Exhibit 99.3

The following discussion and analysis should be read in conjunction with our selected historical consolidated financial data and our accompanying consolidated financial statements and the notes to those financial statements included elsewhere in this report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Overview

We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas in the United States. We own interests in 1,575 producing oil and natural gas wells (859.7 net to us) and we operate 952 of these wells. In managing our business, we are concerned primarily with maximizing return on our stockholders’ equity. To accomplish this goal, we focus on profitably increasing our oil and natural gas reserves and production.

In 2011, we acquired an undeveloped acreage position and some producing oil wells in Gaines and Reeves Counties in West Texas. We operated these properties, which we designated as our West Texas region, through May 2013 when we sold all of these properties for total proceeds of $823.1 million. Accordingly, we are presenting our West Texas operations as discontinued operations in our financial statements for all periods presented. Unless indicated otherwise, the amounts in the accompanying tables and discussion relate to our continuing operations.

Our growth is driven primarily by acquisition, development and exploration activities. In 2015 our growth in natural gas production and proved reserves was primarily driven by our successful drilling activities. Under our current drilling budget, we plan to spend approximately $98.0 million in 2016 for development and exploration activities, which will primarily be focused on natural gas projects. We are currently planning to drill nine horizontal natural gas wells (7.5 net to us) in 2016, targeting the Haynesville/Bossier shales. The actual number of wells that we drill will depend on oil and natural gas prices.

We use the successful efforts method of accounting, which allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration activities. Accordingly, our exploration costs consist of costs we incur to acquire and reprocess 3-D seismic data, impairments of our unevaluated leasehold where we were not successful in discovering reserves and the costs of unsuccessful exploratory wells that we drill.

We generally sell our oil and natural gas at current market prices at the point our wells connect to third party purchaser pipelines or terminals. We have entered into certain transportation and treating agreements with midstream and pipeline companies to transport a substantial portion of our natural gas production in North Louisiana to long-haul gas pipelines. We market our products several different ways depending upon a number of factors, including the availability of purchasers for the product, the availability and cost of pipelines near our wells, market prices, pipeline constraints and operational flexibility. Accordingly, our revenues are heavily dependent upon the prices of, and demand for, oil and natural gas. Oil and natural gas prices have historically been volatile and are likely to remain volatile in the future. Oil and natural gas prices have declined substantially since June 2014 and have continued to decline into early 2016.

Our operating costs are generally comprised of several components, including costs of field personnel, insurance, repair and maintenance costs, production supplies, fuel used in operations, transportation costs, workover expenses and state production and ad valorem taxes.

Like all oil and natural gas exploration and production companies, we face the constant challenge of replacing our reserves. Although in the past we have offset the effect of declining production rates from existing properties through successful acquisition and drilling efforts, there can be no assurance that we will be able to continue to offset production declines or maintain production at current rates through future acquisitions or drilling activity. Our future growth will depend on our ability to continue to add new reserves in excess of production.

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Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and natural gas, and operating safety. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may have an adverse effect on our business, results of operations and financial condition. Applicable environmental regulations require us to remove our equipment after production has ceased, to plug and abandon our wells and to remediate any environmental damage our operations may have caused. The present value of the estimated future costs to plug and abandon our oil and gas wells and to dismantle and remove our production facilities is included in our reserve for future abandonment costs, which was $20.1 million as of December 31, 2015.

Prices for crude oil and natural gas have been highly volatile, and we are currently experiencing a period of extraordinarily low prices primarily due to an oversupply of crude oil and natural gas. As prices remain low, we will continue to experience low revenues and cash flows. We expect our oil production to decline in the future until we resume drilling on these properties. We expect our natural gas production to decline in the future to the extent that we do not offset this decline from production from the new wells we plan to drill in 2016 and future periods. Depending upon future prices and our production volumes, our cash flows from our operating activities may not be sufficient to fund our capital expenditures, and we will need to either curtail drilling activity or we may seek additional borrowings which would increase our interest expense in 2016 and in future periods.

We recognized significant impairments of our proved oil and gas properties in 2015. We may need to recognize further impairments if oil and natural gas prices remain low, and as a result, the expected future cash flows from these properties becomes insufficient to recover their carrying value. Specifically, as part of the impairment review performed at December 31, 2015, we observed that a decline in excess of 30% for our future cash flow estimates for our Eagleville field in South Texas could result in an additional impairment being recorded in an amount that could be at least $130.0 million. In addition, we may recognize additional impairments of our unevaluated oil and gas properties should we determine that we no longer intend to retain these properties for future oil and natural gas development.

Results of Operations

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Our operating data for 2014 and 2015 is summarized below:

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Oil and gas sales. Our oil and gas sales decreased $302.8 million (55%) in 2015 to $252.4 million from $555.2 million in 2014. Oil sales decreased by $247.1 million (63%) from 2014 while our natural gas sales decreased by $55.7 million (34%) from 2014. The decrease in oil sales was attributable to the 28% decline in oil production and a 49% decrease in our realized oil price in 2015. Our natural gas production increased by 20% from 2014 while our realized natural gas price decreased by 45%. Our drilling activity in the Haynesville and Bossier shale fields in East Texas and North Louisiana generated the natural gas production growth.

Production taxes. Production taxes decreased $13.5 million or 57% to $10.3 million in 2015 from $23.8 million in 2014. The decrease in 2015 is due to the 63% decline in our oil sales during the year. Much of our natural gas sales in 2014 and 2015 qualified for temporary exemption from state production taxes.

Gathering and transportation. Gathering and transportation costs in 2015 increased $1.4 million (11%) to $14.3 million as compared to $12.9 million in 2014 due to the 20% increase in natural gas we produced during 2015. Gathering and transportation per Mcf produced improved from 2014 as the additional volumes produced in the Haynesville shale properties allowed us to lower our unit transportation costs.

Lease operating expenses. Our lease operating expenses, including ad valorem taxes, of $64.5 million in 2015 were $4.2 million or 7% higher than our operating expenses of $60.3 million in 2014. Our lease operating expense per Mcfe produced rose by 6% to $0.97 per Mcfe in 2015 as compared to $0.92 per Mcfe in 2014. The increase in operating costs mainly reflects the higher lifting costs associated with our oil wells including additional costs incurred related to adding artificial lift to many of our producing oil wells.

Exploration expense. We incurred $70.7 million in exploration expense in 2015 as compared to $19.4 million in 2014. Exploration expense in 2015 consisted of $69.0 million in impairments of unevaluated leasehold costs and $1.7 million in rig termination fees. Our 2014 exploration cost consisted of $11.8 million in dry hole costs, $6.7 million in rig termination fees, $0.5 million of impairments of unevaluated leasehold costs and $0.4 million for the acquisition of seismic data.

Depreciation, depletion and amortization expense (“DD&A”). DD&A of $321.3 million decreased by $57.0 million (15%) from DD&A of $378.3 million in 2014. Our DD&A rate per Mcfe produced averaged $4.84 in 2015 as compared to $5.74 for 2014. The decrease in DD&A expense and the DD&A rate primarily resulted from higher production from our lower cost natural gas properties.

General and administrative expenses. General and administrative expense of $23.5 million for 2015 was 27% lower than general and administrative expense of $32.4 million for 2014 primarily due to lower employee compensation in 2015 including stock based compensation which decreased to $8.1 million in 2015 as compared to $10.7 million in 2014.

Impairment of oil and gas properties. We assess the need for impairment of the capitalized costs for our oil and gas properties on a property basis. During 2015, with the substantial decline in management’s estimates of future oil and natural gas prices, we recognized an impairment charge of $801.3 million on our oil and gas properties. During 2014 we recognized an impairment charge of $60.3 million.

Derivative financial instruments. We utilized oil and natural gas price swaps to manage our exposure to commodity prices and protect returns on investment from our drilling activities. We had gains of $2.7 million and $8.2 million on derivative financial instruments in 2015 and 2014, respectively. Our total net cash received from derivative financial instruments was $1.2 million and $9.1 million in 2015 and 2014, respectively.

The following tables present our oil and natural gas prices before and after the effect of cash settlements of our derivative financial instruments:

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Interest expense. Interest expense increased $60.0 million (102%) to $118.6 million in 2015 from interest expense of $58.6 million in 2014. The increase was primarily related to the refinancing of our bank credit facility with 10% secured senior notes in March 2015 and a reduction in the interest we capitalized in 2015. We issued $700.0 million of senior secured notes in March 2015. We capitalized interest of $0.9 million and $10.2 million in 2015 and 2014, respectively.

Income taxes. The benefit from income taxes from continuing operations increased in 2015 to $154.4 million from $24.7 million in 2014 due to the higher net loss in 2015. Our effective tax rate of 12.9% in 2015 differed from the federal income tax rate of 35% primarily due to a valuation allowance on deferred tax assets of $282.9 million.

Net loss. We reported a loss of $1.0 billion or $113.53 per share for 2015 as compared to a loss of $57.1 million or $6.20 per share for 2014. The loss in 2015 was primarily due to the oil and gas property impairment charges recognized, the loss on sale of oil and gas properties, lower oil and natural gas prices, higher exploration costs and higher interest expense. The net loss in 2014 was primarily due to impairments of proved and unproved properties, and other exploration costs.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Our operating data for 2013 and 2014 is summarized below:

Oil and gas sales. Our oil and gas sales increased $134.9 million (32%) in 2014 to $555.2 million from $420.3 million in 2013. Oil sales in 2014 increased by $157.9 million (68%) from 2013 while our natural gas sales decreased by $23.0 million (12%) from 2013. The increase in oil sales was attributable to the 86% growth in oil production offset by a 10% decrease in our realized oil prices in 2014. Our drilling activity in the Eagleville and Giddings fields in South Texas principally generated the growth in the oil production. With limited drilling in our natural gas properties in 2014, our natural gas production fell by 29% from 2013 while our realized natural gas prices increased by 23%.

Production taxes. Production taxes increased $9.3 million or 64% to $23.8 million in 2014 from $14.5 million in 2013. The increase in 2014 was due to the 68% growth in our oil sales during the year. Much of our natural gas sales in 2013 and 2014 qualified for a temporary exemption from state production taxes.

Gathering and transportation. Gathering and transportation costs in 2014 decreased $4.3 million (25%) to $12.9 million as compared to $17.2 million in 2013 due to the lower natural gas volumes that we produced in North Louisiana in 2014.

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Lease operating expenses. Our lease operating expenses, including ad valorem taxes, of $60.3 million in 2014 were $7.5 million or 14% higher than our operating expenses of $52.8 million in 2013. Our lease operating expense per Mcfe produced increased by 21% to $0.92 per Mcfe in 2014 as compared to $0.76 per Mcfe in 2013. The increase in operating costs mainly reflects our growing oil production. Our oil wells are typically more costly to operate on a per Mcfe basis than our natural gas wells. The increase in our per unit costs is also partially attributable to the lower production on a Mcfe basis. Oil production comprised 39% of our total production in 2014 as compared to 20% in 2013.

Exploration expense. We incurred $19.4 million in exploration expense in 2014 as compared to $33.4 million in 2013. Exploration expense in 2014 consisted of $11.8 million in dry hole costs, $6.7 million in rig termination fees, $0.5 million of impairments of unevaluated leasehold costs and $0.4 million for the acquisition of seismic data. Our 2013 exploration cost consisted of $33.0 million of impairments of unevaluated leasehold costs and $0.4 million for the acquisition of seismic data.

Depreciation, depletion and amortization expense. DD&A of $378.3 million increased by $41.2 million (12%) from DD&A of $337.1 million in 2013. Our DD&A rate per Mcfe produced averaged $5.74 in 2014 as compared to $4.83 for 2013. The increase in DD&A primarily resulted from the increased development costs per Mcfe associated with the oil wells drilled in 2014 and 2013.

General and administrative expenses. General and administrative expense of $32.4 million for 2014 was 7% lower than general and administrative expense of $34.8 million for 2013. The decrease is primarily related to stock-based compensation which decreased by $2.1 million to $10.7 million in 2014 as compared to $12.8 million in 2013.

Impairment of oil and gas properties. We recorded impairments to our oil and gas properties of $60.3 million and $0.7 million in 2014 and 2013, respectively. These impairments relate to older, conventional oil and gas properties with declining production and limited potential for future investments.

Derivative financial instruments. We utilized oil price swaps to manage our exposure to oil prices and protect returns on investment from our drilling activities in 2013 and 2014. We had a gain of $8.2 million and a loss of $8.4 million on derivative financial instruments in 2014 and 2013, respectively. Our total net cash received from derivative financial instruments was $9.1 million in 2014 and $2.3 million in 2013.

The following table presents our crude oil equivalent prices before and after the effect of cash settlements of our derivative financial instruments:

Interest expense. Interest expense decreased $14.6 million (20%) to $58.6 million in 2014 from interest expense of $73.2 million in 2013. The decrease was primarily related to lower interest expense due to the retirement in September 2013 of our 8 ³⁄₈% senior notes due in 2017. We capitalized interest of $10.2 million and $4.7 million in 2014 and 2013, respectively, which reduced interest expense. We had interest expense allocated to discontinued operations of $8.4 million in 2013 of which $2.0 million was capitalized. Average borrowings under our bank credit facility increased to $319.2 million in 2014 as compared to $201.5 million for 2013 and the average interest rate on the outstanding borrowings under our bank credit facility of 2.0% in 2014 was lower than the interest rate of 2.6% in 2013. Interest expense related to our outstanding senior notes decreased by 21% due to the retirement of our 8 ³⁄₈% senior notes offset partially by the issuance an additional $100.0 million of our 7 ³⁄₄% senior notes in 2014.

Income taxes. The benefit from income taxes from continuing operations decreased in 2014 to $24.7 million from $56.2 million in 2013 due to the lower net loss from continuing operations in 2014. Our effective tax rate of 30.2% in 2014 differed from the federal income tax rate of 35% primarily due to the effect of nondeductible compensation, state income taxes and an increase in the valuation allowance for state income tax net operating loss carry forwards.

Net loss. We reported a net loss from continuing operations of $57.1 million or $6.20 per share for 2014 as compared to a loss of $106.7 million or $11.09 per share for 2013. The net loss in 2014 was primarily due to impairments of proved and unproved properties and other exploration costs. The loss in 2013 was due to impairments of proved and unproved properties and a loss on early extinguishment of debt.

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Net income from discontinued operations for 2013 of $147.8 million, or $15.36 per share, included a gain on the sale of our West Texas oil and gas properties of $230.0 million ($148.6 million after income taxes). Excluding the gain, the net loss from discontinued operations for the year ended December 31, 2013 was $0.8 million.

Liquidity and Capital Resources

Funding for our activities has historically been provided by our operating cash flow, debt or equity financings and asset dispositions. For 2015, our primary source of funds was operating cash flow, borrowings and net proceeds from asset sales. Cash provided by operating activities in 2015 of $30.1 million decreased $370.9 million from $401.0 million in 2014. Cash flow was lower than 2014 due to decreased revenues related to the decreased oil production and lower oil and gas prices along with higher interest expense from our senior notes issued in 2015. Our other primary source of funds in 2015 included net proceeds from our 10% senior secured notes offering of $683.8 million, $40.0 million of net borrowings under our bank credit facility and net proceeds from asset sales of $102.5 million.

In 2014, our primary source of funds was operating cash flow and borrowings. Cash provided by operating activities from continuing operations in 2014 of $401.0 million increased $132.0 million (49%) from $269.0 million in 2013 primarily due to the higher revenues related to increased oil production and higher natural gas prices in 2014. Our other primary source of funds during 2014 included $103.3 million of proceeds from an additional issuance of our 7 ³⁄₄% senior notes and $165.0 million of borrowings under our bank credit facility.

Our primary need for capital, in addition to funding our ongoing operations, relates to the acquisition, development and exploration of our oil and gas properties and servicing and retirement of our debt. In 2015, our capital expenditures of $243.2 million represented a decrease of $345.4 million as compared to 2014 capital expenditures of $588.6 million, mainly due to our significant reduction in drilling activity during 2015 in response to the low commodity price environment throughout the year. During 2014 our capital expenditures of $588.6 million represented an increase of $107.7 million as compared to 2013 capital expenditures of $480.9 million due primarily to our high level of drilling activity during 2014.

Our capital expenditure activity related to our continuing operations is summarized in the following table:

The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments except for contracted drilling and completion services. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. We currently expect to spend approximately $98.0 million in 2016 for development and exploration projects to drill nine wells. Our operating cash flow and, therefore, our capital expenditures are highly dependent on oil and natural gas prices that we realize in 2016. We operate most of our properties and have significant discretion over the amount and timing of our future capital expenditures.

We do not have a specific acquisition budget for 2016 because the timing and size of acquisitions are unpredictable. We intend to use borrowings under our bank credit facility, or other debt or equity financings to the extent available, to finance such acquisitions. The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, oil and natural gas prices and other market conditions. Lack of access to the debt or equity markets due to general economic conditions could impede our ability to complete acquisitions.

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In March 2015, we issued $700.0 million of 10% senior secured notes (the “Secured Notes”) which are due on March 15, 2020. Interest on the Secured Notes is payable semi-annually on each March 15 and September 15. Net proceeds from the issuance of the Secured Notes of $683.8 million were used to retire our bank credit facility and for general corporate purposes. We also have outstanding (i) $376.1 million of 7 ³⁄₄% senior notes (the “2019 Notes”) which are due on April 1, 2019 and bear interest which is payable semi-annually on each April 1 and October 1 and (ii) $194.4 million of 9 ¹⁄₂% senior notes (the “2020 Notes”) which are due on June 15, 2020 and bear interest which is payable semi-annually on each June 15 and December 15. The Secured Notes are secured on a first priority basis equally and ratably with our revolving credit facility, subject to payment priorities in favor of the revolving credit facility by the collateral securing the revolving credit facility, which consists of, among other things, at least 80% of our and our subsidiaries’ oil and gas properties. The Secured Notes, the 2019 Notes and 2020 Notes are our general obligations and are guaranteed by all of our subsidiaries. Such subsidiary guarantors are 100% owned and all of the guarantees are full and unconditional and joint and several obligations. There are no restrictions on our ability to obtain funds from our subsidiaries through dividends or loans. As of December 31, 2015, we had no material assets or operations which are independent of our subsidiaries.

During 2015 we purchased $23.9 million in principal amount of the 2019 Notes and $105.6 million in principal amount of the 2020 Notes for an aggregate purchase price of $42.7 million. The gain of $82.4 million recognized on the purchase of the 2019 Notes and 2020 Notes and the loss resulting from the write-off of deferred loan costs associated with our prior bank credit facility of $3.7 million are included in the net gain on extinguishment of debt, which is reported as a component of other income (expense).

In connection with the issuance of the Secured Notes, we entered into a $50.0 million revolving credit facility with Bank of Montreal and Bank of America, N.A. The revolving credit facility is a four year commitment that matures on March 4, 2019. Indebtedness under the revolving credit facility is secured by substantially all of our and our subsidiaries’ assets and is guaranteed by all of our subsidiaries. Borrowings under the revolving credit facility bear interest at our option at either (1) LIBOR plus 2.5% or (2) the base rate (which is the higher of the administrative agent’s prime rate, the federal funds rate plus 0.5% or 30 day LIBOR plus 1.0%) plus 1.5%. A commitment fee of 0.5% per annum is payable quarterly on the unused credit line. The revolving credit facility contains covenants that, among other things, restrict the payment of cash dividends and repurchases of common stock, limit the amount of consolidated debt that we may incur and limit our ability to make certain loans, investments and divestitures. The only financial covenants are the maintenance of a current ratio of at least 1.0 to 1.0 and the maintenance of an asset coverage ratio of proved developed reserves to debt outstanding under the revolving credit facility of at least 2.5 to 1.0. We were in compliance with these covenants as of December 31, 2015.

We believe that our cash on hand and cash flow from operations and available borrowings under our bank credit facility is sufficient to fund our 2016 planned operating activities. If our plans or assumptions change or our assumptions prove to be inaccurate, we may be required to seek additional capital, including additional equity or debt financings to replace any liquidity that may be lost from low oil and natural gas prices. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.

The following table summarizes our aggregate liabilities and commitments by year of maturity:

Future interest costs are based upon the effective interest rates of our outstanding senior notes.

We have obligations to incur future payments for dismantlement, abandonment and restoration costs of oil and gas properties. These payments are currently estimated to be incurred primarily after 2020. We record a separate liability for the fair value of these asset retirement obligations, which totaled $20.1 million as of December 31, 2015.

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Federal and State Taxation

We have $558.7 million in U.S. federal net operating loss carryforwards. The utilization of $34.7 million of the U.S. federal net operating loss carryforward is limited to approximately $1.1 million per year pursuant to a prior change of control of an acquired company. Accordingly, as of December 31, 2014, a valuation allowance of $23.0 million, with a tax effect of $8.0 million, has been established for the estimated U.S. federal net operating loss carryforwards that will not be utilized as a result of the change in control. As of December 31, 2015, we have also established a valuation allowance of $775.3 million, with a tax effect of $271.4 million, against our other U.S. federal net operating loss carryforwards that are not subject a change in control, due to the uncertainty of generating future taxable income prior to the expiration of the carry-over period. In addition, as of December 31, 2015, we have established a valuation allowance of $957.7 million, with a tax effect of $49.8 million, against our Louisiana state net deferred tax assets due to the uncertainty of generating taxable income in the state of Louisiana prior to the expiration of the carry-over period. As of December 31, 2014, we had a valuation allowance of $742.2 million, with a tax effect of $38.6 million, against our Louisiana state deferred tax assets.

Future use of our net operating loss carryforwards may be limited in the event that a cumulative change in the ownership of our common stock by more than 50% occurs within a three-year period. Such a change in ownership could result in a substantial portion of our net operating loss carryforwards being eliminated or becoming restricted. We established a rights plan on October 1, 2015 to deter ownership changes that would trigger this limitation.

Our federal income tax returns for the years subsequent to December 31, 2011 remain subject to examination. Our income tax returns in one major state income tax jurisdiction remain subject to examination for the year ended December 31, 2008 and various periods subsequent to December 31, 2010. We currently believe that our significant filing positions are highly certain and that all of our other significant income tax filing positions and deductions would be sustained upon audit or the final resolution would not have a material effect on our consolidated financial statements. Therefore, we have not established any significant reserves for uncertain tax positions. Interest and penalties resulting from audits by tax authorities have been immaterial and are included in the provision for income taxes in the consolidated statements of operations.

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and use assumptions that can affect the reported amounts of assets, liabilities, revenues or expenses.

Successful efforts accounting. We are required to select among alternative acceptable accounting policies. There are two generally acceptable methods for accounting for oil and gas producing activities. The full cost method allows the capitalization of all costs associated with finding oil and natural gas reserves, including certain general and administrative expenses. The successful efforts method allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration projects. Costs related to exploration that are not successful are expensed when it is determined that commercially productive oil and gas reserves were not found. We have elected to use the successful efforts method to account for our oil and gas activities and we do not capitalize any of our general and administrative expenses.

Oil and natural gas reserve quantities. The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. The determination of whether impairments should be recognized on our oil and gas properties is also dependent on these estimates, as well as estimates of probable reserves. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve estimates are to some degree imprecise, the quantities and timing of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas prices may all differ materially from those assumed in these estimates. The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Any future downward revisions could adversely affect our financial condition, our future prospects and the value of our common stock.

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Impairment of oil and gas properties. We evaluate our properties on a field area basis for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Expected future cash flows are determined using estimated future prices based on market based forward prices applied to projected future production volumes. The projected production volumes are based on the property’s proved and risk adjusted probable oil and natural gas reserves estimates at the end of the period. At December 31, 2015, we excluded probable undeveloped reserves from our impairment analysis given our limited capital resources available for future drilling activities. The estimated future cash flows that we use in our assessment of the need for an impairment are based on a corporate forecast which considers forecasts from multiple independent price forecasts. Prices are not escalated to levels that exceed observed historical market prices. Costs are also assumed to escalate at a rate that is based on our historical experience, currently estimated at 2% per annum. The oil and natural gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of the average first day of the month historical price for the year. During 2015, our oil and natural gas price outlook declined significantly and our access to capital to develop our proved and probable undeveloped reserves was limited. Accordingly, we recognized impairment charges of $801.3 million to reduce the capitalized costs of our evaluated oil and natural gas properties. It is reasonably possible that our estimates of undiscounted future net cash flows attributable to its oil and gas properties may change in the future. The primary factors that may affect estimates of future cash flows include future adjustments, both positive and negative, to proved and appropriate risk-adjusted probable oil and gas reserves, results of future drilling activities, future prices for oil and natural gas, and increases or decreases in production and capital costs. As a result of these changes, there may be further impairments in the carrying values of our evaluated oil and gas properties. Specifically, as part of the impairment review performed at December 31, 2015, we observed that a decline in excess of 30% for our future cash flow estimates for our Eagleville field in South Texas could result in an additional impairment being recorded in an amount that could be at least $130.0 million. In addition, we may recognize additional impairments of our unevaluated oil and gas properties should we determine that we no longer intend to retain these propertied for future oil and natural gas development.

Income Taxes. The Company accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the future tax consequences attributable to the future utilization of existing tax net operating loss and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that the change in rate is enacted.

In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of our deferred income tax assets will be realized in the future. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. We believe that after considering all the available objective evidence, historical and prospective, with greater weight given to historical evidence, we are not able to determine that it is more likely than not that all of our deferred tax assets will be realized. As a result, in 2015 we established an additional valuation allowance of $775.3 million, with a tax effect of $271.4 million, for our estimated U.S. federal net operating loss carryforwards and other U.S. federal tax assets and an additional valuation allowance of $215.5 million, with a tax effect of $11.2 million, for our estimated Louisiana state net operating loss carryforwards that are not expected be utilized due to the uncertainty of generating taxable income prior to the expiration of the respective U.S. federal and Louisiana state carry-over periods. We will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

Stock-based compensation. We follow the fair value based method in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period.

Recent accounting pronouncements. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which supersedes nearly all existing revenue recognition guidance under existing generally accepted accounting principles. This new standard is based upon the principal that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted beginning with periods after December 15, 2016 and entities have the option of using either a full retrospective or modified approach to adopt ASU 2014-09. We are currently evaluating the new guidance and have not determined the impact this standard may have on our financial statements or decided upon the method of adoption.

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In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and sets rules for how this information should be disclosed in the financial statements. ASU 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods thereafter. Early adoption is permitted. We have elected to not adopt ASU 2014-15 early and do not expect adoption of ASU 2014-15 to have any impact on our consolidated financial condition, results of operations or cash flows.

Related Party Transactions

Along with M. Jay Allison, our Chairman and CEO, and Roland O. Burns, our President, Chief Financial Officer and a director, we formed an entity in 2010 in which we jointly owned and operated a private airplane. The entity was owned 80% by us and 10% by each of Messrs. Allison and Burns. Each party funded their respective share of the acquisition costs of the airplane in exchange for their ownership interest. This arrangement was approved by our audit committee and board of directors. In January 2015, we acquired from Messrs. Allison and Burns their collective 20% interest in the entity for aggregate consideration of $1,680,000, which amount was based upon the then fair market value of the airplane (the only asset owned by the entity). The airplane is leased to and managed by a third party operator. The airplane, which is intended to be used primarily for company business, also provides charter services to third parties. The termination of this related party relationship was approved by our audit committee and the board of directors in accordance with our policy on related party transactions. We have not entered into any other business transactions with our significant stockholders or any other related parties.

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