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HK > SEC Filings for HK > Form 10-Q on 8-May-2012All Recent SEC Filings

Show all filings for HALCON RESOURCES CORP

Form 10-Q for HALCON RESOURCES CORP


8-May-2012

Quarterly Report


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

The following discussion is intended to assist in understanding our results of operations for the three months ended March 31, 2012 and 2011 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management's discussion and analysis included in our Annual Report on Form 10-K for the year ended December 31, 2011.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.

Overview

We are an independent energy company engaged in the acquisition, production, exploration and development of onshore oil and natural gas properties in the United States. Our producing properties are located in basins with long histories of oil and natural gas operations. We have been active in our core producing areas of Texas, Oklahoma and Louisiana since our inception in 1987 and have grown through a balanced strategy of acquisitions, development and exploratory drilling.

Our oil and natural gas assets are characterized by a combination of developing and mature reserves and properties. We have mature oil and natural gas reserves located primarily in Wichita, Wilbarger and Starr Counties, Texas, Pontotoc County, Oklahoma, and in several parishes in Louisiana. We have acquired acreage and may acquire more acreage in the Utica Shale/Point Pleasant, the Woodbine, the Wilcox and the Mississippian Lime formations.

Our average daily oil and natural gas production decreased 6% in the first three months of 2012 compared to the same period in the prior year. During the first three months of 2012, we averaged 4,055 barrels of oil equivalent ("Boe") per day compared to average daily production of 4,300 Boe per day during the first three months of 2011. The decrease in production compared to the prior year period is driven primarily by natural production declines. During the first quarter of 2012, we drilled or participated in the drilling of seven gross (7.0 net) wells of which were completed as wells capable of production and one gross (0.9 net) well was a dry hole, resulting in a success rate of 88%.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominately upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Recent Developments

Recapitalization

On February 8, 2012, HALRES LLC (formerly, "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, former Executive Vice President and Chief Financial Officer of Petrohawk, 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: Floyd C. Wilson, Tucker S. Bridwell, James W. Christmas, Thomas R. Fuller, James L. Irish III, E. Murphy Markham IV, David B. Miller, Daniel Rioux, Stephen P. Smiley and Mark A. Welsh IV. Information as to our recent recapitalization is set forth under Note 2 to the Condensed Consolidated Financial Statements.

New Revolving Credit Facility

In connection with the closing of the recapitalization, we entered into a senior revolving credit agreement (the "Credit Agreement") with JPMorgan Chase Bank, N.A. ("JPMorgan"), as administrative agent, and other lenders 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 lenders and us 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 future notes or other long-term debt securities that we may issue. Funds advanced under the credit agreement may be paid down and re-borrowed during the five-year term of the revolver. The pricing on the Credit Agreement is LIBOR plus a margin ranging from 1.5% to 2.5% based on a percentage of usage. Advances under the Credit Agreement are secured by liens


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on substantially all of our properties and assets. The Credit Agreement contains representations, warranties and covenants customary in transactions of this nature including restrictions on the payment of dividends on the capital stock and financial covenants relating to current ratio and minimum interest coverage ratio. We are required to maintain commodity hedges on a rolling basis of not more than 100% of its projected production for the first 24 months, 75% of its projected production for the next 25 to 36 months and 50% of projected production for the next 37 to 48 months. At March 31, 2012, we are in compliance with the financial debt covenants under the Credit Agreement. At March 31, 2012, we had no indebtedness outstanding under the $500.0 million credit agreement and $225.0 million of borrowing capacity available.

Preferred Stock Offering

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 ("Preferred Stock"), par value $0.0001 per share, each share of which automatically converted into 10,000 shares of our common stock on April 17, 2012. We received gross proceeds of approximately $400.0 million, or $9.00 per share of common stock, before offering expenses. No cash dividends were paid on the convertible Preferred Stock as it converted into common stock on or before May 31, 2012. The Preferred Stock was considered to have a beneficial conversion feature because the proceeds per share, approximately $9.00 per share of common stock, were less than the fair value of our common stock of $10.99 per common share on the commitment date. The estimated fair value allocated to the beneficial conversion feature was $88.4 million and was recorded to additional paid-in capital, creating a discount on the Preferred Stock ("the Discount"). The Discount resulting from the allocation of value to the beneficial conversion feature is required to be amortized over the 71 month contractual period from issuance to required redemption, or fully amortized upon an accelerated date of redemption or conversion, by increasing Preferred Stock and recording the offsetting amount as a deemed non-cash Preferred Stock dividend. For the three month period ended March 31, 2012, we recorded a non-cash preferred dividend of $1.1 million to reflect amortization of the Discount. Due to the conversion date occurring on April 17, 2012, the remaining $87.3 million of Discount amortization will be accelerated to the conversion date and reflected as a Preferred dividend for the three month period ended June 30, 2012.

Agreement and Plan of Merger with GeoResources, Inc.

On April 24, 2012, we entered into an Agreement and Plan of Merger (the "Merger Agreement") with GeoResources, Inc., a Colorado corporation ("GeoResources"), pursuant to which we have agreed to acquire all of the issued and outstanding shares of GeoResources common stock in a cash and stock transaction that values GeoResources at approximately $1.0 billion based on the closing price of our common stock on April 24, 2012. The per share consideration is fixed in the Merger Agreement at $20.00 in cash and 1.932 shares of our common stock for each issued and outstanding share of GeoResources common stock.

The transaction has been approved by each company's board of directors. Prior to closing, the transaction will require approval of each company's shareholders. The transaction is expected to close in the third quarter of 2012 and is subject to customary regulatory approvals.

Prior to the merger, the Company and GeoResources will continue to operate as separate companies. Accordingly, except for specific references to the pending merger, the descriptions of strategy and outlook and the risks and challenges the Company faces, and the discussion and analysis of results of operations and financial condition set forth below relate solely to the Company. Additional details regarding the pending merger are discussed in Note 14 to the Condensed Consolidated Financial Statements, "Subsequent Events."

Capital Resources and Liquidity

The proceeds provided by our recent financing activities has enabled us to increase our focus on expanding our leasehold position in areas we have determined are prospective for oil or liquids-rich resource plays. In addition to the assets held by GeoResources in the pending merger, 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 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.

Our near-term capital spending requirements are expected to be funded with the proceeds from our recent financing activities, cash flows from operations, proceeds from potential asset dispositions and borrowings under our Credit Agreement. We strive to maintain financial flexibility while continuing our aggressive drilling plans and evaluating potential acquisitions, and will therefore likely access capital markets (if on acceptable terms) as necessary to, among other things, maintain substantial borrowing capacity under our Credit Agreement, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position and infrastructure projects while sustaining sufficient operating cash levels. Our ability to complete future debt and equity offerings and maintain or increase our borrowing base is subject to a number of variables, including our level of oil and natural gas production and commodity prices, as well as various economic and market conditions that have historically affected the oil and natural gas industry. If oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.

Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing reserves and production and finding additional reserves. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas industry. We therefore continuously monitor our liquidity and the capital markets and evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources, acquisition opportunities and drilling success.

Cash Flow

Our primary source of cash for the three months ended March 31, 2012 was from financing activities. Our primary sources of cash for the three months ended March 31, 2011 were from operating and financing activities. Proceeds from our recent convertible Preferred Stock offering and recapitalization, as well as borrowings under our 8% convertible note, were slightly offset by repayments of our previous credit facilities and cash used in investing activities to fund our drilling program and acquisition activities. Operating cash flow fluctuations were substantially driven by the increase in general and administrative and interest expense in the first quarter of 2012 as a result of the recapitalization, related change in control matters and the change in credit facilities during the first quarter of 2012. Prices for oil and natural gas have historically been subject to seasonal influences typically characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout recent years. See "Results of Operations" below for a review of the impact of prices and volumes on revenues.


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Net increase in cash is summarized as follows (in thousands):

                                                             Three Months Ended
                                                                  March 31,
                                                             2012           2011
   Cash flows provided by (used in) operating activities   $  (9,199 )    $  4,204
   Cash flows used in investing activities                   (28,378 )      (5,366 )
   Cash flows provided by financing activities               723,311         1,167

   Net increase in cash                                    $ 685,734      $      5

Operating Activities. Net cash used in operating activities for the three months ended March 31, 2012 was $9.2 million as compared to cash provided by operating activities for the three months ended March 31, 2011 of $4.2 million.

The recapitalization, change in control and related activities which occurred during February 2012 resulted in a significant increase in general and administrative and interest expense which adversely affected operating cash flows. Operating cash flows of negative $9.2 million include cash used in operating activities of $1.5 million for expensing a prepayment fee in connection with the payoff of the former credit facilities, $1.8 million in share-based compensation expense for accelerated vesting of stock appreciation rights, $4.2 million in change in control payments to former management, $2.5 million for a consulting agreement termination fee, $0.8 million for legal fees, $0.4 million for derivatives novation fees and $2.4 million of various other charges, all related to the recapitalization and change in control.

Investing Activities. The primary driver of cash used in investing activities is capital spending, inclusive of acquisitions net of dispositions. Cash used in investing activities was $28.4 million and $5.4 million for the three months ended March 31, 2012 and 2011, respectively.

During the first three months of 2012, we spent $24.0 million on oil and natural gas capital expenditures, $16.4 million of which was for unproved leasehold property costs. We participated in the drilling of eight gross (7.9 net) wells and spent an additional $0.6 million on other operating property and equipment capital expenditures. We also had funds held in escrow of approximately $3.8 million related to leasehold acquisitions.

During the first three months of 2011, we spent $5.6 million on oil and natural gas capital expenditures. During the quarter ended March 31, 2011, we participated in the drilling of 15 gross (12.3 net) wells, of which six gross (6.0 net) wells were capable of production. Nine gross (6.3 net) wells were either drilling, testing or waiting on completion as of March 31, 2011. We spent an additional $0.2 million on other operating property and equipment capital expenditures. Proceeds from sales of oil and gas properties were $0.5 million for the three months ended March 31, 2011.

Financing Activities. Net cash flows provided by financing activities were $723.3 million and $1.2 million for the three months ended March 31, 2012 and 2011, respectively.

On February 8, 2012, HALRES LLC 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. The convertible note provided $231.4 million cash flow from borrowings and $43.6 million cash flow from warrants issued.

In connection with the closing of the recapitalization, we entered into a credit agreement with JPMorgan, 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. We did not utilize any of the funds available under the credit facility during the first quarter of 2012; however, we incurred $2.0 million of debt issuance costs in conjunction with the issuance of the credit agreement, and $2.5 million of debt issuance costs in connection with the convertible note.

On March 5, 2012, we received $400.0 million, subject to certain adjustments, from the private placement sale of the convertible Preferred Stock. See Recent Developments in Item 2. for a more detailed discussion.

In connection with the closing of the recapitalization transactions and the Preferred Stock private placement, we incurred a total of $18.0 million in equity issuance costs during the three months ended March 31, 2012.

Capital financing was used to repay borrowings under our previous credit facilities. During the first quarter of 2012, we borrowed $6.0 million and paid down the $208.0 million balance of the previous credit facilities in connection with the recapitalization. During the first quarter of 2011, we refinanced our previous credit facilities, which resulted in $7.9 million in net borrowings on long-term debt offset by $6.7 million in payments for deferred loan costs.


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All restricted stock awards were vested as a result of the change in control in February 2012. We repurchased $2.1 million in common stock from participants under our 2006 Long-term Incentive Plan to net settle the related withholding tax liability.

Contractual Obligations

We have no significant long-term commitments associated with our capital expenditure plans. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, development and exploration activities, oil and natural gas price conditions and other related economic factors. We may enter into commitments related to drilling, non-cancelable operating leases or various other contracts in the future. Currently, no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the year ended December 31, 2011.

Results of Operations

Three Months Ended March 31, 2012 and 2011

We reported a net loss of $33.3 million for the three months ended March 31,
2012 compared to a net loss of $9.9 million for the same period in 2011,
resulting in an increase in the net loss of $23.4 million. The following tables
summarize key items of comparison and their related change for the periods
indicated.



                                                  Three Months Ended
                                                      March 31,
   In thousands                                  2012           2011          Change
   Net loss                                    $ (33,322 )    $  (9,911 )    $ (23,411 )
   Operating revenues:
   Oil                                            22,997         20,412          2,585
   Natural gas                                     1,668          2,892         (1,224 )
   NGLs                                            2,169          2,415           (246 )
   Other revenue                                      36             51            (15 )
   Operating expenses:
   Production:
   Lease operating                                 8,668          8,375            293
   Taxes                                           1,570          1,411            159
   General and administrative:
   General and administrative                     16,231          3,878         12,353
   Share-based compensation                        4,103            669          3,434
   Restructuring costs                               104             -             104
   Depletion, depreciation and amortization:
   Depletion - Full cost                           5,362          5,024            338
   Depreciation - Other                              216            249            (33 )
   Accretion expense                                 401            402             (1 )
   Other expenses, net:
   Net loss on derivative contracts               (4,945 )      (14,250 )        9,305
   Interest expense                              (13,038 )       (6,550 )       (6,488 )
   Other income                                       41             48             (7 )
   Loss before income taxes                      (27,727 )      (14,990 )      (12,737 )
   Income tax provision (benefit)                  5,595         (5,079 )       10,674


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                                                           Three Months Ended
                                                                March 31,
In thousands (except per unit and per Boe amounts)          2012          2011        Change

Production:
Oil (MBbls)                                                     226          222            4
Natural gas (MMcf)                                              615          710          (95 )
NGLs (MBbls)                                                     40           47           (7 )
Total per MBoe                                                  369          387          (18 )
Average daily production (Boe)                                4,055        4,300         (245 )

Average price per unit:
Oil (Bbl)                                                $   101.76      $ 91.95      $  9.81
Natural gas (Mcf)                                              2.71         4.07        (1.36 )
NGLs (Bbl)                                                    54.23        51.38         2.85
Total per Boe                                                 72.72        66.46         6.26

Cash effect of derivative contracts per unit:
Oil (Bbl)                                                $    (0.62 )    $ (4.58 )    $  3.96
Natural gas (Mcf)                                              1.16         2.61        (1.45 )
NGLs (Bbl)                                                       -            -            -
Total per Boe                                                  1.56         2.16        (0.60 )

Average prices computed after cash effect of
settlement of derivative contracts per unit:
Oil (Bbl)                                                $   101.14      $ 87.37      $ 13.77
Natural gas (Mcf)                                              3.87         6.68        (2.81 )
NGLs (Bbl)                                                    54.23        51.38         2.85
Total per Boe                                                 74.28        68.62         5.66

Average cost per Boe:
Production:
Lease operating                                          $    23.49      $ 21.64      $  1.85
Taxes                                                          4.25         3.65         0.60
General and administrative:
General and administrative                                    43.99        10.02        33.97
Share-based compensation                                      11.12         1.73         9.39
Restructuring costs                                            0.28           -          0.28
Depletion                                                     14.53        12.98         1.55

For the three months ended March 31, 2012, oil and natural gas revenues increased $1.1 million from the same period in 2011. The increase was primarily due to higher realized average prices during the 2012 period. Increased realized average price of $6.26 per Boe contributed approximately $2.3 million in revenues for the three months ended March 31, 2012. The increase was partially offset by a decrease in production of 18 MBoe or 5%, which resulted in a $1.2 million decline in oil and natural gas revenues.

Lease operating expenses increased $0.3 million for the three months ended March 31, 2012 primarily due to higher workover expenses and repairs during the 2012 period. This increase in lease operating expense combined with decreased production resulted in increased lease operating expense on a per unit basis. Lease operating expenses were $23.49 per Boe in 2012 compared to $21.64 per Boe in 2011.

Oil and natural gas production taxes increased $0.2 million for the three months ended March 31, 2012 as compared to the same period in 2011. Most production taxes are based on realized prices at the wellhead, while Louisiana production taxes are based on volumes for natural gas and values for oil. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease directly. The increase is primarily due to an increase in oil and natural gas sales for the quarter ended March 31, 2012 compared to the same period in 2011. As a percentage of revenue, oil and natural gas production tax was 6% for the first quarter of 2012 compared to 5% for the first quarter of 2011.

General and administrative expense for the three months ended March 31, 2012 increased $12.4 million to $16.2 million as compared to the same period in 2011, largely reflecting the impact of the recapitalization that included charges of approximately $5.4 million for change in control payments and $2.5 million for engagement termination fees coupled with higher professional fees of approximately $1.0 million related in an increase in corporate activities . . .

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