News Column

GULFPORT ENERGY CORP - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

August 7, 2014

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, Quarterly Reports on Form 10-Q or any other filings we make with the SEC, 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. 2014 Operational Highlights Oil and natural gas revenues increased 63% to $114.5 million for the three

months ended June 30, 2014 from $70.2 million for the three months ended June 30, 2013. Production increased 198% to 2,431,955 barrels of oil equivalent ("BOE") for the three months ended June 30, 2014 from 815,300 BOE for the three months ended June 30, 2013. During the three months ended June 30, 2014, we spud 37 gross (29 net) wells, participated in an additional 19 gross (2.4 net) wells that were drilled by other operators on our Utica Shale acreage and recompleted 46 gross and net wells. Of our 37 new wells spud at June 30, 2014, nine were completed as producing wells, one was non-productive, 22 were waiting on completion and five were being drilled. 31



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In March 2014, we acquired approximately 8,000 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 $179.0 million ($177.4 million net of purchase price adjustments). We are the operator of substantially all of this acreage. 2014 Production and Drilling Activity During the three months ended June 30, 2014, our total net production was 709,484 barrels of oil, 8,972,137 thousand cubic feet, or Mcf, of natural gas, and 9,538,843 gallons of natural gas liquids, or NGLs, for a total of 2,431,955 BOE as compared to 535,182 barrels of oil, 1,414,797 Mcf of natural gas and 1,861,360 gallons of NGLs, or 815,300 BOE, for the three months ended June 30, 2013. Our total net production averaged approximately 26,725 BOE per day during the three months ended June 30, 2014 as compared to 8,959 BOE per day during the same period in 2013. The 198% increase in production is largely the result of the development of our Utica Shale acreage. Utica Shale. As of August 1, 2014, we had acquired leasehold interests in approximately 184,500 gross (183,500 net) acres in the Utica Shale in Eastern Ohio, including the approximately 8,000 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 June 30, 2014, had spud 99 wells, 60 of which had been completed and, as of August 1, 2014 were producing. From January 1, 2014 through August 1, 2014, we spud 47 gross (34 net) wells, of which six were producing, four were waiting on a horizontal rig, 30 were waiting on completion and seven were still being drilled at August 1, 2014. In addition, 19 gross (2.4 net) wells were drilled by other operators on our Utica Shale acreage during the three months ended June 30, 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 June 30, 2014 was approximately 1,930,139 net BOE, or 21,210 BOE per day, 77% of which was from natural gas and 23% of which was from oil and natural gas liquids, or NGLs. During July 2014, our average daily net production from the Utica Shale was approximately 29,088 BOE, 76% of which was from natural gas and 24% of which was from oil and NGLs. The increase in July production was due to increased production as a result of our drilling activity on our Utica Shale acreage. WCBB. From January 1, 2014 through August 1, 2014, we recompleted 60 wells and spud 17 wells. Of the 17 new wells spud at WCBB, 11 were completed as producing wells, four were non-productive, one was waiting on completion and one was being drilled at August 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 June 30, 2014 was approximately 315,860 BOE, or an average of 3,471 BOE per day, 100% of which was from oil. During July 2014, our average net daily production at WCBB was approximately 3,278 BOE, 100% of which was from oil. The slight decrease in July production is primarily the result of timing of bringing our 2014 drilling program wells online and natural production declines. East Hackberry Field. From January 1, 2014 through August 1, 2014, we recompleted 33 wells and spud nine wells. Of the nine new wells drilled at East Hackberry, eight were completed as producing wells and one was waiting on completion at August 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 June 30, 2014 was approximately 152,284 BOE, or an average of 1,673 BOE per day, 89% of which was from oil and 11% of which was from natural gas. During July 2014, our average net daily production at East Hackberry was approximately 1,300 BOE, 93% of which was from oil and 7% of which was from natural gas. The decrease in July production is primarily the result of natural production declines. West Hackberry Field. From January 1, 2014 through August 1, 2014, we recompleted two wells. No new wells were drilled at West Hackberry from January 1, 2014 to August 1, 2014. Aggregate net production from the West Hackberry field was approximately 15,766 BOE, or an average of 173 BOE per day, 100% of which was from oil. During July 2014, our average net daily production at West Hackberry was approximately 137 BOE, 92% of which was from oil and 8% of which was from natural gas. Niobrara Formation. Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado and, as of June 30, 2014, we held leases for approximately 6,549 net acres. From January 1, 2014 32



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through August 1, 2014, there were no wells spud on our Niobrara Formation acreage. Aggregate net production from our Niobrara Formation acreage during the three months ended June 30, 2014 was approximately 4,774 BOE, or an average of 52 BOE per day, 100% of which was from oil. During July 2014, our average net daily production from our Niobrara Formation acreage was approximately 48 BOE, 100% of which was from oil. During 2014, we currently do not anticipate drilling any wells in the Niobrara Formation. Bakken. As of June 30, 2014, we held approximately 864 net acres in the Bakken Formation of Western North Dakota and Eastern Montana with interests in 18 wells and overriding royalty interests in certain existing and future wells. Aggregate net production from this acreage during the three months ended June 30, 2014 was approximately 12,675 BOE, or an average of 139 BOE per day, of which 91% was from oil, 7% was from natural gas and 2% was from NGLs. During July 2014, our average daily net production from our Bakken Formation acreage was approximately 102 BOE, of which 89% was from oil and 11% 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. In June 2014, we sold 1,000,000 shares of our Diamondback common stock and received net proceeds of approximately $89.1 million. As of June 30, 2014, we owned approximately 2,379,500 shares representing approximately 4.7% 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 June 30, 2014, Grizzly had over 800,000 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. Initiation of steam injection at its first project, Algar Lake Phase 1, commenced in January 2014 and first bitumen production was achieved during the second quarter of 2014. Bitumen production averaged 510 barrels per day in May and June and exited the quarter at approximately 1,200 barrels per day. 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. Grizzly is preparing responses to the first round of supplemental information requests, or SIRs, and expects to deliver replies to the Alberta Energy Regulator, or AER, by mid-August. In the first quarter of 2014, a 2D seismic program covering approximately 83 kilometers, was completed to more fully define the development area over the remaining lease beyond the development application area. At the Thickwood thermal project, a development application for a 12,000 barrel per day oil sands project was filed in the fourth quarter of 2012. Since then, the AER announced it is implementing a policy for future regulatory requirements for reservoir containment in shallow SAGD areas, which impacts the Thickwood application. Further work on advancing the Thickwood application will be delayed pending regulatory resolution of the shallow SAGD issue. Grizzly completed construction of the Windell truck-to-rail terminal, proximate to its May River lease, and began crude oil shipments to the U.S. Gulf Coast in the second quarter of 2014. All of Grizzly's oil is now being sold into the U.S. Gulf Coast heavy oil market at Natchez, Mississippi, where Grizzly receives Mars based pricing. Grizzly is in discussion with third parties to expand its transloading business. On the U.S. Gulf Coast, Grizzly has completed the design engineering for the Paulina rail-to-barge terminal and filed development permits. Grizzly is working through the permitting process to gain approval to construct the facility. Both of these terminals will be located on the Canadian National Railway's Company, or CN, main line. Grizzly has entered into a contract with CN that fixes the rate structure for a ten-year period for transportation of bitumen loaded at Windell and shipped to the U.S. Gulf Coast via CN's rail network. 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 33



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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 $1.2 billion at June 30, 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 34



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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 quarter ended June 30, 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.

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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 June 30, 2014, a valuation allowance of $2.6 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 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 June 30, 2014 and December 31, 2013. 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. There were no hedges designated as cash flow hedges during the three months ended June 30, 2014 as all of our current hedges were deemed ineffective at inception. RESULTS OF OPERATIONS Comparison of the Three Months Ended June 30, 2014 and 2013 We reported net income of $47.9 million for the three months ended June 30, 2014 as compared to $43.8 million for the three months ended June 30, 2013. This 9% increase in period-to-period net income was due primarily to $72.9 million of income recognized from our equity method investment in Diamondback and a 198% increase in net production to 2,431,955 BOE from 815,300 BOE, partially offset by a 45% decrease in realized BOE prices to $47.08 from $86.10, a $6.8 million increase in lease operating expenses, an $8.9 million increase in midstream transportation, processing and marketing expenses, a $5.5 million increase in general and administrative expenses, an expense of $6.0 million for litigation settlement and a $5.9 million increase in income tax expense for the three months ended June 30, 2014 as compared to the three months ended June 30, 2013. Oil and Gas Revenues. For the three months ended June 30, 2014, we reported oil and natural gas revenues of $114.5 million as compared to oil and natural gas revenues of $70.2 million during the same period in 2013. This $44.3 million, or 63%, increase in revenues was primarily attributable to a 198% increase in net production to 2,431,955 BOE from 815,300 BOE, partially offset by a 45% decrease in realized BOE prices to $47.08 from $86.10 due to a shift in our production mix toward natural gas and NGLs for the three months ended June 30, 2014 as compared to the three months ended June 30, 2013. The following table summarizes our oil and natural gas production and related pricing for the three months ended June 30, 2014, as compared to such data for the three months ended June 30, 2013: Three months ended June 30, 2014 2013 Oil production volumes (MBbls) 709 535 Gas production volumes (MMcf) 8,972 1,415 Natural gas liquids production volumes (MGal) 9,539 1,861 Oil equivalents (MBOE) 2,432 815 Average oil price (per Bbl) $ 95.95$ 113.98 Average gas price (per Mcf) $ 3.96$ 4.80 Average natural gas liquids (per Gal) $ 1.14$ 1.29 Oil equivalents (per BOE) $ 47.08$ 86.10



Lease Operating Expenses. Lease operating expenses, or LOE, not including production taxes increased to $12.7 million for the three months ended June 30, 2014 from $5.9 million for the three months ended June 30, 2013. This increase was mainly the result of an increase in expenses related to compressor repairs and maintenance, contract pumpers, contract labor and field supervision, environmental services, insurance, location repairs, rentals and salt water disposal. Production Taxes. Production taxes increased slightly to $6.6 million for the three months ended June 30, 2014 from $6.4 million for the same period in 2013. This slight increase was primarily related to a 198% increase in production and changes in our product mix and production location. Midstream Transportation, Processing and Marketing Expenses. Midstream transportation, processing and marketing expenses increased by $8.9 million to $10.8 million for the three months ended June 30, 2014 from $1.9 million for the same period in 2013. This increase was primarily attributable to midstream expenses related to our production volumes in the Utica Shale resulting from our 2013 drilling activities.

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Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense increased to $56.0 million for the three months ended June 30, 2014, and consisted of $55.7 million in depletion of oil and natural gas properties and $0.3 million in depreciation of other property and equipment, as compared to total DD&A expense of $28.5 million for the three months ended June 30, 2013. 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 $10.4 million for the three months ended June 30, 2014 from $4.9 million for the three months ended June 30, 2013. This $5.5 million increase was due to an increase in salaries, stock compensation expenses and benefits resulting from an increased number of employees, increases in corporate fees, computer support, consulting fees and franchise taxes, partially offset by an increase in general and administrative costs related to exploration and development activity capitalized to the full cost pool. Accretion Expense. Accretion expense remained relatively flat at $0.2 million for the three months ended June 30, 2014 and 2013. Interest Expense. Interest expense decreased to $2.4 million for the three months ended June 30, 2014 from $3.3 million for the three months ended June 30, 2013 due primarily to an increase in the amount of interest capitalized in the three months ended June 30, 2014 as compared to June 30, 2013. We capitalized approximately $3.9 million and $2.9 million in interest expense to undeveloped oil and natural gas properties during the three months ended June 30, 2014 and June 30, 2013, respectively. This increase in capitalized interest in the 2014 period was the result of an increase in our undeveloped oil and natural gas properties. As of June 30, 2014, we had $40.0 million of total debt outstanding under our revolving credit facility and, as of June 30, 2013, we had no debt outstanding under our revolving credit facility. Total weighted debt outstanding under our facility was $14.5 million for the three months ended June 30, 2014. As of June 30, 2014, amounts borrowed under our revolving credit facility bore interest at the eurodollar rate of 1.66%. Income Taxes. As of June 30, 2014, we had a net operating loss carry forward of approximately $4.2 million, in addition to numerous temporary differences, which gave rise to a net deferred tax liability. Periodically, management performs a forecast of our 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 June 30, 2014, a valuation allowance of $2.6 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. We recognized an income tax expense of $31.5 million for the three months ended June 30, 2014. Comparison of the Six Months Ended June 30, 2014 and 2013 We reported net income of $130.4 million for the six months ended June 30, 2014 as compared to $88.4 million for the six months ended June 30, 2013. This 48% increase in period-to-period net income was due primarily to $84.8 million of income recognized from our equity method investment in Blackhawk, $121.7 million of income recognized from our equity method investment in Diamondback and a 250% increase in net production to 4,869,806 BOE from 1,390,842 BOE, partially offset by a 47% decrease in realized BOE prices to $47.71 from $89.92, a $13.3 million increase in lease operating expenses, a $16.2 million increase in midstream transportation, processing and marketing expenses, a $10.6 million increase in general and administrative expenses, an expense of $24.0 million for litigation settlements and a $27.0 million increase in income tax expense for the six months ended June 30, 2014 as compared to the six months ended June 30, 2013. Oil and Gas Revenues. For the six months ended June 30, 2014, we reported oil and natural gas revenues of $232.4 million as compared to oil and natural gas revenues of $125.1 million during the same period in 2013. This $107.3 million, or 86%, increase in revenues was primarily attributable to a 250% increase in net production to 4,869,806 BOE from 1,390,842 BOE, partially offset by a 47% decrease in realized BOE prices to $47.71 from $89.92 due to a shift in our production mix toward natural gas and NGLs and a 32% decrease in average natural gas prices for the six months ended June 30, 2014 as compared to the six months ended June 30, 2013. The following table summarizes our oil and natural gas production and related pricing for the six months ended June 30, 2014, as compared to such data for the six months ended June 30, 2013: 37



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Table of Contents Six months ended June 30, 2014 2013 Oil production volumes (MBbls) 1,436 1,052 Gas production volumes (MMcf) 16,634 1,734 Natural gas liquids production volumes (MGal) 27,774 2,084 Oil equivalents (MBOE) 4,870 1,391 Average oil price (per Bbl) $ 98.49$ 108.43 Average gas price (per Mcf) $ 3.24$ 4.76 Average natural gas liquids (per Gal) $ 1.33$ 1.31 Oil equivalents (per BOE) $ 47.71$ 89.92 Lease Operating Expenses. Lease operating expenses, or LOE, not including production taxes increased to $24.3 million for the six months ended June 30, 2014 from $11.1 million for the six months ended June 30, 2013. This increase was mainly the result of an increase in expenses related to contract pumpers, contract labor and field supervision, insurance, environmental services, location repairs, rentals and salt water disposal. Production Taxes. Production taxes increased slightly to $13.6 million for the six months ended June 30, 2014 from $13.3 million for the same period in 2013. This slight increase was primarily related to a 250% increase in production and changes in our product mix and production location. Midstream Transportation, Processing and Marketing Expenses. Midstream transportation, processing and marketing expenses increased by $16.2 million to $18.5 million for the six months ended June 30, 2014 from $2.3 million for the same period in 2013. This increase was primarily attributable to 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 $112.9 million for the six months ended June 30, 2014, and consisted of $112.3 million in depletion of oil and natural gas properties and $0.6 million in depreciation of other property and equipment, as compared to total DD&A expense of $51.1 million for the six months ended June 30, 2013. 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 $19.9 million for the six months ended June 30, 2014 from $9.3 million for the six months ended June 30, 2013. This $10.6 million increase was due to an increase in salaries, stock compensation expenses and benefits resulting from an increased number of employees, increases in corporate fees, computer support, travel expense, consulting fees and franchise tax expense, partially offset by an increase in general and administrative costs related to exploration and development activity capitalized to the full cost pool. Accretion Expense. Accretion expense increased slightly to $0.4 million for the six months ended June 30, 2014 from $0.3 million for the same period in 2013. Interest Expense. Interest expense decreased to $6.3 million for the six months ended June 30, 2014 from $6.8 million for the six months ended June 30, 2013 due primarily to an increase in the amount of interest capitalized in the six months ended June 30, 2014 as compared to the same period in 2013. We capitalized approximately $6.2 million and $5.5 million in interest expense to undeveloped oil and natural gas properties during the six months ended June 30, 2014 and June 30, 2013, respectively. This increase in capitalized interest during the 2014 period was the result of an increase in our undeveloped oil and natural gas properties. As of June 30, 2014, we had $40.0 million of total debt outstanding under our revolving credit facility and, as of June 30, 2013, we had no debt outstanding under our revolving credit facility. Total weighted debt outstanding under our facility was $7.3 million for the six months ended June 30, 2014. As of June 30, 2014, amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate of 1.66%. Income Taxes. As of June 30, 2014, we had a net operating loss carry forward of approximately $4.2 million, in addition to numerous temporary differences, which gave rise to a net deferred tax liability. Periodically, management performs a forecast of 38



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our 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 June 30, 2014, a valuation allowance of $2.6 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. We recognized an income tax expense of $80.7 million for the six months ended June 30, 2014.

Liquidity and Capital Resources Overview. Historically, our primary sources of funds have been cash flow from our producing oil and natural gas properties, borrowings under our credit facility and the issuances of equity and debt securities. Our ability to access any of these sources of funds can be significantly impacted by decreases in oil and natural gas prices or oil and natural gas production. In 2013, we received an aggregate of $733.8 million from the sale of shares of our common stock. In addition, we received an aggregate of $192.7 million in net proceeds from the sale of shares of our Diamondback common stock in 2013. On June 24, 2014, we sold 1,000,000 shares of our Diamondback common stock in an underwritten public offering. The shares were sold to the public at $90.04 per share. We received an approximately $89.1 million in net proceeds from the sale of our shares of Diamondback common stock in this offering. Net cash flow provided by operating activities was $201.5 million for the six months ended June 30, 2014 as compared to net cash flow provided by operating activities of $73.5 million for the same period in 2013. This increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to a 250% increase in our net BOE production and proceeds of $84.8 million from the sale of Blackhawk's equity interest in Ohio Gathering Company, LLC and Ohio Condensate Company, LLC, partially offset by a 47% decrease in net realized BOE prices. Net cash used in investing activities for the six months ended June 30, 2014 was $624.8 million as compared to $384.5 million for the same period in 2013. During the six months ended June 30, 2014, we spent $673.0 million in additions to oil and natural gas properties, of which $98.8 million was spent on our 2014 drilling and recompletion programs, $260.2 million was spent on expenses attributable to the wells drilled and recompleted during 2013, $3.2 million was spent on compressors and other facility enhancements, $4.2 million was spent on plugging costs, $101.1 million was spent on lease related costs, primarily the acquisition of leases in the Utica Shale and $176.2 million was spent on the acquisition of producing properties and non-producing leasehold interests in the Rhino acquisition, with the remainder attributable mainly to capitalized general and administrative expenses. In addition, $16.6 million was invested in Grizzly and $22.6 million was invested in our other equity investments during the six months ended June 30, 2014. We also received approximately $89.1 million from the sale of shares of our Diamondback common stock during the six months ended June 30, 2014. During the six months ended June 30, 2014, we used cash from operations and proceeds from our 2013 equity offerings for our investing activities. Net cash provided by financing activities for the six months ended June 30, 2014 was $39.6 million as compared to net cash provided by financing activities of $358.3 million for the same period in 2013. The 2014 amount provided by financing activities is primarily attributable to borrowings under our revolving credit facility. Credit Facility. On December 27, 2013, we entered into an Amended and Restated Credit Agreement with The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and the other lenders, which we refer to as the amended and restated credit agreement. The amended and restated credit agreement provides for a maximum facility amount of $1.5 billion and matures on June 6, 2018. On April 23, 2014, we entered into a first amendment to the amended and restated credit agreement. The first amendment increased the letter of credit sublimit from $20.0 million to $70.0 million and provided for an increase in the borrowing base availability from $150.0 million to $275.0 million. The first amendment also made certain changes to the lenders and their respective lending commitments thereunder. As of June 30, 2014, approximately $40.0 million of indebtedness was outstanding under our revolving credit facility. As of June 30, 2014, total funds available under our amended and restated credit agreement, after giving effect to an aggregate of $36.7 million of letters of credit, was $198.3 million. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries guarantee our obligations under our revolving credit facility. 39



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Advances under our revolving credit facility, as amended, may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.50% to 1.50%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its "prime rate," and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.50% to 2.50%, plus (2) the London interbank offered rate that appears on Reuters Screen LIBOR01 Page for deposits in U.S. dollars, or, if such rate is not available, the offered rate on such other page or service that displays the average British Bankers Association Interest Settlement Rate for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the "London Interbank Offered Rate" for deposits in U.S. dollars. At June 30, 2014, amounts borrowed under the revolving credit facility bore interest at the eurodollar rate (1.66%). Our amended and restated credit agreement contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries' ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; make investments; make fundamental changes; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with their affiliates. The negative covenants are subject to certain exceptions as specified in our revolving credit facility. Our revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of funded debt to EBITDAX (net income, excluding any non-cash revenue or expense associated with swap contracts resulting from ASC 815, plus without duplication and to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) non-cash losses from minority investments, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings, and less non-cash income attributable to equity income from minority investments) for a twelve-month period may not be greater than 2.00 to 1.00; and (2) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in compliance with these financial covenants at June 30, 2014. Senior Notes. On October 17, 2012, we issued $250.0 million in aggregate principal amount of our 7.75% Senior Notes due 2020, or the October Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act under an indenture among us, our subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee. On December 21, 2012, we issued an additional $50.0 million in aggregate principal amount of our 7.75% Senior Notes due 2020, or the December Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The December Notes were issued as additional securities under the existing senior note indenture. The December Notes and the October Notes are treated as a single class of debt securities under the senior note indenture and are referred to collectively herein as the "Notes". We used a portion of the net proceeds from the October Notes Offering to repay all amounts outstanding at such time under our revolving credit facility. We used the remaining net proceeds of the October Notes Offering and the net proceeds of the December Notes Offering for general corporate purposes, which includes funding a portion of our 2013 capital development plan. In October 2013, as required by the terms of the senior note indenture, we exchanged the October Notes and the December Notes for $300.0 million aggregate principal amount of 7.75% senior notes due 2020 having substantially identical terms except that the exchange notes were registered under the Securities Act of 1933, as amended. We did not receive any proceeds from the issuance of the exchange note. Under the senior note indenture, interest on the Notes accrues at a rate of 7.75% per annum on the outstanding principal amount from October 17, 2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. The Notes are senior unsecured obligations and rank equally in the right of payment with all of our other senior indebtedness and senior in right of payment to any of our future subordinated indebtedness. All of our existing and future restricted subsidiaries that guarantee our secured revolving credit facility or certain other debt guarantee the Notes, provided, however, that the Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of our future unrestricted subsidiaries. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral 40



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securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the Notes. We may redeem some or all of the Notes at any time on or after November 1, 2016, at the redemption prices listed in the senior note indenture. Prior to November 1, 2016, we may redeem the Notes at a price equal to 100% of the principal amount plus a "make-whole" premium. In addition, prior to November 1, 2015, we may redeem up to 35% of the aggregate principal amount of the Notes with the net proceeds of certain equity offerings, provided that at least 65% of the aggregate principal amount of the Notes initially issued remains outstanding immediately after such redemption. If we experience a change of control (as defined in the senior note indenture), we will be required to make an offer to repurchase the Notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use the proceeds in a manner specified in the senior note indenture, we will be required to use the remaining proceeds to make an offer to repurchase the Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. The senior note indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of our subsidiaries as unrestricted subsidiaries. Capital Expenditures. Our recent capital commitments have been primarily for the execution of our drilling programs, for acquisitions (primarily in the Utica Shale), to fund Grizzly's delineation drilling program and initial preparation of the Algar Lake facility and for investments in entities that may provide services to facilitate the development of our acreage. Our strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing properties, subject to economic and industry conditions, (2) pursue acquisition and disposition opportunities and (3) pursue business integration opportunities. Of our net reserves at December 31, 2013, 35.2% were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those activities. From January 1, 2014 through August 1, 2014, we spud 47 gross (34 net) wells in the Utica Shale. We currently expect our 2014 capital expenditures to be $634.0 million to $676.0 million to drill 85 to 95 gross (68 to 76 net) wells on our Utica Shale acreage. In addition, we currently expect to spend $375.0 million to $425.0 million in 2014 to acquire additional acreage in the Utica Shale. From January 1, 2014 through August 1, 2014, we recompleted 60 existing wells and spud 17 new wells at our WCBB field. We currently intend to drill 22 to 24 new wells during 2014 at our WCBB field for aggregate estimated drilling and recompletion expenditures during 2014 of $42.0 million to $45.0 million. In our Hackberry fields, from January 1, 2014 through August 1, 2014, we recompleted 35 existing wells and spud nine new wells. We currently intend to drill ten to twelve wells in our Hackberry fields in 2014. Total capital expenditures for our Hackberry fields during 2014 are estimated to be approximately $24.0 million to $26.0 million. From January 1, 2014 through August 1, 2014, no new wells were spud on our Niobrara Formation acreage. We do not currently anticipate any capital expenditures in the Niobrara Formation in 2014. As of June 30, 2014, our net investment in Grizzly was approximately $203.4 million. Our capital requirements in 2014 related to Grizzly's activities are currently estimated to be approximately $15.0 million to $20.0 million. We had capital expenditures of $1.6 million during the six months ended June 30, 2014 related to our interests in Thailand. We do not currently anticipate any additional capital expenditures in Thailand in 2014. 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 41



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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, Stingray Cementing and 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 and 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 Midstream 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, which owns and operates drilling rigs and related equipment. Also in 2011, we acquired a 25% interest in 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. In the year ended December 31, 2013, we invested approximately $10.0 million in these entities. In the six months ended June 30, 2014, we invested approximately $21.0 million in these entities, and we expect to invest approximately $20.0 million to $23.0 million in these entities in 2014. We are currently evaluating the possibility of contributing our interests in Stingray Energy, Stingray Pressure Pumping, Stingray Cementing, Stingray Logistics, Bison and Muskie to a newly formed limited partnership. The holders of the other interests in these entities would also contribute their interests in these and other entities to the limited partnership which would undertake an initial public offering. A registration statement on Form S-1 has been submitted to the SEC on a confidential basis in connection with these entities, and we may choose to pursue an initial public offering of some or all of these entities later this year subject to market conditions. In January 2014, Blackhawk completed the sale of its equity interests in Ohio Gathering Company, LLC and Ohio Condensate Company, LLC for a purchase price of $190.0 million, of which we received $84.8 million in net proceeds. Our total capital expenditures for 2014 are currently estimated to be in the range of $715.0 million to $767.0 million. In addition, we currently expect to spend $375.0 million to $425.0 million in 2014 to acquire additional Utica Shale acreage, which includes the $184.0 million acquisition of approximately 8,000 net acres from Rhino in March 2014. Our total capital expenditures for the six months ended June 30, 2014 were approximately $230.4 million, excluding our Utica shale acreage acquisition. Approximately 88% of our 2014 estimated capital expenditures are currently expected to be spent in the Utica Shale. This range is up from the $513.5 million spent on 2013 activities, excluding Utica leasehold acquisitions, primarily due to the significant increase in our acreage position in the Utica Shale and our contemplated Utica development plans. We intend to continue to monitor pricing and cost developments and make adjustments to our future capital expenditure programs as warranted. We believe that our cash on hand, cash flow from operations, sales of our Diamondback common stock, and borrowings under our amended and restated credit agreement will be sufficient to meet our normal recurring operating needs and capital requirements for the next twelve months. In the event we elect to further expand or accelerate our drilling program or pursue additional acquisitions, or Grizzly's oil sands projects are accelerated, we may be required to obtain additional funds which we would seek to do through traditional borrowings, offerings of debt or equity securities or other means, including the sale of assets. We regularly evaluate new acquisition opportunities. Needed capital may not be available to us on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions that may be favorable to us. Commodity Price Risk The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past six years, the West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per barrel in December 2008 to a high of $145.31 per barrel in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per million British thermal units, or MMBtu, in September 2009 to a high of $13.31 per MMBtu in July 2008. On August 1, 2014, the West Texas Intermediate posted price for crude oil was $97.88 per barrel and the Henry Hub spot market price of natural gas was $3.80 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. To mitigate the effects of commodity price fluctuations on our oil and natural gas production, we had the following open fixed price swaps and swaptions at June 30, 2014: 42



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Table of Contents Volume Weighted Average (barrels Price ($ per per day) Bbl) Fixed Price Swaps: July 2014 - December 2014 2,000 $ 101.50 Volume Weighted (MMBtu per Average Price day) ($ per MMBtu) Fixed Price Swaps and Swaptions: July 2014 - December 2014 155,000 $ 4.07 January 2015 - December 2015 175,000 $ 4.08 January 2016 - March 2016 105,000 $ 4.04 April 2016 95,000 $ 4.04



Under the 2014 contracts, we have hedged approximately 59% to 67% of our expected 2014 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These fixed price swaps are recorded at fair value pursuant to FASB ASC 815 and related pronouncements.

Commitments

In connection with our acquisition in 1997 of the remaining 50% interest in the WCBB properties, we assumed the seller's (Chevron) obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until our abandonment obligations to Chevron have been fulfilled. Beginning in 2009, we could access the trust for use in plugging and abandonment charges associated with the property, but have not yet done so. As of June 30, 2014, the plugging and abandonment trust totaled approximately $3.1 million. At June 30, 2014, we have plugged 378 wells at WCBB since we began our plugging program in 1997, which management believes fulfills our current minimum plugging obligation. Contractual and Commercial Obligations We have various contractual obligations in the normal course of our operations and financing activities. There have been no material changes to our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2013. Off-balance Sheet Arrangements We had no off-balance sheet arrangements as of June 30, 2014. New Accounting Pronouncements In April 2014, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2014-08: Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360) - Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of a discontinued operation. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. The ASU is effective for annual and interim periods beginning after December 15, 2014, 43



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however, early adoption is permitted. We early adopted this ASU on a prospective basis beginning with the second quarter of 2014. The adoption did not have a material impact on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new standard is for the recognition of revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which the company expects to be entitled in exchange for those goods or services. The new standard will also result in enhanced revenue disclosures, provide guidance for transactions that were not previously addressed comprehensively and improve guidance for multiple-element arrangements. The ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those years, using either a full or a modified retrospective application approach. We are in the process of evaluating the impact on our consolidated financial statements.


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