EXHIBIT 99.1

GMXR

FOR IMMEDIATE RELEASE

FOR ADDITIONAL INFORMATION CONTACT

Jim Merrill        Harry Stahel        Alan Van Horn

Chief Financial        Officer Vice President Finance        Manager, Investor Relations

405.254.5805        405.254.5802        405.254.5839

GMX RESOURCES INC. Announces Financial and Operational Results for the Three and Six Months Ended June 30, 2011

Oklahoma City, Oklahoma, Thursday, August 4, 2011. GMX RESOURCES INC., NYSE: ‘GMXR’ (the “Company” or “GMXR”), reports today on the financial and operating results for the second quarter ending June 30, 2011. Please visit the Company’s website at www.gmxresources.com to view the second quarter presentation, which will be made available no later than 7:30 a.m. CDT, August 4, 2011.

The Company has scheduled a conference call for Thursday, August 4, 2011 at 8:00 a.m. CDT (9:00 a.m. EDT) to discuss the second quarter financial and operating results. To access the call, dial (877) 303-9132 or (408) 337-0136 prior to the conference call start time. Please reference conference code 79577501. A replay of the call will be available after 11:00 a.m. EDT on August 4, 2011 through August 18, 2011 and can be accessed using the following number and pass code: Toll free: (800) 642-1687 or (706) 645-9291. Replay conference code 79577501. In addition, a replay of the call will be archived on our Company website under investor relations / events and presentations. A presentation pertaining to this call will be available on the Company’s website no later than 7:30 a.m. CDT, August 4, 2011. www.gmxresources.com

Management Comments

Michael J. Rohleder, President said: “Our second 2011 production exceeded our guidance and reached a Company record 6.5 BCFE. We drilled four and completed three successful long lateral (~6,500’) Haynesville/Bossier horizontal wells during the second quarter. Production for the quarter was up 8% from the previous quarter and 51% from the second quarter of 2010. The production performance of our H/B long lateral program continued to exceed our expectations. In fact, the performance of our 2011 long lateral wells confirms the prior DeGolyer & MacNaughton EUR estimates of 6.5 Bcfe per well. Due to the continued depressed prices for natural gas and the absence of significant cost reduction for services, we have temporarily suspended our Haynesville/Bossier development until economics become competitive with our oil development. We have subleased our fourth H&P FlexRig and will focus all of our remaining 2011 drilling capital expenditure budget on oil development in the Bakken, Niobrara and other East Texas oil targets. Our new production guidance for 2011 is expected to be in a range of 23.8 Bcfe to 24.2 Bcfe, with the midpoint of 24.0 Bcfe, which is representing an increase of 37% from 2010 production. We expect to increase our oil/NGL production and revenue currently 9% and 21%, to 16% and 31% respectively, by year end.”

Rohleder continued, “Our overarching goals in the next two years are to accelerate revenues and EBITDA growth to reach profitability sooner, and to reduce our leverage. In order to increase revenue and EBITDA, which leads to a quicker return to positive EPS, we intend to concentrate our capital on the development of our oil programs. In support of these objectives, we acquired an additional 11,449 net acres in North Dakota during the second quarter of 2011, which increases our total acreage in the Bakken/Three Forks to 35,524 net acres. The acreage is located in a very active development area in McKenzie, Billings and Stark Counties and greatly enhances our operated position.”

“Transformation to more oil production is the key to accomplishing these goals. We are operational in North Dakota two months ahead of our previous schedule. We now have 600 undrilled 9,500’ lateral locations. Our current acreage position provides us with 43 potential operated 1,280-acre units resulting in 172 undrilled Bakken and Three Forks locations with a 45% to 100% average working interest. We have approximately 13 other 1,280-acre units where we could operate that provide another 52 undrilled locations. On July 7, 2011, we spud our first Company-operated horizontal Three Forks well, the Wock 21-2-1H, with a 100% working interest, commencing our oil drilling program in these properties. We have been granted one additional permit, the Frank 31-4-1H in Stark County, and we have 14 permits in process in McKenzie, Billings and Stark counties. We are also participating in two non-operated wells that will spud in the third quarter of 2011, with six more potential non-operated wells based on permits being filed with NDIC.”

“In Wyoming, our Niobrara development was delayed to shoot two seismic projects, encompassing 135 and 204 square miles. The 135-square mile Goshen County project in the Northern DJ Basin run by Devon is complete. We are participating in one

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Devon-operated well in which we have a 29.2% working interest in the third quarter of 2011, and we expect to participate in up to six additional non-operated wells which have been permitted. We are also planning a vertical well in the second half of 2011. Our second seismic project in Platte, Laramie and Southern Goshen Counties will be completed in the fourth quarter of 2011. We will drill a vertical well in this area subsequent to completion and analysis. There are 29 operators and 258 permits in both project areas. Our Niobrara acreage position has approximately 146 640-acre units and we expect to operate between 236 and 380 (65%) of our approximately 584 undrilled 4,000’ lateral locations.”

“Beginning in the second half of 2011, we plan to commit almost all of our capital expenditures to our oil resources development. We expect our revolver, additional asset sales and potential JV’s will provide additional liquidity during the next 12 months. Increasing the oil percentage of our production is expected to have positive economic benefits due to the current value gap that exists between oil and natural gas, and to significantly change the NAV of the Company.”

Company Highlights for the Three and Six Months Ended June 30, 2011

Operational

Transformation to Oil

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Financial

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Financial Results for the Three and Six Months Ended June 30, 2011

The Company reported a net loss applicable to common shareholders of $15.4 million ($0.28 per basic and fully diluted share) and $69.8 million ($1.43 per basic and fully diluted share) for the three and six months ended June 30, 2011, respectively, compared to a net loss applicable to common shareholders of $3.0 million ($0.11 per basic and fully diluted share) and net income applicable to common shareholders of $0.8 million ($0.03 per basic and fully diluted share) for the three and six months ended 2010, respectively.

Adjusted net loss applicable to common shareholders, a non-GAAP measure adjusting for items set forth below, was $1.4 million and $4.4 million, or $0.03 and $0.09 per basic and fully diluted share, for the three and six months ended June 30, 2011, respectively. Adjusted net income (loss) is provided as a supplemental financial measure. We believe adjusted net income (loss) provides additional information regarding our operating financial performance and is beneficial to the lenders under our credit facility and 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.

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The following table summarizes certain key operating and financial results for the three and six months ended June 30, 2011 compared to the three and six months ended June 30, 2010.

Summary Operating Data

Results of Operations for the Three Months Ended June 30, 2011 Compared to the Three Months Ended June 30, 2010

Oil and Natural Gas Sales. Oil and natural gas sales during the three months ended June 30, 2011 increased 42% to $32.9 million compared $23.2 million in the second quarter of 2010. The increase in oil and natural gas sales was due to a 51.4% increase in production on a Bcfe-basis, a 29.3% increase in oil prices, and a 21.8% increase in the average realized price in natural gas liquids (“NGLs”), offset by a 18.6% 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 (exclusive of ineffectiveness from derivatives) in the three months ended June 30, 2011 was $98.25, $0.95 and $4.55, respectively, compared to $75.98, $0.78 and $5.59, respectively, in the three months ended June 30, 2010. Our realized sales price for natural gas, excluding the effect of hedges of $0.68 and $2.04, for the three months ended June 30, 2011 and 2010, respectively, was approximately 90% and 86% of the average NYMEX closing contract price for the respective periods. In the second quarter of 2011 and 2010, the conversion of natural gas to NGLs produced an upgrade of approximately $0.31 per Mcf

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and $0.40 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. Ineffectiveness of derivative gains (losses) recognized in oil and gas sales of $0.3 million and $(1.8) million for the three months ended June 30, 2011 and 2010, respectively, is 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.

Natural gas production for the three months ended June 30, 2011 increased to 5,852 MMcf compared to 3,592 MMcf for the three months ended June 30, 2010, an increase of 62.9%. The increase in natural gas production resulted from production related to 37.1 net producing H/B horizontal wells that were on-line during the second quarter of 2011 compared to 19.5 net producing Haynesville/Bossier (“H/B”) horizontal wells online during the second quarter of 2010. During the second quarter of 2011, we brought on-line three H/B horizontal wells and production from all H/B horizontal wells, including the three H/B horizontal wells brought on-line in the second quarter 2011, which accounted for 78% of total production for the three months ended June 30, 2011 compared to 61% in the same period in 2010. Oil production for the three months ended June 30, 2011 remained the same as of the three months ended June 30, 2010 at 24 MBbls. 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 June 30, 2011 decreased to 3,678 Mgals compared to 4,005 Mgals for the three months ended June 30, 2010, a decrease of 8.1%. This decrease was due to a decline in production in our non-Haynesville production, which has a higher NGL content compared to our H/B horizontal wells.

For the three months ended June 30, 2011, as a result of hedging activities, excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $3.9 million compared to an increase in natural gas sales of $7.3 million in the second quarter of 2010. In the second quarter of 2011, hedging, excluding ineffectiveness, increased the average natural gas sales price by $0.68 per Mcf compared to an increase in natural gas sales price of $2.04 per Mcf in the second quarter of 2010. The effect of our derivative contracts on oil decreased the average oil sales price $1.79 per Bbl for the three months ended June 30, 2011 compared to no effect in the same period in 2010.

Lease Operations. Lease operations expense increased $0.6 million, or 26%, for the three months ended June 30, 2011 to $2.8 million, compared to $2.2 million for the three months ended June 30, 2010. Lease operations expense, on an equivalent unit of production basis, decreased $0.09 per Mcfe in the three months ended June 30, 2011 to $0.43 per Mcfe, compared to $0.52 per Mcfe for the three months ended June 30, 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 lease operating expense on a per Mcfe basis. 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 in the three months ended June 30, 2011 compared to the three months ended June 30, 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 decreased 47% to $0.2 million in the three months ended June 30, 2011 compared to $0.3 million in the three months ended June 30, 2010.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $4.6 million, or 52%, to $13.3 million in the three months ended June 30, 2011 compared to $8.7 million for the three months ended June 30, 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 June 30, 2011 compared to $1.75 per Mcfe in the three months ended June 30, 2010. This increase in the rate per Mcfe is due to the percentage increase in oil and gas properties subject to amortization exceeding the percentage growth in reserves for the three months ended June 30, 2011.

Impairment of oil and natural gas properties and assets held for sale. For the $16.9 million impairment charge recorded in the second quarter of 2011, $11.5 million was related to the impairment of oil and gas properties subject to the full cost ceiling test and $5.4 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 90% of the Company’s total production, and as a result, a decrease in natural gas prices can significantly impact the Company’s ceiling test. During the second quarter of 2011, the 12-month average of the first day of the month natural gas price increased 3% from $4.10 per MMbtu at March 31, 2011 to $4.21 per MMbtu at June 30, 2011. Even though the 12-month average of the first day

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of the month natural gas price increased during the second quarter of 2011, the Company recorded impairment expense of $11.5 million related to oil and gas properties. Of the $11.5 million related to the impairment of oil and gas properties, $3.0 million resulted from the net book value of oil and gas properties exceeding the net present value of future net revenues, $3.4 million related to the decrease in net present value of the cash flow hedges used in the full cost ceiling test and $5.1 million due to the de-designation of cash flow hedges that could no longer be considered in the full cost ceiling test. The remaining $5.4 million of the $16.9 million impairment charge was related to additional impairment on the Company’s three drilling rigs, currently classified as assets held for sale, and was based on a change in fair value of the rigs used to calculate the impairment which reflects the sales price of one of the rigs sold in July 2011.

General and Administrative Expense. General and administrative expense for the three months ended June 30, 2011 was $7.6 million compared to $6.2 million for the three months ended June 30, 2010, an increase of $1.4 million, or 22%. General and administrative expense per equivalent unit of production was $1.17 per Mcfe for the second quarter of 2011 compared to $1.44 per Mcfe for the comparable period in 2010. The increase in general and administrative expense for the three months ended June 30, 2011 compared to the three months ended June 30, 2010 was primarily due to an increase in salaries, wages and related payroll taxes as a result of an increase in employees needed to transition to and develop the Company’s oil related acreage expansion. General and administrative expenses include $1.2 million and $1.1 million of non-cash compensation expense as of the three months ended June 30, 2011 and 2010, respectively. Non-cash compensation represented 16% and 18% of total general and administrative expenses, for the three months ended June 30, 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 June 30, 2011 was $7.8 million compared to $4.7 million for the same period in 2010. For the three months ended June 30, 2011 and 2010, interest expense includes non-cash interest expense of $1.4 million and $1.7 million, respectively, 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 June 30, 2011 and 2010 was $7.7 million and $2.9 million, respectively, of which $2.0 million and $0.6 million, respectively, was capitalized to properties not subject to amortization on the consolidated balance sheets. The increase in cash interest expense of $4.8 million was mainly due to the Company’s issuance and sale of $200 million aggregate principal amount of 11.375% senior notes due 2019 (“11.375% senior notes”) in February 2011.

Income Taxes. Income tax for the three months ended June 30, 2011 was a provision of $1.4 million as compared to a provision of $2.4 million in the same period in 2010. The income tax expense recognized in the three months ended June 30, 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 $1.7 million for the three months ended June 30, 2011 compared to $0.6 million for the three months ended June 30, 2010. The increase is due to an increase in the gathering fees earned by our majority-owned subsidiary in which the outside non-controlling 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.

Net Loss and Net Loss Per Share

Net Loss and Net Loss Per Share—Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010. For the three months ended June 30, 2011 we reported a net loss applicable to common shareholders of $15.4 million and for the three months ended June 30, 2010, we reported a net loss applicable to common shareholders of $3.0 million. Net loss per basic and fully diluted share was $0.28 for the second quarter of 2011 compared to net loss per basic and fully diluted share of $0.11 for the second quarter of 2010. Weighted average-basic shares outstanding increased by 27,479,391 shares from 28,181,587 shares in the second quarter of 2010 to 55,660,978 shares in the second quarter of 2011. There were no dilutive shares for the three months ended June 30, 2011 and 2010, since the Company was in a loss position and all dilutive shares would have been antidilutive.

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 entered into natural gas swaps, three-way collars and put spreads.

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As of June 30, 2011, we had cash and cash equivalents of $4.9 million and our undrawn borrowing base of $60.0 million. Through the period ended June 30, 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 and $193.7 million, net of original issue discount, raised from the issuance of our 11.375% senior notes. The outstanding balance of our bank credit facility at the time of the offerings was fully repaid, and we completed a $50 million tender offer for a portion of our 5.00% convertible senior notes due 2013 (“5.00% convertible notes”). The remaining proceeds from the offerings were used to fund the Niobrara and Bakken acreage acquisitions and future capital expenditures.

We continually review our drilling and capital expenditure plans and may change the amount we spend based on commodity prices, industry conditions and the availability of capital. In the first six months of 2011, our cash outlay for capital expenditures was $192 million, net of additions to oil and gas properties from issuance of common stock for the Bakken and Niobrara acreage acquisitions. Cash expenditures related to the purchase price of Niobrara and Bakken acreage acquisitions totaled $61.2 million and $90.8 million for the three and six months ended June 30, 2011. In the new Bakken acquisitions completed in the second quarter of 2011, the Company purchased an additional 11,449 net acres in the Bakken for a total purchase price of $28 million, bringing our total Bakken net acres to 35,524.

The revised cash capital expenditure budget for 2011 is $287 million, of which $101 million is the cash portion of acreage acquisitions in the Bakken, DJ Basin-Niobrara and East Texas and $186 million is for drilling operations of which we estimate approximately 28% will be spent on oil related activities. As of June 30, 2011, we have made $192 million of these planned capital expenditures. The Company has elected to temporarily suspend execution of its H/B horizontal program until natural gas prices or lower completed well costs support more economical development. The Company will complete its eighth and final H/B horizontal well for this calendar year in the third quarter of 2011.

The Company anticipates funding the $94 million of cash capital expenditures in the second half of 2011 with positive operating cash flow, the unused portion of our revolving bank credit facility, proceeds from sales of assets held for sale, and continued at-the-market sales of our 9.25% Series B Cumulative Preferred Stock.

In order to protect us against the financial impact of a decline in natural gas prices, we have an active hedging program. As of June 30, 2011, we had natural gas hedges in place of 7.8 Bcf for our remaining estimated natural gas production for 2011 at an average hedge floor price of $6.13 per Mcf. In addition, we have 16.7 Bcf and 4.7 Bcf of natural gas hedged in 2012 and 2013, respectively, at average hedge prices of $6.08 and $5.40 per Mcf. As of June 30, 2011, we have also sold put options that would reduce the average hedge floor price if the monthly natural gas contract settlement price is below $4.18 for 2011, $4.12 for 2012 and $3.75 for 2013. If the monthly natural gas contract settlement is below the average sold put price, we will receive the monthly natural gas contract settlement price plus $1.95 in 2011, $1.95 in 2012, and $1.65 in 2013.

As a result of temporarily suspending the H/B horizontal drilling program in the third quarter of 2011, certain hedged natural gas volumes exceeded estimated future production. In order to reduce the amount of hedged volumes, the Company monetized 84,887 Mcf of 2011 hedges and 4.3 Bcfe of 2012 hedges. Net of deferred premiums payable related to these volumes, the Company received $2.7 million in proceeds.

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Operational Update

Bakken

In May 2011, the Company increased its Bakken position with multiple transactions totaling 11,449 net acres. The first of two significant transactions was a purchase and sale agreement for 9,608 net acres at an average cost of $2,500 per net acre from a private seller located in Billings and Stark Counties, North Dakota. The second transaction was for 1,684 net acres from the State of North Dakota at an average cost of $2,211 per net acre. Approximately 960 net acres are located in McKenzie County while 724 net acres are located in Billings County. The remaining 157 net acres were acquired through the leasing of several fee mineral rights. These acquisitions bring our total Bakken net acres to 35,524. The Company holds leases in approximately 150 potential 1,280-acre units in Bakken and expects to be the operator in approximately 43 of those units providing a minimum of 172 operated locations. The Company expects the working interest in our operated locations will range from approximately 45% to 100%, with the first three operated wells having an 80%-100% working interest.

In March 2011, the Company was granted its first permit from the North Dakota Industrial Commission (NDIC) for a 1,280-acre spaced unit in Stark County. We spud our first operated Three Forks well, the Wock 21-2-1H, on July 7, 2011 and hold a 100% working interest and an 81% NRI. We expect completion in the third quarter of 2011. The Company has its second permit for the Frank 31-4-1H, Stark County, and is submitting applications for permits for an additional 14 wells in 14 new 1,280-acre units in Stark, McKenzie and Billings Counties. Additionally, we are also preparing 14 permits that will be submitted to the NDIC in Q1 2012. GMX expects to operate 43 units on its North Dakota leasehold. These units have a potential for 172 locations, which is an eighteen rig year inventory. We have 13 additional possible operated units in North Dakota that could provide another 52 locations.

The Company has elected to participate in two non-operated wells targeting both the Middle Bakken and Three Forks zones. The working interests in these non-operated wells are 2% and 25%. The Company anticipates participating in an additional six non-operated wells in 2011 with an average working interest of 8.4%.

The Company has entered into a one-year contract with Paramount Drilling U.S. LLC. The contract began with the spudding of our Wock 21-2-1H well in Stark County.

DJ Basin-Niobrara

As previously announced, the Company has nearly 584 undrilled horizontal locations and has participated in a 3D seismic shoot (135 square miles) initiated by Devon Energy Corporation in an area we call North Mustang-Doty Hill (NMDH) that covers the majority of the Company’s leases in Goshen County, Wyoming. The 3D seismic is being utilized to begin our drilling of our NMDH leases. The area consists of 52 gross 640-acre units and 208 potential gross wells, assuming 4 wells per unit. GMXR owns 9,374 net acres, and we expect to operate 25 units containing 100 undrilled locations with an average working interest of at least 45%.

The Company’s 3D seismic shoot in Platte and Laramie Counties (204 square miles) should be completed in the second half of 2011. In all, the Company will acquire in excess of 300 square miles of 3D seismic data to aid in our exploitation of the leases. The Company’s Platte and Laramie County positions consist of 30,818 net acres with 94 gross 640-acre spaced units providing GMX with potentially Company operated 376 gross wells, assuming 4 wells per unit, averaging a 51% working interest.

The Company has elected to participate in the drilling of the Newton Ranches 14-3444H well with the operator, Devon Energy Corporation, Oklahoma City, Oklahoma, (NYSE: DVN), for its 29.2% working interest. The Newton Ranches 14-3444H well is located in Section 34 Township 24N, Range 64W, in Goshen County, WY. With the benefit of 3D seismic data, the well will be drilled as a 12,216’ measured depth horizontal well to test the Niobrara Formation. Three more non-operated wells have been proposed in the area.

We expect to continue to receive additional non-operated proposals given the ramp up of activity by operators in Goshen, Laramie and Platte Counties. We expect that these participations will provide attractive economics, additional data points along with the seismic data that will add to our understanding of the geology of the play and assist in defining the strategy and completion design for the Niobrara development.

East Texas Basin

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Based on continuing low natural gas prices and high service costs, the Company has temporarily suspended new drilling in the Haynesville/Bossier at the end of June and we will be completing our eighth and final H/B Hz well for this calendar year in the third quarter. We will focus all of our drilling efforts towards the the higher rates of return associated with our oil development opportunities that we have in the Bakken, the DJ Basin-Niobrara and potential oil based opportunities in our East Texas property base.

The Company brought three new H/B Hz wells to production during the second quarter of 2011, which is in line with our objective of having one new well added to production per month. For the second quarter of 2011, our average completed well costs were $8.57 million which is approximately $0.1 million less than in the first quarter of 2011. The average stimulated lateral length for the second quarter was 6,589’. The latest long lateral H/B Hz well to come online is the Holt Bosh #5H which has a 30 and 60 running daily average of 7,277 and 6,625 Mcfe/d respectively. The production performance of our longer laterals is in line with our year end estimates of 6.5 Bcfe. The current plan is to resume our H/B drilling program in 2013 and any decision to resume the program at an earlier date would be a function of realized natural gas pricing and completed well costs.

The Company intends to continue with its program of subleasing its fleet of Helmerich and Payne (H&P) Flex Rigs 3™. The Company has subleased H&P rig #420 for another six-month period, starting in July, 2011, and H&P rig #383 has been subleased for the remainder of its term which ends in March 2012. H&P rig #384 is on sublease until February of 2012 and H&P rig # 417 is on sublease until February 2013. At the end of all leases, the Company has the first right to renegotiate new terms on all our H&P rigs.

The Company has begun a 3D seismic shoot of 33 square miles covering almost all of the Company’s contiguous operated acreage in Harrison County, Texas which is expected to be completed in the second half of 2011. The benefits of obtaining 3D seismic across our acreage include: (1) identification of additional oil targets for shallow and deep reservoirs in the Glen Rose and Travis Peak and potentially below the Haynesville Bossier gas shale; and (2) a more complete understanding of the joint and fracture systems of our horizontal development of the H/B and Cotton Valley Sands assets. The Company has suspended further testing for hydrocarbons below the H/B until after evaluation of the data from the 3D seismic shoot.

Update on 9.25% Series B Cumulative Preferred Share “ATM” Offering

On December 14, 2010, the Company announced the launch of an “At the Market” offering of shares of our 9.25% Series B Cumulative Preferred Stock with an aggregate amount not to exceed $62,712,500 million and not to exceed 3,000,000 shares. In the second quarter of 2011, the Company sold 834,927 shares of Series B Cumulative Preferred Stock for approximately $19.9 million in gross proceeds. Since December 14, 2010, the Company has received gross proceeds from the offering of $28.1 million and has issued an additional 1,176,734 shares of Series B Cumulative Preferred Stock.

Second Quarter 2011 Production and Realized Prices and Guidance for 2011 Production and Adjusted EBITDA

We had Company record production of 6.5 Bcfe in the second quarter of 2011 representing an increase of 8% from the first quarter of 2011 and 7% more than the Company’s previous second quarter guidance of 6.1 Bcfe. Due to temporarily suspending our Haynesville/Bossier Hz drilling program, the Company expects production to decline in a range from 7% to 5% from 25.5 to a range of 23.8 Bcfe to 24.2 Bcfe, with the midpoint of 24.0 Bcfe representing an increase of 37% over the 17.5 Bcfe of production for 2010. The Company is continuing to experience increased production performance from its longer lateral H/B Hz drilling program.

The Company’s realized natural gas was 90% of the average NYMEX contract price for the second quarter of 2011. In the first quarter of 2011, the Company’s realized natural gas price was 86% of the average NYMEX contract for the quarter. The Company’s realized gas price is based on a number of factors including (1) the price of gas at the physical sales points, (2) the amount of gas sold on a firm basis at a first of month index price and the amount of gas sold on a daily basis at the market price during the month of delivery, (3) the strike prices of the bought puts, sold puts, and other financial hedges compared to the NYMEX settlement price, (4) the recognition of option premium income received, less the recognition of option premium expenses paid, and (5) the fees paid to third parties to ship our gas to downstream market points.

Full-year adjusted EBITDA guidance for 2011 is now revised to be in the range of $76 million to $81 million due to the Company’s temporary suspension of the Haynesville/Bossier drilling operations and the Company’s strategic decision to focus on developing the Bakken and Niobrara oil resource plays.

GMXR is a resource play rich E&P company with development acreage in two oil shale resources in the Bakken (North Dakota / Montana) targeting the Bakken & Sanish-Three Forks and the DJ Basin (Wyoming) targeting the Niobrara Formation; both plays are 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

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and 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 Bakken properties contain nearly 600 undrilled, 9,500’ lateral length locations, 43 potential operated 1280-acre units and 172 operated locations, with between 45% and 100% working interest. The Niobrara properties contain 584 undrilled, 4,000’ lateral length locations, 94 potential operated 640-acre units and 376 operated locations, with an average working interest of 51%. The Haynesville/Bossier and the Cotton Valley Sand locations include 253 net Haynesville/Bossier horizontal locations, and 108 net Cotton Valley Sand horizontal locations. The Company believes multiple basins and both oil and natural gas resource choices provide us with flexibility to allocate capital to achieve the highest risk adjusted rate of return on 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 the completion of announced acquisitions, commodity price risks, drilling and production risks, risks relating to the Company’s ability to obtain financing for its planned activities, 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.

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GMX Resources Inc. and Subsidiaries

Consolidated Balance Sheets

(dollars in thousands, except share data)

(Unaudited)

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GMX Resources Inc. and Subsidiaries

Consolidated Statements of Operations

(dollars in thousands, except share and per share data)

(Unaudited)

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GMX Resources Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(dollars in thousands)

(Unaudited)

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GMX Resources Inc. and Subsidiaries

Non-GAAP Supplemental Information—Discretionary Cash Flows ⁽¹⁾

(dollars in thousands)

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GMX Resources Inc. and Subsidiaries

Non-GAAP Reconciliations—Adjusted EBITDA ⁽¹⁾

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