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GPOR > SEC Filings for GPOR > Form 10-Q on 8-Aug-2013All Recent SEC Filings

Show all filings for GULFPORT ENERGY CORP

Form 10-Q for GULFPORT ENERGY CORP


8-Aug-2013

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 thereto 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; hurricanes and other natural disasters 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 producing properties are located along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in the Utica Shale in Eastern Ohio. 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 13.5% 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.

Second Quarter 2013 Operational Highlights

         Oil and natural gas revenues increased 6% to $70.2 million for the
          three months ended June 30, 2013 from $66.3 million for the three
          months ended June 30, 2012.



         Net income increased 74% to $43.8 million for the three months ended
          June 30, 2013 from $25.1 million for the three months ended June 30,
          2012, primarily due to $51.4 million of income recognized from our
          equity method investment in Diamondback, which includes the sale of
          1,951,781 shares of our Diamondback common stock, during the three
          months ended June 30, 2013, partially offset by income tax expense of
          $25.5 million.



         Production increased 23% to 815,300 barrels of oil equivalent, or BOE,
          for the three months ended June 30, 2013 from 663,626 BOE for the three
          months ended June 30, 2012 due primarily to the increased production
          results


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from our drilling activity on our Utica Shale acreage, partially offset by the October 2012 contribution of our oil and natural gas properties in the Permian Basin to Diamondback in connection with the Diamondback IPO.

         During the three months ended June 30, 2013, we, and in some cases
          other operators, spud 26 gross (20.8 net) wells and recompleted 40
          gross and net wells. Of these 26 gross new wells at June 30, 2013, five
          had been completed as producing wells, five were waiting on completion,
          nine were waiting on a horizontal rig and seven were being drilled.



         As of June 30, 2013, we had acquired leasehold interests in
          approximately 136,000 gross (128,000 net) acres in the Utica Shale. We
          spud our first well on our Utica Shale acreage in February 2012 and as
          of June 30, 2013 had spud 39 additional wells, including 16 gross wells
          in the second quarter of 2013. See "2013 Production and Drilling
          Activity - Utica Shale" below for a summary of the initial results from
          these wells.

2013 Production and Drilling Activity

During the three months ended June 30, 2013, our total net production was 535,182 barrels of oil, 1,414,797 thousand cubic feet, or Mcf, of natural gas, and 1,861,360 gallons of natural gas liquids, or NGLs, for a total of 815,300 BOE as compared to 608,468 barrels of oil, 216,081 Mcf of natural gas and 804,063 gallons of NGLs, or 663,626 BOE, for the three months ended June 30, 2012. Our total net production averaged approximately 8,959 BOE per day during the three months ended June 30, 2013 as compared to 7,293 BOE per day during the same period in 2012. The 23% increase in production is largely the result of the development of our Utica Shale acreage. In addition, during October 2012, we contributed our Permian Basin oil and natural gas properties to Diamondback in connection with the Diamondback IPO. As a result, during the three months ended June 30, 2013 we had no production from these Permian Basin properties compared to 102,643 BOE of production attributable to these assets during the same period in 2012. This decrease was offset by production related to the 2013 drilling and recompletion activities in our fields.

WCBB. From January 1, 2013 through July 31, 2013, we recompleted 51 existing wells on our WCBB acreage. We also spud ten wells, of which seven were completed as producers and three were waiting on completion. We currently intend to recomplete a total of approximately 60 existing wells and drill a total of 22 to 24 wells during 2013.

Aggregate net production from the WCBB field during the three months ended June 30, 2013 was 297,421 BOE, or 3,268 BOE per day, 100% of which was from oil. During July 2013, our average daily net production at WCBB was approximately 4,228 BOE, 100% of which was from oil. The increase in July 2013 production was the result of our 2013 drilling and recompletion program.

East Hackberry Field. From January 1, 2013 through July 31, 2013, we recompleted 35 existing wells in our East Hackberry field. We also spud ten wells, of which eight were completed as producers, one was non-productive and, at July 31, 2013, one was waiting on completion. We currently intend to drill 12 to 14 wells and recomplete 40 wells in our East Hackberry field in 2013.

Aggregate net production from the East Hackberry field during the three months ended June 30, 2013 was approximately 179,902 BOE, or 1,977 BOE per day, 94% of which was from oil and 6% of which was from natural gas. During July 2013, our average daily net production at East Hackberry was approximately 1,725 BOE, 86% of which was from oil and 14% of which was from natural gas. The decrease in July 2013 production was the result of natural production declines and the timing of our 2013 drilling and recompletion activities.

West Hackberry Field. Aggregate net production from the West Hackberry field during the three months ended June 30, 2013 was approximately 3,801 BOE, or 42 BOE per day, 100% of which was from oil. During July 2013, our average daily net production at West Hackberry was approximately 41 BOE, 100% of which was from oil.

Utica Shale (Eastern Ohio). As of June 30, 2013, we had acquired leasehold interests in approximately 136,000 gross (128,000 net) acres in the Utica Shale in Eastern Ohio. We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of July 31, 2013, had spud 45 wells, 21 of which had been completed. As of July 31, 2013, 15 of these wells were producing. We expect four to six additional wells to be producing by the end of the third quarter of 2013 and 25 to 30 additional wells to be producing by the end of the fourth quarter 2013. In addition, 33 gross (1.3 net) wells were drilled by another operator on our Utica Shale acreage during 2012 and the first six months of 2013.


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At August 1, 2013, we had seven horizontal rigs under contract on our Utica Shale acreage. We currently intend to drill 55 to 60 gross (49 to 54 net) wells on our Utica Shale acreage in 2013.

Aggregate net production from our Utica Shale acreage during the three months ended June 30, 2013 was approximately 320,718 BOE, or 3,524 BOE per day, 30% of which was from oil and NGLs and 70% of which was from natural gas. During July 2013, our average daily net production from the Utica Shale was approximately 6,415 BOE, 28% of which was from oil and NGLs and 72% of which was from natural gas. The increased average daily net production was due to production results from our drilling activity on our Utica Shale acreage.

Niobrara Formation. Effective as of April 1, 2010, we acquired our initial leasehold interests in the Niobrara Formation in Northwestern Colorado and held leases for approximately 10,452 acres as of June 30, 2013. From January 1, 2013 through July 31, 2013, no new wells were spud on our Niobrara Formation acreage. Aggregate net production from our Niobrara Formation acreage during the three months ended June 30, 2013 was approximately 4,425 BOE, or 49 BOE per day, 100% of which was from oil. During July 2013, average daily net production from our Niobrara Formation acreage was approximately 60 BOE. There are no new activities currently scheduled for 2013 for our Niobrara Formation acreage.

Bakken. In the Bakken Formation of Western North Dakota and Eastern Montana, we held approximately 864 net acres, interests in ten wells and overriding royalty interests in certain existing and future wells as of June 30, 2013. Aggregate net production from the Bakken Formation during the three months ended June 30, 2013 was approximately 9,148 BOE, or 101 BOE per day, 97% of which was from oil and NGLs and 3% of which was from natural gas. During July 2013, our average daily net production from the Bakken Formation was approximately 79 BOE. There are no new activities currently scheduled for 2013 for our Bakken acreage.

2013 Updates Regarding Our Equity Investments

Permian Basin. We own approximately 13.5% of the outstanding common stock of Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and gas interests in October 2012 immediately prior to the Diamondback IPO. See Notes 3 and 4 to our consolidated financial statements included elsewhere in this report for additional information regarding our investment in Diamondback.

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., an entity owned by certain investment funds managed by Wexford Capital L.P., or Wexford. As of June 30, 2013, Grizzly had approximately 800,000 acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada. Our total net investment in Grizzly was approximately $176.9 million as of June 30, 2013. As of that date, Grizzly had drilled an aggregate of 263 core holes and six water supply test wells on eleven separate lease blocks and conducted a number of seismic programs. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order in Council authorizing the Alberta Energy Resources Conservation Board, or ERCB, to issue the formal regulatory approval of Grizzly's Algar Lake steam-assisted gravity drainage, or SAGD, project. Construction of the Algar Lake Phase 1 SAGD project commenced in 2012. During 2012, an 11 kilometer road was constructed to the project site, water and natural gas supply pipelines were installed, central plant modules were assembled, transported to the project site and lifted into place, ten production well pairs were drilled and completed and well pad modules and flow lines back to the central plant were installed. Grizzly expects first oil production at Algar Lake during the fourth quarter of 2013. In the first quarter of 2012, Grizzly acquired the May River property comprising approximately 47,000 acres. In the 2012/2013 drilling program, Grizzly completed a 29 well core hole drilling program at May River and plans to file an initial 12,000 barrel per day development application with the ERCB by the end of 2013. At the Thickwood thermal project, Grizzly's 2012 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 anticipates approval of this development application in mid-2014 and first oil production by mid-2017. 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 also pursuing the design, permitting and construction of rail terminals in Northern Alberta and on the Lower Mississippi River, where it plans to develop scalable capacity to accommodate unit trains to ship and receive up to 100,000 barrels per day. Grizzly anticipates beginning to transport the company's bitumen starting in the fourth quarter of 2013. Grizzly's contemplated 2013 activities include the completion of the 2012/2013 core hole drilling and seismic program, submission of a SAGD project regulatory application for May River and the completion of its Algar Lake SAGD project.


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Thailand. During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II, at a cost of $2.4 million. The remaining interests in Tatex II are owned by entities controlled by Wexford. 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. During the six months ended June 30, 2013 we received $0.4 million in distributions from Tatex II. Our investment is accounted for using the equity method. Tatex II accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm's initial gross production was approximately 60 million cubic feet per day. During the three months ended June 30, 2013, net gas production was approximately 118 MMcf per day and condensate production was 516 barrels per day. 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 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.

During the first quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III, at a cost of $0.9 million. In December 2009, we purchased an additional approximately 12.9% ownership interest at a cost of approximately $3.4 million bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately 490,000 acres in Southeast Asia. In 2009, Tatex III completed a 3-D seismic survey on this concession. During the six months ended June 30, 2013, we paid cash calls to Tatex III of approximately $0.6 million. Our total investment in Tatex III was $9.1 million at June 30, 2013. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. Drilling of the second well concluded in March 2011. The second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and carried a flare measuring up to 25 feet throughout drilling below the intermediate casing point of 9,695 feet. During testing, the well produced at rates as high as 16 MMcf per day of gas for short intervals, but would subsequently fall to a sustained rate of two MMcf per day of gas. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. Despite an apparently well-developed porosity system suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial quantities. Tatex III intends to continue testing some of the structures identified through its 3-D seismic survey and has begun the application process for two more drilling locations. Tatex III currently expects to drill the first of these wells, located to the south of the TEW-E well, in 2013.

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%, and paid $2.2 million for our initial investment in Stingray Energy. 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 the second quarter of 2012, we participated in the formation of each of Stingray Pressure Pumping LLC, or Stingray Pressure, and Stingray Cementing LLC, or Stingray Cementing, with an initial ownership interest in each entity of 50%. Stingray Pressure and Stingray Cementing provide well completion services. We also participated in the formation of Blackhawk Midstream LLC, or Blackhawk, with an initial ownership interest of 50%. Blackhawk coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage. In the fourth quarter of 2012, we also participated in the formation of Stingray Logistics LLC, or Stingray Logistics, with an initial ownership interest of 50%. Stingray Logistics provides well services. In March 2012, we participated in the formation of Timber Wolf Terminals LLC, or Timber Wolf, with an initial ownership interest of 50% and made a $1.0 million capital contribution. Also in March 2012, we acquired a 22.5% equity interest in Windsor Midstream LLC, or Midstream, for $7.0 million. Midstream owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011, we acquired a 25% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates drilling rigs and related equipment. In April 2012, we purchased an additional 15% equity interest in Bison for approximately $6.2 million, bringing our total ownership interest in Bison to 40%. Also in 2011, we acquired a 25% interest in Muskie Proppant LLC, or Muskie (formerly known as Muskie Holdings LLC), which is engaged in the mining of hydraulic fracturing grade sand. In 2012, we invested approximately $42.8 million in these entities. In the six months ended June 30, 2013, we invested approximately $6.3 million in these entities. See Note 4 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments.


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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 $872.1 million at June 30, 2013 and $626.3 million at December 31, 2012. 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.

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 NGLs 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 June 30, 2013.

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