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 Three and Nine Months Ended September 30, 2011; Liquidity Solutions Fund Oil Resource Development

Oklahoma City, Oklahoma, Thursday, November 3, 2011. GMX RESOURCES INC., NYSE: ‘GMXR’ (the “Company” or “GMXR”), reports today on the financial and operating results for the third quarter ended September 30, 2011.

The Company has scheduled a conference call for Thursday, November 3, 2011 at 8:00 a.m. CDT (9:00 a.m. EDT) to discuss the third 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 18452580. A replay of the call will be available after 11:00 a.m. EDT on November 3, 2011 through November 17, 2011 and can be accessed using the following number and pass code: Toll free: (800) 585-8367 or (855) 859-2056. Replay conference code 18452580. In addition, a replay of the call will be archived on our Company website under investor relations / events and presentations or alternatively at the following webcast link: http://investor.shareholder.com/media/eventdetail.cfm?eventid=103915&CompanyID=GMXR&e=1&mediaKey=B6D3B9EAE6270A1344B4B56B803EF2BA

A third quarter presentation pertaining to this call will be available on the Company’s website prior to the call at: www.gmxresources.com

Liquidity Update

GMXR has entered into agreements with certain bondholders to purchase up to $100 million of senior secured notes, which will create additional liquidity to allow the Company to execute its capital program.

The Company has entered into separate support agreements (the “Support Agreements”) with holders of greater than 50% (“Supporting Holders”) of its 11.375% Senior Notes due 2019 (the “Existing Notes”) to acquire up to $100 million of the Company’s new senior first lien secured notes (the “New Notes”). The proceeds of the transaction will be used to retire the Company’s existing revolving bank credit facility and to fund the Company’s capital program. The transaction will be effectuated in part through a private exchange offer and is conditioned on consents of holders of at least a majority of Existing Notes.

Subject to, and in accordance with, the terms and conditions contained in these Support Agreements, each of the Supporting Holders have agreed, among other things:

(i) to tender such Supporting Holder’s Existing Notes in an exchange offer, pursuant to which holders of the Existing Notes (including the Supporting Holders) will be entitled to elect to exchange, for $1,000 principal amount of Existing Notes tendered by such holder, either: (a) $750.0 principal amount of 11.0% Senior Secured Notes due 2017 (the “New Notes”); or (b) $971.4 principal amount of New Notes, if the holder also agrees to purchase in a private placement New Notes in an aggregate principal amount equal to .60 multiplied by the principal amount of the Existing Notes tendered by such holder;

(ii) to purchase their pro rata amount of New Notes offered hereby and, if holders do not elect to purchase at least $100.0 million aggregate principal amount of New Notes in connection with the exchange offer, to allow the Company to put to them for cash purchase an amount of additional New Notes such that the aggregate principal amount of New Notes issued is $100.0 million (the “Backstop Obligations”); and

(iii) to consent to certain proposed amendments to the indenture governing the Existing Notes, such consents being irrevocable except under specified conditions.

If holders of 100% of the Existing Notes tender their Existing Notes in the exchange offer and elect to purchase New Notes, the transactions will result in $120 million of cash proceeds and the issuance of approximately $318 million aggregate principal amount of New Notes. The New Notes will mature in December 2017, be secured by substantially all of the assets of the Company and accrue cash interest at 11.0% per annum (or, at the Company’s option, 9.0% cash pay and 4.0% payment in kind in additional New Notes). Other terms of the New Notes, the exchange offer and consent solicitation will be subject to agreement with the Supporting Holders and final documentation.

The securities to be offered to the holders in the exchange offer will not be and have not been registered under the Securities Act of 1933, as amended (the “Securities Act”), and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements.

Monetization of Natural Gas Hedges

As a result of entering into a definitive agreement on the Bond Exchange and to increase current liquidity the Company anticipates monetizing its entire natural gas hedge portfolio in November 2011. As of November 1, 2011, the estimated market value less the deferred hedge premiums was approximately $16.6 million.

Additional Liquidity

The Company continues to pursue the sale of an overriding royalty interest in certain long-lived producing assets primarily in the Cotton Valley Sands layer in Harrison and Panola counties in East Texas through a Volumetric Production Payment (“VPP”). Under the VPP, GMXR will retain its Cotton Valley drilling rights with certain restrictions.

Bank Credit Facility Redetermination

Due to the pending transaction, the previously scheduled bank redetermination has been postponed until the completion of one of the above transactions. Upon issuing the New Notes, the Company expects to terminate its existing bank credit facility but have a letters of credit facility for, or be permitted to cash collateralize, letters of credit up to $10 million.

2012 Capital Expenditure Plan

The 2012 capital expenditure plan of $131 million (excluding capitalized interest expense) pending closing of liquidity transaction(s) and board approval will fund the Bakken, Niobrara and East Texas development plans. In the Bakken, the Company is currently running one rig from Paramount Drilling U.S. LLC. The Company plans to add a second rig in the Bakken during the second quarter of 2012. In the Niobrara, the Company is participating in a Devon operated well, and continues to evaluate the seismic work. Based on the results of the Devon operated well and the seismic data, the Company expects to spud its first operated well in the second quarter of 2012 and begin full development in the third quarter of 2012.

In East Texas, the Company will utilize the seismic work currently being performed to aid in the development in deep and shallow targets, including the Cotton Valley horizontal (“Hz”) targets which are comprised of 18% oil and natural gas liquids. Based on these targets’ liquids contents and the increased availability and lower costs in the service sector, these targets are becoming more economic. Currently all four rigs from Helmerich& Payne are subleased to other operators. The Company expects to fund the 2012 capital expenditure plan from available cash and operating cashflow.

Management Comments

Ken L. Kenworthy, Chief Executive Officer said: “Our objectives for the second half of 2011 have been to increase our cash reserves to fund our reposition of the Company operations into oil/liquids drilling programs. The exchange offer will create $100—$120 million in new liquidity, which ensures our ability to fund our CAPEX in 2012 and into 2013. I am pleased with the support we have received from our major bond holders in the form of the terms of the bond exchange we have announced. When completed, the exchange offer will create between $100 million and $120 million of new drilling capital.”

“Our first oil well in the Bakken/Three Forks System Resource (“B/3F”), the Wock 21-1-1H has been successfully completed with an internally estimated EUR of 400,000 BOE, at current oil prices, this well will provide a 20+% return. The B/3F is a statistical play where expected EURs range from 300,000—800,000 BOE. Current drilling plans in North Dakota over the next several months will include wells in our two largest acreage positions in Billings and McKenzie counties, which contain 128 potential operated locations. This inventory for these two counties alone is 16 years for 1 rig. Over next several months, we should have a better view of the statistical spread of all our well results, non-op wells and those of others around all of our acreage. This production information will allow us to target the highest producing areas in our future development plans, resulting in our target average EUR of 500,000-600,000 BOE.”

“Our Bakken, Niobrara and Cotton Valley Long Horizontal (“CV Hz”) development will all compete for our 2012 CAPEX budget. CV Hz development of 7,500’ laterals, we estimate will cost about $7.5 MM and recover about 7.5 BCFE, including 18% oil and NGLs. Processing uplift plus declining completed well costs of 10%-15% make re-establishing a CV Hz drilling program very economical, with rates of return comparable in all three plays. Our expectations are that adding gas to our pipeline system, further cost softening in East Texas will increase our Endeavor Gas Gathering LLC value and rate of return on this program. This overall repositioning of our development plans funded by financial transactions should create ample liquidity to execute our plan, demonstrating the value and benefits of our multi-basin Four Resource play inventory.”

Company Highlights for the Three and Nine Months Ended September 30, 2011

Transformation to Oil

Bakken

Niobrara

Operational

Financial

Operational Update

Bakken

The Company has successfully drilled and completed its first Bakken Petroleum System well. The Wock 21-1-1H located in Stark County was completed within the Three Forks and had a 24 hour IP test rate of 450 BOE. We are preparing to clean out the lateral and place the well on pump. We expect a peak 30 day average production of 275-300 BOE and an EUR of 400 MBOE. At current commodity prices and expected rates of production, the Wock 21-1-1H should provide a greater than 20% rate of return. In evaluating the results of the Wock 21-1-1H, the Company would point to the fact that there is a high degree of variability in reported 30 day average IP rates as operators have reported rates less than and greater than 300 BOE/d across the entire basin including areas that are well established. While the projected 30 day average production of 275-300 BOE is below the Company’s 500 MBOE type curve, by year three the Wock 21-1-1H cumulative BOE is expected to be 75% of the 500 MBOE type curve which is consistent with the flatter decline curves on mature Three Forks producers. The Company plans to continue to evaluate and adjust its completion designs in future drilling locations including the Frank 31-4-1H which is scheduled for completion in November 2011.

The Company has successfully drilled its second Three Forks Hz well. The Frank 31-4-1H was drilled in Sections 4 & 9 Township 148N Range 98W in Stark County, North Dakota and reached a total depth of 21,058’ with a Hz lateral length of 10,183’. The Frank 31-4-1H is scheduled for a 40 stage completion in the month of November 2011.

The Company has spud its third operated well in the Bakken Petroleum System in Billings County North Dakota. The Evoniuk 21-2-1H is located in Sections 2 & 11 Township 142N Range 100W and was spud on October 25, 2011. The Evoniuk 21-2-1H will target the Three Forks and the well is expected to reach a total depth of 19,850’ and a targeted lateral length of 9,500’. We have received permits for three additional locations in McKenzie County North Dakota and 10 additional permits are in process. We expect to spud the Akovenko 24-34-1H well located in Sections 3 & 10 Township 146N Range 99W in McKenzie County in the fourth quarter.

The Company has approximately 600 undrilled 9,500’ lateral locations in 150 units and expects to operate 52 units on its North Dakota and Montana leasehold of 35,524 net acres. These units have a potential for 208 locations, which is a twenty rig-year inventory. In the three counties of Billings, McKenzie and Stark the Company has 42 units where we would expect to operate. On 1280-acre spacing units, our holdings in Billings County consist of 19 possible units and 76 well locations, our holdings in McKenzie County consist of 13 possible units and 52 well locations, our holdings in Stark County consist of 10 possible units and 40 well locations and our holdings in Richland County, Montana consist of 10 possible units and 40 well locations. Due to acreage swaps and trades, we expect our working interest in our operated units to be 50% to 75%. The Company drilling CAPEX will be focused on areas delivering the best results and as a consequence we would expect our 30 day cumulative BOE average to improve over time and conform to the GMXR long lateral type curve of 500 MBOE.

The Company has elected to participate in four non-operated wells targeting both the Middle Bakken and Three Forks zones. The working interests in these non-operated wells range from 2% to 25% and average 14%. The Company has an interest in six additional non-operated wells that have been permitted with an average working interest of 4% in which we would expect to participate.

Our 2012 CAPEX plan includes adding a second rig in the Bakken Petroleum System in second quarter of 2012. With the expectation that we will participate in one non-operated well per month an average working interest of 5.0% and assuming a spud to spud cycle of 45 days, we expect to drill 21 gross and 8 net wells in 2012.

DJ Basin-Niobrara

The Company has an undeveloped DJ Basin-Niobrara position covering 40,191 acres and is focused in two separate areas. As previously announced the Company has nearly 584 undrilled Hz locations in 146 (640-acre) units and has participated in a two 3D seismic shoots. The first focus area is North Mustang-Doty Hill (“NMDH”) in Goshen County and consists 9,374 net acres and the Company would expect to operate in 25 units containing 100 undrilled locations with an average working interest of at least 45%. The Company has participated in a 3D seismic shoot in NMDH (135 square miles) initiated by Devon Energy Corporation that covers the majority of the Company’s leases in Goshen County, Wyoming.

The Company 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 was drilled to a measured depth of 12,045’ with a Hz length of 4,000’ to test the Niobrara Formation. The Newton Ranches 14-3444H is scheduled for completion in November of 2011.

The second area of focus for the Company is Chugwater in Platte and Laramie Counties and consists of 30,818 net acres and the Company expects to operate 70 units containing 280 undrilled locations with an average working interest of 64%. The Company’s 3D seismic shoot in Platte and Laramie Counties (204 square miles) should be completed in the first quarter of 2012. 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 plans to drill a vertical pilot and core approximately 360 feet of the Niobrara Formation in the first quarter of 2012. The vertical pilot location chosen with the benefit 3D seismic would be then completed as a Hz well in 2012 after evaluation of the core. The Company expects to deploy its first rig in the Niobrara in September of 2012.

East Texas Basin

The Company’s East Texas assets are focused on 25,224 net H/B acres and 17,200 Cotton Valley/Travis Peak (“CVS/TP”) acres. In the H/B the Company has 39 producers, 27 proved undeveloped locations and 226 net undrilled locations. In the CVS/TP the Company has 359 producers and projects 83 net 7,500’ Hz locations.

The Company completed and brought one new H/B Hz wells to production during the third quarter of 2011 and for the third quarter of 2011, our average completed well costs were $8.6 million which is unchanged from the second quarter of 2011. In the third quarter 2011, the Holt Blocker Heirs Blocker Ware #1H well was brought online August 14, 2011 and this well is the last H/B well before suspending H/B Hz drilling for the remainder of 2011. We are currently at 77 days of production, and we are projecting that this 6,534’ lateral well will make in excess of 445 mmcfe during its first 90 days. The last two wells of the second quarter, the Baldwin Mercer 1H and the Holt Bosh 5H had 90 day volumes of 561 mmcfe and 544 mmcfe, respectively. In a review of the Company’s long lateral H/B Hz program, first year production supports an average of 1.4 Bcfe. The current plan is to resume our H/B drilling program in the summer of 2013.

Recent reduction in completion costs have made if viable for the Company to plan to resume a Cotton Valley (“CV”)Hz development program using longer laterals (7,500’). The Company has 83 (7,500’) Hz locations covering its core Cotton Valley acreage and intends to drill up to four CV Hz wells in 2012. The Company expects completed well costs to be approximately $7.5 million and an EUR of 7.5 Bcfe.

The Company plans to complete a 3D seismic shoot (“Crossroads”) of 33 square miles covering almost all of the Company’s contiguous operated acreage in Harrison County, Texas in the fourth quarter of 2011. The benefits of the Crossroads shoot include: (1) identification of additional oil targets for shallow and deep reservoirs in the Glen Rose and Travis Peak and potentially below the H/B gas shale; and (2) a more complete understanding of the joint and fracture systems of our horizontal development of the Cotton Valley Sands and H/B assets.

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

Production for the third quarter was 6.1 Bcfe, an increase of 32% from the third quarter of 2010, and a 6% decrease as compared to the second quarter 2011 of 6.5 Bcfe. The decrease in production can be attributed to temporarily suspending our H/B drilling program beginning in July 2011 and the normal decline in production form existing wells. The Company expects full year 2011 production to be in a range between 23.2 Bcfe to 24.0 Bcfe, with the midpoint of 23.6 Bcfe representing an increase of 35% over the 17.5 Bcfe of production for 2010.

The Company’s realized natural gas price, excluding the effects of hedging, was 89% of the average NYMEX contract price for the third quarter of 2011. In the second quarter of 2011, the Company’s realized natural gas price was 90% 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 expected to be $78 million.

Financial Results for the Three and Nine Months Ended September 30, 2011

The Company reported a net loss applicable to common shareholders of $68.9 million ($1.21 per basic and fully diluted share) and $138.8 million ($2.69 per basic and fully diluted share) for the three and nine months ended September 30, 2011, respectively, compared to net income applicable to common shareholders of $2.2 million ($0.08 per basic and fully diluted share) and of $3.0 million ($0.11 per basic and fully diluted share) for the three and nine months ended 2010, respectively.

Adjusted net loss applicable to common shareholders, a non-GAAP measure adjusting for items set forth below, was $4.0 million and $8.4 million, or $0.07 and $0.16 per basic and fully diluted share, for the three and nine months ended September 30, 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 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.

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

Summary Operating Data

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

Oil and Natural Gas Sales. Oil and natural gas sales during the three months ended September 30, 2011 increased 14% to $28.4 million compared $24.8 million in the third quarter of 2010. Excluding the reduction from ineffectiveness of derivatives on oil and natural gas sales of $2.1 million and $0.1 million for the three months ended September 30, 2011 and 2010, respectively, oil and natural gas sales would have increased by 22% between the three months ended September 30, 2011 and 2010. Exclusive of ineffectiveness from derivatives, the increase in oil and natural gas sales was due to a 32% increase in production on a Bcfe-basis, a 20% increase in oil prices and a 53% increase in the average realized price in natural gas liquids (“NGLs”), offset by a 12% decrease in the average realized price of natural gas. 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 September 30, 2011 was $88.03, $1.01 and $3.74, respectively, compared to $73.65, $0.66 and $3.74, respectively, in the three months ended September 30, 2010. Our realized sales price for natural gas, excluding the effect of hedges of $0.84 and $1.46, for the three months ended September 30, 2011 and 2010, respectively, was approximately 89% and 90% of the average NYMEX closing contract price for the respective periods. In the third quarter of 2011 and 2010, the conversion of natural gas to NGLs produced an upgrade of approximately $0.29 per Mcf and $0.30 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 losses recognized in oil and gas sales of $2.1 million and $0.1 million for the three months ended September 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 September 30, 2011 increased to 5.6 MMcf compared to 4.0 MMcf for the three months ended September 30, 2010, an increase of 40%. The increase in natural gas production resulted from production related to 38.1 net producing H/B horizontal wells that were on-line during the third quarter of 2011 compared to 22.7 net producing H/B Hz wells online during the third quarter of 2010. During the third quarter of 2011, we brought on-line one H/B Hz well and production from this well also contributed to the increase in gas production for the three months ended September 30, 2011. Oil production for the three months ended September 30, 2011 decreased 24% to 19 MBbls, from 25 MBbls for the three months ended September 30, 2010, as a result of normal declines in production for wells of this type. 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 September 30, 2011 decreased to 3,234 Mgals compared to 3,707 Mgals for the three months ended September 30, 2010, a decrease of 13%. 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 Hz wells.

For the three months ended September 30, 2011, as a result of hedging activities, excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $4.7 million compared to an increase in natural gas sales of $5.8 million in the third quarter of 2010. In the third quarter of 2011, hedging, excluding ineffectiveness, increased the average natural gas sales price by $0.84 per Mcf compared to an increase in natural gas sales price of $1.46 per Mcf in the third quarter of 2010. The effect of our derivative contracts on oil had no effect for the three months ended September 30, 2011 and 2010.

Lease Operations. Lease operations expense increased $0.4 million, or 14%, for the three months ended September 30, 2011 to $3.2 million, compared to $2.8 million for the three months ended September 30, 2010. Lease operations expense, on an equivalent unit of production basis, decreased $0.08 per Mcfe in the three months ended September 30, 2011 to $0.52 per Mcfe, compared to $0.60 per Mcfe for the three months ended September 30, 2010. The decrease in lease operations expense on an equivalent unit basis resulted from an increase in H/B Hz well production and cost control measures implemented during 2011 and 2010. 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 Hz 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 September 30, 2011 compared to the three months ended September 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 was an expense of $0.3 million in the three months ended September 30, 2011 compared to income of $0.6 million in the three months ended September 30, 2010.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $4.4 million, or 46%, to $14.0 million in the three months ended September 30, 2011 compared to $9.6 million for the three months ended September 30, 2010. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $2.03 per Mcfe in the three months ended September 30, 2011 compared to $1.77 per Mcfe in the three months ended September 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 September 30, 2011.

Impairment of oil and natural gas properties and assets held for sale. For the $62.6 million impairment charge recorded in the third quarter of 2011, $60.9 million was related to the impairment of oil and gas properties subject to the full cost ceiling test and $1.7 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 91% of the Company’s total production at the end of the third quarter, and as a result, a decrease in natural gas prices can significantly impact the Company’s ceiling test. During the third quarter of 2011, the 12-month average of the first day of the month natural gas price decreased 1% from $4.21 per MMbtu at June 30, 2011 to $4.16 per MMbtu at September 30, 2011, contributing to the impairment for the third quarter. Of the $60.9 million related to the impairment of oil and gas properties, $53.5 million resulted from the net book value of oil and gas properties exceeding the net present value of future net revenues and $7.4 million related to the decrease in net present value of the cash flow hedges used in the full cost ceiling test. The remaining $1.7 million of the $62.6 million impairment charge was related primarily to additional impairment on the Company’s three drilling rigs classified as assets held for sale. The impairment was based on a change in fair value of the rigs, which reflects the sales price of one of the rigs sold in October 2011. Two rigs were sold in the third quarter of 2011.

General and Administrative Expense. General and administrative expense for the three months ended September 30, 2011 was $7.6 million compared to $6.7 million for the three months ended September 30, 2010, an increase of $0.9 million, or 14%. General and administrative expense per equivalent unit of production was $1.24 per Mcfe for the third quarter of 2011 compared to $1.43 per Mcfe for the comparable period in 2010. The increase in general and administrative expense for the three months ended September 30, 2011 compared to the three months ended September 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 $0.9 million and $1.1 million of non-cash compensation expense as of the three months ended September 30, 2011 and 2010, respectively. Non-cash compensation represented 12% and 17% of total general and administrative expenses, for the three months ended September 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 September 30, 2011 was $7.7 million compared to $4.8 million for the same period in 2010. For the three months ended September 30, 2011 and 2010, interest expense includes non-cash interest expense of $1.4 million and $1.6 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 September 30, 2011 and 2010 was $7.8 million and $3.2 million, respectively, of which $2.5 million and $0.7 million, respectively, was capitalized to properties not subject to amortization on the consolidated balance sheets. The increase in cash interest expense of $4.6 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 September 30, 2011 was a benefit of $2.4 million as compared to a benefit of $2.9 million in the same period in 2010. The income tax benefit recognized in the three months ended September 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 was $1.2 million for the three months ended September 30, 2011, which was the same amount for the three months ended September 30, 2010.

Net Loss and Net Loss Per Share

Net Income/Loss and Net Income/Loss Per Share—Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010. For the three months ended September 30, 2011 we reported a net loss applicable to common shareholders of $68.9 million and for the three months ended September 30, 2010, we reported net income applicable to common shareholders of $2.2 million. Net loss per basic and fully diluted share was $1.21 for the third quarter of 2011 compared to net income per basic and fully diluted share of $0.08 for the third quarter of 2010. Weighted average-basic shares outstanding increased by 28,585,652 shares from 28,256,684 shares in the third quarter of 2010 to 56,842,336 shares in the third quarter of 2011. There were no dilutive shares for the three months ended September 30, 2011, since the Company was in a loss position and all dilutive shares would have been antidilutive. There were 11,097 dilutive shares for the three months ended September 30, 2010, related to the dilutive effect of our outstanding restricted stock and stock options.

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.

As of September 30, 2011, we had cash and cash equivalents of $3.2 million and $29.7 million undrawn on our borrowing base of $60.0 million as of September 30, 2011. Through the period ended September 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 preferred shares 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 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.

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. In the first nine months of 2011, our cash outlay for capital expenditures was $242 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 approximately $91 million for the nine months ended September 30, 2011.

Our cash capital expenditure budget for 2011 is approximately $283 million, of which $101 million is the cash portion of acreage acquisitions in the Williston Basin, DJ Basin-Niobrara and East Texas and $182 million is for drilling operations of which we estimate approximately 20% will be spent on oil-related activities. 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 2013.

We anticipate funding approximately $40 million of cash capital expenditures in the fourth quarter 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 the anticipated issuance of senior secured notes during the fourth quarter of 2011.

In order to protect us against the financial impact of a decline in natural gas prices, we have an active hedging program. As of September 30, 2011, we had natural gas hedges in place of 3.9 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 12.3 Bcf and 4.7 Bcf of natural gas hedged in 2012 and 2013, respectively, at average hedge prices of $6.05 and $5.40 per Mcf. As of September 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 $4.17 for 2011, $4.09 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 $1.96 in 2011, $1.96 in 2012, and $1.65 in 2013.

As a result of temporarily suspending the H/B Hz drilling program in July 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 4.4 Bcf of 2012 hedges. Net of deferred premiums payable related to these volumes, the Company received $2.7 million in proceeds.

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 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 83 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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