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HK > SEC Filings for HK > Form 10-Q on 1-Aug-2013All Recent SEC Filings

Show all filings for HALCON RESOURCES CORP

Form 10-Q for HALCON RESOURCES CORP


1-Aug-2013

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 and six months ended June 30, 2013 and 2012 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, 2012.

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 focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. We were incorporated in Delaware on February 5, 2004 and were recapitalized on February 8, 2012. Historically, our producing properties have been located in basins with long histories of oil and natural gas operations. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in selected prospect areas. We now have an extensive drilling inventory in multiple basins that we believe allows for multiple years of profitable production growth and provides us with broad flexibility to direct our capital resources to projects with the greatest potential returns.

Our oil and natural gas assets consist of a combination of undeveloped acreage positions in unconventional liquids-rich basins/fields and mature liquids-weighted reserves and production in more conventional basins/fields. We have mature oil and natural gas reserves located primarily in Texas, North Dakota, Louisiana, Oklahoma and Montana. We have acquired acreage, and may acquire additional acreage, in the Bakken / Three Forks formations in North Dakota and Montana, the Eagle Ford formation in East Texas, the Utica / Point Pleasant formations in Ohio and Pennsylvania, and the Woodbine formation in East Texas.

Our average daily oil and natural gas production increased 593% in the first six months of 2013 compared to the same period in the prior year. During the first six months of 2013, we averaged 27,602 barrels of oil equivalent (Boe) per day compared to average daily production of 3,984 Boe per day during the first six months of 2012. The increase in production compared to the prior year period was driven primarily by the acquisitions of GeoResources, the East Texas Assets and the Williston Basin Assets. The acquisitions of GeoResources, the East Texas Assets and the Williston Basin Assets combined to contribute approximately 23,600 Boe per day of the increase. During the first six months of 2013, we participated in the drilling of 159 gross (68.3 net) wells of which 157 gross
(66.3 net) wells were completed and capable of production, and 2 gross (2.0 net)
wells were dry holes.

Our 2013 budget for drilling and completion capital expenditures has been increased from approximately $1.2 billion to approximately $1.4 billion. While this amount represents the vast majority of our expected capital expenditures in 2013, we have and will continue to incur additional capital expenditures associated with ongoing leasing efforts, transportation, infrastructure and seismic and other expenditures. Our drilling and completion budget for 2013 is based on our current view of market conditions and current business plans, and is subject to change.

Recent Developments

Issuance of 5.75% Series A Convertible Perpetual Preferred Stock

On June 18, 2013, we completed our offering of 345,000 shares of 5.75% Series A Convertible Perpetual Preferred Stock (the Series A Preferred Stock) at a public offering price of $1,000 per share.


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The net proceeds to us from the offering of the Series A Preferred Stock were approximately $335.5 million, after deducting the underwriting discount and offering expenses. We used the net proceeds from the offering to repay a portion of the outstanding borrowings under our Senior Credit Agreement. Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, cumulative dividends at the rate of 5.75% per annum (the dividend rate) on the $1,000 liquidation preference per share of the Series A Preferred Stock, payable quarterly in arrears on each dividend payment date. Dividends may be paid in cash or, where freely transferable by any non-affiliate recipient thereof, in shares of common stock or a combination thereof, and are payable on March 1, June 1, September 1 and December 1 of each year, commencing on September 1, 2013. See Item 1. Condensed Consolidated Financial Statements (Unaudited)-Note 11, "Preferred Stock and Stockholders' Equity" for additional information on the Series A Preferred Stock.

Amendments to the Senior Credit Agreement and Borrowing Base

Upon the closing of the Eagle Ford divestiture on July 19, 2013, the borrowing base under the Senior Credit Agreement was reduced from $850.0 million to $810.0 million.

On June 11, 2013, we entered into the Fifth Amendment to the Senior Credit Agreement (the Fifth Amendment). The Fifth Amendment provides, among other things, for us to pay cash dividends to holders of our preferred capital stock.

On May 8, 2013, we entered into the Fourth Amendment to our Senior Credit Agreement (the Fourth Amendment). The Fourth Amendment provides for EBITDA (as defined in the Credit Facility) to be annualized for the balance of calendar year 2013 for purposes of measuring compliance with the interest coverage test. Specifically, (i) for the fiscal quarter ended June 30, 2013, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the three month period then ended multiplied by 4; (ii) for the fiscal quarter ended September 30, 2013, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the six month period then ended multiplied by 2; and (iii) for the fiscal quarter ended December 31, 2013, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the nine month period then ended multiplied by 4/3.

On April 26, 2013, we entered into the Third Amendment to our Senior Credit Agreement (the Third Amendment) by and among us, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders signatory thereto, which amends the Senior Credit Agreement in order to provide, among other things, additional flexibility under certain affirmative and negative covenants.

On January 25, 2013, we entered into the Second Amendment to our Senior Credit Agreement (the Second Amendment) by and among us, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders signatory thereto. The Second Amendment amends the Senior Credit Agreement with respect to our ability to enter into certain commodity hedging agreements.

See Item 1. Condensed Consolidated Financial Statements (Unaudited)-Note 6, "Long-Term Debt" for additional information on the amendments to our Senior Credit Agreement.

Issuance of Additional 2021 Notes

On January 14, 2013, we issued an additional $600 million aggregate principal amount of our 8.875% senior notes due 2021 at a price to the initial purchasers of 105% of par. The net proceeds from the sale of the additional 2021 Notes of approximately $619.5 million (after the initial purchasers' premiums, commissions and offering expenses) were used to repay all of the outstanding borrowings under our Senior Credit Agreement and for general corporate purposes, including funding a portion of our 2013 capital expenditures program. These notes were issued as "additional notes" under the indenture governing our 2021 Notes and pursuant to which we had previously issued $750 million


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aggregate principal amount of 2021 Notes in November 2012, and under the indenture are treated as a single series with substantially identical terms as the 2021 Notes previously issued. See Item 1. Condensed Consolidated Financial Statements (Unaudited)-Note 6, "Long-Term Debt" for additional information on the 2021 Notes.

Capital Resources and Liquidity

During the first half of 2013, we shifted the focus of our capital program from acquiring leasehold and producing properties to drilling and completion activities. We are currently focused on developing our core areas which include the Bakken / Three Forks formations in North Dakota, the Eagle Ford formation in East Texas, Utica / Point Pleasant formations in Ohio and Pennsylvania, and the Woodbine formation in East Texas. In addition to our ongoing drilling and completion activities we continue to acquire leasehold in our core areas and select other exploratory areas we believe are prospective for oil and liquids-rich hydrocarbons. During the first six months of 2013, we invested $1.0 billion in oil and natural gas capital expenditures.

Our near-term capital spending requirements are expected to be funded with cash flows from operations, proceeds from potential non-core asset dispositions, proceeds from potential capital market transactions and borrowings under our Senior Credit Agreement, which has a current borrowing base of $810.0 million. Our borrowing base is redetermined on a semi-annual basis (with us and the lenders each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations) and adjusted based on our oil and natural gas properties, reserves, other indebtedness and other relevant factors. Our ability to utilize the full amount of our borrowing capacity is influenced by a variety of factors, including redeterminations of our borrowing base, and covenants under our Senior Credit Agreement and our senior unsecured debt indentures. Our Senior Credit Agreement contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and minimum coverage of interest expenses (as defined in the Senior Credit Agreement) of not less than 2.5 to
1.0. We are subject to additional covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. Additionally, the indentures governing our senior unsecured debt contain covenants limiting our ability to incur additional indebtedness, including borrowings under our Senior Credit Agreement, unless we meet one of two alternative tests. The first test, the fixed charge coverage ratio test, applies to all indebtedness and requires that after giving effect to the incurrence of additional debt the ratio of our adjusted consolidated EBITDA (as defined in our indentures) to our adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0. The second test allows us to incur additional indebtedness, beyond the limitations of the fixed charge coverage ratio test, as long as this additional debt is incurred under Credit Facilities (as defined in our indentures) and the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of our adjusted consolidated net tangible assets (as defined in our indentures), which is determined primarily using discounted future net revenues from proved oil and natural gas reserves as of the end of each year. At June 30, 2013, we had $343.0 million of indebtedness outstanding, $1.2 million of letters of credit outstanding and $505.8 million of borrowing capacity available under the Senior Credit Agreement.

We strive to maintain financial flexibility while continuing our aggressive drilling plans and evaluating potential acquisitions, and will therefore likely continue to access capital markets (if on acceptable terms) as necessary to, among other things, maintain substantial borrowing capacity under our Senior 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


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production, reserves 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, and meet our financial obligations 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 successes.

Cash Flow

Our primary source of cash for the six months ended June 30, 2013 and 2012 was from financing activities. In the first six months of 2013, proceeds from the additional 2021 Notes and the Series A Preferred Stock issuance were the primary drivers of the net cash provided by financing activities. The increase in cash received from operations, coupled with the cash from financing activities, were offset by cash used in investing activities to fund our drilling program and acquire additional leasehold interests. Operating cash flow fluctuations were substantially driven by the 593% increase in production volumes as compared to the six months ended June 30, 2012 and, to a lesser extent, higher commodity prices. Fluctuation in commodity prices and our overall cash flow may result in an increase or decrease in our future capital expenditures. Prices for oil and natural gas have historically been subject to seasonal fluctuations 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 sales.

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

                                                          Six Months Ended June 30,
                                                             2013             2012
                                                               (In thousands)
Cash flows provided by (used in) operating activities    $      229,890    $   (2,708 )
Cash flows provided by (used in) investing activities        (1,165,750 )    (500,809 )
Cash flows provided by (used in) financing activities           936,415       722,676

Net increase (decrease) in cash                          $          555    $  219,159

Operating Activities. Net cash provided by operating activities for the six months ended June 30, 2013 was $229.9 million as compared to cash used in operating activities for the six months ended June 30, 2012 of $2.7 million.

The $229.9 million of operating cash flows primarily reflects the net income for the six months ended June 30, 2013 of $42.6 million coupled with significant non-cash items, namely $177.2 million of depletion, depreciation and accretion. Increased production from our recent acquisitions and developmental drilling activities drove a significant increase in revenues, as compared to the prior year period, which outpaced related production costs and higher general and administrative expenses pertaining to additional personnel and infrastructure in support of the rapidly expanding business base, resulting in $63.9 million of income from operations.

Investing Activities. The primary driver of cash used in investing activities is capital spending, specifically drilling and completions coupled with the acquisition of unevaluated leaseholds in our


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targeted areas. Net cash used in investing activities was approximately $1.2 billion and $500.8 million for the six months ended June 30, 2013 and 2012, respectively.

During the first six months of 2013, we incurred cash expenditures of $1.0 billion on oil and natural gas capital expenditures. We participated in the drilling of 159 gross (68.3 net) wells of which 157 gross (66.3 net) wells were completed and capable of production and two gross (2.0 net) wells were dry holes. We spent an additional $80.7 million on other operating property and equipment capital expenditures, of which $68.9 million pertained to pipelines and related infrastructure projects, and the remainder was spent on leasehold improvements, computers and software primarily in our corporate office in Houston, Texas.

During the first six months of 2012, we spent $468.2 million on oil and natural gas capital expenditures, primarily on the acquisition of unevaluated leasehold. We participated in the drilling of 15 gross (14.2 net) wells of which 14 gross (13.3 net) wells were completed as wells capable of production and one gross (0.9 net) well was a dry hole, and spent an additional $3.5 million on other operating property and equipment capital expenditures, primarily on leasehold improvements, computers and software in our corporate office in Houston, Texas. Proceeds from sales of oil and gas properties were $0.3 million. We also had funds held in escrow of approximately $29.4 million related to pending acquisitions.

Financing Activities. Net cash flows provided by financing activities were $936.4 million and $722.7 million for the six months ended June 30, 2013 and 2012, respectively. The primary drivers of cash provided by financing activities for the six months ended June 30, 2013, are proceeds of $619.5 million from the issuance of the additional 2021 Notes and $335.5 million, net of issuance costs, from the issuance of Series A Preferred Stock. The impact of our Senior Credit Agreement was substantially neutral to financing activities for the six months ended June 30, 2013 as additional borrowings were offset by repayments.

On June 18, 2013, we completed our offering of 345,000 shares of the Series A Preferred Stock at a public offering price of $1,000 per share. The net proceeds to us from the offering of the Series A Preferred Stock were approximately $335.5 million, after deducting the underwriting discount and offering expenses. We used the net proceeds from the offering to repay a portion of the outstanding borrowings under our Senior Credit Agreement.

On January 14, 2013, we completed the issuance of an additional $600 million aggregate principal amount of our 2021 Notes at a price to the initial purchasers of 105% of par. The net proceeds from the sale of the additional 2021 Notes were approximately $619.5 million (after deducting offering fees and expenses). The net proceeds from this offering were used to repay all of the then outstanding borrowings under our Senior Credit Agreement and for general corporate purposes, including funding a portion of our 2013 capital expenditures program.

During the first six months of 2012, as discussed in Item 1. Condensed Consolidated Financial Statements (Unaudited)-Note 2, "Recapitalization," HALRES 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 8.0% convertible note and warrants for the purchase of an additional 36.7 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. Proceeds from the Recapitalization were used to repay the $208.0 million of borrowings under previous credit facilities. In addition, we received $400.0 million, subject to certain adjustments, from the private placement sale of convertible Preferred Stock during March 2012. In connection with the closing of the Recapitalization and the Preferred Stock, we incurred a total of $18.1 million in equity issuance costs during the six months ended June 30, 2012.


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All restricted stock awards were vested as a result of the change in control in February 2012. For the six months ended June 30, 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 lease corporate office space in Houston and Plano, Texas; Tulsa, Oklahoma; Denver, Colorado; and Williston, North Dakota as well as a number of other field office locations. Rent expense was approximately $4.4 million and $1.2 million for the six months ended June 30, 2013 and 2012, respectively. In addition, we have commitments for certain equipment under long-term operating lease agreements, namely drilling rigs as well as pipeline and well equipment, with various expiration dates through 2015. Early termination of the drilling rig commitments would result in termination penalties approximating $42.6 million, which would be in lieu of the remaining $68.9 million of drilling rig commitments as of June 30, 2013. As of June 30, 2013, the amount of commitments under office and equipment lease agreements is consistent with the levels at December 31, 2012 disclosed in our Annual Report on Form 10-K, approximating $66.7 million in the aggregate, and containing various expiration dates through 2024.

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, 2012.


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Results of Operations

Three Months Ended June 30, 2013 and 2012

    We reported net income of $37.1 million and $7.7 million for the three
months ended June 30, 2013 and 2012, respectively. The following table
summarizes key items of comparison and their related change for the periods
indicated.

                                                          Three Months
                                                         Ended June 30,
 In thousands (except per unit and per Boe amounts)     2013        2012      Change
 Net income (loss)                                    $  37,088   $  7,659   $  29,429
 Operating revenues:
 Oil                                                    202,490     20,383     182,107
 Natural gas                                              6,845      1,270       5,575
 Natural gas liquids                                      4,254      1,653       2,601
 Other                                                      754         35         719
 Operating expenses:
 Production:
 Lease operating                                         31,833      8,303      23,530
 Workover and other                                         623        540          83
 Taxes other than income                                 18,567      1,908      16,659
 Gathering and other                                      2,802         60       2,742
 Restructuring                                             (164 )      903      (1,067 )
 General and administrative:
 General and administrative                              28,886     12,362      16,524
 Share-based compensation                                 4,640        529       4,111
 Depletion, depreciation and accretion:
 Depletion-Full cost                                     92,915      5,183      87,732
 Depreciation-Other                                       1,471        345       1,126
 Accretion expense                                          929        428         501
 Other income (expenses):
 Net gain (loss) on derivative contracts                 34,100     13,671      20,429
 Interest expense and other, net                         (5,732 )   (4,179 )    (1,553 )
 Income tax (provision) benefit                         (23,121 )    5,387     (28,508 )
 Production:
 Oil-MBbls                                                2,212        221       1,991
 Natural Gas-Mmcf                                         1,881        584       1,297
 Natural gas liquids-MBbls                                  129         38          91
 Total MBoe(1)                                            2,654        356       2,298
 Average daily production-Boe(1)                         29,165      3,912      25,253
 Average price per unit(2):
 Oil price-Bbl                                        $   91.54   $  92.23   $   (0.69 )
 Natural gas price-Mcf                                     3.64       2.17        1.47
 Natural gas liquids price-Bbl                            32.98      43.50      (10.52 )
 Total per Boe(1)                                         80.48      65.47       15.01
 Average cost per Boe:
 Production:
 Lease operating                                      $   11.99   $  23.32   $  (11.33 )
 Workover and other                                        0.23       1.52       (1.29 )
 Taxes other than income                                   7.00       5.36        1.64
 Gathering and other                                       1.06       0.17        0.89
 Restructuring                                            (0.06 )     2.54       (2.60 )
 General and administrative:
 General and administrative                               10.88      34.72      (23.84 )
 Share-based compensation                                  1.75       1.49        0.26
 Depletion                                                35.01      14.56       20.45


--------------------------------------------------------------------------------
    (1)


Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

(2)
Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.


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For the three months ended June 30, 2013, oil, natural gas and natural gas liquids revenues increased $190.3 million from the same period in 2012. The increase was primarily due to an increase in production volumes resulting from the Merger, the East Texas Acquisition and the Williston Basin Acquisition and the continued development within these areas, which collectively accounted for . . .

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