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HK > SEC Filings for HK > Form 10-K on 5-Mar-2012All Recent SEC Filings

Show all filings for HALCON RESOURCES CORP



Annual Report

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


We are an independent energy company engaged in the acquisition, production, exploration and development of onshore oil and natural gas properties. Through our RAM Energy subsidiary, we have been active in our core producing areas of Texas, Louisiana and Oklahoma since 1987. Our management team has extensive technical and operating expertise in all areas of our geographic focus.

Recent Developments

On February 8, 2012, Halcón Resources, LLC, a newly-formed company led by Floyd C. Wilson, former Chairman and Chief Executive Officer of Petrohawk Energy Corporation, recapitalized us with a $550.0 million investment structured as the purchase of $275.0 million in new common stock, a $275.0 million five-year 8% convertible note and warrants for the purchase of an additional 36,666,666 million shares of our common stock at an exercise price of $4.50 per share. At closing, Floyd C. Wilson was appointed as our Chairman, President and Chief Executive Officer, and our name was changed to Halcón Resources Corporation. Mark Mize was also appointed as our Executive Vice President, Chief Financial Officer, Treasurer and was designated as our Principal Accounting Officer, and the composition of our board was altered to consist of 10 new individuals. Information as to our recent recapitalization is set forth under Note N to the Consolidated Financial Statements.

In connection with the closing of the Halcón Transaction, we entered into a Senior Revolving Credit Agreement (the "credit agreement") with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders named therein on February 8, 2012. The credit agreement provides for a $500.0 million facility with an initial borrowing base of $225.0 million. Amounts borrowed under the credit agreement will initially mature on February 8, 2017. The borrowing base will be redetermined semi-annually, with the company and the lenders each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and gas lending criteria. The borrowing base is subject to a reduction equal to the product of 0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any notes or other long-term debt securities that we may issue.

Following the recapitalization, our primary focus is to expand our leasehold position in areas we have determined are prospective for oil or liquids-rich resource plays. We have identified several target resource plays for potential leasehold acquisition, including the Utica Shale/Point Pleasant formations in Ohio and Pennsylvania, the Mississippian Lime formation in Northern Oklahoma and Southern Kansas, the Wilcox formation in Southwest Louisiana and the Woodbine/Eagle Ford formation in East Texas. In addition to our ongoing lease acquisition efforts in our targeted resource plays, we have identified several new exploratory areas we believe are prospective for oil and liquids-rich hydrocarbons.

On March 5, 2012, we sold in a private placement to certain institutional accredited investors 4,444.4511 shares of 8% automatically convertible preferred stock, par value $0.0001 per share, each share of which will convert into 10,000 shares of our common stock (or a proportionate number of shares of common stock with respect to any fractional shares of preferred stock), subject to certain adjustments, for approximately $400.0 million, or $9.00 per share of common stock, before offering expenses. The convertible preferred stock will convert into common stock automatically on the 20th calendar day after we mail a definitive information statement to holders of our common stock notifying them that our majority stockholder has consented to the issuance of common stock upon conversion of the convertible preferred stock. No dividend will be paid on the convertible preferred stock if it converts into common stock on or before May 31, 2012.

As a result of the recapitalization and the sale of the convertible preferred stock, we have substantial liquidity available to support our anticipated 2012 capital expenditures.

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On December 8, 2010, we completed the sale to Milagro Producing, LLC, a privately owned company located in Houston, Texas, of all of our oil and natural gas properties and related assets located in the Boonsville and Newark East fields of Jack and Wise Counties, Texas. The effective date of the sale was October 1, 2010. The sale properties included all of our Bend Conglomerate shallow gas properties and all of our North Texas Barnett Shale properties, including both producing properties and undeveloped leasehold. We received net cash proceeds at closing of $42.3 million subject to customary post-closing adjustments. As of December 31, 2010, net proceeds including post-closing adjustments were $41.0 million. Proved reserves from these properties accounted for approximately 26.4 billion cubic feet equivalent (Bcfe) of natural gas, natural gas liquids and oil, or an estimated 13% of our year-end 2009 proved reserves of 204 Bcfe. Information as to our recent divestitures is set forth under Note B to the Consolidated Financial Statements.

Oil and natural gas prices have historically been volatile. In 2011, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $93.86 per Bbl and $4.01 per Mcf, respectively, compared to 2010 average realized prices of $76.95 per Bbl and $4.21 per Mcf, respectively. A significant decline in annual average prices for oil and natural gas began during the last half of 2008 and continued into the first quarter of 2009. It is difficult to predict the frequency, duration or outcome of crude oil and natural gas price movements or the long-term impact on drilling and operating costs and the impacts, whether favorable or unfavorable, to our results of operations and liquidity. We continue to monitor operations and planned capital budget expenditures as the economics of many projects may diminish as a result of prolonged price declines.

Critical Accounting Policies

The preparation of our financial statements in conformity with generally accepted accounting principles requires our management to make estimates and assumptions that affect our reported assets, liabilities and contingencies as of the date of the financial statements and our reported revenues and expenses during the related reporting period. Our actual results could differ from those estimates. See Note A to our Consolidated Financial Statements included in Item 8 of this report for further discussions of our significant accounting policies and recently adopted accounting standards.

We follow the full cost method of accounting for oil and natural gas operations. Under this method all productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and natural gas reserves are capitalized. No gains or losses are recognized upon the sale or other disposition of oil and natural gas properties except in transactions that would significantly alter the relationship between capitalized costs and proved reserves. The costs of unevaluated oil and natural gas properties are excluded from the amortizable base until the time that either proven reserves are found or it has been determined that such properties are impaired. As properties become evaluated, the related costs transfer to proved oil and natural gas properties using full cost accounting.

Under the full cost method the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at 10% (the "Ceiling Limitation"). In arriving at estimated future net revenues, estimated lease operating expenses, development costs, and certain production-related and ad valorem taxes are deducted. In calculating future net revenues, prices and costs are held constant indefinitely, except for changes that are fixed and determinable by existing contracts. The net book value is compared to the Ceiling Limitation on a quarterly and yearly basis. The excess, if any, of the net book value above the Ceiling Limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. At March 31, 2009, the net book value of our oil and natural gas properties exceeded the Ceiling Limitation resulting in reduction in the carrying value of our oil and natural gas properties by $47.6 million, or $30.3 million net of tax. We incurred no impairment charge in 2010 or 2011.

The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If this unweighted

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average oil and natural gas price at December 31, 2011 had been 10% lower while all other factors remain constant, our ceiling amount related to our net book value of oil and natural gas properties would have been reduced approximately $44.5 million. This reduction would not have resulted in a full cost ceiling impairment.

Estimates of our crude oil and natural gas reserves are prepared by independent petroleum and geological engineers in accordance with guidelines established by the SEC. Proved reserves, estimated future net revenues and the present value of our reserves are estimated based upon a combination of historical data and estimates of future activity. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. Estimates of proved crude oil and natural gas reserves may significantly affect the amount at which oil and natural gas properties are recorded and significantly affect our amortization and depreciation expense.

Our rate of recording depreciation, depletion and amortization expense (DD&A) is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices, which may make it non-economic to drill for and produce higher cost reserves. A five percent positive revision to proved reserves would decrease the DD&A rate by approximately $0.68 per Boe, and a five percent negative revision to proved reserves would increase the DD&A rate by approximately $0.75 per Boe.

Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment cots include costs to dismantle and relocate or dispose of our production facilities, gathering systems and related structures and restoration costs. We develop estimates of these costs for each of our properties based upon their geographic, type of production structure, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis. A five percent decrease or increase in future development and abandonment costs would decrease or increase the DD&A rate by approximately $0.30 per Boe.

On December 31, 2008, the SEC issued Release No. 33-8995 amending its oil and natural gas reporting requirements for oil and natural gas producing companies. Companies were not permitted to comply at an earlier date. Among other things, Release No. 33-8995:

• Revises a number of definitions relating to proved oil and natural gas reserves to make them consistent with the Petroleum Resource Management System, which includes certain non-traditional resources in proved reserves;

• Permits the use of new technologies for determining proved oil and natural gas reserves;

• Requires the use of average prices for the trailing twelve-month period in the estimation of oil and natural gas reserve quantities and, for companies using the full cost method of accounting, in computing the Ceiling Limitation, in place of a single day price as of the end of the fiscal year;

• Permits the disclosure in filings with the SEC of probable and possible reserves and reserves sensitivity to changes in prices;

• Requires additional disclosures (outside of the financial statements) regarding the status of undeveloped reserves and changes in status of these from period to period; and

• Requires a discussion of the internal controls in place to assure objectivity in the reserve estimation process and disclosure of the technical qualifications of the technical person having primary responsibility for preparing the reserve estimates.

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Our independent petroleum engineers applied the procedures specified in SEC Release No. 33-8995 in preparing the estimate of our proved reserves as of December 31, 2010 and 2011, as reflected in this report.

Topic 410 of the Codification addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs and amends Statement of Financial Accounting Standards No. 19, now Topic 932 of the Codification. Topic 410 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. We determine our asset retirement obligation on our oil and natural gas properties by calculating the present value of the estimated cash flows related to the liability.

As set forth in Topic 740 of the Codification, deferred income taxes are recognized at each period end for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. We routinely assess the realizability of our deferred tax assets. We consider future taxable income in making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance. However, despite our attempt to make an accurate estimate, the ultimate utilization of our deferred tax assets is highly dependent upon our actual production and the realization of taxable income in future periods.

We account for our derivative arrangements as set forth in Topic 815 of the Codification. Topic 815 requires the accounting recognition of all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We may or may not elect to designate a derivative instrument as a hedge against changes in the fair value of an asset or a liability (a "fair value hedge") or against exposure to variability in expected future cash flows (a "cash flow hedge"). The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated by us as a hedge. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the statement of operations due to the fact that changes in fair value of the derivative offsets changes in the fair value of the hedged item. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in the fair value are recognized in earnings. We have not elected to designate our derivative instruments as hedges as required by Topic 815 in order to receive hedge accounting treatment. Accordingly, all gains and losses on the derivative instrument have been recorded in earnings.

During June 2008, the FASB issued authoritative guidance on whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in computing basic earnings per share. The guidance was effective for fiscal years beginning after December 15, 2008, and interim periods within those years. Additionally, all prior period earnings per share must be adjusted retrospectively. As our restricted stock awards granted under our Long-Term Incentive Plan qualify as participating securities, we adopted the guidance during 2009, which resulted in an increase in our basic and diluted weighted average shares outstanding.

We account for share-based payments under authoritative guidance, as set forth in Topic 718 of the Codification. Topic 718 requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

We account for uncertain tax positions under the guidance set forth in Topic 740 of the Codification. This Topic prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, the enterprise determines whether it is more

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likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based solely on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.

New Accounting Pronouncements

In December 2010, the FASB issued an update to authoritative guidance, as set forth in Topic 805 of the Codification, relating to business combinations. This update provides clarification requiring public companies that have completed material acquisitions to disclose the revenue and earnings of the combined business as if the acquisition took place at the beginning of the comparable prior annual reporting period, and also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, non-recurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. We will be required to apply this guidance prospectively for business combinations for which the acquisition date is on or after January 1, 2011. Adoption of this guidance on January 1, 2011 did not have a material impact on our financial position or statement of operations.

In May 2011, the FASB issued Accounting Standards Update ("ASU") No. 2011-04, "Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Accounting Reporting Standards ("IFRS")". This pronouncement was issued to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between U.S. GAAP and IFRS. ASU 2011-04 changes certain fair value measurement principles and enhances the disclosure requirements particularly for level 3 fair value measurements. This update is effective for reporting periods beginning on or after December 15, 2011. The adoption of ASU 2011-04 did not have a significant impact on our financial position or results of operations.

In June 2011, the FASB issued ASU No. 2011-05, "Presentation of Comprehensive Income". ASU 2011-05 eliminates the option to report other comprehensive income and its components in the statement of changes in stockholders' equity and requires an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. This update is effective for fiscal years, and interim periods within those years beginning after December 15, 2011. In December 2011, the FASB issued ASU No. 2011-12, which becomes effective at the same time as ASU 2011-05, to defer the effective date of provisions of ASU 2011-05 that relate to the presentation of reclassification adjustments. We expect adoption of ASU 2011-05 or ASU 2011-12 will not have an impact on our financial position or results of operations.

In December 2011, the FASB issued ASU No. 2011-11 which will enhance disclosures by requiring an entity to disclose information about netting arrangements, including rights of offset, to enable users of its financial statements to understand the effect of those arrangements on its financial position. This pronouncement was issued to facilitate comparison between financial statements prepared on the basis of U.S. GAAP and IFRS. This update is effective for annual and interim reporting periods beginning on or after January 1, 2013 and is to be applied retroactively for all comparative periods presented. The adoption of ASU 2011-11 is not expected to have a significant impact on our financial position or results of operations.

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Results of Operations

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

The following tables summarize our oil and natural gas production volumes,
average sale prices and comparisons for the years ended December 31, 2011 and

                                         Texas         Oklahoma         Louisiana         Other         Total
Year Ended December 31, 2011
Aggregate Net Production
Oil (MBbls)                                 499              297                60            28           884
NGLs (MBbls)                                147               16                -             13           176
Natural Gas (MMcf)                        1,562              410               558           132         2,662

MBoe                                        906              382               153            63         1,504

Year Ended December 31, 2010
Aggregate Net Production
Oil (MBbls)                                 559              322                79            35           995
NGLs (MBbls)                                341               10                -             13           364
Natural Gas (MMcf)                        3,128              849               689           150         4,816

MBoe                                      1,421              473               194            73         2,161

Change in MBoe                             (515 )            (91 )             (41 )         (10 )        (657 )
Percentage Change in MBoe                 -36.2 %          -19.2 %           -21.1 %       -13.7 %       -30.4 %

                                            Years Ended
                                           December 31,
                                         2011        2010        (Decrease)
                Average sale prices:
                Oil (per Bbl)           $ 93.86     $ 76.95            22.0%
                NGL (per Bbl)             56.14       38.89            44.4%
                Natural gas (per Mcf)      4.01        4.21           (4.8%)
                Per Boe                   68.83       51.36            34.0%

In December 2010, we sold assets located in Texas and Oklahoma for net proceeds including post-closing adjustments of $48.8 million. The following table provides pro forma results for the year ended December 31, 2010 excluding those sold properties to assist our description of results of operations:

                                                    Year ended December 31, 2010
                                                                 Sold          Pro
                                                  Actual        Assets        Forma
    Oil and natural gas sales (in thousands):
    Oil                                         $   76,563     $  1,144     $  75,419
    Natural gas                                     20,265        4,936        15,329
    NGLs                                            14,156        4,882         9,274

    Total oil and natural gas sales             $  110,984     $ 10,962     $ 100,022
    Production expenses (in thousands):
    Oil and natural gas production taxes        $    6,063     $    486     $   5,577
    Oil and natural gas production expenses         33,891        1,692        32,199
    Production volumes (MBoe):
    Texas                                            1,421          298         1,123
    Oklahoma                                           473           63           410
    Other                                              267           -            267

    Total production                                 2,161          361         1,800

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Oil and natural gas sales decreased $7.5 million, or 7%, to $103.5 million for the year ended December 31, 2011, as compared to $111.0 million for the year ended December 31, 2010. Excluding asset sales, oil and natural gas sales increased $3.5 million for the year ended December 31, 2011, as compared to the year ended December 31, 2010. This increase was driven by commodity price increases on a per Boe basis of 34% for the year ended December 31, 2011 as compared to 2010 partially offset by decreased production.

Production volumes decreased 30% overall during the year ended December 31, 2011, as compared to the year ended December 31, 2010. Excluding the activities related to the asset divestitures, our production volume decreased 16% as compared to the same period last year primarily due to a shut-in of one well as a result of a major workover in Louisiana and natural production declines. Production from our Texas fields decreased by 217 MBoe in the current year, excluding asset sales, due to decline in well performance in our South Texas gas properties. Drilling activity included 45 gross (42.8 net) development wells in our Texas fields. Of the 45 gross development wells in our Texas fields, 40 gross (38.6 net) wells were capable of production, four gross (4.0 net) wells were either drilling or waiting on completion and one gross (0.2 net) well was abandoned. Production from our Oklahoma fields decreased 28 MBoe for the current year, excluding asset sales, primarily due to natural production declines. Drilling activity in Oklahoma included one gross (0.2 net) development well and . . .

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