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GPOR > SEC Filings for GPOR > Form 10-K on 28-Feb-2014All Recent SEC Filings

Show all filings for GULFPORT ENERGY CORP

Form 10-K for GULFPORT ENERGY CORP


28-Feb-2014

Annual Report


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in Item 1A. "Risk Factors" and the section entitled "Cautionary Note Regarding Forward-Looking Statements" appearing elsewhere in this Annual Report on Form 10-K.
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. 2013 and 2014 Year to Date Highlights
Oil and natural gas revenues increased 5% to $262.2 million for the year ended December 31, 2013 from $248.6 million for the year ended December 31, 2012.

Production increased 60% to approximately 4,118,131 BOE for the year ended December 31, 2013 from approximately 2,572,618 BOE for the year ended December 31, 2012.

During 2013, we drilled 98 gross (79 net) wells, participated in an additional 49 gross (2.6 net) wells that were drilled by other operators on our Utica Shale acreage and recompleted 150 gross and net wells. Of our 98 new wells drilled at year end 2013, 64 were completed as producing wells, two were non-productive, 14 were waiting on completion, nine were waiting on a horizontal rig and nine were drilling.

On February 26, 2014, we entered into a binding letter of intent with Rhino to acquire approximately 8,200 net acres in the Utica Shale of Eastern Ohio and approximately 1,000 BOEPD of production during January 2014 for a total purchase price of $185.0 million, subject to closing adjustments. We are the operator of substantially all of this acreage.

Through February 27, 2014, after giving pro forma effect to our pending acquisition disclosed above, we would have acquired leasehold interests in approximately 167,700 gross (165,400 net) acres in the Utica Shale in Eastern Ohio. During 2013, we drilled 52 gross (39 net) wells on our Utica Shale acreage and, as of February 14, 2014, we had spud six gross (five net) wells during 2014, all of which were being drilled.

In June and November 2013, we sold shares of our Diamondback common stock in underwritten public offerings for an aggregate of $192.7 million in net proceeds. As of December 31, 2013, we owned approximately 7.2% of Diamondback's outstanding common stock.

In February 2013, we completed an underwritten public offering of an aggregate of 8,912,500 shares of our common stock and received net proceeds of approximately $325.8 million. We used approximately $220.4 million to fund our acquisition of approximately 22,000 net acres in the Utica Shale in Eastern Ohio and the remaining net proceeds for general corporate purposes, which included funding a portion of our 2013 capital development plan.

In November 2013, we completed an underwritten public offering of an aggregate of 7,475,000 shares of our common stock and received net proceeds of approximately $408.0 million. We have used, and intend to continue to use, the net proceeds from this equity offering for general corporate purposes, which may include expenditures associated with our 2014 drilling program and additional acreage acquisitions in the Utica Shale.


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Index to Financial Statements

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 $950.6 million at December 31, 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 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 year ended December 31, 2013.

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


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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.
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 future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Periodically, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2013, a valuation allowance of $4.7 million had been provided for state net operating loss and federal tax credit deferred tax assets based on the uncertainty these assets may be realized.
Revenue Recognition. We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded at the end of the quarter after payment is received. Historically, our actual payments have not significantly deviated from our accruals. Investments-Equity Method. Investments in entities greater than 20% and less than 50% and/or investments in which we have significant influence are accounted for under the equity method. Under the equity method, our share of investees' earnings


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or loss is recognized in the statement of operations. In accordance with FASB ASC 825, "Financial Instruments," we have elected the fair value option of accounting for our equity method investment in Diamondback's stock. At the end of each reporting period, the quoted closing market price of Diamondback's stock is multiplied by the total shares owned by us and the resulting gain or loss is recognized in (income) loss from equity method investments in the consolidated statements of operations.
We review our investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, we recognize an impairment provision. There was no impairment of equity method investments at December 31, 2013 or 2012.
Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. We are involved in certain litigation for which the outcome is uncertain. Changes in the certainty and the ability to reasonably estimate a loss amount, if any, may result in the recognition and subsequent payment of legal liabilities.
Derivative Instruments and Hedging Activities. We seek to reduce our exposure to unfavorable changes in oil and natural gas prices by utilizing energy swaps and collars, or fixed-price contracts. We follow the provisions of FASB ASC 815, "Derivatives and Hedging," as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using established index prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and our realized prices, time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.
The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. We recognize any change in fair value resulting from ineffectiveness immediately in earnings.
See "Item 7. Commodity Price Risk" for a summary of our fixed price swaps and swaptions in place as of December 31, 2013.
RESULTS OF OPERATIONS
Results of Operations
The markets for oil and natural gas have historically been, and will continue to be, volatile. Prices for oil and natural gas may fluctuate in response to relatively minor changes in supply and demand, market uncertainty and a variety of factors beyond our control.
The following table presents our production volumes, average prices received and average production costs during the periods indicated:


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  Index to Financial Statements

                                                 2013              2012              2011
Production Volumes:
Oil (MBbls)                                       2,317             2,323             2,128
Gas (MMcf)                                        8,891             1,108               878
Natural gas liquids (MGal)                       13,416             2,714             2,468
Oil equivalents (MBOE)                            4,118             2,573             2,333
Average Prices:
Oil (per Bbl)                                $    96.74   (1)  $   104.46   (1)  $   104.33   (1)
Gas (per Mcf)                                $     2.36   (1)  $     2.91        $     4.37
Natural gas liquids (per Gal)                $     1.27        $     0.98        $     1.25
Oil equivalents (per BOE)                    $    63.68        $    96.63        $    98.13
Production Costs:
Average production costs (per BOE)           $     6.48        $     9.45        $     8.96
Average production taxes and midstream costs
(per BOE)                                    $     9.22        $    11.43        $    11.29
Total production and midstream costs and
production taxes (per BOE)                   $    15.70        $    20.88        $    20.25


_____________________


(1) Includes various derivative contracts at a weighted average price of:

                         Per barrel
January - December 2013 $     101.90
January - December 2012 $     108.31
January - December 2011 $      86.96


                         Per MMBtu
January - December 2013 $      4.00

Excluding the net effect of fixed price swaps, the average price for 2013 would have been $104.51 per barrel of oil, $3.73 per Mcf of gas and $70.99 per BOE. The total volume hedged for 2013 represented approximately 48% of our total sales volumes for the year. Excluding the net effect of fixed price swap contracts, the average oil price for 2012 would have been $106.11 per barrel of oil and $98.12 per BOE. The total volume hedged for 2012 represented approximately 46% of our total sales volumes for the year. Excluding the net effect of forward sales contracts, the average oil price for 2011 would have been $107.13 per barrel of oil and $100.68 per BOE. The total volume hedged for 2011 represented approximately 31% of our total sales volumes for the year. From 2012 to 2013, our net equivalent oil production increased 60% from 2,572,618 BOE to 4,118,131 BOE primarily as a result of the development of our Utica Shale acreage. From 2011 to 2012, our net equivalent oil production also increased 10% from 2,333,208 BOE to 2,572,618 BOE due to the results of our 2012 drilling and recompletion activities. We currently estimate that our 2014 production will be between 18,250,000 and 21,900,000 BOE. However, our actual production may be different due to changes in our currently anticipated drilling and recompletion activities, changing economic climate, adverse weather conditions or other unforeseen events.
Comparison of the Years Ended December 31, 2013 and December 31, 2012 We reported net income of $153.2 million for the year ended December 31, 2013 as compared to $68.4 million for the year ended December 31, 2012 . This 124% increase in period-to-period net income was due primarily to $220.1 million of income recognized from our equity method investment in Diamondback and a 60% increase in net production to 4,118,131 BOE from 2,572,618, partially offset by a 34% decrease in realized BOE prices to $63.68 from $96.63, a $2.4 million increase in lease operating expenses, a $10.6 million increase in midstream transportation, processing and marketing expenses, an $8.7 million increase in general and administrative expenses, a $10.0 million increase in interest expense and a $71.8 million increase in income tax expense for the year ended December 31, 2013 as compared to the year ended December 31, 2012.


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Oil and Gas Revenues. For the year ended December 31, 2013, we reported oil and natural gas revenues of $262.2 million as compared to oil and natural gas revenues of $248.6 million during 2012. This $13.6 million, or 5%, increase in revenues was primarily attributable to a 60% increase in net production to 4,118,131 BOE from 2,572,618 BOE, partially offset by a 34% decrease in realized BOE prices to $63.68 from $96.63, for the year ended December 31, 2013 as compared to the year ended December 31, 2012.
The following table summarizes our oil and natural gas production and related pricing for the years ended December 31, 2013 and December 31, 2012:

                                                   Year Ended
                                                  December 31,
                                                2013       2012
Oil production volumes (MBbls)                  2,317       2,323
Gas production volumes (MMcf)                   8,891       1,108
Natural gas liquids production volumes (MGal)  13,416       2,714
Oil equivalents (MBOE)                          4,118       2,573
Average oil price (per Bbl)                   $ 96.74    $ 104.46
Average gas price (per Mcf)                   $  2.36    $   2.91
Average natural gas liquids (per Gal)         $  1.27    $   0.98
Oil equivalents (per BOE)                     $ 63.68    $  96.63

Lease Operating Expenses. Lease operating expenses, or LOE, not including production taxes increased to $26.7 million for the year ended December 31, 2013 from $24.3 million for the year ended December 31, 2012. This increase was mainly the result of an increase in expenses related to property taxes, compressor rentals, compressor repairs and maintenance, contract pumpers, environmental services, insurance expense, and salt water disposal.
Production Taxes. Production taxes decreased to $26.9 million for the year ended December 31, 2013 from $29.0 million for 2012. This decrease was primarily related to changes in our product mix and production location. Midstream Transportation, Processing and Marketing Expenses. Midstream transportation, processing and marketing expenses increased by $10.6 million to $11.0 million for the year ended December 31, 2013 from $0.4 million for 2012. This increase was primarily the result of midstream expenses related to our production volumes in the Utica Shale resulting from our 2013 drilling activities.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense increased to $118.9 million for the year ended December 31, 2013, and consisted of $118.1 million in depletion of oil and natural gas properties and $0.8 million in depreciation of other property and equipment, as compared to total DD&A expense of $90.7 million for 2012. This increase was due to an increase in our full cost pool as a result of our capital activities as well as an increase in our production, partially offset by an increase in our total proved reserves volume used to calculate our total DD&A expense.
General and Administrative Expenses. Net general and administrative expenses increased to $22.5 million for the year ended December 31, 2013 from $13.8 million for the year ended December 31, 2012. This $8.7 million increase was due to an increase in salaries, stock compensation expenses and benefits resulting from an increased number of employees, increases in legal expenses, corporate fees, consulting fees and fees for auditing services and a reduction in administrative services reimbursements under the acquisition team agreement, partially offset by an increase in general and administrative costs related to . . .

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