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GPOR > SEC Filings for GPOR > Form 10-Q on 8-Nov-2012All Recent SEC Filings

Show all filings for GULFPORT ENERGY CORP

Form 10-Q for GULFPORT ENERGY CORP


8-Nov-2012

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 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. During 2010, we acquired our initial acreage position in the Niobrara Formation of northwestern Colorado. During 2011, we acquired our initial acreage position in the Utica Shale in Eastern Ohio and our first well in the Utica Shale was spud in February 2012. As of November 1, 2012, we had spud 11 additional wells in the Utica Shale. On October 11, 2012, we completed the Contribution described below under the heading "-Contribution." As a result, we now hold an equity interest in Diamondback Energy, Inc., or Diamondback, rather than leasehold interests in the Permian Basin acreage operated by Diamondback. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, and have 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.

Contribution

On May 7, 2012, we entered into a contribution agreement with Diamondback. Under the terms of the contribution agreement, we agreed to contribute to Diamondback, prior to the closing of Diamondback's initial public offering, or the Diamondback IPO, all of our oil and gas interests in the Permian Basin. On October 11, 2012, we completed this contribution, which we refer to herein as the Contribution. At the closing of the 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 is subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and other items of Windsor Permian LLC, or Windsor Permian, referred to in the contribution agreement as of the date of the Contribution. Windsor Permian is a wholly-owned subsidiary of Diamondback. If the Contribution had closed on September 30, 2012, based on Diamondback's preliminary estimates, Diamondback would


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have owed us approximately $16.0 million for this post-closing adjustment. However, the actual amount due based on the October 11, 2012 closing date has not been determined, and the actual amount may vary materially from the estimated amount on September 30, 2012. Under the contribution agreement, we are generally responsible for all liabilities and obligations with respect to the contributed properties arising prior to the Contribution and Diamondback is responsible for such liabilities and obligations with respect to the contributed properties arising after the Contribution.

In connection with the Contribution, we and Diamondback entered into an investor rights agreement in which we have the right, for so long as we beneficially own more than 10% of Diamondback's outstanding common stock, to designate one individual as a nominee to serve on Diamondback's board of directors. Such nominee, if elected to Diamondback's board, will also serve on each committee of the board so long as he or she satisfies the independence and other requirements for service on the applicable committee of the board. So long as we have the right to designate a nominee to Diamondback's board and there is no nominee of ours actually serving as a Diamondback director, we will have the right to appoint one individual as an advisor to the board who shall be entitled to attend board and committee meetings. We are also entitled to certain information rights and Diamondback granted us certain demand and "piggyback" registration rights obligating Diamondback to register with the Securities and Exchange Commission, or the SEC, any shares of Diamondback common stock that we own. Immediately upon completion of the Contribution, we owned a 35% equity interest in Diamondback, rather than leasehold interests in our Permian Basin acreage. Upon completion of the Diamondback IPO on October 17, 2012, we owned approximately 22.5% of Diamondback's outstanding common stock. On October 18, 2012, the underwriters of the Diamondback IPO exercised in full their option to purchase additional shares of common stock of Diamondback and, upon the closing of such purchase on October 23, 2012, we owned approximately 21.4% of Diamondback's outstanding common stock. Our investment in Diamondback will be accounted for as an equity method investment going forward.

Third Quarter 2012 Operational Highlights

         Oil and natural gas revenues increased 4% to $60.5 million for the
          three months ended September 30, 2012 from $58.0 million for the three
          months ended September 30, 2011.



         Net income decreased 98% to $0.5 million for the three months ended
          September 30, 2012 from $29.0 million for the three months ended
          September 30, 2011, primarily due to deferred income tax expense of
          $15.5 million for the three months ended September 30, 2012 based upon
          the latest taxable income forecast that includes the affects of the
          contribution of our Permian Basin assets to Diamondback.



         Production increased 11% to approximately 655,000 barrels of oil
          equivalent, or BOE, for the three months ended September 30, 2012 from
          approximately 590,000 BOE for the three months ended September 30,
          2011.



         During the three months ended September 30, 2012, we, and in some cases
          other operators, drilled 26 gross (18.5 net) wells and recompleted 25
          gross (24.3 net) wells. Of these 26 gross new wells at September 30,
          2012, 11 had been completed as producing wells, ten were waiting on
          completion, two were resting and three were being drilled.



         During 2011 and through September 30, 2012, we acquired leasehold
          interests in approximately 128,000 gross (64,000 net) acres in the
          Utica Shale in Eastern Ohio. We spud our first well on our Utica Shale
          acreage in February 2012 and subsequently have spud 11 additional
          wells. Between August 1 and October 31, 2012, we brought our first well
          on line and tested five additional wells. See "2012 Production and
          Drilling Activity - Utica Shale (Eastern Ohio)" below for a summary of
          the initial results from these wells.

2012 Production and Drilling Activity

During the three months ended September 30, 2012, our total net production was 579,000 barrels of oil, 315,000 thousand cubic feet, or Mcf, of gas, and 996,000 gallons of natural gas liquids, or NGLs, for a total of 655,000 BOE as compared to 545,000 barrels of oil, 196,000 Mcf of gas and 505,000 gallons of NGLs, or 590,000 BOE, for the three months ended September 30, 2011. Our total net production averaged approximately 7,124 BOE per day during the three months ended September 30, 2012 as compared to 6,414 BOE per day during the same period in 2011. The 11% increase in production is primarily related to the 2012 drilling and recompletion activities in our fields.

WCBB. From January 1, 2012 through November 1, 2012, we recompleted 49 existing wells. We also spud 29 wells, of which 24 were completed as producers and two were non-productive and, at November 1, 2012, two were waiting on


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completion and one was being drilled. We currently intend to recomplete a total of approximately 60 existing wells and drill a total of 30 wells during 2012.

Aggregate net production from the WCBB field during the three months ended September 30, 2012 was 252,876 BOE, or 2,749 BOE per day, 96% of which was from oil and 4% of which was from natural gas. During October 2012, our average daily net production at WCBB was approximately 3,024 BOE, 98% of which was from oil and 2% of which was from natural gas. The increase in October 2012 production was the result of the timing of 2012 drilling and the impact of Hurricane Isaac in August 2012.

East Hackberry Field. From January 1, 2012 through November 1, 2012, we recompleted 26 existing wells. We also spud 21 wells, of which 15 were completed as producers and three were non-productive and, at November 1, 2012, one was waiting on completion and two were being drilled. During 2009, we entered into a two-year exploration agreement with an active gulf coast operator covering approximately 2,868 net acres adjacent to our field. We are the designated operator under the agreement and will participate in proposed wells with at least a 70% working interest. We currently intend to drill 22 wells and recomplete 26 wells in our East Hackberry field in 2012.

Aggregate net production from the East Hackberry field during the three months ended September 30, 2012 was approximately 257,799 BOE, or 2,802 BOE per day, 97% of which was from oil and 3% of which was from natural gas. During October 2012, our average daily net production at East Hackberry was approximately 2,231 BOE, 97% of which was from oil and 3% of which was from natural gas. The decrease in October 2012 production was the result of natural production declines.

West Hackberry Field. Aggregate net production from the West Hackberry field during the three months ended September 30, 2012 was approximately 3,243 BOE, or 35 BOE per day. During October 2012, our average daily net production at West Hackberry was approximately 18 BOE, 100% of which was from oil.

Permian Basin. From January 1, 2012 through the closing of the Contribution on October 11, 2012, 19 gross (8.3 net) wells, including our first horizontal well, were spud on our Permian Basin acreage, all of which were completed as producers. One gross (0.3 net) existing well was recompleted from January 1, 2012 to October 11, 2012.

Aggregate net production from our Permian Basin acreage during the three months ended September 30, 2012 was approximately 110,846 BOE, or 1,205 BOE per day. During the first eleven days of October 2012, the average daily net production from our Permian Basin acreage was approximately 1,156 BOE, of which approximately 66% was oil, 19% was natural gas liquids and 15% was natural gas.

As discussed above under the heading "-Contribution," 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 the 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 is subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and other items of Windsor Permian referred to in the contribution agreement as of the date of the Contribution. As of October 23, 2012, following the closing of the Diamondback IPO and the underwriters' exercise in full of their option to purchase additional shares of common stock of Diamondback, we owned approximately 21.4% of Diamondback's outstanding common stock.

Niobrara Formation. Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Colorado and held leases for approximately 11,693 acres as of September 30, 2012. From January 1, 2012 through November 1, 2012, three gross (1.0 net) wells, including one gross (0.03 net) well drilled by another operator, were spud on our Niobrara Formation acreage, two of which were completed as producers and one was non-productive. Aggregate net production from the Niobrara play during the three months ended September 30, 2012 was approximately 4,756 BOE, or 52 BOE per day, 100% of which was from oil. During October 2012, average daily net production in Niobrara was approximately 47 BOE.

We have completed a 60 square mile 3-D seismic survey over our Craig Dome prospect and have received a processed version of the seismic. We currently intend to drill two gross wells in the Niobrara Formation during 2012.

Bakken. In the Bakken Formation, as of September 30, 2012, we held approximately 800 net acres, interests in eight wells and overriding royalty interests in certain existing and future wells.

Aggregate net production from the Bakken Formation during the three months ended September 30, 2012 was approximately 7,295 BOE, or 79 BOE per day. During October 2012, our average daily net production from the Bakken formation was approximately 86 BOE. There are no new activities currently scheduled for 2012 for our Bakken acreage.


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Utica Shale (Eastern Ohio). As of September 30, 2012, we had acquired leasehold interests in approximately 128,000 gross (64,000 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 November 1, 2012, had spud 11 additional wells. In August 2012, the first well was brought online and tested at a gross peak rate of 17.1 million cubic feet, or MMcf, of natural gas per day, 432 barrels of condensate per day and 1,881 barrels of NGLs per day assuming full ethane recovery and a natural gas shrink of 18%, or 4,650 BOE per day. Our second well, the Boy Scout 1-33H, tested at a peak rate of 1,560 barrels of condensate per day, 7.1 MMcf of natural gas per day and 1,008 barrels of NGLs per day assuming full ethane recovery and a natural gas shrink of 25%, or 3,456 BOE per day. In October 2012, four more wells were tested. The Shugert 1-1H was tested at a peak rate of 20.0 MMcf of natural gas per day, 144 barrels of condensate per day and 2,002 barrels of NGLs per day assuming full ethane recovery and a natural gas shrink of 17%, or 4,913 BOE per day. The Ryser 1-25H tested at a peak rate of 1,488 barrels of condensate per day, 5.9 MMcf of natural gas per day and 649 barrels of NGLs per day assuming full ethane recovery and a natural gas shrink of 21%, or 2,914 BOE per day. The Groh 1-12H tested at a peak rate of 1,186 barrels of condensate per day, 2.8 MMcf of natural gas per day and 367 barrels of NGLs per day assuming full ethane recovery and a natural gas shrink of 18%, or 1,935 BOE per day. After only a 30-day resting period, the BK Stephens 1-16H tested at a peak rate of 1,224 barrels of condensate per day, 6.9 MMcf per day of natural gas and 759 barrels of NGLs per day assuming full ethane recovery and a natural gas shrink of 11%, or 3,007 BOE per day. In addition, one gross (0.05 net) well was drilled by another operator on our Utica Shale acreage between January 1, 2012 and November 1, 2012.

Aggregate net production from the Utica Shale during the three months ended September 30, 2012 was approximately 17,764 BOE, or 193 BOE per day, 13% of which was from oil and 87% of which was from natural gas. During October 2012, our average daily net production from the Utica Shale was approximately 328 BOE, 18% of which was from oil and natural gas liquids and 82% of which was from natural gas.

Grizzly. We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in Grizzly is owned by an entity controlled by Wexford. As of September 30, 2012, Grizzly had approximately 800,000 acres under lease in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles of other existing oil sands projects. Our total net investment in Grizzly was approximately $165.0 million as of September 30, 2012. As of that date, Grizzly had drilled an aggregate of 232 core holes and seven water supply test wells, tested eleven separate lease blocks and conducted a seismic program. 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 (ERCB) to issue the formal regulatory approval of Grizzly's Algar Lake SAGD project. During the second quarter of 2012, Grizzly finished SAGD well pair drilling at Algar Lake and began the process of completing those well pairs for SAGD injection and production. In the first quarter of 2012, Grizzly completed the acquisition of approximately 47,000 acres through the purchase of its May River property and recently set forth a full field development plan for this property under which May River will be developed in multiple phases with the goal of producing 70,000 barrels per day of bitumen by the year 2020. Grizzly's contemplated 2012 activities included the completion of the 2011/2012 core hole drilling and seismic program, submission of a SAGD project regulatory application for Thickwood Hills and the development of its Algar Lake SAGD project, which included the fabrication and onsite construction of a central processing facility and the drilling of ten initial SAGD well pairs which has now been completed.

Thailand. We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex
II. 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, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately two million acres which includes the Phu Horm Field. As of September 30, 2012, our net investment in Tatex II was $0.3 million. Our investment is accounted for on the equity method. Tatex II accounts for its investment in APICO using the cost method. During the third quarter ended September 30, 2012, net gas production from the Phu Horm field was approximately 93 MMcf per day and condensate production was 426 barrels per day. Hess Corporation operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTTEP (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.

We also own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately one million acres. During the nine months ended September 30, 2012, we paid $0.6 million in cash calls, bringing our total investment in Tatex III to $8.7 million. 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


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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.

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 applicable period, 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 $234.6 million at September 30, 2012 and $138.6 million at December 31, 2011. 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 applicable period, 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, . . .

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