UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

FORM 10-Q

 

For the quarterly period ended June 30, 2015

OR

Commission File No. 001-34464

 

RESOLUTE ENERGY CORPORATION

(Exact Name of Registrant as Specified in its Charter)

 

 

(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   þ    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  þ    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  þ

As of July 31, 2015, 77,511,951 shares of the Registrant’s $0.0001 par value Common Stock were outstanding.

 

 

 

 

 

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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, our production and cost guidance for 2015; anticipated capital expenditures in 2015 and the sources of such funding; availability of alternative oil purchase markets and oil takeaway systems; our financial condition and management of the Company in the current commodity price environment; future financial and operating results; our intention to evaluate and pursue de-levering transactions, including joint ventures and asset sales; liquidity and availability of capital including projections of free cash flow; additional future potential full cost ceiling impairments; future downward adjustments in estimated proved reserves as a result of low commodity prices; future borrowing base adjustments and the effect thereof; future production, reserve growth and decline rates; production rates, decline rates and estimated ultimate recoveries of oil and gas; our plans and expectations regarding our development activities including drilling, deepening, recompleting, fracing and refracing wells, the number of such potential projects, locations and productive intervals, and the resource potential of such projects; and the prospectivity of our properties and acreage. 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, although not exclusively, located under the heading “Risk Factors.” All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, we undertake no obligation to update any forward-looking statement. Factors that could cause actual results to differ materially from our expectations include, among others, those factors referenced in the “Risk Factors” section of this report, if any, in our Annual Report on Form 10-K for the year ended December 31, 2014, and such things as:

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Additionally, the Securities and Exchange Commission (“SEC”) requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods and governmental regulations. The SEC permits the optional disclosure of “probable” and “possible” reserves. From time to time, we may elect to disclose probable reserves and possible reserves, excluding their valuation, in our SEC filings, press releases and investor presentations. The SEC defines “probable” reserves as “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are likely as not to be recovered.” The SEC defines “possible” reserves as “those additional reserves that are less certain to be recovered than probable reserves.” The Company

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applies these definitions when estimating probable and possible reserves. Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserves estimates or potential resources disclosed in our public filings, press releases and investor presentations that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s reserves reporting guidelines.

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

Finally, 24 hour peak IP rates and 30 day peak IP rates for both our wells and for those wells that are operated by others are limited data points in each well’s productive history and not necessarily indicative or predictive of future production rates, EUR or economic rates of return from such wells and should not be relied upon for such purpose. Equally, the way we calculate and report 24 hour and 30 day peak IP rates and the methodologies employed by others may not be consistent, thus the values reported may not be directly and meaningfully comparable.

You are urged to consider closely the disclosure in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 2014, in particular the factors described under “Risk Factors.”

 

 

 

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TABLE OF CONTENTS

 

 

 

 

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RESOLUTE ENERGY CORPORATION

Condensed Consolidated Balance Sheets (Unaudited)

(in thousands, except share amounts)

 

 

See notes to condensed consolidated financial statements

 

 

 

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RESOLUTE ENERGY CORPORATION

Condensed Consolidated Statements of Operations (Unaudited)

(in thousands, except per share data)

 

 

See notes to condensed consolidated financial statements

 

 

 

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RESOLUTE ENERGY CORPORATION

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

(in thousands)

 

 

See notes to condensed consolidated financial statements

 

 

 

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RESOLUTE ENERGY CORPORATION

Condensed Consolidated Statements of Cash Flows (Unaudited)

(in thousands)

 

 

See notes to condensed consolidated financial statements

 

 

 

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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 primarily of properties in Aneth Field located in the Paradox Basin in southeast Utah (the “Aneth Field Properties” or “Aneth Field”), the Permian Basin in west Texas and southeast New Mexico and the Big Horn and Powder River basins in Wyoming. The Company conducts all of its activities in the United States of America.

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.

 

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, 2014. 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, 2014. 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, 2014.

Recent Accounting Pronouncements

In April 2015, the FASB issued new authoritative guidance related to the presentation of deferred financing costs. This authoritative guidance is effective for the annual period beginning after December 15, 2015, including interim reporting periods within that reporting period. The new guidance prescribes that the application be applied retrospectively.  The Company elected to early-adopt this guidance in the first quarter of 2015. Accordingly, the Company has reclassified all deferred financing costs to a direct deduction from the carrying amounts of debt for the balance sheets at June 30, 2015, and December 31, 2014 (See Note 5 to the condensed consolidated financial statements).

In August 2014, the FASB issued new authoritative accounting guidance related to management’s responsibility to evaluate whether there is substantial doubt about an organization’s ability to continue as a going concern. This authoritative accounting guidance is effective for the annual period beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

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.

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

Oil and Gas Properties

The Company uses the full cost method of accounting for oil and gas operations. Accounting rules require Resolute to perform a quarterly “ceiling test” calculation to test its oil and gas properties for possible impairment. The primary components affecting this calculation are commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. If the net capitalized cost of the Company’s oil and gas properties subject to amortization (the “carrying value”) exceeds the ceiling limitation, the excess is 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.

For the three and six months ended June 30, 2015, the Company recorded a non-cash impairment of the carrying value of its oil and gas properties of $210 million and $430 million, respectively, as a result of the ceiling test limitation. The Company recorded no ceiling test impairment during the comparable prior year periods. If in future periods a negative impact continues on one or more of the components of the calculation, including market prices of oil and gas (based on a trailing twelve-month unweighted average of the oil and natural gas prices in effect on the first day of each month), differentials from posted prices, future drilling and capital plans, operating costs or expected production, the Company may incur further full cost ceiling impairment related to its oil and gas properties in such periods.

 

Note 3 — Acquisitions and Divestitures

Sale of Howard and Martin County Properties

During the period ended June 30, 2015, the Company sold its Howard and Martin County properties in the Permian Basin for approximately $42 million. A portion of the purchase price ($2.1 million) has been escrowed and classified as an other current asset at June 30, 2015, in connection with post-closing indemnification rights under the purchase and sale agreement. The sale was consummated on May 1, 2015 with an effective date of March 1, 2015.

 

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 and options 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):

 

 

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

 

 

 

Note 5 — Long Term Debt

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

 

 

For the three months ended June 30, 2015 and 2014, the Company incurred interest expense on long-term debt of $15.9 million and $7.6 million, respectively. For the six months ended June 30, 2015 and 2014, the Company incurred interest expense on long-term debt of $27.0 million and $15.4 million, respectively. The Company capitalized $0.5 million and $4.0 million of interest expense during the three months ended June 30, 2015 and 2014, respectively. The Company capitalized $5.0 million and $7.8 million of interest expense during the six months ended June 30, 2015 and 2014, respectively.

Revolving Credit Facility

Resolute’s revolving credit facility is with a syndicate of banks led by Wells Fargo Bank, National Association, as Administrative Agent, and Bank of Montreal, as Syndication Agent (the “Revolving Credit Facility”) with Resolute as the borrower. The Revolving 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. The Revolving Credit Facility matures in March 2018.

In December 2014 Resolute entered into the Eleventh Amendment to the amended and restated Revolving Credit Facility agreement that set the borrowing base at $330 million, eliminated the total debt-to-EBITDA covenant and conformed the covenant package in the Revolving Credit Facility to that of the Secured Term Loan Facility (defined below). The covenants require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) secured debt to EBITDA of no more than 3.5

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to 1.0, (ii) PV-10 of total proved reserves to total secured debt of at least 1.1 to 1.0, rising over time to 1.5 to 1.0, and (iii) PV-10 of proved developed reserves to total secured debt of at least 1.0 to 1.0. Our Revolving Credit Facility and our Secured Term Loan Facility also require us to enter into derivative agreements covering at least 70% of our anticipated production from proved properties on a rolling twenty four month basis, but prohibit us from entering into derivative arrangements for more than (i) 85% of our anticipated production from proved properties in the next two years and (ii) the greater of 75% of our anticipated production from proved properties or 85% of our production from projected proved developed producing reserves using economic parameters specified in our Revolving Credit Facility.

In April 2015 Resolute entered into the Twelfth Amendment to the amended and restated Revolving Credit Facility agreement which set the borrowing base at $275 million effective April 15, 2015, and included a provision for the sale of the oil and gas properties in Howard and Martin counties, Texas (which was consummated May 1, 2015), subject to a $5 million automatic reduction in the borrowing base upon the closing of such sale. Furthermore, the amendment extended the deadline for incurring up to $50 million of additional loans under the Secured Term Loan Agreement (discussed below) to May 31, 2015, amended the claw back provision related thereto such that the borrowing base was reduced automatically upon such incurrence by an amount equal to 20% of the principal amount of such additional loans (rather than the 90% claw back provision previously in effect) and modified the maximum first lien leverage ratio covenant so that the ratio level will not step down to 2.0 to 1.0 until the aggregate outstanding principal balance of the second lien debt exceeds $200 million (rather than when it equals or exceeds $200 million).

In May 2015 Resolute borrowed an additional $50 million of second lien term debt (discussed below). As a result, the Company’s borrowing base under the Revolving Credit Facility was automatically reduced by $10 million to $260 million.

Each base rate borrowing under the Revolving Credit Facility accrues interest at either (a) the London Interbank Offered Rate (“LIBOR”), plus a margin which varies from 1.50% to 2.50% or (b) the alternative Base Rate defined as the greater of (i) the Administrative Agent’s Prime Rate (ii) the Federal Funds effective Rate plus 0.5% or (iii) an adjusted London Interbank Offered Rate plus a margin which ranges from 0.50% to 1.50%. Each such margin is based on the level of utilization under the borrowing base.

As of June 30, 2015, outstanding borrowings under the Revolving Credit Facility were $160 million, under a borrowing base of $260 million. The borrowing base availability had been reduced by $3.1 million in conjunction with letters of credit issued at June 30, 2015. 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. However, should the borrowing base be set at a level below the outstanding balance, Resolute would be required to eliminate that excess over 120 days following that determination. The Revolving Credit Facility is guaranteed by all of Resolute’s subsidiaries and is collateralized by substantially all of the proved oil and gas assets of Resolute Aneth, LLC, Resolute Wyoming, Inc. and Resolute Natural Resources Southwest, LLC, which are wholly-owned subsidiaries of the Company.

As of June 30, 2015, the weighted average interest rate on the outstanding balance under the Revolving Credit Facility was 2.19%. The fair value of the Revolving Credit Facility approximates its principal amount because the interest rate of the Revolving Credit Facility is variable over the term of the loan.

The Revolving Credit Facility includes customary terms and covenants that place limitations on certain types of activities, the payment of dividends, and require satisfaction of certain financial tests. Resolute was in compliance with all material terms and covenants of the Revolving Credit Facility at June 30, 2015.

Secured Term Loan Agreement

On December 30, 2014, Resolute and certain of its subsidiaries, as guarantors, entered into a second lien Secured Term Loan Agreement with Bank of Montreal, as administrative agent, and the lenders party thereto, pursuant to which the Company borrowed $150 million (the “Secured Term Loan Facility”). Initial funding of the Secured Term Loan Facility occurred on December 31, 2014, with net proceeds of approximately $135 million after payment of transaction-related fees, expenses and discounts. Net proceeds were used to repay amounts outstanding under the Revolving Credit Facility. The Secured Term Loan Facility will mature on the date that is six months after the maturity of the Company’s existing Revolving Credit Facility, but in no event later than November 1, 2019.

 

On May 18, 2015, Resolute and certain of its subsidiaries, as guarantors, entered into an Amendment to the Secured Term Loan Agreement and Increased Facility Activation Notice-Incremental Term Loans (the “Amendment”) with Bank of Montreal, as administrative agent, and the lenders party thereto, pursuant to which the Company borrowed an additional $50 million of second lien term debt (the “Incremental Term Loans”) under its Secured Term Loan Agreement dated December 30, 2014.  Funding of the Incremental Term Loans occurred on May 19, 2015.  The Incremental Term Loans have the same terms as the existing second lien borrowings under the Secured Term Loan Agreement, adjusted for the date of the closing. The $50 million of Incremental Term Loans was placed with the same lenders that participated in the initial $150 million second lien closing in December 2014. Net proceeds from the Incremental Term Loans of approximately $46 million after payment of transaction-related fees, expenses and discounts, were used to repay amounts outstanding under the Revolving Credit Facility.

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Obligations under the Secured Term Loan Facility are guaranteed by certain of the Company’s subsidiaries and secured by second priority liens on substantially all of the assets of the Company and its subsidiaries that serve as collateral under the Revolving Credit Facility.

Borrowings under the Secured Term Loan Facility will generally bear interest at adjusted LIBOR plus 10%, with a 1% LIBOR floor. The covenants in the Secured Term Loan Facility require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) secured debt to EBITDA of no more than 3.5 to 1.0, (ii) PV-10 of total proved reserves to total secured debt of at least 1.1 to 1.0, rising over time to 1.5 to 1.0, and (iii) PV-10 of proved developed reserves to total secured debt of at least 1.0 to 1.0.

The Company may prepay all or a portion of the Secured Term Loan Facility at any time. The Secured Term Loan Facility is subject to mandatory prepayments of 75% of the net cash proceeds from asset sales after any mandatory repayment of first lien debt, subject to a limited right to reinvest proceeds in oil and gas activities. Prepayments made out of proceeds from asset sales are not subject to prepayment premiums. Mandatory repayments are required of 100% of the net cash proceeds of certain debt or equity issuances. Such prepayments are subject to a premium of between 10% declining to 2% during the first 36 months after closing. To the extent not otherwise achieved, aggregate repayments that substantially pay off principal amounts under the second lien facility shall include an additional payment sufficient to ensure that the lenders achieve a 1.25 to 1.0 minimum multiple of their invested capital. However, in connection with the Twelfth Amendment to the amended and restated Revolving Credit Facility agreement described above, the mandatory prepayment of Secured Term Loan Facility debt under the Howard and Martin County properties sale was waived.

Due to the lack of an active market, quoted market prices for the Company’s Secured Term Loan Facility or similar debt are not available.  The Company used valuation techniques that relied on unobservable inputs, current information including LIBOR interest rates and the specific terms of the Secured Term Loan Facility to estimate the fair value (a Level 3 fair value measurement).  The fair value of the Company’s Secured Term Loan Facility at June 30, 2015, was estimated to be $186.4 million, which approximates its carrying value (as defined as principal less the unamortized discount).

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”). The Senior Notes are due May 1, 2020, and bear an annual interest rate of 8.50% with the interest on the Senior Notes payable semiannually in cash on May 1 and November 1 of each year.

The Senior Notes were issued under an Indenture (the “Indenture”) among the Company, the Company’s existing subsidiaries (the “Guarantors”) and U.S. Bank National Association, as trustee (the “Trustee”) in a private transaction not subject to the registration requirements of the Securities Act of 1933. In March 2013, the Company registered the Senior Notes with the Securities and Exchange Commission by filing an amendment to the registration statement on Form S-4 enabling holders of the Senior Notes to exchange the privately placed Senior Notes for publically registered Senior Notes with substantially identical terms. The Indenture contains affirmative and negative covenants that, among other things, limit the Company’s and the Guarantors’ ability to make investments, incur additional indebtedness or issue preferred stock, create liens, sell assets, enter into agreements that restrict dividends or other payments by restricted subsidiaries, consolidate, merge or transfer all or substantially all of the assets of the Company, engage in transactions with the Company’s affiliates, pay dividends or make other distributions on capital stock or prepay subordinated indebtedness and create unrestricted subsidiaries. The Indenture also contains customary events of default. Upon occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the Trustee or the holders of the Senior Notes. Upon the occurrence of certain other events of default, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under its Senior Notes as of June 30, 2015.

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. The Senior Notes may 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 Senior 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 the Company purchase all

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of such holder’s Senior Notes in an amount equal to 101% of the principal of such Senior Notes, plus accrued and unpaid interest, if any, to the date of the purchase.

The fair value of the Senior Notes at June 30, 2015, was estimated to be $242.5 million based upon data from independent market makers (Level 2 fair value measurement).

 

Note 6 — Income Taxes

Income tax benefit (expense) during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income (loss), plus any significant unusual or infrequently occurring items that are recorded in the interim period. The provision for income taxes for the three and six months ended June 30, 2015 and 2014, differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to income before income taxes. The lower effective rate in 2015 relates to the valuation allowance placed on the net deferred tax asset in 2015, in addition to state income taxes and estimated permanent differences.

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

 

 

The Company had no reserve for uncertain tax positions as of June 30, 2015. The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will be realized. The Company considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. As a result of the Company’s analysis, it was concluded that as of June 30, 2015, a valuation allowance should be established against the Company’s net deferred tax asset. The Company recorded a valuation allowance as of June 30, 2015 of $155.7 million on its long-term deferred tax asset. There was no valuation allowance established as of June 30, 2014. The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that the deferred tax assets will be realized.

 

Note 7 — Stockholders’ Equity and Long-term Employee Incentive Plan

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, 2015, or December 31, 2014.

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, 2015, and December 31, 2014, the Company had 77,538,199 and 77,634,737 shares of common stock issued and outstanding, respectively.

Long-term Employee Incentive Plan

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 12,257,744 (which includes the additional 3,100,000 shares under Amendment No. 2 to the Incentive Plan approved by the shareholders on June 8, 2015).

On May 5, 2015, the Board and its Compensation Committee approved a long-term incentive program for 2015 under the Incentive Plan consisting of grants of (i) options to purchase shares of common stock of the Company, vesting in equal annual installments on each of the first three anniversaries of the date of grant, with an exercise price of $1.35 per share and a ten year term,

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(ii) time-vested restricted cash awards of $5.2 million, vesting in equal annual installments on each of the first three anniversaries of the date of grant, and (iii) performance-vested restricted cash awards of $2.9 million, as described below.

For the three and six months ended June 30, 2015 and 2014, the Company recorded expense related to the Incentive Plan as follows (in thousands):

As of June 30, 2015, the Company held unrecognized share-based compensation expense (in thousands) which is expected to be recognized over a weighted-average period as follows:

Equity Awards

Equity awards consist of service-based and performance-based restricted stock units and stock options under the Incentive Plan.

Stock Option Awards

Options issued on May 5, 2015 to employees to purchase shares of common stock vest in three equal annual installments at specified dates based on continued employment, with an exercise price of $1.35 per share and a ten year term. The compensation expense to be recognized for the option awards was measured based on the Company’s estimated fair value at the date of grant using a Black-Scholes pricing model as well as an estimated forfeiture rate of 10% which will be updated periodically based on actual employee turnover. During the six months ended June 30, 2015, the Company granted 1,895,496 options to employees to purchase shares of common stock, pursuant to the Incentive Plan.

The following table summarizes the changes in non-vested option awards for the six months ended June 30, 2015:

 

Time-Based Restricted Stock Awards

Shares of time-based restricted stock issued to employees 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 restricted stock awards was measured based on the Company’s closing stock price on the dates of grant, utilizing estimated forfeiture rates between 10% and 20% which are updated periodically based on actual employee turnover. During the six months ended June 30, 2015, the Company granted 160,500 shares of time-based 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 restricted stock awards for the six months ended June 30, 2015:

 

 

Stock Appreciation 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 $11.639 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.”          

The following table summarizes the changes in non-vested Stock Appreciation Awards for the six months ended June 30, 2015:

 

 

TSR Awards

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

The Compensation Committee and Board 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 was measured based on the estimated fair value at the date of grant using a Monte Carlo simulation model and utilizes estimated forfeiture rates between 4% and 10% which are updated periodically based on actual employee turnover.

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The valuation model for the Performance-Based Awards used the following assumptions:

 

 

          The following table summarizes the changes in non-vested TSR Awards for the six month period ended June 30, 2015:

 

Liability Awards

Liability awards consist of awards that are settled in cash instead of shares, as discussed below.

Time-Based Restricted Cash Awards

Awards of time-based restricted cash issued to employees vest in three equal annual increments at specified dates based on continued employment. The compensation expense to be recognized for the time-based restricted cash awards was measured utilizing an estimated forfeiture rate of 15% which will be updated periodically based on actual employee turnover. The total estimated future liability of the time-based restricted cash awards as of June 30, 2015, was $4.4 million, of which $0.2 million has been accrued.

Performance-Based Restricted Cash Awards

The performance criteria for the performance-based restricted cash awards granted in May 2015 will be based on future prices of the Company’s common stock trading at or above specified thresholds. If and as certain stock price thresholds are met, using a 60 trading day average, various multiples of the performance-vested cash award will be attained. The first stock price hurdle is at $2.00 at which the award would be payable at 1x, and the highest stock price hurdle would be $8.00 at which the award would be payable at a multiple of 6x. Interim hurdles and multiples between these end points are set forth in the governing agreements. The performance-based cash awards have a ten year term (i.e., the Company’s obligation would be triggered at any time the defined stock price multiples are met over a ten year period, subject to the initial three year vesting period, described below, and provided the employee continues to be employed by the Company). A time vesting element will apply to the performance-vested cash awards such that attained multiples will not be paid out earlier than upon satisfaction of a three-year vesting timetable from the date of grant. In order for an award to be paid, both the performance criteria and the time criteria would need to be satisfied. Once a time vesting date passes, the employee is entitled to be paid one third, two thirds or 100%, as applicable, of whatever multiples have been achieved. Any multiples achieved following 100% time vesting would be paid within 60 days of such achievement.

The fair value of the performance-based restricted cash awards as of grant date and June 30, 2015, was $0.9 million and $1.2 million, respectively, of which $0.1 million has been accrued at quarter end based upon the three-year vesting. The fair value was estimated using an option pricing model for a cash or nothing call, an estimated forfeiture rate of 5% and an average effective term of seven years. As the fair value of liability awards is required to be re-measured at each period end, amounts recognized in future periods will vary.

 

 

 

 

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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 and facilities in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or revised, that ranges between 7% and 12%. Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. Asset retirement obligations are valued utilizing Level 3 fair value measurement inputs.

The following table provides a reconciliation of Resolute’s asset retirement obligations for the periods presented (in thousands):

 

 

 

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 cash flow hedges under the provisions of FASB ASC Topic 815, Derivatives and Hedging. As a result, these derivative instruments are marked to market at the end of each reporting period and changes in the fair value are recorded in the accompanying consolidated statements of operations. Gains and losses on commodity derivative instruments from Resolute’s price risk management activities are recognized in other income (expense). The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as financing activities in the condensed consolidated statement of cash flows.

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 put price and the floor price. 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, when used in connection with fixed price swaps, to fix the price differential between the NYMEX Commodity price and the index price at which the gas production is sold.

As of June 30, 2015, the fair value of the Company’s commodity derivatives was a net asset of $74.0 million (Level 2 fair value measurement).

The following table represents Resolute’s commodity swap contracts as of June 30, 2015:

 

 

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The following table represents Resolute’s two-way commodity collar contracts as of June 30, 2015:

 

 

 

The following table represents Resolute’s three-way commodity collar contracts as of June 30, 2015:

 

 

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

 

 

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 Revolving Credit Facility. Accordingly, Resolute is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Revolving Credit Facility. Resolute’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). Typical terms for each ISDA include credit support requirements, cross default provisions, termination events, and set-off provisions. Resolute generally has set-off provisions with its lenders that, in the event of counterparty default, allow Resolute to set-off amounts owed under the Revolving Credit Facility or other general obligations against amounts owed for derivative contract liabilities.

Resolute does not offset the fair value amounts of commodity derivative assets and liabilities with the same counterparty for financial reporting purposes. The following is a listing of Resolute’s commodity derivative assets and liabilities required to be measured at fair value on a recurring basis and where they are classified within the hierarchy as of June 30, 2015, and December 31, 2014 (in thousands):

 

 

 

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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 ultimate CO₂ volumes planned for use on the enhanced recovery projects exceed the minimum daily volumes provided in these take-or-pay purchase agreements. Although the Company may incur deficiency payments from time to time, Resolute expects to avoid any payments for deficiencies over the term of the agreement.

Future minimum CO₂ purchase commitments as of June 30, 2015, under this purchase agreement, based on prices and volumes in effect at June 30, 2015, are as follows (in thousands):

 

 

Cooperative Agreement with Navajo Nation Oil and Gas Company

Resolute is party to a cooperative agreement with Navajo Nation Oil and Gas Company (“NNOGC”) related to the Aneth Field Properties (the “Cooperative Agreement”). Pursuant to the Cooperative Agreement, NNOGC holds an option to purchase an additional 10% of Resolute’s interest in the Aneth Field Properties. The option is exercisable in July 2017 at the then-current fair market value of such interest at that time.

 

 

 

 

 

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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, 2014, 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 primarily 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 Basin Properties”) and the Big Horn and Powder River Basins in Wyoming (the “Wyoming Properties”). Our primary operational focus for 2015 is on maintaining production while reducing operating costs in the current depressed commodity price environment. Over the longer term, we will focus on increasing reserves and production from these properties while improving efficiency and optimizing operating costs. We plan to expand our reserve base production 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 Basin Properties, through carefully targeted exploration activities in our properties, and through opportunistic acquisitions.

During 2014 oil sales comprised approximately 89% of revenue, and our December 31, 2014, estimated net proved reserves were approximately 74.2 million barrels of oil equivalent (“MMBoe”), of which approximately 56% and 45% were proved developed reserves and proved developed producing reserves (“PDP”), respectively. Approximately 86% of our estimated net proved reserves were oil and approximately 92% were oil and natural gas liquids (“NGL”). The December 31, 2014, pre-tax present value discounted at 10% (“PV-10”) of our net proved reserves was $973 million and the standardized measure of our estimated net proved reserves was $833 million.

 

Estimates of proved reserves are based upon many assumptions and are highly dependent on market oil and gas prices (based on a trailing twelve-month un-weighted average of the prices in effect on the first of each month) and operating costs. Although Resolute has been successful in meaningfully reducing operating costs in 2015, oil prices realized in 2015 have been significantly lower than prices realized during the same period in 2014. If these lower oil prices persist during the remainder of 2015, it is likely that we will have downward adjustments to our estimated net proved reserves at December 31, 2015, perhaps by a substantial amount.

Pursuant to full cost accounting rules, we perform ceiling tests each quarter on our proved oil and gas assets. We recorded non-cash impairments of the carrying value of our proved oil and gas properties of $120 million, $220 million, and $210 million at December 31, 2014, March 31, 2015, and June 30, 2015, respectively, as a result of the ceiling test limitation. These impairments resulted primarily from lower oil prices realized beginning in October 2014 and continuing through the date of this report. Our estimates of the present value of future net cash flows were based on a pricing methodology required by SEC rules.  This commodity price assumption used in calculating our future net cash flows at June 30, 2015, significantly exceeds the current market price of oil and gas.  Therefore it is likely that we will have substantial downward adjustments in our estimated discounted future net cash flows from proved reserves and substantial additional impairments in future periods if the current low commodity price environment persists.

In view of the current depressed oil and gas price environment, we have adopted an operating and financial plan for 2015 that holds production essentially flat, while preserving capital, enhancing liquidity and paying down debt. We expect to fund our 2015 capital expenditures exclusively from internally generated cash flow. We will pursue such actions as are necessary to preserve our liquidity and to remain in compliance with the terms and conditions of our Revolving Credit Facility, Secured Term Loan Facility and Senior Notes, including asset sales, sales of other debt or equity securities, and other transactions. We have taken steps to enhance our liquidity through the sale of assets in Howard and Martin counties, Texas. We also have drawn down an additional $50 million of second lien debt for additional liquidity. We currently have secured a borrowing base of $260 million under our Revolving Credit Facility. In addition, we have significantly reduced our lease operating and general and administrative expenses from 2014 levels. When these cost saving measures are combined with our strong hedge position, we expect to generate cash flow in excess of our 2015 capital expenditure budget and to further reduce our bank debt. In 2015 we will also continue to explore other ways to de-lever our balance sheet, including pursuing additional asset sales and potential joint ventures to drill wells on the Company’s acreage, particularly in the Permian Basin. In June 2015 the Company commenced a process to sell Hilight Field. There can be no assurance that a sale will be consummated on terms acceptable to the Company. We also continue to explore opportunities to increase activity within our asset base in light of the commodity price environment and the evolving drilling, completion and operating cost structure.

Our Revolving Credit Facility, Secured Term Loan Facility and Senior Notes include customary terms and covenants that place limitations on certain types of activities and require satisfaction of certain financial tests.  We were in compliance with all material terms and covenants of the Revolving Credit Facility, Secured Term Loan Facility and Senior Notes at June 30, 2015.

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Our management uses a variety of financial and operational measurements to analyze our operating performance, including but not limited to, production levels, pricing and cost trends, reserve trends, operating and general and administrative expenses, operating cash flow and Adjusted EBITDA. The analysis of these measurements should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2014.

Aneth Field Properties

Our largest asset, constituting 73% of our net proved reserves as of December 31, 2014, 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 own working interests of 62%, 67.5% and 59%, respectively, at June 30, 2015. 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.

The field is connected by pipeline to a refinery located near Gallup, New Mexico that is owned and operated by Western Refining Southwest, Inc., a subsidiary of Western Refining Inc. (“Western”). Western currently purchases all of the oil production from Aneth Field under a purchase agreement dated July 2014. On December 31, 2014, the Company entered into an amendment to the purchase agreement with Western which provides for Resolute to receive a price equal to the NYMEX oil price minus a differential of $8.00 per barrel of oil. The amendment also provides that the term of the purchase agreement shall continue automatically after December 31, 2014, until March 31, 2015, and thereafter on a month-to-month basis until terminated by either party, with ninety days prior notice. If, for any reason, Western is unable to process our oil, there is alternative access to markets through rail and truck facilities or through the FERC-regulated Texas-New Mexico pipeline owned by Western.

Permian Basin Properties

Our Permian Basin Properties, constituting 19% of net proved reserves as of December 31, 2014, are located in the Permian Basin of Texas and southeast New Mexico. Our position is divided among three principal project areas: the Delaware Basin project area in Reeves County, the Midland Basin project area in Midland and Ector counties and the Northwest Shelf project area located in the Denton, Gladiola and Knowles fields in the Northwest Shelf area in Lea County, New Mexico. Our project area located in the Delaware Basin portion of the Permian Basin, in Reeves County, targets the Wolfcamp formation. We believe that growth potential exists from our more than 280 gross prospective wells targeting three zones in the Wolfcamp formation based on 160-acre spacing. Significant additional opportunity exists from reduced spacing as well as additional subzones. Our second project area located in the Midland Basin portion of the Permian Basin, in Midland and Ector counties, primarily targets the Wolfcamp and Spraberry formations. We believe that growth potential exists from more than 110 gross prospective horizontal wells targeting multiple zones in the Wolfcamp and Spraberry formations. Our third project area, in 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 believe that growth potential and upside may exist in these properties from activities such as deepening existing wells and infill drilling from 40-acre to 20-acre spacing.

As of June 30, 2015, we had 1 gross (0.2 net) non-operated well awaiting completion operations in the Delaware Basin.

During the period ended June 30, 2015, we sold our Howard and Martin County properties in the Permian Basin for approximately $42 million. A portion of the purchase price ($2.1 million) has been escrowed and classified as an other current asset in connection with post-closing indemnification rights under the purchase and sale agreement. The sale was consummated on May 1, 2015 with an effective date of March 1, 2015.

Wyoming Properties

Hilight Field, constituting 8% of net proved reserves as of December 31, 2014, is located in the Powder River Basin in Campbell County, Wyoming. The Powder River Basin is experiencing a transformation due to horizontal drilling targeting oil-bearing formations such as the Turner, Niobrara, Shannon, Sussex, Parkman and Mowry. Along with these unconventional opportunities, the 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 Hilight Field and the review of our extensive log data and data from operators drilling wells close to Hilight. We have successfully drilled and completed three horizontal wells in the Turner formation and we believe there are 70 additional horizontal drilling locations in the Turner on our leasehold, based on 215-acre spacing. While drilling our recent wells we collected additional petrophysical data in the Parkman, Shannon, Sussex and Niobrara formations. We believe there may be more than 66 potential Parkman horizontal locations on our acreage, assuming 160-acre spacing. During the second quarter of 2015, oil differentials have been significantly reduced due to improved infrastructure related to transportation of oil in the area.

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In June 2015 the Company commenced a process to sell Hilight Field. There can be no assurance that a sale will be consummated on terms acceptable to the Company.

Divestiture of North Dakota Properties

In March 2014 we sold our remaining operated properties in North Dakota for approximately $7.0 million.  

Factors That Significantly Affect Our Financial Results

Revenue, cash flow from operations and future growth are all directly related to the price of oil and depend on many factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Historical oil prices have been volatile and are expected to fluctuate widely in the future. Sustained periods of low prices for oil and lower realized prices for our 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.

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, 2015, in comparison to results for the three and six months ended June 30, 2014.

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:

 

 

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Quarter Ended June 30, 2015, Compared to the Quarter Ended June 30, 2014

Revenue. Revenue from oil and gas activities decreased by 45% to $48.4 million during 2015, from $88.5 million during 2014. Of the $40.1 million decrease in revenue, more than 100% of the difference, or approximately $48.8 million, was attributable to decreased commodity pricing ($39.31 per Boe in 2015 versus $78.96 per Boe in 2014) offset by $8.7 million in increased production. Sales volumes increased 10% to 1,231 MBoe during 2015 as compared to 1,120 MBoe during 2014 due to increased production from the drilling of additional wells in the Permian Basin Properties.

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 decreased to $19.4 million during 2015, from $29.4 million during 2014. The $10.0 million, or 34%, decrease was attributable to reduced spending initiatives driven by depressed commodity pricing. On a per-unit basis, lease operating expense decreased 40% to $15.77 in 2015 from $26.23 in 2014.

Production and ad valorem taxes in 2015 of $6.4 million decreased from $10.0 million in 2014 and were less on a per-unit basis, due to decreased revenue from oil and gas activities. Production and ad valorem taxes were 13.2% of total revenue in 2015 versus 11.3% of total revenue in 2014.

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

General and administrative expenses decreased to $7.5 million during 2015, as compared to $10.5 million during 2014. The $3.0 million, or 28%, decrease in general and administrative expenses primarily resulted from targeted cost reductions associated with salaries, wages and burdens. On a unit-of-production basis, general and administrative expenses decreased 35%. Cash-based general and administrative expense decreased 24% to $4.8 million in 2015 from $6.3 million in 2014.

Restricted cash award expense increased to $0.3 million during 2015, as compared to no related expense during 2014. On a per-unit basis, restricted cash award expense was $0.28 per Boe in 2015. The increased expense is a result of the May 2015 grant of time- and performance-based restricted cash awards under the long-term incentive program for 2015. The time-based awards will vest and be expensed ratably over three years. The performance-based awards will vest ratably over three years but their fair value will be re-measured at each period end over their ten-year life.

Depletion, depreciation, amortization and accretion expenses decreased to $26.6 million during 2015, as compared to $31.6 million during 2014. On a per-unit basis, depreciation, amortization and accretion expenses decreased to $21.61 per Boe in 2015 from $28.23 per Boe in 2014 due to a decrease in the 2015 amortization base offset by a 10% increase in 2015 production.

Pursuant to full cost accounting rules, we perform ceiling tests each quarter on our proved oil and gas assets. We recorded a $210 million non-cash impairment of the carrying value of our proved oil and gas properties at June 30, 2015, as a result of the ceiling test limitation. No impairment was recorded at June 30, 2014. The 2015 impairment resulted primarily from lower oil prices realized. In addition, our estimate of proved reserves as of June 30, 2015, was based on a pricing methodology required by SEC rules. This commodity price assumption used in calculating our reserves significantly exceeds the current market price of oil and gas. Therefore it is likely that we will have additional impairment resulting from substantial downward adjustments in our estimated proved reserves and discounted future net cash flows if the current low commodity price environment persists.  

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 2015 the loss on oil and gas commodity derivatives was $21.3 million, consisting of $39.3 million of mark-to-market losses offset by $18.0 million of derivative settlement gains. During 2014 the loss on oil and gas commodity derivatives was $22.2 million, consisting of $14.9 million of mark-to-market losses and $7.3 million of derivative settlement losses.

Interest expense in 2015 increased to $15.9 million from the $7.6 million recorded in 2014. The $8.3 million increase in interest expense was primarily due to higher interest rates associated with the Secured Term Loan Facility entered into on December 30, 2014, as well as lower capitalized interest due to decreased exploration activity. The components of our interest expense are as follows (in thousands):  

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Income Tax Benefit (Expense). There was no income tax benefit recognized during 2015, as compared to income tax benefit of $6.7 million, or 29.3% of the loss before income taxes in 2014. The lower 2015 effective rate was attributable to the valuation allowance that was established during 2015, in addition to noncash executive compensation that is anticipated to be nondeductible for income tax purposes and to permanent differences related to share-based compensation.

Six Months Ended June 30, 2015, compared to Six Months Ended June 30, 2014

Revenue. Revenue from oil and gas activities decreased by 50% to $89.5 million during 2015, from $179.3 million during 2014. Of the $89.8 million decrease in revenue, more than 100% of the difference, or approximately $105.1 million, was attributable to decreased commodity pricing ($36.60 per Boe in 2015 from $79.56 per Boe in 2014) offset by $15.3 million in increased production. Sales volumes increased 9% to 2,446 MBoe during 2015 as compared to 2,254 MBoe during 2014 primarily due to increased production from the drilling of additional wells in the Permian Basin Properties as well as increased response from tertiary recovery techniques in the Aneth Field Properties.

Operating Expenses. Lease operating expenses decreased to $39.8 million during 2015, from $58.0 million during 2014. The $18.2 million, or 31%, decrease was attributable to reduced spending initiatives driven by depressed commodity pricing. On a per-unit basis, lease operating expense decreased 37% to $16.26 in 2015 from $25.75 in 2014.

 

Production and ad valorem taxes of $12.3 million in 2015, versus $20.6 million in 2014 and were less on a per-unit basis, due to decreased revenue from oil and gas activities. Production and ad valorem taxes were 13.7% of total revenue in 2015 versus 11.5% of total revenue in 2014.

General and administrative expenses decreased to $14.8 million during 2015, as compared to $19.1 million during 2014. The $4.3 million, or 22%, decrease in general and administrative expenses primarily resulted from targeted cost reductions associated with salaries, wages and burdens. On a unit-of-production basis, general and administrative expenses decreased 29%. Cash based general and administrative expense decreased 24% to $9.2 million from $12.2 million.

Restricted cash award expense increased to $0.3 million during 2015, as compared to no related expense during 2014. On a per-unit basis, restricted cash award expense was $0.14 per Boe in 2015. The increased expense is a result of the May 2015 grant of time- and performance-based restricted cash awards under the long-term incentive program for 2015. The time-based awards will vest and be expensed ratably over three years. The performance-based awards will vest ratably over three years but their fair value will be re-measured at each period end over their ten-year life.

Depletion, depreciation, amortization and accretion expenses decreased $5.0 million, or 8%, to $58.5 million during 2015, as compared to $63.5 million during 2014. On a per-unit basis, depreciation, amortization and accretion expenses decreased to $23.92 per Boe in 2015 from $28.19 per Boe in 2014 due to a decrease in the 2015 amortization base offset by a 9% increase in 2015 production.

Pursuant to full cost accounting rules, we perform ceiling tests each quarter on our proved oil and gas assets. We recorded a $430 million non-cash impairment of the carrying value of our proved oil and gas properties at June 30, 2015 as a result of the ceiling test limitation. No impairment was recorded at June 30, 2014. The 2015 impairment resulted primarily from lower oil prices realized. In addition, our estimate of proved reserves as of June 30, 2015 was based on a pricing methodology required by SEC rules. This commodity price assumption used in calculating our reserves significantly exceeds the current market price of oil and gas. Therefore it is likely that we will have additional impairment resulting from substantial downward adjustments in our estimated proved reserves and discounted future net cash flows if the current low commodity price environment persists.  

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Other Income (Expense). During 2015, the gain on oil and gas commodity derivatives was $3.6 million, consisting of $42.1 million of derivative settlement gains and $38.5 million of mark-to-market losses. During 2014, the loss on oil and gas commodity derivatives was $30.1 million, consisting of $18.0 million of mark-to-market losses and $12.1 million of derivative settlement losses.

Interest expense in 2015 increased to $27.0 million from the $15.4 million recorded in 2014. The $11.6 million increase in interest expense was primarily due to higher interest rates associated with the Secured Term Loan Facility entered into on December 30, 2014, as well as lower capitalized interest due to decreased exploration activity. The components of our interest expense were as follows (in thousands):

 

Income Tax Benefit (Expense). Income tax benefit recognized during 2015 was $22.4 million, or 4.6% of the loss before income taxes, as compared to income tax benefit of $7.8 million, or 28.4% of the loss before income taxes during 2014. The significant difference in effective tax rate in 2015 is primarily due to the valuation allowance that was established during 2015, in addition to noncash executive compensation that is anticipated to be nondeductible for income tax purposes and to permanent differences related to share-based compensation.

 

Liquidity and Capital Resources

 

Our primary sources of liquidity have been cash generated from operations, amounts available under our Revolving Credit Facility, proceeds from the issuance of debt and equity securities and sales of 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, 2015 and 2014.

 

 

Net cash provided by operating activities was $40.4 million for the first six months of 2015 as compared to $91.7 million for the 2014 period. Cash provided by operating activities is largely dependent upon commodity prices and production volumes, net of the effects of settlement of our derivative contracts. The decrease in net cash provided by operating activities in 2015 over 2014 was primarily due to decreased revenue resulting from lower commodity prices (offset by increased production and derivative settlement gains), and changes in working capital as a result of lower commodity prices and reduced drilling activities in 2015. Resolute’s cash flows from operating activities are also affected by the costs related to continued operations and debt service.

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

In view of the current depressed oil and gas price environment, we have adopted an operating and financial plan for 2015 that holds production essentially flat, while preserving capital, enhancing liquidity and paying down debt. We expect to fund our 2015 capital expenditures exclusively from internally generated cash flow. We will pursue such actions as are necessary to preserve our liquidity and to remain in compliance with the terms and conditions of our Revolving Credit Facility, Secured Term Loan Facility and Senior Notes, asset sales, sales of other debt or equity securities, and other transactions. We have taken steps to enhance our liquidity through the sale of assets in Howard and Martin counties, Texas. We also have drawn down an additional $50 million of second lien debt for additional liquidity. We currently have secured a borrowing base of $260 million under our Revolving Credit Facility. In addition, we have significantly reduced our lease operating and general and administrative expenses from 2014 levels. When these

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cost saving measures are combined with our strong hedge position, we expect to generate cash flow in excess of our 2015 capital expenditure budget and to further reduce our bank debt. In 2015 we will also continue to explore other ways to de-lever our balance sheet, including pursuing additional asset sales and potential joint ventures to drill wells on the Company’s acreage, particularly in the Permian Basin. In June 2015 the Company commenced a process to sell Hilight Field. There can be no assurance that a sale will be consummated on terms acceptable to the Company. We also continue to explore opportunities to increase activity within our asset base in light of the commodity price environment and the evolving drilling, completion and operating cost structure.

Net cash used in investing activities was $11.1 million in 2015 compared to $89.0 million in 2014. The primary investing activity in 2015 was cash used for capital expenditures of $50.1 million. Capital expenditures consisted primarily of $7.7 million in compression and facility projects in Aneth Field, $4.5 million in CO₂ acquisition, $34.4 million in drilling activities and infrastructure projects in the Permian Basin of west Texas and $3.5 million in drilling activities and infrastructure in our Wyoming Properties. Capital divestitures included $40.0 million of proceeds from the sale of the Howard and Martin County properties in the Permian Basin and $0.6 million of proceeds from the sale of certain properties in the Bakken trend of North Dakota and acreage in Park County, Wyoming and Andrews County, Texas. The 2014 capital expenditures consisted primarily of $15.0 million in compression and facility and drilling projects in Aneth Field, $8.0 million in CO₂ acquisition, $64.0 million in drilling activities and infrastructure projects in the Permian Basin of west Texas and $3.3 million in recompletion and drilling activities in our Wyoming Properties. Capital divestitures in 2014 included $4.8 million of proceeds from the sale of certain operated properties in the Bakken trend of North Dakota.

Net cash used in financing activities was $33.3 million in 2015 compared to $1.5 million in 2014. The primary financing activities in 2015 were $75 million in net payments under the Revolving Credit Facility, $3.7 million in financing costs paid and $0.9 million in Secured Term Loan Facility principal payments offset by $46.5 million in net proceeds from the issuance of the Incremental Term Loans under the Secured Term Loan Facility.

If cash flow from operating activities does not meet expectations, we may reduce our expected level of capital expenditures and/or fund a portion of our capital expenditures using borrowings under our Revolving Credit Facility (if available), issuances of other debt or equity securities or from other sources, such as asset sales. We have in place an effective shelf registration statement, with a remaining capacity of $394 million; however our ability to access this capacity may be substantially limited by applicable shelf eligibility rules and market conditions. 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 covenants in our Revolving Credit Facility, Secured Term Loan Facility or our Senior Notes. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to satisfy our objectives under our existing indebtedness, finance the capital expenditures necessary to maintain production or proved reserves or complete acquisitions that may be favorable to us.

Our Revolving Credit Facility and our Secured Term Loan Facility require us to enter into derivative agreements covering at least 70% of our anticipated production from proved properties on a rolling twenty four month basis, but prohibit us from entering into derivative arrangements for more than (i) 85% of our anticipated production from proved properties in the next two years and (ii) the greater of 75% of our anticipated production from proved properties or 85% of our production from projected proved developed producing reserves using economic parameters specified in our Revolving Credit Facility.

We plan to continue our practice of hedging a significant portion of our production through the use of various commodity derivative transactions. Our existing derivative transactions have not been designated 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 Revolving Credit Facility to fund our operations.

Revolving Credit Facility

Our Revolving Credit Facility is with a syndicate of banks led by Wells Fargo Bank, National Association, as Administrative Agent, and Bank of Montreal, as Syndication Agent with Resolute as the borrower. The Revolving 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. Based upon the current depressed oil and gas price environment, we expect that the current borrowing base of $260 million will be reduced, perhaps significantly, at the fall borrowing base redetermination, which will be effective in October 2015. Under certain circumstances, either the Company or the lenders may request an interim redetermination. The Revolving Credit Facility matures in March 2018.

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In December 2014 we entered into the Eleventh Amendment to the amended and restated Revolving Credit Facility agreement which set the borrowing base at $330 million, eliminated the total debt-to-EBITDA covenant and conformed the covenant package in the Revolving Credit Facility to that of the Secured Term Loan Facility. The covenants require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) secured debt to EBITDA of no more than 3.5 to 1.0, (ii) PV-10 of total proved reserves to total secured debt of at least 1.1 to 1.0, rising over time to 1.5 to 1.0, and (iii) PV-10 of proved developed reserves to total secured debt of at least 1.0 to 1.0. Our Revolving Credit Facility and our Secured Term Loan Facility also require us to enter into derivative agreements covering at least 70% of our anticipated production from proved properties on a rolling twenty four month basis, but prohibit us from entering into derivative arrangements for more than (i) 85% of our anticipated production from proved properties in the next two years and (ii) the greater of 75% of our anticipated production from proved properties or 85% of our production from projected proved developed producing reserves using economic parameters specified in our Revolving Credit Facility.

In April 2015 we entered into the Twelfth Amendment to the amended and restated Revolving Credit Facility agreement which set the borrowing base at $275 million effective April 15, 2015, and included a provision for the sale of the oil and gas properties in Howard and Martin Counties, Texas (which was consummated May 1, 2015), subject to a $5 million automatic reduction in the borrowing base upon the closing of such sale. Furthermore, the amendment extended the deadline for incurring up to $50 million of additional loans under the Secured Term Loan Agreement (discussed below) to May 31, 2015, amended the claw back provision related there to such that the borrowing base was reduced automatically upon such incurrence by an amount equal to 20% of the principal amount of such additional loans (rather than the 90% claw back provision previously in effect) and modified the maximum first lien leverage ratio covenant so that the ratio level will not step down to 2.0 to 1.0 until the aggregate outstanding principal balance of the Second Lien debt exceeds $200 million (rather than when it equals or exceeds $200 million).

In May 2015 we borrowed an additional $50 million of second lien term debt (discussed below). As a result, the borrowing base under the Revolving Credit Facility was automatically reduced by $10 million to $260 million.

Each base rate borrowing under the Revolving Credit Facility accrues interest at either (a) the London Interbank Offered Rate, plus a margin which varies from 1.50% to 2.50% or (b) the alternative Base Rate defined as the greater of (i) the Administrative Agent’s Prime Rate (ii) the Federal Funds effective Rate plus 0.5% or (iii) an adjusted London Interbank Offered Rate (“LIBOR”) plus a margin which ranges from 0.50% to 1.50%. Each such margin is based on the level of utilization under the borrowing base.

As of June 30, 2015, outstanding borrowings under the Revolving Credit Facility were $160 million, with a borrowing base of $260 million. The borrowing base availability is reduced by $3.1 million in conjunction with letters of credit issued at June 30, 2015. 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. However, should the borrowing base be set at a level below the outstanding balance, we would be required to eliminate that excess over the 120 days following that determination. The Revolving 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.

As of June 30, 2015, the weighted average interest rate on the outstanding balance under the Revolving Credit Facility was 2.19%.

The Revolving Credit Facility includes customary terms and covenants that place limitations on certain types of activities, the payment of dividends, and require satisfaction of certain financial tests. We were in compliance with all material terms and covenants of the Revolving Credit Facility at June 30, 2015.

 

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.

 

Secured Term Loan Agreement

On December 30, 2014, we entered into a second lien Secured Term Loan Agreement with Bank of Montreal, as administrative agent, and the lenders party thereto, pursuant to which we borrowed $150 million. Initial funding of the Secured Term Loan Facility occurred on December 31, 2014 with net proceeds of approximately $135 million after payment of transaction-related fees, expenses and discounts. Net proceeds were used to repay amounts outstanding under the Revolving Credit Facility. The Secured Term Loan Facility will mature on the date that is six months after the maturity of our existing Revolving Credit Facility, but in no event later than November 1, 2019.

On May 18, 2015, Resolute and certain of its subsidiaries, as guarantors, entered into an Amendment to the Secured Term Loan Agreement and Increased Facility Activation Notice-Incremental Term Loans with Bank of Montreal, as administrative agent, and the lenders party thereto, pursuant to which the Company borrowed an additional $50 million of Incremental Term Loans under its

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Secured Term Loan Agreement dated December 30, 2014.  Funding of the Incremental Term Loans occurred on May 19, 2015.  The Incremental Term Loans have the same terms as the existing second lien borrowings under the Secured Term Loan Agreement, adjusted for the date of the closing. The $50 million of Incremental Term Loans was placed with the same lenders that participated in the initial $150 million second lien closing in December 2014. Net proceeds from the Incremental Term Loans, of approximately $46 million after payment of transaction-related fees, expenses and discounts, were used to repay amounts outstanding under the Revolving Credit Facility.

Obligations under the Secured Term Loan Facility are guaranteed by our subsidiaries and secured by second priority liens on substantially all of our assets that serve as collateral under the Revolving Credit Facility.

Borrowings under the Secured Term Loan Facility will generally bear interest at adjusted LIBOR plus 10%, with a 1% LIBOR floor. The covenants in the Secured Term Loan Facility require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) secured debt to EBITDA of no more than 3.5 to 1.0, (ii) PV-10 of total proved reserves to total secured debt of at least 1.1 to 1.0, rising over time to 1.5 to 1.0, and (iii) PV-10 of proved developed reserves to total secured debt of at least 1.0 to 1.0.

We may prepay all or a portion of the Secured Term Loan Facility at any time. The Secured Term Loan Facility is subject to mandatory prepayments of 75% of the net cash proceeds from asset sales, after any mandatory repayment to first lien debt, subject to a limited right to reinvest proceeds in oil and gas activities. Prepayments made out of proceeds from asset sales are not subject to prepayment premiums. Mandatory repayments are required of 100% of the net cash proceeds of certain debt or equity issuances. Such prepayments are subject to a premium of between 10% declining to 2% during the first 36 months after closing. To the extent not otherwise achieved, aggregate repayments that substantially pay off principal amounts under the second lien facility shall include an additional payment sufficient to ensure that the lenders achieve a 1.25 to 1.0 minimum multiple of their invested capital. However, in connection with the Twelfth Amendment to the amended and restated Revolving Credit Facility agreement described above, the mandatory prepayment of Secured Term Loan Facility debt under the Howard and Martin County properties sale was waived.

Senior Notes

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

The Senior Notes were issued under an Indenture (the “Indenture”) among the Company, our existing subsidiaries (the “Guarantors”) and U.S. Bank National Association, as trustee (the “Trustee”) in a private transaction not subject to the registration requirements of the Securities Act of 1933. In March 2013, the Company registered the Senior Notes with the Securities and Exchange Commission by filing an amendment to the registration statement on Form S-4 enabling holders of the Senior Notes to exchange the privately placed Notes for publically registered Notes with substantially identical terms. The Indenture contains affirmative and negative covenants that, among other things, limit our and the Guarantors’ ability to make investments, incur additional indebtedness or issue preferred stock, create liens, sell assets, enter into agreements that restrict dividends or other payments by restricted subsidiaries, consolidate, merge or transfer all or substantially all of our assets, engage in transactions with our affiliates, pay dividends or make other distributions on capital stock or prepay subordinated indebtedness and create unrestricted subsidiaries. The Indenture also contains customary events of default. Upon occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the Trustee or the holders of the Senior Notes. Upon the occurrence of certain other events of default, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. We were in compliance with all financial covenants under our Senior Notes as of June 30, 2015.

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. The Senior Notes may be redeemed at any time prior to May 1, 2016, at the option of the Company at a redemption price equal to 100% of the principal amount of the notes redeemed plus the applicable premium, and accrued and unpaid interest and additional interest, if any, to the applicable redemption date as set forth in the Indenture. If a change of control occurs, each holder of the Notes will have the right to require that we purchase all of such holder’s Notes in an amount equal to 101% of the principal of such Notes, plus accrued and unpaid interest, if any, to the date of the purchase.

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

By removing the price volatility from a significant portion of our oil and gas production, we have mitigated, but not eliminated, the potential effects of volatile prices on cash flow from operations for the periods hedged. While mitigating negative effects of falling commodity prices, certain of these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers. As of June 30, 2015, the fair value of our commodity derivatives was a net asset of $74.0 million.

The following table represents our commodity swap contracts as of June 30, 2015:

 

 

The following table represents our two-way commodity collar contracts as of June 30, 2015:

 

 

 

The following table represents our three-way commodity collar contracts as of June 30, 2015:

 

Interest Rate Risk

At June 30, 2015, we had $160 million and $199.1 million of outstanding debt under the Revolving Credit Facility and Secured Term Loan Facility, respectively. 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 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 Revolving 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 Revolving Credit Facility. Our

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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 Revolving Credit Facility lenders that, in the event of counterparty default, allow us to set-off amounts owed under the Revolving Credit Facility or other general obligations against amounts owed for derivative contract liabilities.

 

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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, 2015. Based on the evaluation, those officers have concluded that:

There has not been any change in the Company’s internal control over financial reporting that occurred during the quarterly period ended June 30, 2015, that has materially affected, or is reasonably likely to affect, the Company’s internal control over financial reporting.

 

 

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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.

 

Information about material risks related to our business, financial condition and results of operations for the quarter ended June 30, 2015, 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, 2014. These risks are not the only risks facing the Company.

 

Issuer Purchases of Equity Securities

In connection with the vesting of Company restricted common stock under the 2009 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.

 

 

 

None

 

Not applicable

 

None

 

 

 

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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.

 

 

 

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