News Column

HALCON RESOURCES CORP - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

February 27, 2014

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 completion wells, infrastructure projects and other leasehold acquisitions. We participated in the drilling of 192 gross (88.2 net) wells of which 189 gross (85.3 net) wells were completed and

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capable of production and 3 gross (2.9 net) wells were dry holes. We also drilled and completed 6 gross (5.0 net) salt water disposal wells. We spent an additional $38.5 million on other operating property and equipment capital expenditures primarily related to gathering and transportation systems. Proceeds from sales of oil and natural gas properties were $22.0 million.

In 2011, we spent $25.2 million on capital associated with of evaluated oil and natural properties. We drilled or participated in the drilling of 54 gross (49.0 net) wells on our oil and natural gas properties, of which, 49 gross (44.8 net) wells were successfully completed as producing wells, 5 gross (4.2 net) wells were abandoned wells and 7 gross (5.9 net) wells were either drilling or waiting to be completed at the end of that period.

Financing Activities. Net cash flows provided by financing activities were $1.6 billion and $2.8 billion for the years ended December 31, 2013 and 2012, respectively. Net cash flows used in financing activities were $4.4 million for the year ended December 31, 2011. The primary drivers of cash provided by financing activities are proceeds from the issuance of our senior notes, common stock and preferred stock, offset by repayments under our Senior Credit Agreement.

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.

On August 13, 2013, we completed the issuance of $400.0 million aggregate principal amount of our 2022 Notes. The net proceeds to us from the offering were approximately $392.1 million after deducting commissions and offering expenses and were used to repay a portion of the then outstanding borrowings under our Senior Credit Agreement.

On August 13, 2013, we also issued of 43.7 million shares of common stock in an underwritten public offering. The net proceeds from the offering of our 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.

On June 18, 2013, we issued 345,000 shares of our Series A Preferred Stock in a public offering at a 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.

On January 14, 2013, we issued an additional $600.0 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. We used the net proceeds from the offering 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.

On December 6, 2012, in conjunction with the closing of the Williston Basin Assets acquisition, we received net proceeds of approximately $294.0 million from the private placement of 41.9 million shares of our common stock with CPP Investment Board PMI-2, Inc., which acquired the shares for a purchase price of approximately $7.16 per share.

On November 6, 2012, we issued $750.0 million aggregate principal amount of our 8.875% senior notes due 2021. Net proceeds of $725.6 million from the offering were placed into escrow pending the acquisition of the Williston Basin Assets and were subsequently released upon closing and used to fund a portion of the cash consideration paid in the acquisition.

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On July 16, 2012, we issued $750.0 million aggregate principal amount of 9.75% senior notes due 2020. Net proceeds of $723.1 million from the offering were placed into escrow pending our acquisition of GeoResources, Inc. and subsequently released from escrow on August 1, 2012 and utilized to fund our acquisition of GeoResources, Inc. and the East Texas Assets.

On March 5, 2012, we issued shares of automatically convertible preferred stock that subsequently converted into approximately 44.4 million shares of common stock for gross proceeds of $400.0 million. We used the proceeds for general corporate purposes.

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 8.0% 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. In connection with the closing of the recapitalization, we entered into our Senior Credit Agreement and terminated our prior credit facilities with the payoff of the $210.8 million balance.

Cash flows provided by financing activities include net borrowings under our Senior Credit Agreement of $298.0 million for the year ended December 31, 2012, primarily used to fund our acquisition activities and our ongoing drilling activities.

Contractual Obligations

We have a significant degree of flexibility to adjust the level of our future capital expenditures as circumstances warrant. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, developmental and exploration activities, oil and natural gas price conditions, our access to capital and liquidity and other related economic factors. We currently have no material off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities. The following table summarizes our contractual obligations and commitments by payment periods as of December 31, 2013. Payments Due by Period 2019 and Contractual Obligations Total 2014 2015 - 2016 2017 - 2018 Beyond (In thousands) Senior revolving credit facility $ - $ - $ - $ - $ - 9.25% senior notes due 2022 400,000 - - - 400,000 8.875% senior notes due 2021(1) 1,350,000 - - - 1,350,000 9.75% senior notes due 2020(2) 1,150,000 - - - 1,150,000 8.0% convertible note(3) 289,669 - - 289,669 - Interest expense on long-term debt(4) 1,997,872 294,732 589,464 540,636 573,040 Operating leases 68,631 8,540 17,917 18,346 23,828 Drilling rig commitments 48,947 37,672 11,275 - - Other commitments 15,388 15,388 - - - Total contractual obligations $ 5,320,507$ 356,332$ 618,656$ 848,651$ 3,496,868



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(1) Excludes $5.1 million unamortized discount recorded in conjunction with the original issuance of the notes and a $27.5 million premium recorded in conjunction with the January 2013 issuance of the additional 2021 Notes. (2) Excludes $8.9 million unamortized discount recorded in conjunction with the original issuance of the notes and a $11.0 million premium recorded in conjunction with the December 2013 issuance of the additional 2020 Notes. (3) Excludes $30.3 million unamortized discount recorded in conjunction with the issuance of the note. 54



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Table of Contents (4) Future interest expense was calculated based on interest rates and amounts outstanding at December 31, 2013 less required annual repayments.



We also have various long-term gathering, transportation and sales contracts in the Bakken / Three Forks formations in North Dakota which are not included in the table above. As of December 31, 2013, we had in place nine long-term crude oil contracts and two long-term natural gas contracts in this area. Under the terms of these contracts we have committed a substantial portion of our Bakken / Three Forks production for periods ranging from five to ten years from the date of first production. The sales prices under these contracts are based on posted market rates. We believe that there are sufficient available reserves and supplies in the Bakken / Three Forks formations to meet our commitments, as the proved reserves from this area represent approximately 67% of our total proved reserves.

Additionally, as of December 31, 2013, we had one long-term natural gas transportation contract and one long-term natural gas gathering contract in the Woodbine formation in East Texas which are not included in the table above. The rate under the transportation contract was negotiated based on market rates and the contract term is five years from the date of first production. Under the gathering contract, we have committed substantially all of our natural gas production from specific wells in the area, until a contracted volume amount is reached, in exchange for the construction of a gathering system. The contract term is five years from the date of first production.

Historically, we have been able to meet our delivery commitments.

The contractual obligations table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. In addition, amounts related to our asset retirement obligations are not included in the table above given the uncertainty regarding the actual timing of such expenditures. The total estimated amount of our asset retirement obligations at December 31, 2013 was $39.3 million.

Senior Revolving Credit Facility

In connection with the closing of the Recapitalization, discussed in Item 8. Consolidated Financial Statements and Supplementary Data-Note 2, "Recapitalization," we entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto on February 8, 2012. The Senior Credit Agreement provides for a $1.5 billion facility with a current borrowing base of $700.0 million. Amounts borrowed under the Senior Credit Agreement will 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 the estimated value of our oil and natural gas reserves, total indebtedness, and other relevant factors consistent with customary oil and natural 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 Senior Credit Agreement may be paid down and re-borrowed during the five-year term of the revolver. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 0.50% to 1.50% for ABR-based loans or at specified margins over LIBOR of 1.50% to 2.50% for Eurodollar-based loans. These margins fluctuate based on our utilization of the facility. Advances under the Senior Credit Agreement are secured by liens on substantially all of our properties and assets. The Senior Credit Agreement contains customary representations, warranties and covenants including, among others, restrictions on the payment of dividends on our capital stock and financial 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.

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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 for us under the indebtedness limitation in our indentures.

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.

March 2011 Credit Facilities

Our March 2011 credit facilities included a $250.0 million revolving credit facility and a $75.0 million second lien term loan facility, replacing the November 2007 facility. SunTrust Bank was the administrative agent for the revolving credit facility, and Guggenheim Corporate Funding, LLC was the administrative agent for the second lien term loan facility. The revolving credit facility allowed for funds advanced to be paid down and re-borrowed during the five-year term of the revolver, and bore interest at LIBOR plus a margin ranging from 2.5% to 3.25% based on a percentage of usage. The second lien term loan facility provided for payments of interest only during its 5.5 year term, and bore interest at LIBOR plus 9.0% with a 2.0% LIBOR floor, or if any period we elected to pay a portion of the interest "in kind," then the interest rate would have been LIBOR plus 10.0% with a 2.0% LIBOR floor, and with 7.0% of the interest amount paid in cash and the remaining 3.0% paid-in-kind by being added to principal. At December 31, 2011, $127.0 million was outstanding under the revolving credit facility and $75.0 million was outstanding under the second lien term loan facility. On February 8, 2012, we paid in full the outstanding balances under the revolving credit facility and the second lien term loan facility and both facilities were terminated, resulting in a $1.5 million charge to interest expense related to an early termination penalty.

9.25% Senior Notes

On August 13, 2013, we issued at par $400.0 million aggregate principal amount of 9.25% senior notes due 2022 (the 2022 Notes). The net proceeds from the offering of approximately $392.1 million (after deducting commissions and offering expenses) were used to repay a portion of the then outstanding borrowings under our Senior Credit Agreement.

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The 2022 Notes bear interest at a rate of 9.25% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on February 15, 2014. The 2022 Notes will mature on February 15, 2022. The 2022 Notes are senior unsecured obligations of ours, rank equally with all of our current and future senior indebtedness and are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by our existing 100% owned subsidiaries. We, the issuer of the 2022 Notes, have no material independent assets or operations apart from the assets and operations of our subsidiaries.

8.875% Senior Notes

On November 6, 2012, we completed a private offering of $750.0 million aggregate principal amount of 8.875% senior notes due 2021, issued at 99.247% of par (the 2021 Notes). The net proceeds from the offering were approximately $725.6 million after deducting the initial purchasers' discounts, commissions and offering expenses and were used to fund a portion of the cash consideration paid in the Williston Basin Assets acquisition. See Item 8. Consolidated Financial Statements and Supplementary Data-Note 4, "Acquisitions and Divestitures," for additional information regarding the Williston Basin Assets acquisition.

On January 14, 2013, we completed the issuance of an additional $600.0 million aggregate principal amount of 2021 Notes, issued at 105% of par. The net proceeds from the sale of the additional 2021 Notes were approximately $619.5 million (after deducting offering fees). The net proceeds from this offering 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.

The 2021 Notes bear interest at a rate of 8.875% per annum, payable semi-annually on May 15 and November 15 of each year, beginning on May 15, 2013. The Notes will mature on May 15, 2021. In connection with the issuance of the original 2021 Notes, we recorded a discount of approximately $5.7 million to be amortized over the remaining life of the 2021 Notes using the effective interest method. The remaining unamortized discount was $5.1 million at December 31, 2013. In connection with the issuance of the additional 2021 Notes, we recorded a premium of approximately $30.0 million to be amortized over the remaining life of the 2021 Notes using the effective interest method. The remaining unamortized premium was $27.5 million at December 31, 2013. See Item 8. Consolidated Financial Statements and Supplementary Data-Note 6, "Long-Term Debt," for additional information regarding the 2021 Notes.

9.75% Senior Notes

On July 16, 2012, we completed a private offering of $750.0 million aggregate principal amount of 9.75% senior notes due 2020 issued at 98.646% of par (the 2020 Notes). The net proceeds from the offering were approximately $723.1 million after deducting the initial purchasers' discounts, commissions and offering expenses and were used to fund a portion of the cash consideration paid in the merger with GeoResources, Inc. (the Merger) and the East Texas Assets acquisition. See Item 8. Consolidated Financial Statements and Supplementary Data-Note 4, "Acquisitions and Divestitures," for additional information regarding the Merger and the East Texas Assets acquisition.

On December 19, 2013, we issued an additional $400.0 million aggregate principal amount of the 2020 Notes at a price to the initial purchasers of 102.750% of par. The net proceeds from the sale of the additional 2020 Notes of approximately $406.1 million (after the initial purchasers' premiums, commissions and offering expenses) were used to repay a portion of the then outstanding borrowings under the Senior Credit Agreement and for general corporate purposes. These notes were issued as "additional notes" under the indenture governing the 2020 Notes and under the indenture are treated as a single series with substantially identical terms as the 2020 Notes previously issued.

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The 2020 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on January 15 and July 15 of each year, which began on January 15, 2013. The 2020 Notes will mature on July 15, 2020. In connection with the issuance of the 2020 Notes, we recorded a discount of approximately $10.2 million to be amortized over the remaining life of the 2020 Notes using the effective interest method. The remaining unamortized discount was $8.9 million at December 31, 2013. In connection with the issuance of the additional 2020 Notes, we recorded a premium of approximately $11.0 million to be amortized over the remaining life of the 2020 Notes using the effective interest method. The remaining unamortized premium was $11.0 million at December 31, 2013. See Item 8. Consolidated Financial Statements and Supplementary Data-Note 6, "Long-Term Debt," for additional information regarding the 2020 Notes.

8.0% Convertible Note

On February 8, 2012, we issued the 8.0% senior note in the principal amount of $275.0 million (the 2017 Note) together with the February 2012 Warrants for an aggregate purchase price of $275.0 million. The 2017 Note bears interest at a rate of 8% per annum, payable quarterly on March 31, June 30, September 30 and December 31 of each year and matures on February 8, 2017. Through the March 31, 2014 interest payment date, we may elect to pay-in-kind, by adding to the principal of the 2017 Note, all or any portion of the interest due on the 2017 Note. We elected to pay the interest in-kind on March 31, June 30 and September 30, 2012, and rolled $3.2 million, $5.7 million and $5.8 million of interest incurred during the first, second and third quarters of 2012, respectively, into the 2017 Note, increasing the principal amount to $289.7 million. We did not elect to pay-in-kind interest for the quarterly payments due subsequently to September 30, 2012. As of February 8, 2014, the note can be converted into common stock. Each $4.50 of principal and accrued but unpaid interest is convertible into one share of our common stock. The 2017 Note is a senior unsecured obligation of ours.

We allocated the proceeds received for the 2017 Note and February 2012 Warrants on a relative fair value basis. Consequently, we recorded a discount of $43.6 million to be amortized over the remaining life of the 2017 Note utilizing the effective interest rate method. The remaining unamortized discount was $30.3 million at December 31, 2013.

Promissory Notes

On December 28, 2012, we completed the acquisition of certain oil and natural gas properties in Brazos County, Texas for approximately $83.7 million, before and subject to, customary closing adjustments, consisting of approximately $8.4 million in cash and approximately $75.3 million in promissory notes. During the three months ended March 31, 2013, we completed our review of the properties and paid approximately $62.4 million during the period for properties deemed to have clear title and no defects. In addition, notice was given to the sellers of our assertion of title and environmental defects amounting to $12.9 million for the remaining properties. During the three months ended September 30, 2013, the title and environmental defects were cured by the sellers and we paid the remaining portion of the purchase price. The promissory notes were classified as current at December 31, 2012.

In conjunction with the issuance of the promissory notes in December 2012, we recorded a discount of approximately $0.6 million to be amortized over the remaining life of the promissory notes using the effective interest method. We expensed the discount during the first quarter of 2013.

Off-Balance Sheet Arrangements

At December 31, 2013, we did not have any material off-balance sheet arrangements.

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Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States. We also describe the most significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our audit committee. See Results of Operations above and Item 8. Consolidated Financial Statements and Supplementary Data-Note 1, "Summary of Significant Events and Accounting Policies," for a discussion of additional accounting policies and estimates made by management.

Oil and Natural Gas Activities

Accounting for oil and natural gas activities is subject to unique rules. Two generally accepted methods of accounting for oil and natural gas activities are available-successful efforts and full cost. The most significant differences between these two methods are the treatment of unsuccessful exploration costs and the manner in which the carrying value of oil and natural gas properties are amortized and evaluated for impairment. The successful efforts method requires unsuccessful exploration costs to be expensed as they are incurred upon a determination that the well is uneconomical while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and natural gas properties under the successful efforts method is based on an evaluation of the carrying value of individual oil and natural gas properties against their estimated fair value, while impairment under the full cost method requires an evaluation of the carrying value of oil and natural gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using the unweighted arithmetic average of the first day of the month for each of the 12-month prices for oil and natural gas within the period, holding prices and costs constant and applying a 10% discount rate.

Full Cost Method

We use the full cost method of accounting for our oil and natural gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized into a cost center (the amortization base or full cost pool). Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. All general and administrative costs unrelated to drilling activities are expensed as incurred. The capitalized costs of our evaluated oil and natural gas properties, plus an estimate of our future development and abandonment costs are amortized on a unit-of-production method based on our estimate of total proved reserves. Our financial position and results of operations could have been significantly different had we used the successful efforts method of accounting for our oil and natural gas activities.

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Proved Oil and Natural Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States and Securities Exchange Commission (SEC) guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and accretion expense and the full cost ceiling test limitation. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

Our estimated proved reserves for the years ended December 31, 2013 and 2012 were prepared by Netherland, Sewell, an independent oil and natural gas reservoir engineering consulting firm. Our estimated proved reserves for the year ended December 31, 2011 was prepared by Forrest A. Garb & Associates, an independent oil and natural gas reservoir engineering consulting firm. For more information regarding reserve estimation, including historical reserve revisions, refer to Item 8. Consolidated Financial Statements and Supplementary Data-"Supplemental Oil and Gas Information (Unaudited)."

Depreciation, Depletion and Accretion

Our rate of recording depletion, depreciation and accretion expense (DD&A) is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2013, a five percent positive revision to proved reserves would decrease the DD&A rate by approximately $1.77 per Boe and a five percent negative revision to proved reserves would increase the DD&A rate by approximately $1.95 per Boe.

Full Cost Ceiling Test Limitation

Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write down to the extent of such excess. If required, it would reduce earnings and impact stockholders' equity in the period of occurrence and result in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If average oil and natural gas prices decline, or if we have downward revisions to our estimated proved reserves, it is possible that write downs of our oil and natural gas properties could occur in the future.

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If the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ended December 31, 2013 had been 10% lower while all other factors remained constant, our ceiling amount related to our net book value of oil and natural gas properties would have been reduced by approximately $545.0 million. This reduction would have increased our full cost ceiling impairment by approximately $545.0 million before income taxes.

Future Development Costs

Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production facilities, gathering systems and related structures and restoration costs. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis. A five percent decrease or increase in future development and abandonment costs would decrease or increase the DD&A rate by approximately $0.78 per Boe at December 31, 2013.

Asset Retirement Obligations

We have obligations to remove tangible equipment and facilities associated with our oil and natural gas wells and our gathering systems, and to restore land at the end of oil and natural gas production operations. Our removal and restoration obligations are associated with plugging and abandoning wells and our gathering systems. Estimating the future restoration and removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlements and changes in the legal, regulatory, environmental and political environments.

Accounting for Derivative Instruments and Hedging Activities

We account for our derivative activities under the provisions of Accounting Standards Codification (ASC) No. 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, we may hedge a portion of our forecasted oil, natural gas, and natural gas liquids production. Derivative contracts entered into by us have consisted of transactions in which we hedge the variability of cash flow related to a forecasted transaction. We elected to not designate any of our positions for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in "Net gain (loss) on derivative contracts" on the consolidated statements of operations.

Goodwill

We account for goodwill in accordance with ASC 350, Intangibles-Goodwill and Other (ASC 350). Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. ASC 350 requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more

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frequently if an event occurs or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. Our goodwill related to the acquisition of GeoResources in 2012.

Accounting Standards Update (ASU) No. 2011-08, Testing for Goodwill Impairment (ASU 2011-08), simplifies testing for goodwill impairments by allowing entities to first assess qualitative factors to determine whether the facts or circumstances lead to the conclusion that it is more likely than not that the fair value of a reporting unit is less than the carrying value. If the entity concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then the entity does not have to perform the two-step impairment test. However, if the same conclusion is not reached, the Company is required to perform the first step of the two-step impairment test. In this step, the fair value of the reporting unit is calculated and compared to the carrying value of the reporting unit. If the carrying value exceeds the fair value, then the entity must perform the second step of the impairment test to measure the amount of impairment loss, if any. ASU 2011-08 also allows a company to bypass the qualitative assessment and proceed directly with performing the two-step goodwill impairment test.

Income Taxes

Our provision for taxes includes both state and federal taxes. We account for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized.

In assessing the need for a valuation allowance on our deferred tax assets, we consider possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. We consider all available evidence (both positive and negative) in determining whether a valuation allowance is required. A significant item of objective negative evidence considered was the cumulative book loss over the three-year period ended December 31, 2013 driven primarily by the full cost ceiling impairments in 2013. Based upon the evaluation of the available evidence we recorded an increase of $262.8 million to our valuation allowance resulting in $265.1 million being applied against our deferred tax assets as of December 31, 2013.

We follow ASC 740, Income Taxes (ASC 740). ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows. The evaluation of a tax position in accordance with ASC 740 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

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Comparison of Results of Operations

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

We reported a net loss of $1.2 billion for the year ended December 31, 2013 compared to a net loss of $53.9 million for the comparable period in 2012. The following table summarizes key items of comparison and their related change for the periods indicated.

Years Ended December 31, In thousands (except per unit and per Boe amounts) 2013 2012 Change Net income (loss) $ (1,222,662 )$ (53,885 )$ (1,168,777 ) Operating revenues: Oil 944,535 223,056 721,479 Natural gas 27,319 12,735 14,584 Natural gas liquids 24,564 11,180 13,384 Other 3,088 1,351 1,737 Operating expenses: Production: Lease operating 139,182 49,859 89,323 Workover and other 6,268 4,429 1,839 Taxes other than income 88,622 19,253 69,369 Gathering and other 11,745 459 11,286 Restructuring 4,471 2,406 2,065 General and administrative: General and administrative 115,298 104,608 10,690 Share-based compensation 17,112 6,741 10,371 Depletion, depreciation and accretion: Depletion-Full cost 453,537 86,215 367,322 Depreciation-Other 6,522 1,763 4,759 Accretion expense 3,596 2,306 1,290 Full cost ceiling impairment 1,147,771 - 1,147,771 Other operating property and equipment impairment 67,454 - 67,454 Goodwill impairment 228,875 - 228,875 Other income (expenses): Net gain (loss) on derivative contracts (31,233 ) (6,126 ) (25,107 ) Interest expense and other, net (58,198 ) (31,223 ) (26,975 ) Income tax benefit (provision) 157,716 13,181 144,535 Production: Crude oil-MBbls 10,148 2,415 7,733 Natural gas-Mmcf 8,003 4,554 3,449 Natural gas liquids-MBbls 683 268 415 Total MBoe(1) 12,165 3,442 8,723 Average daily production-Boe(1) 33,329 9,404 23,925 Average price per unit(2): Crude oil price-Bbl $ 93.08$ 92.36$ 0.72 Natural gas price-Mcf 3.41 2.80 0.61 Natural gas liquids price-Bbl 35.96 41.72 (5.76 ) Total per Boe(1) 81.91 71.75 10.16 Average cost per Boe: Production: Lease operating $ 11.44$ 14.49$ (3.05 ) Workover and other 0.52 1.29 (0.77 ) Taxes other than income 7.28 5.59 1.69 Gathering and other 0.97 0.13 0.84 Restructuring 0.37 0.70 (0.33 ) General and administrative: General and administrative 9.48 30.39 (20.91 ) Share-based compensation 1.41 1.96 (0.55 ) Depletion 37.28 25.05 12.23



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(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. 63



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For the year ended December 31, 2013, oil, natural gas and natural gas liquids revenues increased $749.4 million from the same period in 2012. The increase was primarily due to increased production volumes associated with the development of the properties we acquired in 2012 in the Bakken / Three Forks, Woodbine and El HalcÓn areas. These areas collectively accounted for 8,243 MBoe and $717.8 million of incremental revenues year over year. Realized average prices per Boe increased $10.16 per Boe to $81.91 per Boe.

Lease operating expenses increased $89.3 million for the year ended December 31, 2013, primarily due to $73.4 million of expenses on properties acquired in 2012 and our development of these properties in 2013. Lease operating expenses were $11.44 per Boe in 2013 compared to $14.49 per Boe in 2012. The decrease per Boe is primarily due to lower operating expenses per Boe on the newly developed properties. As we continue to strive for operational efficiencies and divest non-core properties with higher operating costs our lease operating expense per Boe should decline.

Workover and other expenses increased $1.8 million for the year ended December 31, 2013 compared to the same period in 2012 primarily due to $3.2 million of expenses associated with increased activity on acquired properties as we continue to develop these areas.

Taxes other than income increased $69.4 million for the year ended December 31, 2013 as compared to the same period in 2012 primarily due to increased production from the development of the properties we acquired in 2012. 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 proportionately. On a per unit basis, taxes other than income were $7.28 per Boe and $5.59 per Boe, for the years ended 2013 and 2012, respectively. The increase on a per Boe basis in 2013 is driven by increased production and revenue in our Bakken / Three Forks area which has higher production tax rates than our other areas.

Gathering and other expenses for the year ended December 31, 2013 and 2012 were $11.7 million and $0.5 million, respectively. In 2013, approximately $3.4 million of these expenses were attributable to midstream infrastructure that we developed in our Woodbine and Utica / Point Pleasant operating areas and approximately $8.3 million relates to gathering and other fees paid on our oil and natural gas production.

In March 2012, we announced our intention to close our 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, through May 2013. Approximately $0.5 million of our restructuring expense in 2013 relates to costs from the restructuring. Additionally, in the fourth quarter of 2013, in conjunction with our divestitures of certain non-core assets, we incurred approximately $4.0 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees in these non-core areas.

General and administrative expense for the year ended December 31, 2013 increased $10.7 million to $115.3 million as compared to the same period in 2012. The increase was primarily due to increases in payroll and related employee benefit costs of $17.9 million and office related expenses of $9.2 million, in support of our expanding employee and business base, partially offset by a decrease in transaction costs. On a per unit basis, general and administrative expenses were $9.48 per Boe and $30.39 per Boe, for the years ended 2013 and 2012, respectively.

Share-based compensation expense for the year ended December 31, 2013 was $17.1 million, an increase of $10.4 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 our recapitalization. The year over year increase,

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excluding these change in control payments, is approximately $6.1 million, reflecting our investment in additional personnel since the prior year.

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 for the evaluated properties. Depletion expense increased $367.3 million to $453.5 million for the year ended December 31, 2013 compared to the same period in 2012 of $86.2 million, primarily due to a higher depletion rate per Boe and increased production. On a per unit basis, depletion expense was $37.28 per Boe for the year ended December 31, 2013 compared to $25.05 per Boe for the year ended December 31, 2012. The increase in depletion expense and the depletion rate per Boe is primarily due to the increase in production volumes and in our capital spending associated with our development of the properties we acquired in 2012. Additionally, in the third quarter of 2013, we transferred unevaluated property costs of $655.7 million to the full cost pool, which is discussed further below, which contributed to the increase in depletion expense on both an absolute dollar and per Boe basis when compared to 2012.

We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the "ceiling," based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We recorded a full cost ceiling test impairment before income taxes of $1.1 billion for the year ended December 31, 2013. During the year ended December 31, 2013, we transferred $655.7 million of unevaluated property costs to the full cost pool primarily related to Woodbine assets in East Texas where capital has been reallocated to El HalcÓn, and certain Utica / Point Pleasant assets in Northwest Pennsylvania related to non-economical drilling results obtained in the third quarter of 2013. The combined impact of less favorable oil price differentials adversely affecting proved reserve values and the aforementioned non-routine transfers of unevaluated properties to the full cost pool primarily contributed to the ceiling impairment. Changes in production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

We review our gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360. For the year ended December 31, 2013, we recorded a non-cash impairment charge of $67.5 million. The impairment relates to our gross investments of $72.1 million in gas gathering infrastructure that will not be economically recoverable due to our shift in exploration, drilling and developmental plans from the Woodbine area to El HalcÓn during the third quarter of 2013.

During the third quarter of 2013, we performed our annual goodwill impairment test, using a measurement date of July 1, and based on this review; we recorded a non-cash impairment charge of $228.9 million to reduce the carrying value of goodwill to zero. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than the carrying amount, including goodwill, primarily due to pricing deterioration in the NYMEX forward pricing curve for oil, coupled with less favorable oil price differentials in our core areas, both factors which adversely impacted the fair value of our proved reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill.

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Accretion expense is a function of changes in the discounted asset retirement obligation liability from period to period. We recorded $3.6 million for the year ended December 31, 2013, compared to $2.3 million for the year ended December 31, 2012.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations. At December 31, 2013, we had a $24.8 million derivative asset, $2.0 million of which was classified as current, and we had a $37.2 million derivative liability of which $17.9 million was classified as current. We recorded a net derivative loss of $31.2 million ($10.1 million net unrealized loss and $21.1 million net realized loss on settled contracts and premium costs) for the year ended December 31, 2013 compared to a net derivative loss of $6.1 million ($13.2 million net unrealized loss and $7.1 million net realized gain on settled contracts and premium costs) in the prior year.

Interest expense increased $27.0 million for the year ended December 31, 2013. This increase was primarily due to the issuance of new long-term debt partially offset by capitalized interest expense on unevaluated properties. We incurred interest expense before capitalization of $259.2 million in 2013 compared to $85.4 million in the prior year. Due to significant costs incurred during 2012 on unevaluated properties we began capitalizing interest, resulting in $204.0 million and $53.5 million capitalized for the years ended December 31, 2013 and 2012, respectively.

We recorded an income tax benefit of $157.7 million on a loss before income taxes of $1.4 billion for the year ended December 31, 2013. The benefit reflects the impact of the change in the valuation allowance for the year of $262.8 million and the nondeductible goodwill impairment of $84.5 million. For the year ended December 31, 2012, we recorded an income tax benefit of $13.2 million on a loss before income taxes of $67.1 million. The benefit reflects nondeductible interest expense on the convertible notes issued as part of the Recapitalization of $3.2 million and nondeductible merger related costs of $3.6 million.

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Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

We reported a net loss of $53.9 million for the year ended December 31, 2012 compared to a net loss of $1.4 million for the comparable period in 2011. The following table summarizes key items of comparison and their related change for the periods indicated.

Years Ended December 31,



In thousands (except per unit and per Boe amounts) 2012 2011 Change

Net income (loss) $ (53,885 )$ (1,403 )$ (52,482 ) Operating revenues: Oil 223,056 82,968 140,088 Natural gas 12,735 10,933 1,802 Natural gas liquids 11,180 10,505 675 Other 1,351 168 1,183 Operating expenses: Production: Lease operating 49,859 30,043 19,816 Workover and other 4,429 1,967 2,462 Taxes other than income 19,253 7,214 12,039 Gathering and other 459 885 (426 ) Restructuring 2,406 1,071 1,335



General and administrative:

General and administrative 104,608 17,025 87,583 Share-based compensation 6,741 3,584 3,157



Depletion, depreciation and accretion:

Depletion-Full cost 86,215 20,381 65,834 Depreciation-Other 1,763 964 799 Accretion expense 2,306 1,641 665



Other income (expenses):

Net gain (loss) on derivative contracts (6,126 ) 3,479 (9,605 ) Interest expense and other, net (31,223 ) (17,879 ) (13,344 ) Income tax benefit (provision) 13,181 (6,802 ) 19,983 Production: Crude oil-MBbls 2,415 884 1,531 Natural gas-Mmcf 4,554 2,662 1,892 Natural gas liquids-MBbls 268 176 92 Total MBoe(1) 3,442 1,504 1,938 Average daily production-Boe(1) 9,404 4,121 5,283



Average price per unit(2):

Crude oil price-Bbl $ 92.36$ 93.86$ (1.50 ) Natural gas price-Mcf 2.80 4.11 (1.31 ) Natural gas liquids price-Bbl 41.72 59.69 (17.97 ) Total per Boe(1) 71.75 69.42 2.33 Average cost per Boe: Production: Lease operating 14.49 19.98 (5.49 ) Workover and other 1.29 1.31 (0.02 ) Taxes other than income 5.59 4.80 0.79 Gathering and other 0.13 0.59 (0.46 ) Restructuring 0.70 0.71 (0.01 ) General and administrative: General and administrative 30.39 11.32 19.07 Share-based compensation 1.96 2.38 (0.42 ) Depletion 25.05 13.55 11.50



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(1) Natural gas reserves are converted to oil reserves using a 1:6 equivalent ratio. 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. 67



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For the year ended December 31, 2012, oil, natural gas and natural gas liquids revenues increased $142.6 million from the same period in 2011. The increase was primarily due to an increase in production volumes resulting from the Merger, the East Texas Assets acquisition and the Williston Basin Assets acquisition which collectively accounted for an increase of 1,942 MBoe in production and $145.3 million of incremental revenues. Realized average prices per Boe increased $2.33 per Boe to $71.75 per Boe.

Lease operating expenses increased $19.8 million for the year ended December 31, 2012, primarily due to $16.3 million of costs incurred on our newly acquired assets. The remaining increases are due to surface repair and maintenance costs. Lease operating expenses were $14.49 per Boe in 2012 compared to $19.98 per Boe in 2011. The decrease per Boe is primarily due to a lower rate per Boe on the newly acquired properties.

Workover and other expenses increased $2.5 million for the year ended December 31, 2012 compared to the same period in 2011 primarily due to $2.7 million of expenses incurred on our newly acquired assets.

Taxes other than income increased $12.0 million for the year ended December 31, 2012 as compared to the same period in 2011 primarily due to $9.6 million of production taxes incurred on our newly 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 $5.59 per Boe and $4.80 per Boe, for the years ended 2012 and 2011, respectively. The increase on a per Boe basis in 2012 is driven by increased production and revenue in our Bakken / Three Forks area which has higher production tax rates than our other areas.

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 have incurred $2.4 million in Restructuring costs for the year ended December 31, 2012. In October 2011, we announced a company-wide reorganization of our operating and administrative functions. As part of the reorganization, we recognized restructuring expense of $1.1 million, including $0.7 million of one-time severance benefits, $0.2 million of retention payments, and $0.2 million of share-based compensation related to the acceleration of employee restricted stock awards and payment of share appreciation rights. The reorganization was completed in full during the quarter ended December 31, 2011.

General and administrative expense for the year ended December 31, 2012 increased $87.6 million to $104.6 million as compared to the same period in 2011. The increase was primarily due to transaction costs of $41.0 million in the aggregate for the Merger, the East Texas Assets acquisition and the Williston Basin Assets acquisition. We incurred $8.9 million in connection with the Recapitalization, which included $5.4 million for change in control payments and $2.5 million for engagement termination fees. The remaining increase in general and administrative expenses is attributable to increases in payroll and related employee benefit costs of $18.3 million, office related expenses of $5.2 million and professional fees of $9.7 million, in support of the expanding business base and increased corporate activities subsequent to the Recapitalization. On a per unit basis, general and administrative expense was $30.39 per Boe and $11.32 per Boe, for the years ended 2012 and 2011, respectively.

Share-based compensation expense for the year ended December 31, 2012 was $6.7 million, an increase of $3.2 million compared to the same period in 2011. The increase is primarily due to the accelerated vesting of restricted stock awards and stock appreciation rights resulting from the change in control that occurred due to our Recapitalization, which totaled $4.3 million.

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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 for the evaluated properties. Depletion expense increased $65.8 million to $86.2 million for the year ended December 31, 2012 compared to the same period in 2011 of $20.4 million, primarily due to a higher depletion rate per Boe and increased production. On a per unit basis, depletion expense was $25.05 per Boe for the year ended December 31, 2012 compared to $13.55 per Boe for the year ended December 31, 2011. The increase in depletion and the depletion rate per Boe and production is primarily due to the Merger and acquisitions of the East Texas Assets and the Williston Basin Assets.

Accretion expense is a function of changes in the discounted asset retirement obligation liability from period to period. We recorded $2.3 million for the year ended December 31, 2012, compared to $1.6 million for the year ended December 31, 2011.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. We have also, in the past, entered into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations. At December 31, 2012, we had a $7.8 million derivative asset, $7.4 million of which was classified as current, and we had a $12.9 million derivative liability of which $10.4 million was classified as current. We recorded a net derivative loss of $6.1 million ($13.2 million net unrealized loss and $7.1 million net realized gain on settled contracts and premium costs) for the year ended December 31, 2012 compared to a net derivative gain of $3.5 million ($4.8 million net unrealized gain and $1.3 million net realized loss on settled contracts and premium costs) in the prior year.

Interest expense increased $13.3 million for the year ended December 31, 2012. This increase was primarily due to the issuance of new long-term debt partially offset by capitalized interest expense on unevaluated properties. We incurred interest expense before capitalization of $85.4 million in 2012 compared to $17.4 million in the prior year. Due to significant costs incurred during 2012 on unevaluated properties we began capitalizing interest during 2012, resulting in $53.5 million capitalized for the year ended December 31, 2012. No amounts were capitalized in 2011.

We recorded an income tax benefit of $13.2 million on a loss before income taxes of $67.1 million for the year ended December 31, 2012. The benefit reflects nondeductible interest expense on the convertible notes issued as part of the Recapitalization of $3.2 million and nondeductible merger related costs of $3.6 million. For the year ended December 31, 2011, we recorded an income tax provision of $6.8 million on income before income taxes of $5.4 million. The income tax provision for 2011 included a $6.0 million decrease to deferred tax assets, including a Section 382 adjustment related to net operating loss limitations and a decrease in the valuation allowance of $1.9 million.

Recently Issued Accounting Pronouncements

We discuss recently adopted and issued accounting standards in Item 8. Consolidated Financial Statements and Supplementary Data-Note 1, "Summary of Significant Events and Accounting Policies."


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Source: Edgar Glimpses


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