Financial and Operating Results for the Twelve Months Ended December 31, 2014
Oil and gas production increased 43.9% for the twelve months ended December 31, 2014 to 6,161 MBoe or an average of 16,879 Boe/d (58.9% natural gas), compared with 4,281 MBoe or an average of 11,728 Boe/d for the twelve months ended December 31, 2013. The increase in production was attributable primarily to the Company's expanded drilling program in its core areas of operations in the Marcellus Shale and Utica Shale.
Magnum Hunter reported an increase in oil and gas revenues of 21.7% to $268.5 million for the twelve months ended December 31, 2014, compared with $220.7 million for the twelve months ended December 31, 2013. The increase in oil and gas revenues resulted principally from increases in the Company's oil and natural gas production as a result of its expanded drilling operations in its unconventional resources plays in the Marcellus Shale and Utica Shale throughout 2014.
The Company reported a net loss of ($249.9) million attributable to common shareholders, or ($1.32) per basic and diluted common shares outstanding, for the twelve months ended December 31, 2014, compared with a net loss of ($278.9) million, or ($1.64) per basic and diluted common shares outstanding, for the twelve months ended December 31, 2013. When adjusted for non-cash expenses and non-recurring gains on asset sales, the Company's adjusted net loss attributable to common shareholders for the twelve months ended December 31, 2014 was ($0.65) per basic and diluted common shares outstanding (see Non-GAAP Financial Measures and Reconciliations below).
For the twelve months ended December 31, 2014, Magnum Hunter's Adjusted Earnings Before Interest, Income Taxes, Depreciation, Amortization and Exploration ("Adjusted EBITDAX") was $150.5 million, compared with $120.4 million for the twelve months ended December 31, 2013 (See Non-GAAP Financial Measures and Reconciliations below). The 25.0% increase in Adjusted EBITDAX was primarily due to (i) an overall production increase as a result of our expanded drilling operations in the Marcellus Shale and Utica Shale and (ii) higher average realized natural gas prices during the period. Natural gas production shut-ins, increased transportation and processing costs and higher non-recurring cash general and administrative costs (see Non-GAAP Financial Measures and Reconciliations below) per Boe, partially offset the increase. Production costs per Boe decreased in fiscal year 2014, compared with fiscal year 2013, due primarily to (i) lower recurring costs in the Appalachian Basin and Williston Basin, (ii) lower non-recurring workover expenses primarily in the Williston Basin and (iii) the sale of certain assets in the Williston Basin that historically carried a higher lifting cost. General and administrative expenses increased overall during the twelve months ended December 31, 2014 due primarily to a one-time, non-cash charge of $32.6 million resulting from a reallocation of midstream capital expenditures between the Company and its principal co-owner in Eureka Hunter Holdings. Excluding this one-time charge, general and administrative expenses decreased $6.4 million, or 7.8%, to $76.1 million for fiscal year 2014 compared with fiscal year 2013. The decrease resulted primarily from (i) lower share-based compensation and 401K plan matching expense and (ii) lower professional services fees related to accounting and auditing services. The Company anticipates that its reliance on third-party consultants will continue to substantially decrease, which, combined with reductions in corporate offices and headcount, will further reduce its recurring general and administrative expenses per Boe in fiscal year 2015.
Financial and Operating Results for the Three Months Ended December 31, 2014
Oil and gas production increased 34% for the three months ended December 31, 2014 to 1.6 million Boe or an average of 17,178 Boe per day (63% natural gas), compared with production of 1.2 million Boe or an average of 12,786 Boe per day for the three months ended December 31, 2013. The increase in production was attributable primarily to the Company's expanded drilling program in its core areas of operations. In addition, the Company's natural gas production mix increased to 63% of overall production in the fourth quarter of 2014, compared with 46% in the fourth quarter of 2013. These increases in production and natural gas mix are a result of last year's focus on capital expenditures to further develop the Company's Marcellus Shale and Utica Shale properties.
Magnum Hunter reported a decrease in oil and gas revenues of 27.7% to $46.3 million for the three months ended December 31, 2014, compared with $63.9 million for the three months ended December 31, 2013. Revenues decreased during the quarter ended December 31, 2014 due to (i) decreases in oil prices, (ii) decreased volumes due to the divestitures of certain non-core oil and gas properties located in Divide County, North Dakota during the fourth quarter and (iii) shut-ins of certain Marcellus Shale and Utica Shale wells due to pad drilling, all of which wells are now producing.
The Company reported net income of $42.8 million attributable to common shareholders, or $0.21 per basic and diluted common shares outstanding, for the three months ended December 31, 2014, compared with a net loss of ($61.2) million, or ($0.36) per basic and diluted common shares outstanding, for the three months ended December 31, 2013. When adjusted for a combination of non-cash expenses and non-recurring gains on asset sales, the Company's adjusted net loss attributable to common shareholders for the three months ended December 31, 2014 was ($0.24) per basic and diluted common shares outstanding (see Non-GAAP Financial Measures and Reconciliations below).
For the three months ended December 31, 2014, Magnum Hunter's Adjusted EBITDAX was $25.9 million, compared with $35.8 million for the three months ended December 31, 2013 (See Non-GAAP Financial Measures and Reconciliations below), a decrease of 27.6%. The decrease in Adjusted EBITDAX was due primarily to the decrease in revenues during the quarter ended December 31, 2014 referred to above. Recurring general and administrative expenses per Boe for the three months ended December 31, 2014 decreased 49% to $3.72 per Boe from $7.24 per Boe for the three months ended December 31, 2013, due primarily to (i) production increases during the period and (ii) less reliance on third-party consultants (See Non-GAAP Financial Measures and Reconciliations below). The Company anticipates that its reliance on third-party consultants will continue to substantially decrease, which, combined with reductions in corporate offices and headcount, will further reduce its recurring general and administrative expenses per Boe in fiscal year 2015.
In the fourth quarter of 2014, the Company's production was impacted by production shut-ins in the Appalachian region due primarily to the previously reported wells that were shut-in due to multi-well pad development.
Magnum Hunter Resources Reports Fourth Quarter and Full Year 2014 Financial and Operating Results
New Record Daily Production of ~205.8 MMcfe/d (34,299 Boe/d); New Record Throughput on Eureka Hunter Pipeline of ~463,400 MMBtu/d New Record Daily Production of ~205.8 MMcfe/d (34,299 Boe/d); New Record Throughput on Eureka Hunter Pipeline of ~463,400 MMBtu/d
use the ignore feature yahoo provides .it works wonders .I see one other poster besides you .
In a report published Friday, Wunderlich Securities analyst Jason A. Wangler reiterated a Buy rating and $3.00 price target on Halcon Resources Corp. (NYSE: HK).
In the report, Wunderlich Securities noted, "Halcon Resources (HK) reported a solid 4Q14 as EPS of $0.05 were nicely ahead of our -$0.05 figure and the Street's $0.00 forecast due to a production beat and cost controls. Halcon had pre-announced much of its information already, so the CapEx plans, reserves, and its liquidity position were known, but the company was able to provide additional color around these numbers as well as commentary on its focus going forward. As expected, there was a significant focus on the financial position of Halcon as it goes through the current downturn, and we continue to believe that Halcon has the ability to see this through to the other side. As such, we reiterate our Buy rating and $3 price target as we feel the company has an asset base and management team that can survive today and excel tomorrow."
Halcon Resources closed on Thursday at $1.97.
headline news section this a.m.
Form 10-K for HALCON RESOURCES CORP
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding our results of operations and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K contain additional information that should be referred to when reviewing this material.
Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.
We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. We were incorporated in Delaware on February 5, 2004 and were recapitalized on February 8, 2012. 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 and 2014, 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, 2014, 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 189.1 MMBoe, consisting of 155.6 MMBbls of oil, 16.3 MMBbls of natural gas liquids, and 103.7 Bcf of natural gas. Approximately 41% and 40% of our proved reserves were classified as proved developed as of December 31, 2014 and 2013, respectively. We maintain operational control of approximately 93% of our proved reserves. Production for the fourth quarter of 2014 averaged 46,076 Boe/d. Full year 2014 production averaged 42,107 Boe/d compared to 33,329 Boe/d in 2013. Our total operating revenues for 2014 were approximately $1.1 billion compared to $999.5 million in 2013.
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 and the Eagle Ford formation in East Texas, as well as several other areas.
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Our average daily production increased 26% year over year. The increase in production compared to the prior year period was driven by our operated drilling results and increased production volumes associated with the development of properties we have acquired in the Bakken / Three Forks and the Eagle Ford formation in East Texas (which we refer to as "El Halc�n"). These areas collectively accounted for approximately 37,500 Boe/d in 2014, or 89% of our production. In 2014, we participated in the drilling of 320 gross (98.3 net) wells all of which were completed and capable of production.
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, 2014 we incurred capital expenditures for drilling and completions of approximately $1.2 billion. We expect to spend approximately $350 million to $400 million on drilling and completion capital expenditures during 2015. In addition, we expect to spend approximately $20 million on leasehold, infrastructure, seismic and other in 2015. The significant decrease in planned capital spending for 2015, as compared to actual 2014 drilling and completion capital expenditures, is in response to the significant decrease in crude oil prices over the latter half of 2014 and our expectations that prices may not recover in the near term. Approximately 60 - 65% of our 2015 drilling and completions budget is expected to be spent in the Bakken / Three Forks formations in North Dakota, approximately 30 - 35% is budgeted for the El Halc�n area in East Texas, and the remaining amount is planned for various other project areas. Our 2015 drilling and completion budget contemplates two operated rigs running in the Bakken / Three Forks and one operated rig running in the El Halc�n area. Our drilling and completion budget for 2015 is based on our current view of market conditions and current business plans, and is subject to change.
We expect to fund our budgeted 2015 capital expenditures with cash flows from operations, proceeds from potential capital market transactions, 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 are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may further curtail our capital spending.
Oil and natural gas prices are inherently volatile and, as mentioned above, decreased significantly over the latter half of 2014. Sustained lower commodity prices will likely have a material impact upon our full cost ceiling test calculation. The ceiling calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. For the year ended December 31, 2014, those prices were $94.99 per Bbl for oil and $4.350 per MMBtu for natural gas, while first day of the month oil and natural gas prices for January and February 2015 were $53.27 per Bbl and $48.24 per Bbl for oil and $3.00 per MMBtu and $2.68 per MMBtu for natural gas, respectively. If commodity prices remain at decreased levels, the average prices used in the ceiling calculation will decline and will likely cause write downs of our oil and natural gas properties. Continued write downs of oil and natural gas properties may occur until such time as commodity prices have recovered, and remained at recovered levels, so as to meaningfully increase the 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.
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Amendments to the Senior Credit Agreement and Borrowing Base Confirmation
On February 25, 2015, we entered into the Ninth Amendment to our Senior Credit Agreement (the Ninth Amendment). The Ninth Amendment provides additional flexibility under the interest coverage test by modifying the minimum Interest Coverage Ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before March 31, 2016. On February 25, 2015, the borrowing base under the Senior Credit Agreement was confirmed at $1.05 billion.
On September 30, 2014, we entered into the Eighth Amendment to our Senior Credit Agreement (the Eighth Amendment). The Eighth Amendment increased the borrowing base under our Senior Credit Agreement to $1.05 billion. On March 21, 2014, we entered into the Seventh Amendment to our Senior Credit Agreement (the Seventh Amendment). The Seventh Amendment provided us additional flexibility under the interest coverage test by modifying the minimum Interest Coverage Ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before December 31, 2014.
HK TMS, LLC Preferred Stock Issuance
On June 16, 2014, we entered into a transaction with funds and accounts managed by affiliates of Apollo Global Management, LLC (Apollo) pursuant to which HK TMS, LLC (HK TMS), our subsidiary which holds our acreage in Mississippi and Louisiana that we believe is prospective for the Tuscaloosa Marine Shale (TMS), initially sold 150,000 preferred shares in exchange for $150 million and the right to overriding royalty interests in future wells. HK TMS does not participate in our Senior Credit Agreement and is not a guarantor of any of our senior notes.
Divestiture of East Texas Assets
On May 9, 2014, we completed the divestiture of certain non-core assets in East Texas (the East Texas Assets) to a privately-owned company for a total purchase price of $424.5 million after closing adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. As of December 31, 2013, estimated proved reserves associated with the East Texas Assets, were approximately 16.3 MMBoe. Production from the East Texas Assets averaged approximately 3,700 Boe/d during the first quarter of 2014. The effective date of the transaction was April 1, 2014. Proceeds from the sale were recorded as a reduction to the carrying value our full cost pool with no gain or loss recorded.
Capital Resources and Liquidity
Our near-term capital spending requirements are expected to be funded with cash flows from operations, proceeds from potential capital market transactions and borrowings under our Senior Credit Agreement, which has a current borrowing base of $1.05 billion. 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 i) not less than 2.0 to 1.0 through March 31, 2016 (pursuant to the Ninth Amendment), and ii) not less than 2.5 to 1.0 for subsequent periods. We are subject to additional
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covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. Additionally, the indentures governing our senior unsecured debt contain covenants limiting our ability to incur additional indebtedness, including borrowings under our Senior Credit Agreement, unless we meet one of two alternative tests. The first test, the fixed charge coverage ratio test, applies to all indebtedness and requires that after giving effect to the incurrence of additional debt the ratio of our adjusted consolidated EBITDA (as defined in our indentures) to our adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0. The second test allows us to incur additional indebtedness, beyond the limitations of the fixed charge coverage ratio test, as long as this additional debt is incurred under Credit Facilities (as defined in our indentures) and the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of our adjusted consolidated net tangible assets (as defined in 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, 2014, we had $557.0 million of indebtedness outstanding, $1.1 million of letters of credit outstanding and $491.9 million of borrowing capacity available under our Senior Credit Agreement.
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 have also impacted 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.
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 various non-core producing properties and invest in the acquisition and drilling of undeveloped acreage would have caused us to fall below the interest coverage ratio. We requested reductions in the minimum required interest coverage ratio of 2.0 to 1.0 for 2014 and 2015 and those requests were granted on March 21, 2014 and again on February 25, 2015, respectively. The basis for the amendment 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 and in recognition of lower oil prices, we have scaled back our capital expenditures budget, focused our drilling program on our highest return projects, entered into a transaction with funds and accounts managed by the affiliates of Apollo Global Management, LLC, to finance the development of our TMS assets, and we continue to explore opportunities to divest non-core properties.
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If, in the future, the lenders under our Senior Credit Agreement are 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 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.
We are exposed to various risks including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly, as they have in the latter half of 2014, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include costless collars, swaps, and deferred put options. The total volumes which we hedge through the use of our derivative instruments varies from period to period, however, generally our objective is to hedge approximately 70% to 80% of our current and anticipated production for the next 18 to 24 months. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.
Our primary sources of cash in 2014 were from operating and financing activities. In 2013 and 2012, our primary source of cash was from financing activities. In 2014, cash provided by operations
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was driven by increased revenues and cash provided by financing activities was attributable to net borrowings on our Senior Credit Agreement and the sale of HK TMS preferred stock to Apollo.
Operating cash flow fluctuations were substantially driven by changes in commodity prices and changes in our production volumes. Working capital was substantially influenced by these variables. Fluctuation in commodity prices and our overall cash flow may result in an increase or decrease in our future capital expenditures. Prices for oil and natural gas have historically been subject to seasonal fluctuations characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have 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,
2014 2013 2012
Cash flows provided by (used in) operating
activities $ 667,934 $ 493,924 $ 84,360
Cash flows provided by (used in) investing
activities (1,271,093 ) (2,100,699 ) (2,832,466 )
Cash flows provided by (used in) financing
activities 644,038 1,607,103 2,750,563
Net increase (decrease) in cash $ 40,879 $ 328 $ 2,457
Operating Activities. Net cash flows provided by operating activities were $667.9 million, $493.9 million and $84.4 million for the years ended December 31, 2014, 2013 and 2012, respectively. Key drivers of net operating cash flows are commodity prices, production volumes, operating costs and realized settlements on our derivative contracts.
For the year ended December 31, 2014, net cash provided by operating activities increased $174.0 million over the prior year. The improvement in operating cash flows primarily reflects the impact of the 26% increase in our average daily production compared to the 2013 period, which drove the increase in operating revenues. Production for 2014 averaged 42,107 Boe/d compared to 33,329 Boe/d in 2013.
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.
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 $1.3 billion, $2.1 billion and $2.8 billion for the years ended December 31, 2014, 2013 and 2012, respectively.
In 2014, we incurred cash expenditures of $1.5 billion on oil and natural gas capital expenditures, of which $1.2 billion related to drilling and completion costs and the remainder was primarily
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associated with leasing, acquisitions and seismic data. We participated in the drilling of 320 gross (98.3 net) wells, all of which were completed and capable of production. These expenditures were offset by $484.2 million in proceeds received from the divestitures of various non-core assets, including the East Texas Assets. As part of HK TMS's transaction with Apollo, discussed in further detail below, as well as in Item 8. Consolidated Financial Statements and Supplementary Data-Note 11, "Mezzanine Equity," we received proceeds of approximately $33.8 million from the conveyance of an overriding royalty interest to Apollo.
On December 20, 2013, we entered into a carry and earning agreement, as amended (the Agreement) with an independent third party (the Seller) associated with the acquisition of certain properties believed to be prospective for the TMS, primarily in Wilkinson County, Mississippi and in West Feliciana and East Feliciana Parishes, Louisiana. The agreement required us to fund up to $189.4 million (the Carry Amount) in exchange for approximately 117,870 net acres. We paid $62.5 million of the Carry Amount at closing on February 28, 2014 and the remaining $126.9 million during the three months ended June 30, 2014, reflected as "Advance on carried interest" in the accompanying consolidated statements of cash flows. The Carry Amount is to be used by the Seller to fund wells prospective for the TMS to be drilled by the Seller (the Carry Wells) on the Seller's retained acreage. As part of the transaction, we will also receive a 5% working interest in the Carry Wells. As of December 31, 2014, approximately $71.9 million of the Carry Amount remained in escrow to be spent by the Seller. Any portion of the Carry Amount not spent by the Seller, in accordance with the Agreement, on or before August 31, 2017, will be returned to us.
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 . . .
and spring will be sprung .Placed my order for some seeds to start inside in a week or so .won't be long and I will be starting to till the garden for planting them sprouts .
Select spot prices for delivery today
New England 29.25 +46.3 169.38 -19.5 0.00
Mid-Atlantic 13.08 -28.9 86.73 -25.2 0.00
Midwest 4.64 -4.0 28.96 -35.6 0.00
Southwest 2.83 -7.5 28.08 -0.1 8.26
Northwest 2.50 -7.6 24.25 -4.9 6.77
*Percent changes based on daily settlement price from previous business day.
Source: Daily Prices
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2/19/2015 Natural gas spot and futures prices
1/30/2015 Natural gas prices
1/30/2015 Natural gas gross withdrawals and production
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from what I can see he loves it ."I would ignore the people who just want to fight and spend your time and energy keeping us all in the loop." that he will not do for the same reason he enjoys the attention .
HOUSTON, TX--(Marketwired - Feb 24, 2015) - Magnum Hunter Resources Corporation (NYSE: MHR) (NYSE MKT: MHR.PRC) (NYSE MKT: MHR.PRD) (NYSE MKT: MHR.PRE) (the "Company" or "Magnum Hunter") announced today that its Chairman and CEO, Gary C. Evans, will be presenting at the Credit Suisse 20th Annual Energy Summit on February 24, 2015, at 1:05 p.m. CT in Vail, Colorado.