Exhibit 99.1

GMXR

FOR IMMEDIATE RELEASE

FOR ADDITIONAL INFORMATION CONTACT

Alan Van Horn

Manager, Investor Relations

405.254.5839

GMX RESOURCES INC. Announces Financial and Operational Results for the Fourth Quarter and Full Year Ended December 31, 2011

Oklahoma City, Oklahoma, Thursday, March 1, 2012. GMX RESOURCES INC., NYSE: ‘GMXR’ (the “Company” or “GMXR”), reports today on the Company’s financial and operating results for the fourth quarter and full year ended December 31, 2011.

The Company has scheduled a conference call for Thursday, March 1, 2012 at 8:00 a.m. CST (9:00 a.m. EST) to discuss the fourth quarter and full year ended December 31, 2011 financial and operating results. To access the call, domestic participants should dial (877) 303-9132 and international participants should dial (408) 337-0136 prior to the conference call start time. Please reference conference code 50981306. A telephonic replay of the call will be available after 11:00 a.m. EST on March 1, 2012 through March 15, 2012 and can be accessed using the following number and pass code: Toll free: (855) 859-2056 or (800) 585-8367 using pass code 50981306. A presentation pertaining to this call will be available on the Company’s website prior to the start of the call. www.gmxresources.com

Participants are encouraged to access the live audio webcast of the conference call through the following web link or by accessing the webcast through the Company’s website:

http://investor.shareholder.com/media/eventdetail.cfm?eventid=109365&CompanyID=GMXR&e=1&mediaKey=B6D3B9EAE6270A1344B4B56B803EF2BA

Company Highlights for the Fourth Quarter and Full Year Ended December 31, 2011

Transition to Liquids

Management Comments

Ken L. Kenworthy, Chief Executive Officer said: “We are establishing a momentum in our drilling program in North Dakota that will drive our transition to oil such that 40-50% of our 2012 revenue will primarily come from our Bakken development production. This is vital to our ability to increase our enterprise value. Our response to the continued fall in natural gas prices in 2010 was to acquire oil resources and direct our capital investments into oil development which provides greater rates of return in this economic environment. Our acquisition of approximately 75,000 acres in the Bakken and Niobrara will have a dramatic impact on our revenues; the evidence of this as already been seen in our fourth quarter oil production and revenues. We have assembled a top tier level of talent, established a meaningful operational footprint in the most competitive oil play in North America and successfully drilled and completed three Williston Basin wells during 2011. As of today we have a total of eleven wells in the Bakken. Our 2012 Bakken development will be focused in our McKenzie and Billings County, North Dakota acreage. This acreage has been de-risked through the drill bit by us and others.”

Kenworthy continued: “The near term outlook for natural gas pricing remains poor, and the obvious challenge for us and other companies who have been primarily natural gas producers has been the development of alternative strategies to combat the continued decline in natural gas pricing ironically caused by the tremendous success that we and others have had in developing shale gas resources. As an example, the eight long-lateral Haynesville/Bossier (“H/B”) horizontal wells completed in 2011, with lengths from 5,900’ to 7,000’ have been audited by DeGolyer MacNaughton (“D&M”) and received estimated ultimate recoveries (“EURs”) ranging from 5.4 Bcf to 6.9 with an average of 6.4 Bcf.”

Kenworthy concluded: “The precipitous drop in natural gas prices prompted us to take an unprecedented series of liquidity enhancing moves, including the exchange of our 2019 bonds for a new 2017 secured bonds with $100 million of new money, a volumetric production payment (“VPP”) involving a portion of our Haynesville production, monetizing our hedge portfolio book, retiring our bank revolver, selling non-core assets, subleasing our Texas-based rigs, and temporarily suspending H/B drilling. These transactions have provided a clear capital runway for our 2012 development plan. We are continuing to solve for additional liquidity. Based off the activity of other operators in the DJ Basin and new interest in our Niobrara acreage sale we remain optimistic in completing a partial sale. We remain vigilant to potential solutions concerning our 2013 convertible notes and we have six Bakken completions expected in the next 90 days which should provide our company a significant revenue boost and continue successful transformation to an oil producer.”

2012 Capital Expenditure Plan

The 2012 approved capital expenditure plan is $97 million (including capitalized interest expense and G&A), which will fund our oil focused drilling and development plans. In the Bakken, the Company expects to spend approximately $68 million and plans to complete 7.1 net wells in 2012. Decisions regarding the addition of a second drilling rig in the Bakken and the level of participation in the non-operated development of the Niobrara will be made based on available liquidity and drilling results.

Production Guidance for 2012

Revised production guidance for the first quarter 2012 is approximately 583,000 BOE, which includes an estimated 37,000 BBLs of oil, and 108,000 BBLs of NGLs. The revision to first quarter guidance is the result of reduction in the expected oil production due to availability of workover rigs. The Company maintains full year guidance and projects oil production to increase 300% from 92,837 BBLs during 2011 to approximately 373,000 during 2012, and for NGL production to increase 10% from 345,000 BBLs in 2011 to 378,000 BBLs in 2012; total production for 2012 is estimated to be approximately 2,311,000 BOE. Oil production in BBLs from the year-end 2011 to year-end 2013 is projected to have a compound annual growth rate of approximately 215% assuming a second rig is added in the third quarter of 2012 and a third rig is added in the third quarter of 2013. The production guidance is net of all committed VPP volumes.

Operations Recap

The following table summarizes our Bakken and Niobrara development as of March 1, 2012.

Bakken

Niobrara

Significant Accomplishments in 2011

Over the last 14 months, the Company has made many important accomplishments in connection with its strategic transformation from a concentrated natural gas producer into a more diversified energy company, currently focused on accelerating its oil production while improving liquidity in challenging market conditions.

Operational

Financial

Oil and Natural Gas Reserves

The following table shows the estimated net quantities of our proved reserves as of the dates indicated and the Estimated Future Net Revenues and Present Values attributable to total proved reserves at December 31. Proved reserves in the Williston Basin and Haynesville/Bossier were prepared by the independent reserve engineering firm DeGolyer and MacNaughton while our Cotton Valley Sands/Other reserves were prepared by MHA Petroleum Consultants Inc. All of our proved reserves are located in the United States:

The following table shows our total 2011 and 2010 proved reserves by area:

Proved Reserves-2011 SEC Pricing ^{(2) (3)}

Proved Reserves-2010 SEC Pricing

Financial Results for the three months and year ended December 31, 2011

The Company reported a net loss applicable to common shareholders of $79.8 million ($1.39 per basic and fully diluted share) and $218.6 million ($4.12 per basic and fully diluted share) for the three months and year ended December 31, 2011, respectively, compared to a net loss applicable to common shareholders of $149.0 million ($5.27 per basic and fully diluted share) and $146.0 million ($5.18 per basic and fully diluted share) for the three months and year ended December 31, 2010, respectively.

Adjusted net loss applicable to common shareholders, a non-GAAP measure adjusting for items set forth below, was $6.6 million and $15.0 million, or $0.12 and $0.28 per basic and fully diluted share, for the three months and year ended December 31, 2011, respectively. Adjusted net loss is provided as a supplemental financial measure. We believe adjusted net loss provides additional information regarding our operating financial performance and is beneficial to the investment community.

Adjusted net loss is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income applicable to common shareholders, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP.

The following table summarizes certain key operating and financial results for the three months and year ended December 31, 2011 compared to the three months and year ended December 31, 2010.

Summary Operating Data

Results of Operations for the Three Months Ended December 31, 2011 Compared to the Three Months Ended December 31, 2010

Oil and Natural Gas Sales. Oil and natural gas sales during the three months ended December 31, 2011 decreased 4% to $26.1 million compared to $27.2 million in the during the three months ended December 31, 2010. Oil and natural gas sales included gains from ineffectiveness of derivatives of $1.5 million and $0.1 million for the three months ended December 31, 2011 and 2010, and are the result of a difference in the fair value of our cash flow hedges and the fair value of the projected cash flows of a hypothetical derivative based on our expected sales point. The decrease in oil and natural gas sales was due to a 9% decrease in production on a Bcfe-basis and a decrease of 13% in the average realized price of natural gas, excluding ineffectiveness of hedging activities, offset by a 10% increase in oil prices. The average price per barrel of oil, per gallon of NGLs and Mcf of natural gas received (excluding ineffectiveness from derivatives) in the three months ended December 31, 2011 was $90.08, $1.05 and $4.19, respectively, compared to $81.99, $0.78 and $4.79, respectively, in the three months ended December 31, 2010. Our realized sales price for natural gas, excluding the effect of hedges of $1.27 and $1.45, for the three months ended December 31, 2011 and 2010, respectively, was approximately 82% and 88% of the average NYMEX closing contract price for the respective periods. During the three months ended December 31, 2011 and 2010 , the conversion of natural gas to NGLs produced an upgrade of approximately $1.22 per Mcf and $0.55 per Mcf, respectively, for every Mcf of natural gas produced. This additional value from the sale of NGLs was previously included in the realized price of our natural gas sales.

Production for the three months ended December 31, 2011 of 5.3 Bcfe, which includes the production of 0.45 Bcfe related to the VPP, was consistent with production for the three months ended December 31, 2010 of 5.3 Bcfe. During the first quarter of 2011, we began to separate and report the production and revenue from our NGLs, compared to prior periods in which we had included NGL production and revenues in our natural gas production and sales amounts. NGL production for the three months ended December 31, 2011 increased to 4,616 Mgals compared to 3,294 Mgals for the three months ended December 31, 2010, an increase of 40.1%. This increase is primarily due to new access to additional third party plants with higher efficiencies and recoveries of NGLs from our operated natural gas.

For the three months ended December 31, 2011, as a result of hedging activities, excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $5.6 million compared to an increase in natural gas sales of $6.8 million for the three months ended December 31, 2010. The effect of our derivative contracts on oil had no effect for the three months ended December 31, 2011 and 2010.

Lease Operations. Lease operations expense increased $1.9 million, or 78%, for the three months ended December 31, 2011 to $4.5 million, compared to $2.5 million for the three months ended December 31, 2010. Lease operations expense, on an equivalent unit of production basis, increased $0.38 per Mcfe, including VPP volumes, in the three months ended December 31, 2011 to $0.85 per Mcfe, including VPP volumes, compared to $0.47 per Mcfe for the three months ended December 31, 2010. The overall increase in lease operations expense is primarily related to a compression cost adjustment of $1.3 million on non-operated wells dating from 2009 to current from Penn Virginia Corporation recorded in the fourth quarter of 2011.

Production and Severance Taxes. The State of Texas grants an exemption of severance taxes for wells that qualify as “high cost” wells. Certain wells, including all of our H/B wells, qualify for full severance tax relief for a period of ten years or recovery of 50% of the cost of drilling and completions, whichever is less. As a result, refunds for severance tax paid to the State of Texas on wells that qualify for reimbursement are recognized as accounts receivable and offset severance tax expense for the amount refundable. Production and severance taxes was an expense of $0.3 million in the three months ended December 31, 2011 compared to an expense of $0.3 million in the three months ended December 31, 2010.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $3.2 million, or 24%, to $10.2 million in the three months ended December 31, 2011 compared to $13.4 million for the three months ended December 31, 2010. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.81 per Mcfe in the three months ended December 31, 2011 compared to $2.25 per Mcfe in the three months ended December 31, 2010. This decrease in the rate per Mcfe is due to impairment charges during 2011 reducing the Company’s oil and natural gas properties subject to amortization.

Impairment of oil and natural gas properties and assets held for sale. For the $78.0 million non-cash impairment charge recorded in the fourth quarter of 2011, $76.0 million was related to the impairment of oil and gas properties subject to the full cost ceiling test and $2.0 million was related to a change in value of assets held for sale. The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels, value of cash flow hedges, and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Any excess of the net book value is generally written off as an expense. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Natural gas represented

approximately 96% of the Company’s total proved reserves at the end of 2011, and as a result, a decrease in natural gas prices can significantly impact the Company’s ceiling test. Of the $76.0 million related to the non-cash impairment of oil and gas properties, $38.1 million resulted from the net book value of oil and gas properties exceeding the net present value of future net revenues, $33.9 million related to the monetization of cash flow hedges that were previously used in the full cost ceiling test and $4.0 million related to impairment on our acquisition cost of East Texas and North Louisiana undeveloped acreage outside of our primary development area being subject to the full cost method ceiling test and was based on the Company’s decision not to develop the acreage. The remaining $2.0 million of the $78.0 million non-cash impairment charge was related primarily to an impairment on rig related and equipment that was sold in 2011.

General and Administrative Expense. General and administrative expense for the three months ended December 31, 2011 was $6.6 million compared to $7.1 million for the three months ended December 31, 2010, a decrease of $0.5 million, or 7%. General and administrative expense per equivalent unit of production was $1.25 per Mcfe, including VPP volumes, for the fourth quarter of 2011 compared to $1.36 per Mcfe for the comparable period in 2010. The decrease in general and administrative expense for the three months ended December 31, 2011 compared to the three months ended December 31, 2010 was primarily due to cost cutting initiatives implemented during the fourth quarter of 2011 which included a reduction in employee related compensation and travel and entertainment expenses. Offsetting these decreases in the fourth quarter of 2011 was approximately $0.7 million of legal expenses related to the VPP transaction and other legal matters and approximately $0.6 million related to monetization of the Company’s hedges. General and administrative expenses include $0.8 million and $0.8 million of non-cash compensation expense as of the three months ended December 31, 2011 and 2010, respectively. Non-cash compensation represented 12% and 11% of total general and administrative expenses for the three months ended December 31, 2011 and 2010, respectively. General and administrative expense has not historically varied in direct proportion to oil and natural gas production because certain types of general and administrative expenses are non-recurring or fixed in nature.

Interest. Interest expense for the three months ended December 31, 2011 was $8.3 million compared to $5.0 million for the same period in 2010. For both the three months ended December 31, 2011 and 2010, interest expense includes non-cash interest expense of $1.6 million related to the accounting for convertible bonds, our share lending agreement and deferred premiums on derivative instruments. Cash interest expense for the three months ended December 31, 2011 and 2010 was $8.2 million and $3.3 million, respectively, of which $2.3 million and $0.8 million, respectively, was capitalized to properties not subject to amortization on the consolidated balance sheets. The increase in cash interest expense of $4.9 million was mainly due to the Company’s February issuance and sale of $200 million aggregate principal amount of our senior notes due 2019.

Income Taxes. Income tax for the three months ended December 31, 2011 was a provision of $0.1 million as compared to a provision of $2.1 million in the same period in 2010. The income tax provision recognized in the three months ended December 31, 2011 and 2010, respectively, was a result of a change in the valuation allowance on net deferred tax assets caused by a change in deferred tax liabilities primarily related to unrealized gains on derivative contracts designated as hedges where the mark-to-market change on the hedges, net of deferred taxes is recorded to other comprehensive income.

Net income to non-controlling interest. Net income to non-controlling interest increased to $1.1 million for the three months ended December 31, 2011 compared to $1.0 million for the three months ended December 31, 2010.

Net Income/Loss and Net Income/Loss Per Share. For the three months ended December 31, 2011 we reported a net loss applicable to common shareholders of $79.8 million and for the three months ended December 31, 2010, we reported a net loss applicable to common shareholders of $149.0 million. Net loss per basic and fully diluted share was $1.39 for the fourth quarter of 2011 compared to net loss per basic and fully diluted share of $5.27 for the fourth quarter of 2010. Weighted average-basic shares outstanding increased by 29,118,089 shares from 28,279,607 shares in the fourth quarter of 2010 to 57,397,696 shares in the fourth quarter of 2011. There were no dilutive shares for the three months ended December 31, 2011 and 2010, since the Company was in a loss position and all dilutive shares would have been antidilutive.

Results of Operations—Year ended December 31, 2011 Compared to Year ended December 31, 2010

Oil and Natural Gas Sales. Oil and natural gas sales during the year ended December 31, 2011 increased 21% to $116.7 million compared to $96.5 million during the year ended December 31, 2010. Oil and natural gas sales included gains (losses) from the ineffectiveness from derivatives of $0.1 million and $(1.3) million for the year ended December 31, 2011 and 2010, respectively, and are the result of a difference in the fair value of our cash flow hedges and the fair value of the projected cash flows of a hypothetical derivative based on our expected sales point. The increase in oil and natural gas sales was due to a 35% increase in production on a Bcfe-basis, a 20% increase in oil prices, a 24% increase in the average realized price of NGLs, offset by a 16% decrease in the average realized price of natural gas, excluding ineffectiveness of hedging activities. The average price per barrel of oil, per gallon of natural gas liquids NGLs and Mcf of natural gas received (excluding ineffectiveness from derivatives) in the year ended December 31, 2011 was $92.33, $0.98 and $4.50, respectively, compared to $76.77, $0.79 and $5.33, respectively, for the year ended December 31, 2010. Our realized sales price for natural gas, excluding the effect of hedges of $0.90 and $1.60, for the year ended December 31, 2011 and 2010, respectively, was approximately 89%

and 85% of the average NYMEX closing contract price for the respective periods. During the year ended December 31, 2011 and 2010 , the conversion of natural gas to NGLs produced an upgrade of approximately $0.67 per Mcf and $0.81 per Mcf, respectively, for every Mcf of natural gas produced. This upgrade in value was previously included in the realized price of our natural gas sales.

Production for the year ended December 31, 2011, increased to 24.0 Bcfe, which includes the production of 0.45 Bcfe related to VPP, compared to 17.5 Bcfe for the year ended December 31, 2010, an increase of 37%. We completed and brought on-line 8 H/B wells during 2011, which contributed to the increase in gas production for the period. During the first quarter of 2011, we began to separate and report the production and revenue from our NGLs, compared to prior periods in which we had included NGL production and revenues in our natural gas production and sales amounts. NGL production for the year ended December 31, 2011 decreased to 14,292 Mgals compared to 15,024 Mgals for the year ended December 31, 2010, a decrease of 4.9%. This decrease was due to a decrease in production in our non-Haynesville production for the year ended December 31, 2011, which has a higher NGL content compared to our H/B wells.

For the year ended December 31, 2011, as a result of hedging activities, excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $18.7 million compared to an increase in natural gas sales of $23.6 million for the year ended December 31, 2010. The effect of our derivative contracts on oil had a $(0.47) per barrel impact in 2011 and no impact in 2010.

Lease Operations. Lease operations expense increased $2.8 million, or 26%, for the year ended December 31, 2011 to $13.4 million, compared to $10.7 million for the year ended December 31, 2010. Lease operations expense on an equivalent unit of production basis decreased $0.05 per Mcfe for the year ended December 31, 2011 to $0.56 per Mcfe, including VPP volumes, compared to $0.61 per Mcfe for the year ended December 31, 2010. The decrease in lease operations expense on an equivalent unit basis resulted from an increase in H/B horizontal well production and cost control measures implemented by us during 2010 which lowered overall lease operating expense. With little to no incremental increase in lease operations cost from a Cotton Valley vertical well, the significantly larger amount of production from a H/B horizontal well will result in lower per unit lease operations costs. The overall increase in lease operations expense is primarily related to higher gathering costs plus an increase in salt water disposal expense related to the increase in production for the year ended December 31, 2011 compared to the year ended December 31, 2010.

Production and Severance Taxes. The State of Texas grants an exemption of severance taxes for wells that qualify as “high cost” wells. Certain wells, including all of our H/B wells, qualify for full severance tax relief for a period of ten years or recovery of 50% of the cost of drilling and completions, whichever is less. As a result, refunds for severance tax paid to the State of Texas on wells that qualify for reimbursement are recognized as accounts receivable and offset severance tax expense for the amount refundable. Production and severance taxes increased 61% to $1.2 million for the year ended December 31, 2011 compared to $0.7 million for the year ended December 31, 2010.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $12.2 million, or 32%, to $50.3 million for the year ended December 31, 2011 compared to $38.1 million for the year ended December 31, 2010. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.88 per Mcfe for both the years ended December 31, 2011 and 2010. The increase in the depreciation, depletion and amortization expense is due to the increase increase in production during 2011.

Impairment of oil and natural gas properties. For the $205.8 million non-cash impairment charge recorded in the year ended 2011, $196.4 million of the charge was related to the impairment of oil and gas properties subject to the full cost ceiling test and $9.3 million was related to a change in value of assets held for sale. The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels, value of cash flow hedges and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Any excess of the net book value is generally written off as an expense. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Natural gas represents 96% of the Company’s total proved reserves, and as a result, a decrease in natural gas prices can significantly impact the Company’s ceiling test. During the year ended December 31, 2011, the 12-month average of the first day of the month natural gas price decreased 6% from $4.38 per MMbtu at December 31, 2010 to $4.12 per MMbtu at December 31, 2011. Of the $196.4 million related to the impairment of oil and gas properties, $121.4 million resulted from the net book value of oil and gas properties exceeding the net present value of future net revenues, $52.3 million related to the monetization of the cash flow hedges that were used in the full cost ceiling test and $22.7 million related to the acquisition cost of East Texas and North Louisiana undeveloped acreage outside of our primary development area being subject to the full cost method ceiling test. Approximately $9.3 million of the $205.8 million impairment charge was related to impairment on the Company’s three drilling rigs and other inventory and equipment, previously classified in assets held for sale. The impairment on these assets was based on the sales price of the rigs sold in 2011.

General and Administrative Expense. General and administrative expense for the year ended December 31, 2011 was $28.9 million compared to $27.1 million for the year ended December 31, 2010, an increase of $1.8 million, or 6%. General and administrative expense per equivalent unit of production was $1.20 per Mcfe, including VPP volumes, for the year ended

December 31, 2011 compared to $1.56 per Mcfe for the comparable period in 2010. The overall increase in general and administrative expense for the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily due to approximately $1.3 million in expenses for the year ended December 31, 2011, legal fees related to the VPP, and other legal matters, as well as transaction fees related to the hedge monetization. General and administrative expenses include $3.7 million and $5.5 million of non-cash compensation expense as of the year ended December 31, 2011 and 2010, respectively. Non-cash compensation represented 13% and 20% of total general and administrative expenses for the year ended December 31, 2011 and 2010, respectively. General and administrative expense has not historically varied in direct proportion to oil and natural gas production because certain types of general and administrative expenses are non-recurring or fixed in nature.

Interest. Interest expense for the year ended December 31, 2011 was $31.9 million compared to $18.6 million for the same period in 2010. For the year ended December 31, 2011 and 2010, interest expense includes non-cash interest expense of $5.9 million and $6.5 million, respectively, related to the accounting for convertible bonds, our share lending agreement and deferred premiums on derivative instruments. Cash interest expense for the year ended December 31, 2011 and 2010 was $30.3 million and $12.0 million, respectively, of which $7.8 million and $2.6 million, respectively was capitalized to properties not subject to amortization on the consolidated balance sheets. The increase in cash interest expense of $18.3 million was mainly due to the Company’s issuance and sale in February 2011 of $200 million aggregate principal amount of the Senior Notes due 2019.

Income Taxes. Income tax for the year ended December 31, 2011 was a provision of $0.6 million as compared to a benefit of $4.2 million in the same period in 2010. The income tax expense and benefit recognized for the year ended December 31, 2011 and 2010, respectively, were a result of a change in the valuation allowance on net deferred tax assets caused by a change in deferred tax liabilities primarily related to unrealized gains on derivative contracts designated as hedges where the mark-to-market change on the hedges, net of deferred taxes is recorded to other comprehensive income.

Net income to noncontrolling interest. Net income to noncontrolling interest increased to $5.4 million for the year ended December 31, 2011 compared to $3.1 million for the year ended December 31, 2010. The increase is due to an increase in the gathering fees earned by our majority-owned subsidiary in which the outside noncontrolling interest member is currently allocated 80% of the distributions. The gathering fees earned by the subsidiary increased as a result of an increase in production from the H/B horizontal wells that were completed and brought online.

Capital Resources and Liquidity

Our business is capital intensive. Our ability to grow our reserve base is dependent upon our ability to obtain outside capital and generate cash flows from operating activities to fund our drilling and capital expenditures. Our cash flows from operating activities are substantially dependent upon crude oil and natural gas prices, and significant decreases in market prices of crude oil or natural gas could result in reductions of cash flow and affect our drilling and capital expenditure plan. To mitigate a portion of our exposure to fluctuations in natural gas prices, we have historically entered into natural gas swaps, three-way collars and put spreads. As a result of paying off our bank credit facility and to increase current liquidity, the Company monetized its remaining natural gas hedge portfolio in December 2011. The Company received $18.5 million, net of deferred premiums payable. We plan to continue to hedge oil and natural gas in the future to mitigate our commodity price risk.

We continually review our drilling and capital expenditure plans and may change the amount we spend based on industry and market conditions and the availability of capital. For the year ended December 31, 2011 our cash outlays for capital expenditures were $272 million, of which $126 million was the cash portion of acreage acquisitions and seismic in the Williston Basin, DJ Basin-Niobrara and East Texas, $124 million was for drilling operations, and $22 million related to capitalized interest, corporate expenditures and rig sub-lease fees. Of the $124 million in capital expenditures for drilling operations, $16.2 million related to drilling operations in the Williston Basin-Niobrara and $107.8 million related to East Texas drilling and other capital expenditures. We have elected to temporarily suspend execution of our H/B Hz program until natural gas prices or lower completed well costs support more economical drilling, which we expect to occur by mid-year 2014.

As of December 31, 2011, we had cash and cash equivalents of $106.8 million. Through the period ended December 31, 2011, we have funded our operating expenses and capital expenditures through positive operating cash flows, as well as from $105.3 million raised from the issuance of 22,173,518 shares of our common stock in February 2011, $25.8 million raised from the issuance of 1,135,565 shares of our 9.25% Series B Cumulative Preferred Stock preferred shares, $193.7 million, net of original issue discount, raised from the issuance of our 11.375% senior notes, $49.7 million in connection with the VPP, $21.2 million from the settlement of our oil and natural gas hedge portfolio, net of premiums payable, and $100 million raised from a bond exchange of our Senior Notes due 2019 for our new Senior Secured Notes due 2017.

The outstanding balance of our bank credit facility at the time of the offerings in February 2011 of $110 million was fully repaid, and we completed a $50 million tender offer for a portion of our 5.00% convertible notes. The remaining proceeds from the offerings were used to fund the Niobrara and Bakken acreage acquisitions and other capital expenditures. On December 12, 2011, the Company fully repaid the outstanding balance on our bank credit facility of $39.1 million and terminated our agreement in accordance with the covenants of the new Senior Secured Notes.

We anticipate funding approximately $97 million of cash capital expenditures in 2012 with cash on hand, positive operating cash flow, and a partial sale of our Niobrara acreage or other potential capital market activities. The 2012 capital expenditure budget will focus on our Bakken development plans. In the Bakken, we are currently running one rig from Paramount Drilling U.S. LLC. Based on available liquidity, we plan to add a second rig in the Bakken during the third quarter of 2012. In the Niobrara for 2012, we are budgeting for participating in a Devon Energy operated well, and will continue to evaluate our seismic work and surrounding well results from other operators.

GMXR is a resource play rich E&P company. Oil shale resources are located in the Williston Basin, North Dakota & Montana targeting the Bakken Petroleum System and in the DJ Basin, Wyoming targeting the Niobrara Petroleum System; both plays are estimated 90% oil. Our natural gas resources are located in the East Texas Basin, in the Haynesville/Bossier gas shale and the Cotton Valley Sand Formation, where the majority of our acreage is contiguous, with infrastructure in place and mostly held by production. We believe these oil and natural gas resource plays provide a substantial inventory of operated, high probability, repeatable, organic growth opportunities. The Company’s multiple basin strategy provides flexibility to allocate capital to achieve the highest risk adjusted rate of return, with both oil and natural gas resources throughout our portfolio. Please visit www.gmxresources.com for more information on the Company.

This press release includes certain statements that may be deemed to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. They include statements regarding the Company’s financing plans and objectives, drilling plans and objectives, related exploration and development costs, number and location of planned wells, reserve estimates and values, statements regarding the quality of the Company’s properties and potential reserve and production levels. These statements are based on certain assumptions and analysis made by the Company in light of its experience and perception of historical trends, current conditions, expected future developments, and other factors it believes appropriate in the circumstances, including the assumption that there will be no material change in the operating environment for the Company’s properties. Such statements are subject to a number of risks, including but not limited to risks relating to the Company’s ability to obtain financing for its planned activities, commodity price risks, drilling and production risks, risks related to weather and unforeseen events, governmental regulatory risks and other risks, many of which are beyond the control of the Company. Reference is made to the Company’s reports filed with the Securities and Exchange Commission for a more detailed disclosure of the risks. For all these reasons, actual results or developments may differ materially from those projected in the forward-looking statements.

GMX Resources Inc. and Subsidiaries

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GMX Resources Inc. and Subsidiaries

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GMX Resources Inc. and Subsidiaries

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