional operating expenses associated with the Permian Acquisitions. On a per-unit basis, lease operating expense remained unchanged at $22.68.

Production and ad valorem taxes increased by 6% to $21.1 million in 2013, versus $19.9 million in 2012, due to the increase in production over 2012 offset by lower ad valorem tax estimates associated with the decrease in the assessed value of reserves in 2013. Production and ad valorem taxes were 13% of total revenue in 2013 versus 16% of total revenue in 2012.

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Depletion, depreciation, amortization and accretion expenses increased to $53.7 million during 2013, as compared to $36.0 million during 2012. The $17.7 million, or 49%, increase is principally due to an increase in the depletion, depreciation and amortization rate from $22.23 per Boe in 2012 to $23.97 per Boe in 2013 as a result of increased finding costs on new drilling and completion activities.

General and administrative expenses for Resolute increased to $17.7 million during 2013, as compared to $10.9 million during 2012. The $6.8 million, or 62%, increase in general and administrative expenses resulted from increases of $5.2 million in salaries and wages, $2.8 million in share-based compensation expense, $0.9 million in professional services, $0.3 million in corporate overhead, offset by increases in capitalized labor and overhead billings. On a unit-of-production basis, general and administrative expenses increased 17%. Cash based general and administrative expense increased from $7.1 million to $11.0 million, or 56%.

Other Income (Expense). During 2013, the gain on oil and gas derivatives was $0.1 million, consisting of $13.8 million of unrealized gains and $13.7 million of realized losses. During 2012, the gain on oil and gas derivatives was $15.7 million, consisting of $33.4 million of unrealized gains and $17.7 million of realized losses on derivative settlements.

Interest expense in 2013 increased to $15.3 million from the $4.9 million recorded in 2012 as a result of the higher interest rate associated with the Senior Notes issuances in 2012 and increased average borrowings. The components of our interest expense were as follows (in thousands).


	Six Months Ended June 30,
	2013			2012
8.50% Senior Notes	$	17,000		$	3,896
Credit Facility		4,378			2,123
Amortization of deferred financing costs and Senior Notes premium		1,245			704
Other		(12	)		(1	)
Capitalized interest		(7,349	)		(1,812	)

	$	15,262		$	4,910

Income Tax Benefit (Expense). Income tax expense recognized during 2013 was $3.6 million, or 37.4% of income before income taxes, as compared to income tax expense of $13.2 million, or 37.4% of the income before income taxes during 2012.

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, issuance of Senior Notes (defined below), public equity offerings 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 six months ended June 30, 2013 and 2012.


	Six Months Ended June 30,
	2013			2012
	(in thousands)
Cash provided by operating activities	$	64,524		$	40,570
Cash used in investing activities		(322,163	)		(127,104	)
Cash provided by financing activities		257,584			88,251

Net cash provided by operating activities was $64.5 million for the first six months of 2013 compared to $40.6 million for the 2012 period, which reflects increased production, offset by lower commodity prices realized in 2013, and increases in working capital.

We plan to reinvest a sufficient amount of our cash flow in our development operations in order to maintain our production over the long term, and 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 $322.2 million in 2013 compared to $127.1 million in 2012. The primary investing activity in 2013 was cash used for capital expenditures of $374.6 million. Capital expenditures consisted of $257 million paid to acquire additional interest in the Permian Properties, $17.1 million in compression and facility and drilling projects in Aneth Field, $9.7 million in CO₂ acquisition, $58.5 million in drilling activities and infrastructure projects in the Permian Basin of West Texas, $28.0 million in drilling and completion activities in the Bakken trend of North Dakota, and $4.0 million in recompletion and drilling activities in our Wyoming Properties. A portion of these capital costs were accrued and not paid at period end. The 2012 capital expenditures were comprised of $23.4 million in compression, facility and drilling projects in Aneth Field, $35.8 million for the Denbury acquisition, $7.8 million in CO₂ acquisition, $30.7 million in drilling activities and infrastructure projects in the Permian Basin of West Texas, $33.6 million in drilling and completion activities in the Bakken trend of North Dakota, $7.2 million in recompletion activities in our Wyoming Properties and $0.2 million in other capital projects.

Net cash provided by financing activities was $257.6 million in 2013 compared to $88.3 million in 2012. The primary financing activities in 2013 were net borrowings of $158.0 million under the Credit Facility (defined below) and $101.8 million in net proceeds received from the issuances of common stock. The primary financing activities in 2012 were $250.0 million in proceeds received from the issuance of the Senior Notes offset by net payments of $143.0 million under the Credit Facility, and $10.0 million paid to retire publicly traded Company warrants.

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 the covenants in our Credit Facility or our Senior Notes. 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 (the “Credit Facility”) with the Company 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 we 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 (which expires on March 22, 2018) and a $40 million non-conforming tranche. The Sixth Amendment, among other things, also amended the Maximum Leverage Ratio to (a) 4.50:1.00 for all fiscal quarters ending through December 31, 2013, (b) 4.25:1.00 for the fiscal quarter ending March 31, 2014, and (c) 4.00:1.00 for all fiscal quarters ending June 30, 2014, and thereafter. In addition, the maturity date of the Credit Facility was extended from April 2017 to March 2018. In April 2013 the Company entered into the Seventh Amendment to the amended and restated Credit Facility which adjusted the Maximum Leverage Ratio to (a) 4.25:1.00 for the fiscal quarter ending December 31, 2012, (b) 4.85:1:00 for the fiscal quarter ending March 31, 2013, (c) 4.50:1.00 for all fiscal quarters ending June 30, 2013 through December 31, 2013, (d) 4.25:1.00 for the fiscal quarter ending March 31, 2014, and (e) 4.00:1.00 for all fiscal quarters ending June 30, 2014 and thereafter. 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 Rate 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 connection with the equity offering that closed in May 2013, the $40 million non-conforming tranche of the borrowing base was automatically terminated, resulting in a borrowing base decrease to $445 million. In July 2013, the borrowing base under the Company’s revolving credit facility was further reduced by $30 million, to $415 million, as a result of the disposition of the New Home Properties.

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As of June 30, 2013, outstanding borrowings were $320 million under the borrowing base of $445 million. The borrowing base availability had been reduced by $3.1 million in conjunction with letters of credit issued to vendors at June 30, 2013, and other limitations based upon a multiple of trailing Adjusted EBITDA as defined in the Credit Facility. 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 terms and covenants that place limitations on certain types of activities, including the payment of dividends, and requires satisfaction of certain financial tests. We were in compliance with all terms and covenants of the Credit Facility at June 30, 2013.

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, 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” or the “Notes”). 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, 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. 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 June 30, 2013.

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 our option, 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 Senior 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

We entered into the Sixth Amendment to the Amended and Restated Credit Facility (described above) which extended the maturity date of our conforming tranche from April 2017 to March 2018. Accordingly, the $320 million outstanding on the Credit Facility at June 30, 2013, is due March 2018.

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) 85% of our anticipated production from proved properties in the next two years and for years thereafter not to exceed (ii) the greater of 75% of our anticipated production from proved properties or 85% of our anticipated production from proved developed producing properties in each case 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 of which are members of Resolute’s Credit Facility bank syndicate at June 30, 2013. As of June 30, 2013, the fair value of our commodity derivatives was a net liability of $17.2 million.

The following table represents our two-way commodity collar contracts as of June 30, 2013.


					(NYMEX WTI - $/Bbl)
Year			Bbl per Day		Weighted Average Floor Price		Weighted Average Ceiling Price		Fair Value of Asset (Liability) (in thousands)
2013				775	$	80.00	$	105.00	$	(597	)
2014				1,500	$	65.00	$	110.00	$	(2,543	)

The following table represents our three-way commodity collar contracts as of June 30, 2013.

			(NYMEX WTI - $/Bbl)
Year	Bbl Per Day		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price		Fair Value of Asset (Liability) (in thousands)
2014		2,000	$	70.00	$	85.00	$	100.83	$	471

The following table represents our commodity call option contracts as of June 30, 2013.
Year	Bbl per Day		(NYMEX WTI - $/Bbl) Weighted Average Bought Call Price		Bbl per Day		(NYMEX WTI - $/Bbl) Weighted Average Sold Call Price		Fair Value of Asset (Liability) (in thousands)
2013		2,000	$	82.50		4,000	$	87.63	$	802

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The following table represents our commodity put option contracts as of June 30, 2013.


								(NYMEX WTI - $/Bbl)
Year					Bbl per Day			Weighted Average Bought Put Price		Weighted Average Sold Put Price		Fair Value of Asset (Liability) (in thousands)
2013						2,000		$	85.00	$	70.00	$	(1,204	)
2014						1,200		$	85.00	$	70.00	$	(754	)

The following table represents our commodity swap contracts as of June 30, 2013.

Year	Bbl per Day		(NYMEX WTI - $/Bbl) Weighted Average Swap Price		Fair Value of Asset (Liability)			MMBtu per Day		(NYMEX HH - $/MMBtu) Weighted Average Swap Price		Fair Value of Asset (Liability) (in thousands)
2013		5,000	$	79.41	$	(14,270	)		6,900	$	5.056	$	1,788
2014		2,000	$	89.08	$	(620	)		5,000	$	4.165	$	462

The following table represents our basis swaps as of June 30, 2013.


Year	Index	MMBtu per Day		Weighted Average Price Differential per MMBtu		Fair Value of Asset (Liability) (in thousands)
2013	Rocky Mountain NWPL		1,800	$	2.100	$	(623	)
2013	Rocky Mountain CIG		500	$	0.590	$	(30	)
2014	Rocky Mountain CIG		1,000	$	0.590	$	(105	)

Interest Rate Risk

At June 30, 2013, 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 June 30, 2013. 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 June 30, 2013, 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 June 30, 2013, 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, 2012. These risks are not the only risks facing the Company.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

In connection with the vesting of company restricted common stock under the 2009 Long Term Performance Incentive Plan (“Incentive Plan”), we retain shares of common stock at the election of the recipients of such awards in satisfaction of withholding tax obligations. These shares are retired by the Company.


2013	Total Number of Shares Purchased⁽¹⁾		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publically Announced Plan		Maximum Number of Shares That May Yet Be Purchased Under The Plan⁽²⁾
April		1,395	$	11.32		—		—
May		2,847	$	8.77		—		—

1)	All shares purchased in 2013 were to offset tax withholding obligations that occur upon the vesting and delivery of outstanding common shares under the terms of the Incentive Plan.

2)	As of June 30, 2013, the maximum number of shares that may yet be purchased would not exceed the employees’ portion of taxes withheld on unvested shares (3,786,497 common shares) and the shares yet to be granted under the Incentive Plan (4,019,407 common shares).

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 furnished 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. In accordance with Rule 406T of Regulation S-T, the information in these exhibits is furnished and is deemed not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Exchange Act of 1934, and otherwise is not subject to liability under these sections except as expressly set forth by the specific reference in such filing

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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	Chief Executive Officer (Principal Executive Officer)	August 5, 2013
Nicholas J. Sutton	Chief Executive Officer (Principal Executive Officer)	August 5, 2013

/s/ Theodore Gazulis	Chief Financial Officer (Principal Financial Officer)	August 5, 2013
Theodore Gazulis	Chief Financial Officer (Principal Financial Officer)	August 5, 2013

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