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GPOR > SEC Filings for GPOR > Form 10-Q on 9-May-2014All Recent SEC Filings

Show all filings for GULFPORT ENERGY CORP

Form 10-Q for GULFPORT ENERGY CORP


9-May-2014

Quarterly Report


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the "Management's Discussion and Analysis of Financial Condition and Results of Operations" section and audited consolidated financial statements and related notes included in our Annual Report on Form 10-K and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report on Form 10-Q.
Disclosure Regarding Forward-Looking Statements

This report includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical facts included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and natural gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, general economic, market or business conditions; the opportunities (or lack thereof) that may be presented to and pursued by us; competitive actions by other oil and natural gas companies; changes in laws or regulations; adverse weather conditions and natural disasters such as hurricanes and other factors, including those listed in the "Risk Factors" section of our most recent Annual Report on Form 10-K, many of which are beyond our control. Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements, and we cannot assure you that the actual results or developments anticipated by us will be realized or, even if realized, that they will have the expected consequences to or effects on us, our business or operations. We have no intention, and disclaim any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise.

Overview
We are an independent oil and natural gas exploration and production company focused on the exploration, exploitation, acquisition and production of crude oil, natural gas liquids and natural gas in the United States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects. Our principal properties are located in the Utica Shale in Eastern Ohio and along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields. In addition, we have producing properties in the Niobrara Formation of Northwestern Colorado and the Bakken Formation. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, an equity interest in Diamondback Energy, Inc., or Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and natural gas interests in October 2012 immediately prior to Diamondback's initial public offering, or the Diamondback IPO, and interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. First Quarter 2014 Operational Highlights
Oil and natural gas revenues increased 115% to $117.9 million for the three months ended March 31, 2014 from $54.9 million for the three months ended March 31, 2013.

Production increased 324% to approximately 2,437,851 barrels of oil equivalent ("BOE") for the three months ended March 31, 2014 from approximately 575,543 BOE for the three months ended March 31, 2013.

During the three months ended March 31, 2014, we drilled 20 gross (16 net) wells, participated in an additional 26 gross (2.7 net) wells that were drilled by other operators on our Utica Shale acreage and recompleted 38 gross and net wells. Of our 20 new wells drilled, at March 31, 2014, four were completed as producing wells, one was non-productive, nine were waiting on completion and six were being drilled.


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In March, 2014, we acquired approximately 8,200 net acres in the Utica Shale of Eastern Ohio from Rhino Exploration LLC, or Rhino, as well as its interest in producing wells, for a total purchase price of $184.0 million, subject to closing adjustments. We are the operator of substantially all of this acreage.

2014 Production and Drilling Activity
During the three months ended March 31, 2014, our total net production was 726,720 barrels of oil, 7,661,819 thousand cubic feet, or Mcf, of natural gas, and 18,234,754 gallons of natural gas liquids, or NGLs, for a total of 2,437,851 BOE as compared to 516,954 barrels of oil, 319,658 Mcf of natural gas and 223,126 gallons of NGLs, or 575,543 BOE, for the three months ended March 31, 2013. Our total net production averaged approximately 27,087 BOE per day during the three months ended March 31, 2014 as compared to 6,395 BOE per day during the same period in 2013. The 324% increase in production is largely the result of the development of our Utica Shale acreage.
Utica Shale (Eastern Ohio). As of May 1, 2014,we had acquired leasehold interests in approximately 180,000 gross (179,000 net) acres in the Utica Shale in Eastern Ohio, including the approximately 8,200 net acres acquired from Rhino during the first quarter of 2014. We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of March 31, 2014, had spud 75 wells, 50 of which had been completed and, as of May 1, 2014 were producing. From January 1, 2014 through May 1, 2014, we spud 14 gross (ten net) wells, of which ten were waiting on completion and four were still being drilled at May 1, 2014. In addition, 26 gross (2.7 net) wells were drilled by other operators on our Utica Shale acreage during the first quarter of 2014.
We have seven rigs under contract on our Utica Shale acreage. We currently intend to drill 85 to 95 gross (68 to 76 net) wells on our Utica Shale acreage in 2014.
Aggregate net production from our Utica Shale acreage during the three months ended March 31, 2014 was approximately 1,895,608 net BOE, or 21,062 BOE per day, 66% of which was from natural gas and 34% of which was from oil and natural gas liquids, or NGLs. During April 2014, our average daily net production from the Utica Shale was approximately 18,981 BOE, 27% of which was from oil and NGLs and 73% of which was from natural gas. April production was negatively impacted due to 14 wells being taken offline for ongoing completion activities in the Utica Shale.
WCBB. From January 1, 2014 through May 1, 2014, we recompleted 34 wells and drilled nine wells. Of the nine new wells drilled at WCBB, seven were completed as producing wells, one was non-productive and one was being drilled at May 1, 2014. During 2014, we currently anticipate drilling 22 to 24 wells at our WCBB field.
Aggregate net production from the WCBB field during the three months ended March 31, 2014 was approximately 302,463 BOE, or an average of 3,361 BOE per day, 100% of which was from oil. During April 2014, our average net daily production at WCBB was approximately 3,412 BOE, 100% of which was from oil. The increase in April production is primarily the result of our 2014 drilling program. East Hackberry Field. From January 1, 2014 through May 1, 2014, we recompleted 20 wells and drilled five wells. Of the five new wells drilled at East Hackberry, four were completed as producing wells and one was being drilled at May 1, 2014. During 2014, we currently anticipate drilling ten to twelve wells. Aggregate net production from the East Hackberry field during the three months ended March 31, 2014 was approximately 189,047 BOE, or an average of 2,101 BOE per day, 92% of which was from oil and 8% of which was from natural gas. During April 2014, our average net daily production at East Hackberry was approximately 2,183 BOE, 90% of which was from oil and 10% of which was from natural gas. The increase in April production is primarily the result of our 2014 drilling program.
West Hackberry Field. From January 1, 2014 through May 1, 2014, we recompleted two wells. No new wells were drilled at West Hackberry from January 1, 2014 to May 1, 2014.
Aggregate net production from the West Hackberry field was approximately 28,297 BOE, or an average of 314 BOE per day, 99% of which was from oil and 1% of which was from natural gas. During April 2014, our average net daily production at West Hackberry was approximately 35 BOE, 100% of which was from oil. Niobrara Formation. Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado and, as of March 31, 2014, we held leases for approximately 7,071 net acres. From January 1, 2014 through May 1, 2014, there were no wells spud on our Niobrara Formation acreage. Aggregate net production from our


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Niobrara Formation acreage during the three months ended March 31, 2014 was approximately 10,124 BOE, or an average of 112 BOE per day, 100% of which was from oil. During April 2014, our average net daily production from our Niobrara Formation acreage was approximately 55 BOE, 100% of which was from oil. During 2014, we currently do not anticipate drilling any wells in the Niobrara Formation.
Bakken. As of March 31, 2014, we held approximately 864 net acres in the Bakken Formation of Western North Dakota and Eastern Montana with interests in 16 wells and overriding royalty interests in certain existing and future wells. Aggregate net production from this acreage during the three months ended March 31, 2014 was approximately 12,152 BOE, or an average of 135 BOE per day, of which 92% was from oil 6% was from natural gas and 2% was from NGLs. During April 2014, our average daily net production from our Bakken Formation acreage was approximately 104 BOE, of which 90% was from oil and 10% was from natural gas. 2014 Updates Regarding Our Equity Investments Permian Basin. On October 11, 2012, we contributed to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and natural gas interests in the Permian Basin. At the closing of this contribution, Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was repaid to us at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and certain other items of a Diamondback subsidiary as of the date of this contribution. In January 2013, we received an additional payment from Diamondback of $18.6 million as a result of this post-closing adjustment. In June and November of 2013, we sold 2,234,536 and 2,300,000 shares of our Diamondback common stock, respectively and received aggregate net proceeds of approximately $192.7 million. As of March 31, 2014, we owned approximately 3,379,500 shares representing 6.7% of Diamondback's outstanding common stock. Our investment in Diamondback is accounted for as an equity method investment. Grizzly Oil Sands. We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc. As of March 31, 2014, Grizzly had approximately 830,000 net acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada and had three oil sands projects in various stages of development and had drilled an aggregate of 255 core holes and six water supply test wells on ten separate lease blocks and conducted a number of seismic programs. At Grizzly's first 11,300 barrel per day steam-assisted gravity drainage, or SAGD, oil sand project at Algar Lake, reservoir steam injection commenced in January 2014 and first bitumen production was achieved during the first quarter of 2014 and averaged approximately 275 barrels of bitumen per day in April 2014. In the first quarter of 2012, Grizzly acquired the May River property comprising approximately 47,000 acres. An initial 12,000 barrel per day development application was filed with the regulatory authorities in the fourth quarter of 2013, covering the eastern portion of the May River lease. A 29 well delineation drilling program was completed in the first quarter of 2013 over the development application area and a 2D seismic program covering approximately 80 kilometers is currently underway to more fully define the development area. At the Thickwood thermal project, Grizzly's activities included the completion of a 22 well core hole drilling program and the acquisition of 31 kilometers of seismic data. A development application for a 12,000 barrel per day oil sands project at Thickwood was filed in the fourth quarter of 2012. Grizzly has also entered into a memorandum of understanding that outlines the rate structure for a ten year agreement with Canadian National Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via CN's rail network. Grizzly expects that this arrangement will provide consistent access to Brent-based pricing from Grizzly's Algar Lake project. Grizzly is developing the Windell Terminal, a rail loadout facility in Conklin, Alberta, and the Paulina Terminal, a rail to barge off-load facility on the lower Mississippi River. Construction of the 15,000 barrel per day Windell Terminal, proximate to its May River lease, was completed and the facility commenced operating during the first quarter of 2014, at which time the first load of bitumen from Algar Lake was hauled by truck to the Windell terminal for sales.
. In the U.S. Gulf Coast, Grizzly has begun engineering design work of the 40,000 barrel per day Paulina Terminal project located on the lower Mississippi River and has filed development permits. Thailand. We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex
II. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. Our investment is accounted for on the equity method. Tatex II accounts for its investment in APICO using the cost method. Hess Corporation, or Hess, operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTT Exploration and Production Public Company Limited (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex II as a member of APICO) in the Phu Horm field is 0.7%. Since our ownership in the Phu


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Horm field is indirect and Tatex II's investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information.
We own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Tatex III owns a concession covering approximately 245,000 acres in Southeast Asia. In 2009, Tatex III completed a 3-D seismic survey on this concession. In October 2013, Tatex III spud the TEW-K well, located to the south of the TEW-E well. The well tested gas at non-commercial rates. During drilling, the well flowed gas with rates as high as 20 MMcf per day of gas; however, no acceptable sustainable rate was established.
Other Investments. In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In the first quarter of 2013, we participated in the formation of Stingray Energy Services LLC, or Stingray Energy, with an initial ownership interest of 50%. Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites. In 2012, we participated in the formation of Stingray Pressure Pumping LLC, or Stingray Pressure, Stingray Cementing LLC, or Stingray Cementing, and Stingray Logistics LLC, or Stingray Logistics, with an initial ownership interest in each entity of 50%. These entities provide well completion and other well services. In 2012, we also participated in the formation of Blackhawk Midstream LLC, or Blackhawk, and Timber Wolf Terminals LLC, or Timber Wolf, with an initial ownership interest of 50% in each entity. Blackhawk coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage and Timber Wolf will operate a crude/condensate terminal and a sand transloading facility in Ohio. Also in 2012, we acquired a 22.5% equity interest in Windsor Midstream LLC which owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011 and 2012, we acquired an aggregate 40% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates drilling rigs and related equipment. Also in 2011, we acquired a 25% interest in Muskie Proppant LLC, or Muskie, which is engaged in the processing and sale of hydraulic fracturing grade sand. See Note 3 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments.

Critical Accounting Policies and Estimates Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates including those related to oil and natural gas properties, revenue recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements:
Oil and Natural Gas Properties. We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the prior twelve months, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet,
(b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds and totaled $1.1 billion at March 31, 2014 and $950.6 million at December 31, 2013. These costs are reviewed quarterly by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and available funds for exploration and development.


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Ceiling Test. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the prior twelve months of the applicable year beginning with 2009, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. For instance, as a result of the drop in commodity prices on December 31, 2008 and subsequent reduction in our proved reserves, we recognized a ceiling test impairment of $272.7 million for the year ended December 31, 2008. If prices of oil, natural gas and natural gas liquids decline, we may be required to further write down the value of our oil and gas properties, which could negatively affect our results of operations. No ceiling test impairment was required for the quarter ended March 31, 2014.

Asset Retirement Obligations. We have obligations to remove equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities.
We account for abandonment and restoration liabilities under FASB ASC 410 which requires us to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.
The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging and abandonment or retirement, annual inflations of these costs, the productive life of the asset and our risk adjusted cost to settle such obligations discounted using our credit adjustment risk free interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates.
Oil and Gas Reserve Quantities. Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell & Associates, Inc., Ryder Scott Company, L.P. and to a lesser extent our personnel have prepared reserve reports of our reserve estimates at December 31, 2013 on a well-by-well basis for our properties. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been prepared in accordance with the guidelines of the Securities and Exchange Commission, or SEC. The accuracy of our reserve estimates is a function of many factors including the following:
the quality and quantity of available data;

the interpretation of that data;

the accuracy of various mandated economic assumptions; and

the judgments of the individuals preparing the estimates.

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. Therefore, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.


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Income Taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the . . .

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