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HK > SEC Filings for HK > Form 10-K on 27-Feb-2014All Recent SEC Filings

Show all filings for HALCON RESOURCES CORP

Form 10-K for HALCON RESOURCES CORP


27-Feb-2014

Annual Report


ITEM 7. 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 and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K contain additional information that should be referred to when reviewing this material.

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 assets in the United States. We were incorporated in Delaware on February 5, 2004 and were recapitalized on February 8, 2012, as described more fully herein. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in selected prospect areas, providing us with an extensive drilling inventory in multiple basins that we believe allow for multiple years of production growth and broad flexibility to direct our capital resources to projects with the greatest potential returns. During 2013, we focused on the development of acquired properties and also divested non-core assets in order to fund activities in our core resource plays.

At December 31, 2013, our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc. (Netherland, Sewell), were approximately 136 MMBoe, consisting of 114.5 MMBbls of oil, 9.8 MMBbls of natural gas liquids, and 69.7 Bcf of natural gas. Approximately 40% of our proved reserves were classified as proved developed. We maintain operational control of approximately 92% of our proved reserves. Production for the fourth quarter of 2013 averaged 40,217 Boe/d. Pro forma for the divestitures of certain non-core assets, production for the fourth quarter of 2013 averaged 37,489 Boe/d. Full year 2013 production averaged 33,329 Boe/d compared to 9,404 Boe/d in 2012. Our total operating revenues for 2013 were approximately $999.5 million compared to $248.3 million in 2012.

Our oil and natural gas assets consist of undeveloped acreage positions in unconventional liquids-rich basins/fields. We have acquired acreage and may acquire additional acreage in the Bakken / Three Forks formations in North Dakota, the Eagle Ford formation in East Texas, the Utica / Point Pleasant formations in Ohio and Pennsylvania and the Tuscaloosa Marine Shale formation in Louisiana and Mississippi, as well as several other areas.

Our average daily production increased 254% year over year. The increase in production compared to the prior year period was driven by our operated drilling results and increased production volumes


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associated with the development of properties we acquired in 2012 in the Bakken / Three Forks, Woodbine, and the Eagle Ford formation in East Texas (which we refer to as "El Halcón"). These areas collectively accounted for approximately 25,764 Boe/d in 2013, or 77% of our production. In 2013, we participated in the drilling of 284 gross (107.4 net) wells of which 281 gross (104.4 net) wells were completed and capable of production, and 3 gross (3.0 net) wells were dry holes.

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 predominantly 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.

For the twelve months ended December 31, 2013 we incurred capital expenditures for drilling and completions of approximately $1.5 billion. We expect to spend approximately $950 million on drilling and completion capital expenditures during 2014. Approximately 49% of our 2014 drilling and completions budget is expected to be spent in the Bakken / Three Forks formations in North Dakota, approximately 40% is budgeted for the El Halcón area in East Texas, and the remaining amount is planned for various other project areas, including the Tuscaloosa Marine Shale in Louisiana and Mississippi and the Utica / Point Pleasant formations in Ohio. Our 2014 drilling and completion budget contemplates four to five operated rigs running in the Bakken / Three Forks, three to four operated rigs running in the El Halcón area and one to two operated rigs running in the other areas. Our drilling and completion budget for 2014 is based on our current view of market conditions and current business plans, and is subject to change.

We expect to fund our budgeted 2014 capital expenditures with cash flows from operations, proceeds from additional potential non-core asset divestitures and borrowings under our Senior Credit Agreement. We strive to maintain financial flexibility and may access capital markets as necessary to 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. In the event our cash flows or proceeds from additional potential non-core asset dispositions are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.

Recent Developments

Divestitures of Non-core Assets

During the second half of 2013, we entered into three separate purchase and sale agreements with unrelated parties to divest certain non-core assets located throughout the United States for total consideration of approximately $302.0 million, all three of which closed in the fourth quarter of 2013. In aggregate, as of December 31, 2012, estimated proved reserves associated with these non-core assets, were approximately 21.2 MMBoe (69% oil). Production from these non-core assets averaged approximately 4,400 Boe/d during the third quarter of 2013. Proceeds from the sales of the non-core assets were recorded as a reduction to the carrying value of our full cost pool with no gain or loss recorded. The borrowing base reduction associated with these non-core assets sales was $50.0 million. Following the closing of the last of these three divestitures on December 20, 2013, the borrowing base on our Senior Credit Agreement was reduced by the $50.0 million to $700.0 million.


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Issuance of Additional 9.75% Senior Notes

On December 19, 2013, we issued an additional $400.0 million aggregate principal amount of our 9.75% senior notes due 2020. The net proceeds from the sale of the additional 2020 Notes of approximately $406.1 million were used to repay a portion of the then outstanding borrowings under our Senior Credit Agreement. In total, we have issued $1.15 billion of 9.75% senior notes due 2020. See Item 8. Consolidated Financial Statements and Supplementary Data-Note 6, "Long-Term Debt" for additional information on the additional 2020 Notes.

Issuance of 9.25% Senior Notes and Common Stock

On August 13, 2013, we issued $400.0 million aggregate principal amount of 9.25% senior notes due 2022 (the 2022 Notes). The net proceeds from the offering were approximately $392.1 million after deducting the commissions and offering expenses and were used to repay a portion of the then outstanding borrowings on our Senior Credit Agreement. See Item 8. Consolidated Financial Statements and Supplementary Data-Note 6, "Long-Term Debt" for additional information on the 2022 Notes.

On August 13, 2013, we also completed the issuance and sale of 43.7 million shares of common stock in an underwritten public offering. The net proceeds from the offering of common stock were approximately $215.2 million, after deducting the underwriting discount and estimated offering expenses. We used the net proceeds from the offering to repay a portion of the then outstanding borrowings on our Senior Credit Agreement. See Item 8. Consolidated Financial Statements and Supplementary Data-Note 11, "Preferred Stock and Stockholders' Equity" for additional information on the common stock offering.

Divestiture of Eagle Ford Assets

On July 19, 2013, we completed the sale of our interest in Eagle Ford assets in Fayette and Gonzales Counties, Texas, to private buyers for proceeds of approximately $147.9 million, before post-closing adjustments. Proceeds from the sale were recorded as a reduction to the carrying value of our full cost pool with no gain or loss recorded. As of December 31, 2012, we had approximately
3.6 MMBoe of estimated proved reserves associated with these properties. Production from the Eagle Ford assets averaged approximately 1,811 Boe/d during the second quarter of 2013.

Issuance of 5.75% Series A Convertible Perpetual Preferred Stock

On June 18, 2013, we issued in a public offering 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. 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 then 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 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 8. Consolidated Financial Statements and Supplementary Data-Note 11, "Preferred Stock and Stockholders' Equity" for additional information on the Series A Preferred Stock.


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Issuance of Additional 8.875% Senior Notes

On January 14, 2013, we completed the issuance of an additional $600.0 million aggregate principal amount of our 8.875% senior notes due 2021. The additional 2021 Notes were issued at 105% of par and provided net proceeds of approximately $619.5 million (after deducting offering fees). The net proceeds from this offering were used to repay a portion of the then outstanding borrowings under our Senior Credit Agreement and for general corporate purposes. See Item 8. Consolidated Financial Statements and Supplementary Data-Note 6, "Long-Term Debt" for additional information on the additional 2021 Notes.

Amendments to the Senior Credit Agreement and Borrowing Base

On October 31, 2013, we entered into the Sixth Amendment to our Senior Credit Agreement (the Sixth Amendment). The Sixth Amendment increased our borrowing base to $850.0 million, which was subsequently reduced to $700.0 million upon the closing of the final non-core divestiture in December 2013. Additionally, the Sixth Amendment provides for EBITDA (as defined in the Senior Credit Agreement) to be annualized for the next three fiscal quarters for purposes of measuring compliance with the interest coverage test. Specifically,
(i) for the fiscal quarter ended December 31, 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 March 31, 2014, 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 June 30, 2014, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the nine month period then ended multiplied by 1.333.

On June 11, 2013, we entered into the Fifth Amendment to the Senior Credit Agreement which permits us, among other things, to pay cash dividends to holders of our preferred capital stock. On May 8, 2013, we entered into the Fourth Amendment to the Senior Credit Agreement which modified the calculation of the interest coverage test, which was superseded by the Sixth Amendment. On April 26, 2013, we entered into the Third Amendment to our Senior Credit Agreement, which, among other things, provided additional flexibility under certain affirmative and negative covenants and on January 25, 2013, we entered into the Second Amendment to our Senior Credit Agreement which expanded our ability to enter into certain commodity hedging agreements.

Capital Resources and Liquidity

Our near-term capital spending requirements are expected to be funded with cash flows from operations, proceeds from additional potential non-core asset divestitures, proceeds from additional potential capital market transactions and borrowings under our Senior Credit Agreement, which has a current borrowing base of $700.0 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 the estimated value of our oil and natural gas reserves, the amount and cost of our 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


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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 by the value of discounted future net revenues from proved oil and natural gas reserves as of the date of such determination. At December 31, 2013, we had no indebtedness outstanding under our Senior Credit Agreement, $1.2 million of letters of credit outstanding and $698.8 million of borrowing capacity, of which approximately $629 million was available to us under the indebtedness limitation in our indentures.

Our ability to meet our debt covenants and our capacity to incur additional indebtedness will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. For example, lower oil and natural gas prices could result in a redetermination of the borrowing base under our Senior Credit Agreement at a lower level and reduce our adjusted consolidated EBITDA, as well as our adjusted consolidated net tangible assets as determined under our Indentures, and thus could reduce our ability to incur indebtedness. Our strategic divestitures of non-core producing properties in favor of investing in undeveloped acreage, coupled with our aggressive drilling plans also impact our near-term ability to comply with our debt covenants, particularly the interest coverage test under our Senior Credit Agreement and the fixed charge coverage ratio under our Indentures by reducing our production and reserves on a current and, for purposes of covenant calculations, a pro forma historical basis, while drilling takes time to replace these losses. Of course, over the longer term, we expect that our strategy and our investments will result in increased production and reserves, lower lease operating costs and more abundant drilling opportunities. As a consequence, we constantly monitor our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues and work with the lenders under our Senior Credit Agreement to address any such issues ahead of time.

As noted above under "Recent Developments", we have in the past obtained amendments to the covenants under our Senior Credit Agreement under circumstances where we anticipated that it might be challenging for us to comply with our financial covenants for a particular period of time. During 2013, we obtained amendments to the calculation of the interest coverage ratio covenant under our Senior Credit Agreement allowing us to annualize our quarterly EBITDA because, among other things, we anticipated that our strategic decision to divest our Eagle Ford shale producing properties and invest in the acquisition and drilling of undeveloped acreage would have caused us to fall below the interest coverage ratio. We have discussed with the administrative agent and various lenders under our Senior Credit Agreement a waiver of compliance with the interest coverage and current ratios for 2014 and expect that request to be granted in conjunction with the next redetermination of our borrowing base prior to the end of our first fiscal quarter. The basis for the waiver request is similar to previously requested waivers described above, i.e., the potential for us to fall out of compliance primarily as a result of our strategic decision to divest producing properties, invest extensively in undeveloped acreage and the long lead times associated with replacing lost production through our drilling program. As part of our plan to manage liquidity risks, we have scaled back our capital expenditures budget, focused our drilling program on our highest return projects, are actively considering various joint venture opportunities to finance development of our Tuscaloosa Marine Shale properties, and continue to explore opportunities to divest non-core properties.

In the event that the lenders under our Senior Credit Agreement prove unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we may be forced to repay or refinance amounts then outstanding under the Senior Credit Agreement and seek


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alternative sources of capital to fund our business and anticipated capital expenditures. In the event that we are unable to access sufficient capital to fund our business and planned capital expenditures, we may be required to curtail our drilling, development, land acquisition and other activities, which could result in a decrease in our production of oil and natural gas, may be subject to forfeitures of leasehold interests to the extent we are unable or unwilling to renew them, and may be forced to sell some of our assets on an untimely or unfavorable basis, each of which could adversely affect our results of operations and financial condition. Further, the failure to comply with the restrictive covenants relating to our indebtedness could result in the declaration of a default and cross default under the instruments governing our indebtedness, potentially resulting in acceleration of our obligations and adversely impacting our financial condition.

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.

We strive to maintain financial flexibility while pursuing our 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. Even if we are otherwise successful in growing our reserves and production, 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.

Cash Flow

Our primary source of cash in 2013 and 2012 was from financing activities. Our primary source of cash in 2011 was from operating activities. In 2013, proceeds from the 2022 Notes, the additional 2021 Notes, the additional 2020 Notes, the issuance of common stock and the issuance of our Series A Preferred Stock were the primary drivers of the net cash provided by financing activities.

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


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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.

                                                       Years Ended December 31,
                                                    2013           2012         2011
                                                            (In thousands)
Cash flows provided by (used in) operating
activities                                      $    493,924   $     84,360   $  29,835
Cash flows provided by (used in) investing
activities                                        (2,100,699 )   (2,832,466 )   (25,376 )
Cash flows provided by (used in) financing
activities                                         1,607,103      2,750,563      (4,447 )


Net increase (decrease) in cash                 $        328   $      2,457   $      12

Operating Activities. Net cash flows provided by operating activities were $493.9 million, $84.4 million and $29.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs.

Net loss for the year ended December 31, 2013 was $1.2 billion. Non-cash items, including a $1.1 billion full cost ceiling impairment, $228.9 million goodwill impairment, $67.5 million other operating property and equipment impairment and $463.7 million depreciation, depletion and accretion served to more than offset this net loss. The improvement in operating cash flows primarily reflects the impact of the 254% increase in our average daily production compared to the 2012 period, which drove the significant increase in operating revenues.

Net loss for the year ended December 31, 2012 was $53.9 million. Non-cash items, including $90.3 million of depreciation, depletion and accretion, $9.4 million of non-cash interest and amortization and $6.2 million of amortization and write-off of deferred loan costs served to offset this net loss. Our recapitalization, including change in control and related activities which occurred during February 2012, our acquisition of GeoResources, Inc. and transaction costs, and the impact of additional personnel and facilities in support of our expanding business base, drove a significant increase in general and administrative expenditures, which adversely affected our operating cash flows. The remaining improvement in operating cash flows is largely attributable to a favorable mix in working capital changes.

Net cash flows provided by operating activities decreased in 2011 primarily due to a 30% decrease in our production volumes, which was partially offset by a 34% increase in our average realized Boe price compared to the same period in 2010.

Investing Activities. The primary driver of cash used in investing activities is capital spending on our oil and natural gas properties. Net cash used in investing activities was $2.1 billion, $2.8 billion and $25.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.

In 2013, we incurred cash expenditures of $2.4 billion on oil and natural gas capital expenditures, of which $1.5 billion related to drilling and completion costs and the remainder was primarily associated with leasing, acquisitions and seismic data. These expenditures were offset by $448.3 million in proceeds received from the sale of our Eagle Ford properties and other non-core asset divestitures. We participated in the drilling of 284 gross (107.4 net) wells of which 281 gross (104.4 net) wells were completed and capable of production and 3 gross (3.0 net) wells were dry holes. We spent an additional $139.3 million on other operating property and equipment capital expenditures primarily related to gathering and transportation systems.

In 2012, we incurred cash expenditures of $579.5 million, net of cash acquired, on our acquisition of GeoResources, Inc., $756.1 million on the acquisition of the Williston Basin Assets, and $296.1 million on our acquisition of the East Texas Assets. Additionally, we spent $1.2 billion on drilling and . . .

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