Search the web
Welcome, Guest
[Sign Out, My Account]
EDGAR_Online

Quotes & Info
Enter Symbol(s):
e.g. YHOO, ^DJI
Symbol Lookup | Financial Search
HK > SEC Filings for HK > Form 10-Q on 2-May-2013All Recent SEC Filings

Show all filings for HALCON RESOURCES CORP | Request a Trial to NEW EDGAR Online Pro

Form 10-Q for HALCON RESOURCES CORP


2-May-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 months ended March 31, 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 Utica / Point Pleasant formations in Ohio and Pennsylvania, the Woodbine formation in East Texas, the Eagle Ford formation in East Texas, the Bakken / Three Forks formations in North Dakota and Montana, the Tuscaloosa Marine Shale formation in Louisiana, the Midway / Navarro formations in Southeast Texas and the Wilcox formation in Texas and Louisiana as well as several other undisclosed locations.

Our average daily oil and natural gas production increased 542% in the first three months of 2013 compared to the same period in the prior year. During the first three months of 2013, we averaged 26,022 barrels of oil equivalent (Boe) per day compared to average daily production of 4,055 Boe per day during the first three months of 2012. The increase in production compared to the prior year period was driven primarily by the acquisitions of GeoResources, Inc. (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 21,200 Boe per day of the increase. During the first three months of 2013, we participated in the drilling of 53 gross (13.7 net) wells of which 52 gross (12.7 net) wells were completed and capable of production, and one gross (1.0 net) well was a dry hole.

Recent Developments

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


Table of Contents

indenture governing our 2021 Notes and pursuant to which we had previously issued $750 million 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. There was no borrowing base reduction to our Senior Credit Agreement as a result of the issuance of the additional 2021 Notes. See Item 1. Condensed Consolidated Financial Statements (Unaudited)-Note 6, "Long-Term Debt" for additional information on the 2021 Notes.

Second Amendment to the Senior Credit Agreement

On January 25, 2013, we entered into the Second Amendment to 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 Second Amendment.

Third Amendment to the Senior Credit Agreement

On April 26, 2013, we entered into the Third Amendment to 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. Also on April 26, 2013, the lenders reaffirmed our current borrowing base of $850.0 million under the Senior Credit Agreement.

Capital Resources and Liquidity

The proceeds provided by our recent financing activities have enabled us to increase our focus on expanding our leasehold position in liquids-rich resource areas. We have acquired and/or identified several core resource plays for additional leasing, including the Bakken / Three Forks formations in North Dakota, Utica / Point Pleasant formations in Ohio and Pennsylvania, the Woodbine formation in East Texas, and the Eagle Ford formation in East Texas. In addition to our ongoing lease acquisition efforts in our core resource plays, we have identified several new exploratory areas we believe are prospective for oil and liquids-rich hydrocarbons. In the first quarter of 2013, we invested $389.5 million in oil and natural gas capital expenditures. The majority of these expenditures were for acreage in the Utica / Point Pleasant, Bakken, Woodbine and Eagle Ford formations.

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 $850.0 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. On April 26, 2013, the lenders reaffirmed our current borrowing base of $850.0 million under the Senior Credit Agreement. 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


Table of Contents

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 all of 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 March 31, 2013, we had $133.0 million of indebtedness outstanding, $1.3 million of letters of credit outstanding and $715.7 million of borrowing capacity available under the Senior Credit Agreement.

On April 26, 2013, we entered into the Third Amendment to 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. Also on April 26, 2013, the lenders reaffirmed our current borrowing base of $850.0 million 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 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 three months ended March 31, 2013 and 2012 was from financing activities. In the first three months of 2013, proceeds from the additional 2021 Notes, borrowings under the Senior Credit Agreement and cash received from operations were offset by cash used in investing activities to fund our drilling program. Operating cash flow fluctuations were substantially driven by changes in commodity prices and changes in our production volumes. Working capital was substantially influenced by these variables. 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


Table of Contents

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):

                                                             Three Months Ended
                                                                 March 31,
                                                              2013        2012
                                                               (In thousands)
   Cash flows provided by (used in) operating activities   $   55,279   $  (9,199 )
   Cash flows provided by (used in) investing activities     (454,593 )   (28,378 )
   Cash flows provided by (used in) financing activities      397,610     723,311

   Net increase (decrease) in cash                         $   (1,704 ) $ 685,734

Operating Activities. Net cash provided by operating activities for the three months ended March 31, 2013 was $55.3 million as compared to cash used in operating activities for the three months ended March 31, 2012 of $9.2 million.

The $55.3 million of operating cash flows reflects the net income for the three months ended March 31, 2013 of $5.5 million coupled with significant non-cash items, including $81.9 million of depletion, depreciation and accretion and $16.1 million of unrealized losses on derivative contracts which more than offset changes in working capital. Increased production from our recent acquisitions and drilling activities drove a solid 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 $32.0 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 targeted areas. Net cash used in investing activities was $454.6 million and $28.4 million for the three months ended March 31, 2013 and 2012, respectively.

During the first three months of 2013, we incurred cash expenditures of $389.5 million on oil and natural gas capital expenditures. We participated in the drilling of 53 gross (13.7 net) wells of which 52 gross (12.7 net) wells were completed and capable of production and one gross (1.0 net) well was a dry hole. We spent an additional $36.5 million on other operating property and equipment capital expenditures; of which $31.0 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 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.

Financing Activities. Net cash flows provided by financing activities were $397.6 million and $723.3 million for the three months ended March 31, 2013 and 2012, respectively. The primary drivers of cash provided by financing activities are proceeds from the issuance of long-term debt and borrowings under our Senior Credit Agreement partially offset by repayments on our Senior Credit Agreement.

On January 14, 2013, we completed the issuance of an additional $600 million aggregate principal amount of our 8.875% senior notes due 2021. The net proceeds from the sale of the additional 2021


Table of Contents

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 three 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.

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 $2.5 million and $0.5 million for the three months ended March 31, 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. Early termination of the drilling rig commitments would result in termination penalties approximating $42 million, which would be in lieu of the remaining $68 million of drilling rig commitments as of March 31, 2013. As of March 31, 2013, the amount of office and equipment lease agreements is consistent with the levels at December 31, 2012 disclosed in our Annual Report on Form 10-K, approximating $68.8 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.


Table of Contents

Results of Operations

Three Months Ended March 31, 2013 and 2012

    We reported net income available to common stockholders of $5.5 million and
a net loss available to common stockholders of $34.4 million for the three
months ended March 31, 2013 and 2012, respectively. The following table
summarizes key items of comparison and their related change for the periods
indicated.

                                                       Three Months Ended
                                                           March 31,
In thousands (except per unit and per Boe amounts)      2013        2012       Change
Net income (loss) available to common stockholders    $   5,465   $ (34,424 ) $  39,889
Operating revenues:
Oil                                                     180,780      22,997     157,783
Natural gas                                               5,539       1,668       3,871
Natural gas liquids                                       3,808       2,169       1,639
Other                                                       530          36         494
Operating expenses:
Production:
Lease operating                                          25,440       7,501      17,939
Workover and other                                        1,624         833         791
Taxes other than income                                  17,436       1,926      15,510
Restructuring                                               671         104         567
General and administrative:
General and administrative                               29,262      16,209      13,053
Share-based compensation                                  2,335       4,103      (1,768 )
Depletion, depreciation and accretion:
Depletion-Full cost                                      79,891       5,362      74,529
Depreciation-Other                                        1,071         216         855
Accretion expense                                           896         401         495
Other income (expenses):
Net gain (loss) on derivative contracts                 (18,422 )    (4,945 )   (13,477 )
Interest expense and other, net                          (4,850 )   (12,997 )     8,147
Income tax benefit (provision)                           (3,294 )    (5,595 )     2,301
Production:
Oil-MBbls                                                 1,931         226       1,705
Natural Gas-Mmcf                                          1,811         615       1,196
Natural gas liquids-MBbls                                   109          40          69
Total MBoe(1)                                             2,342         369       1,973
Average daily production-Boe(1)                          26,022       4,055      21,967
Average price per unit(2):
Oil price-Bbl                                         $   93.62   $  101.76   $   (8.14 )
Natural gas price-Mcf                                      3.06        2.71        0.35
Natural gas liquids price-Bbl                             34.94       54.23      (19.29 )
Total per Boe(1)                                          81.18       72.72        8.46
Average cost per Boe:
Production:
Lease operating                                       $   10.86   $   20.33   $   (9.47 )
Workover and other                                         0.69        2.26       (1.57 )
Taxes other than income                                    7.44        5.22        2.22
Restructuring                                              0.29        0.28        0.01
General and administrative:
General and administrative                                12.49       43.93      (31.44 )
Share-based compensation                                   1.00       11.12      (10.12 )
Depletion                                                 34.11       14.53       19.58


--------------------------------------------------------------------------------
    (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.


Table of Contents

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

For the three months ended March 31, 2013, oil, natural gas and natural gas liquids revenues increased $163.3 million from the same period in 2012. The increase was primarily due to an increase in production volumes resulting from the GeoResources Merger, the East Texas Assets acquisition and the Williston Basin Assets acquisition, which collectively accounted for an increase of approximately 21,200 Boe per day in production and $157.2 million of incremental revenues. Realized average prices per Boe increased $8.46 to $81.18 per Boe.

Lease operating expenses increased $17.9 million for the three months ended March 31, 2013, primarily due to $14.8 million of costs incurred on our newly acquired assets. The remaining increases are due to higher power costs, service costs and repairs. Lease operating expenses were $10.86 per Boe for the first quarter of 2013 compared to $20.33 per Boe for the same period in 2012. The decrease per Boe is due to a lower rate per Boe on the recently acquired properties and cost saving measures we have implemented.

Workover expenses increased $0.8 million for the three months ended March 31, 2013 compared to the same period in 2012 primarily due to $1.3 million of expenses associated with our recently acquired assets. This increase was partially offset by decreased workover expenses on our existing properties.

Taxes other than income increased $15.5 million for the three months ended March 31, 2013 as compared to the same period in 2012 primarily due to $15.0 million of taxes associated with our recently acquired properties. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease directly. On a per unit basis, taxes other than income were $7.44 per Boe and $5.22 per Boe for the three months ended March 31, 2013 and 2012, respectively.

In March 2012, we announced our intention to close the Plano, Texas office and began the process of relocating key administrative functions to our corporate headquarters in Houston, Texas (the Restructuring). As part of the Restructuring, we offered certain severance and retention benefits to affected employees. We incurred $0.7 million and $0.1 million in costs associated with the Restructuring for the three months ended March 31, 2013 and 2012, respectively.

General and administrative expense for the three months ended March 31, 2013 increased $13.1 million to $29.3 million as compared to the same period in 2012. The increase in general and administrative expenses is attributable to increases in payroll and related employee benefit costs of $5.1 million, office related expenses of $3.9 million and professional fees of $2.5 million, in support of the expanding business base and increased corporate activities subsequent to the Recapitalization.

Share-based compensation expense for the three months ended March 31, 2013 was $2.3 million, a decrease of $1.8 million compared to the same period in 2012. In 2012, we incurred approximately $4.3 million for the accelerated vesting of restricted stock awards and stock appreciation rights resulting from the change in control that occurred due to the Recapitalization in February 2012.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production volume for the current period to total remaining reserve volume as of the beginning of the period for the evaluated properties. Depletion expense increased $74.5 million to $79.9 million for the three months ended March 31, 2013 compared to the same period in 2012, primarily due to a higher depletion rate per Boe and increased production. On a per unit basis, depletion expense was $34.11 per Boe for the three months ended March 31, 2013 compared to $14.53 per Boe for the three months ended March 31, 2012. The increase in depletion expense and the depletion rate per Boe is primarily due to the GeoResources Merger, the East Texas Assets . . .

  Add HK to Portfolio     Set Alert         Email to a Friend  
Get SEC Filings for Another Symbol: Symbol Lookup
Quotes & Info for HK - All Recent SEC Filings
Sign Up for a Free Trial to the NEW EDGAR Online Pro
Detailed SEC, Financial, Ownership and Offering Data on over 12,000 U.S. Public Companies.
Actionable and easy-to-use with searching, alerting, downloading and more.
Request a Trial Sign Up Now


Copyright © 2014 Yahoo! Inc. All rights reserved. Privacy Policy - Terms of Service
SEC Filing data and information provided by EDGAR Online, Inc. (1-800-416-6651). All information provided "as is" for informational purposes only, not intended for trading purposes or advice. Neither Yahoo! nor any of independent providers is liable for any informational errors, incompleteness, or delays, or for any actions taken in reliance on information contained herein. By accessing the Yahoo! site, you agree not to redistribute the information found therein.